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| {{#Wiki_filter:W0LF CREEK 'NUCLEAR OPERATING CORPORATION May 09, 2008 Richard D. Flannigan Manager Regulatory Affairs RA 08-0042 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 | | {{#Wiki_filter:}} |
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| ==Subject:==
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| Docket No. 50-482: Transmittal of 2007 Annual Financial Reports Gentlemen:
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| Wolf Creek Nuclear Operating Corporation (WCNOC) is transmitting one copy each of the 2007 annual reports, including financial statements for its owners: Kansas Gas and Electric Company (KGE), a wholly-owned subsidiary of Westar Energy, Inc., Kansas City Power & Light Company (KCPL), a wholly-owned subsidiary of Great Plains Energy Incorporated, and Kansas Electric Power Cooperative, Inc. (KEPCo). This information is being submitted in accordance with 10 CFR 50.71(b).
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| If you have any questions concerning this matter, please contact me at (620) 364-4117, or Diane Hooper at (620) 364-4041.
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| Sincerely, Richard D. Flannigan RDF/rlt Enclosure cc: E. E. Collins (NRC), w/e V. G. Gaddy (NRC), w/e B. K. Singal (NRC), w/e Senior Resident Inspector (NRC), w/e PO. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET
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| Contents Page Financial Statements Pagie Organization and Resources .... 1 Report of Independent Public Accountants ............ -. 1i3 Leadership Message ............................................... 2-3 Balance Sheets .................................................... 14- 15 2007 Highlights ... ..................... .......................... 4-5 Statements of Revenues and Expenses .................. 16 KEPCo Trustees and Managers ................................ 6-9 Changes in Patronage Capital ............................. 16 KEPCo Member Area Map ......................... 9 Statements of Cash Flows ..................................... 17 Operating Statistics .............................................. 10-11 Notes to Financial Statements ............................... 18-29 KEPCo Staff I
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| Stephen Parr ........................... Executive Vice President Shari Koch ..... Accounting, Payroll & Benefits Specialist
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| & Chief Executive Officer Elizabeth Lesline ... Administrative Assistant/Receptionist Bob Bowser ....................... Vice President of Regulatory Mitch Long .................. Sr. SCADA/Metering Technician
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| & Technical Services Loren Medley ......... Business Development Coordinator Les Evans ..................... Vice President of Power Supply Michael Morris ............. Sr. SCADA/Metering Technician J. Michael Peters .......... Vice President of Administration
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| & General Counsel Erika Old .......................... Finance & Benefits Analyst 2 Coleen Wells ..... Vice President of Finance & Controller Matt Ottm an ................................................ Engineer 3 Laura Armstrong ...................... Administrative Assistant John Payne .......................................... Senior Engineer Mark Barbee .................. Manager of Engineering, Robert Peterson ................... Sr. Engineering Technician KSI Vice President of Engineering Rita Petty ......................................... Executive Assistant Sam Delap ........... Information System Specialist & Manager of Office Services Terry Deutscher ............ EMS/SCADA System Specialist Paul Stone ............... ................... System Operator Carol Gardner ................................. Operations Analyst Phil Wages ............ Director of Member Services
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| & External Affairs Robert Hammersmith.... SCADA/Metering Technician 2
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| Organization & Resources Kansas Electric Power Cooperative, Inc. (KEPCo), headquartered at Topeka, Kansas, was incorporated in 1975 is a not-for-profit generation and transmission cooperative (G&T). It is KEPCds responsibility to procure an ad-equate and reliable power supply for its nineteen distribution Rural Electric Cooperative Members at a reasonable cost.
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| Through their combined resources, KEPCo Members support a wide range of other services such as rural eco-niomic development, marketing and diversification opportunities, power requirement and engineering studies, rate jesign; etc.
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| KEPCo is governed by a Board of Trustees representing each of its nineteen Members which collectively serve more than 100,000 electric meters in two-thirds of rural Kansas. The KEPCo Board of Trustees meets regularly to stablish policies and act on issues that often include recommendations from working committees of the Board and
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| ýEPCo Staff. The Board also elects a seven-person Executive Committee which includes the President, Vice Presi-dent, Secretary, Treasurer, and three additional Executive Committee members.
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| KEPCo is under the jurisdiction of the Kansas Corporation Commission (KCC) and was granted a limited certifi-cate of convenience and authority in 1980 to act as a G&T public utility. KEPCo's power supply resources consist of: 70 MW of owned generation from the Wolf Creek Generating Station; the 20 MW Sharpe Generating Station located in Coffey County; hydropower purchases of an equivalent 100 MW from the Southwestern Power Admin-istration, and 14 MW from the Western Area Power Administration; plus partial requirement power purchases from regional utilities.
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| KEPCo is a Touchstone Energy Cooperative. Touchstone Energy is a nationwide alliance of more than 625 cooperatives committed to promoting the core strengths of electric cooperatives - integrity, accountability, innova-tion, personal service and a legacy of community commitment. The national program is anchored by the motto "The Power of Human Connections."
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| Kansas Electric Power Cooperative, Inc.
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| P.O. Box 4877 Topeka, KS 66604 600 SW Corporate View Topeka, KS 66615 (785) 273-7010 www.kepco.org 0
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| ATouchstone Energy Cooperative
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| 2007 Message from Kenneth J Maginley KEPCo President Stephen E Parr Executive Vice President
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| & Chief Executive Officer uring 2007, global climate change continued its rapid ac-celeration as a national and world issue. Many varying schools of thought exist about climate change and the im- M P a plications thereof. One implication is very clear. The costs associ-ated to reduce greenhouse gas emissions will undoubtedly increase the cost of electricity. KEPCo will not be exempt from this implication.
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| Since 1985, over fifty percent of KEPCo's energy mix, nuclear and hydroelectric, has not emitted any green-house gas. This is a statement that perhaps can only be made by a handful of utilities in the U.S. KEPCo has not sought headlines or pats on the back for its environmentally friendly energy mix. Rather, KEPCo has sought recogni-i tion from policy makers that imposing laws or trade systems to reduce emissions must be balanced with commer-cially viable technologies that are implemented over a reasonable and economically feasible time period in order to minimize the financial impact to our Members. KEPCos large percentage of non-greenhouse gas emitting genera-tion will prove to be a valuable asset, well into the future, as the electric industry deals with the reduction of emis-sions.
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| Thanks to the efforts of Staff and Westar Energy, KEPCo made further progress in advancing its mission of providing its Members with a reliable and economical power supply. Two years of negotiations culminated in Au-gust with the signing of a thirty-eight year power purchase agreement with-Westar. Once approved by the Federal Energy Regulatory Commission (FERC), the new contract will enable KEPCo and its Members to have access to Westar's existing low-cost generating resources and mitigate the risk of being vulnerable to price fluctuations in the open market.
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| KEPCo will purchase electricity based on Westar's cost to produce the power and combine it with KEPCds own resources to meet all of its Members' energy needs. KEPCo and its Members will also benefit by having Westar help manage the scheduling of KEPCds resources. The contract allows for KEPCo and Westar to "pool" their respec-tive loads and generating capabilities to make the most efficient use of both companies' resources. KEPCo will also receive nuclear energy form Westar's share of Wolf Creek and credit for wind energy purchased from Westar under the new contract, thus increasing KEPCo's percentage of non-greenhouse gas emitting resources.
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| KEPCo and its Member Cooperatives continue to experience steady load growth, primarily from an increase in methane gas production and the development of ethanol plants in Kansas, as well as the growth in consumer electronics, such as home entertainment equipment and home computers. Since 2004, KEPCo's peak load has increased fourteen percent. In 2007, KEPCo realized a slight reduction in its peak, due to a cooler than normal sum-mer season.
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| KEPCds ownership participation in the latan 2 coal plant, being constructed in Weston, Missouri, by Kansas City Power & Light, continues with the unit scheduled for commercial operation in the summer of 2010. Given the focus on climate change, many proposed coal-fired generating units have recently been cancelled or placed on hold. latan 2 may be one of the last base load, coal-fired generating units to be constructed for many years and will
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| be a critical part of KEPCds power supply for decades to come.
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| The cost of generation fuel continues to be a concern. The average delivered cost of coal in Kansas has in-creased nearly sixteen percent since 2004. The average annual fuel cost for the Wolf Creek Generating Station has increased twelve percent over the same period. Increases in contract demand costs, as well as operations and maintenance costs, predicated the need for KEPCo to file for a 5.2% rate increase to be implemented in late 2008.
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| KEPCo's last rate change became effective in early 2002. The new rate will allow KEPCo to meet its mortgage re-quirements with its lenders and maintain KEPCo in a sound financial position.
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| Cost control has, and will continue to be, a point of emphasis for KEPCo. Implemented in 1990, KEPCo contin-ues to support an aggressive load management program with its Members. This year, KEPCo was able to shed 35 MW, saving our Members approximately $2.1 million.
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| A decision was made in October that is cause for concern for all Kansas electric utilities. The Kansas Depart-ment of Health and Environment
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| ýKDHE) denied the issuance of an
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| ýir permit for a coal-fired generat-
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| .ng plant proposed by Sunflower Electric Power Corporation, a G&T
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| ,n Hays, KS. The denial was based
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| .ipon the Secretary of KDHE citing
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| 'he potential harmful effects that zarbon dioxide emissions would have on the health and environment of Kansans. This decision is being challenged, but if upheld, will have a negative economic impact, not only on the choice and cost of future base load generation, but potentially on the cost of existing generation, if 2007-08 KEPCo Executive Committee (seated): Robert Reece, Scott Whittington; the KDHE places limits on carbon Harlow Haney; (standing) Stephen Parr,Executive Vice President & CEO; Kenneth dioxide emissions from existing coal Magintey, President; Bryan Coover, Treasurer; Gordon Coulter, Secretary; and Kirk plants. Thompson, Vice President.
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| Since its inception, KEPCo has been blessed with dedicated and supportive Members and a highly skilled Board of Trustees, well versed in electric utility matters, which make decisions based upon sound business and economic principles. In addition, KEPCds small, but exceptionally skilled Staff, is a stalwart asset that serves our Members well. Recent events have shown how quickly the industry can change and how change can impact not only one utility, but the industry as a whole. The changes our industry is facing today may alter its landscape more in the next five years than in the past fifty years. KEPCo's continued success will be made possible by the direction of its Mem-.
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| bers and the Board of Trustees, and the subsequent performance of Staff, as we navigate these uncharted waters.
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| The challenge facing the electric utility industry today, and for the foreseeable future, is to ensure that adequate, affordable, and reliable resources are developed and efficiently utilized to ensure the continued growth of America's economy and its energy security. New energy policies are being crafted and debated on a daily basis, both at the state and federal levels. Policies directed at reducing greenhouse gas emissions must exist in harmony with the na-tion's need for economical base load generation. KEPCo will stand firm against any initiative that disproportionately impacts Kansas Cooperatives. As the new regulatory environment evolves, KEPCds challenge and emphasis will continue to be to control costs, procure a reliable energy supply and ensure rates are as economical as possible.
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| Kenneth J. Maginle* Stephen E. Parr
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| 2007 KEPCo Highlights KEPCo ended 2007 with an average Member rate of 5.84 cents per kilowatt hour, its lowest rate since 2004.
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| KEPCo's diverse power supply again providedfifty percent of the energy needed to serve its Members from resources which do not emit greenhousegases.
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| KEPCo executed a thirty-eight year, cost-based, Power Purchase Agreement with Westar Energy. Once approved by FERC, this contract will help secure a stable and economical power supply for the next four decades. KEPCo also finalized a new five-year Power Purchase Agreement with KCP&L.
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| Wolf Creek ran continuously in 2007 and ranked eighth among all U.S. nuclear power plants in capacity factor and fourth in gross generation.
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| KEPCo completed a new whole-sale rate study with the assistance of C.H. Guernsey and Company, the Board's rate consultant, and filed a request for a change in rates with the Kansas Corporation Commission on December 21, 2007.
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| KEPCo continued its legislative efforts by working with Kansas Electric Cooperatives, Inc. on issues in Kansas and with NRECA in Washington, D.C.
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| KEPCo completed the loan process for the Wolf Creek Capital Additions Loan for 2000 - 2005 and filed loan documents with RUS for a Wolf Creek Capital Additions Loan for the years 2006 - 2010.
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| Construction continued throughout the year on latan 2, the new coal-fired generat-ing unit in which KEPCo is an owner-par-ticipant. Commercial operation Is scheduled for the summer of 2010.
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| KEPCo supported the efforts of the Southwest Power Pool in becoming the Regional Transmission Organization and Reliability Coordinator for its seven-state region and focused efforts on meeting the new electric system reliability requirements of the North American Electric Reliability Corporation (NERC).
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| Severe weathermade 2007 a difficult andchallenging year for KEPCo'sMembers. KEPCo supported its Mem-bers' recovery efforts by assisting with the damagefrom two major ice storms, the Greensburgtomado and the floods in southeast Kansas.
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| Staff prepared and submitted the 2007 Integrated Re-source Plan (IRP) to Western Area Power Administration
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| 'SUbstation damaged by Greensbur which covers the time frame 2007-2012.
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| With KEPCo'sassistance, six Member economic development projects with a total combined cost of $6,385,187 were selected by USDA for REDLG funding. Of this total,
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| $2,620,000 of the cost was met with zero inter-est financing. These projects created101 new jobs and saved or secured 140 additionaljobs.
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| KEPCo continued to focus on energy ef-ficiency and conservation through an active Continued on page 12
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| KEPCo Member Cooperatives Trustees, Alternates and Managers Ark Valley Electric Cooperative Assn., Inc.
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| PO Box 1246, Hutchinson, KS 67504 620-662-6661 Trustee Rep. -- Dwight Engelland Alternate Trustee Rep. -- Joseph Seiwert Manager -- Bob Hall Dwight Engelland Joseph Seiwert Bob Hall Bluestem Electric Cooperative, Inc.
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| PO Box 5, Wamego, KS 66547 785-456-2212 PO Box 513, Clay Center, KS 67432 785-632-3111 Trustee Rep. -- Kenneth J. Maginley Alternate Trustee Rep. -- Robert M. Ohlde Manager -- Kenneth J. Maginley Ken Maginley Bob Ohlde Brown-Atchison Electric Cooperative Assn., Inc.
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| PO Box 230, Horton, KS 66439 785-486-2117 Trustee Rep. -- Kevin D. Compton Alternate Trustee Rep. -- Dale Bodenhausen Manager -- Rodney V. Gerdes Kevin Compton Dale Bodenhausen Rod Gerdes Butler Rural Electric Cooperative Assn., Inc.
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| P0 Box 1242, El Dorado, KS 67042 316-321-9600 Trustee Rep. -- Richard Pearson Alternate Trustee Rep. -- Dale Short Manager -- Dale Short Caney Valley Electric Cooperative Assn., Inc.
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| PO Box 308, Cedar Vale, KS 67024 620-758-2262 Trustee Rep. -- Dwane Kessinger Alternate Trustee Rep. -- Allen A. Zadorozny Manager -- Allen A. Zadorozny
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| --a~l -.au,.u.y
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| CMS Electric Cooperative, Inc.
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| PO Box 790, Meade, KS 67864 620-873-2184 Trustee Rep. -- Kirk A. Thompson Alternate Trustee Rep. -- Clifford Friesen Manager -- Kirk A. Thompson DS&O Rural Electric Cooperative Assn., Inc.
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| PO Box 286, Solomon, KS 67480 785-655-2011 Trustee Rep. -- Harlow L. Haney Alternate Trustee Rep. -- Donald E. Hellwig Manager -- Donald E. Hellwig Flint Hills Rural Electric Cooperative Assn., Inc.
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| PO Box B, Council Grove, KS 66846 620-767-5144 Trustee Rep. -- Robert E. Reece Alternate Trustee Rep. -- Gus H. Hamm Manager -- Robert E. Reece UU* lldllll II Heartland Rural Electric Cooperative, Inc.
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| PO Box 40, Girard, KS 66743 620-724-8251 District Offices, Iola 620-365-5151 Mound City, 913-795-2221 Trustee Rep. -- Dennis Peckman Alternate Trustee Rep. -- Dale Coomes Manager -- Dale Coomes Leavenworth-Jefferson Electric Cooperative, Inc.
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| PO Box 70, McLouth, KS 66054 913-796-6111 Trustee Rep. -- Larry H. Stevens Alternate Trustee Rep. -- H.B. Canida Manager -- H.B. Canida n-. *.,l- -dO Lyon-Coffey Electric Cooperative, Inc.
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| PO Box 229, Burlington, KS 66839 620-364-2116 Trustee Rep. -- Scott Whittington Alternate Trustee Rep. -- Donna Williams Manager -- Scott Whittington CowIwnIJU]lYwu
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| KEPCo Member Cooperatives Trustees, Alternates and Managers Ninnescah Electric Cooperative Assn., Inc.
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| PO Box 967, Pratt, KS 67124 620-672-5538 Trustee Rep. -- Gordon Coulter Alternate Trustee Rep. -- Carla A. Bickel Manager -- Carla A. Bickel Gordon Coulter Carta Bickel Prairie Land Electric Cooperative, Inc.
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| PO Box 360, Norton, KS 67654 785-877-3323 District Office, Bird City 785-734-2311 Trustee Rep. -- Gilbert Berland Alternate Trustee Rep. -- Allan J. Miller Manager -- Allan J. Miller Gilbert Berland Allan Miller Radiant Electric Cooperative, Inc.
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| PO Box 390, Fredonia, KS 66736 620-378-2161 Trustee Rep. -- Dennis Duft Alternate Trustee Rep. -- Tom Ayers Administrative Manager -- Leah Tindle Operations Manager -- Dennis Duff Dennis Duff Tom Ayers Leah "Tindle Rolling Hills Electric Cooperative, Inc.
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| PO Box 307, Mankato, KS 66956 785-378-3151 District Offices, Belleville 785-527-2251 Ellsworth 785-472-4021 Trustee Rep. -- Melroy Kopsa Alternate Trustee Rep. -- Leon Eck Manager -- Douglas J. Jackson Sedgwick County Electric Cooperative Assn., Inc.
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| PO Box 220, Cheney, KS 67025 316-542-3131 Trustee Rep. -- Donald Metzen Alternate Trustee Rep. -- Alan L. Henning Manager -- Alan L. Henning
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| Sumner-Cowley Electric Cooperative, Inc.
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| PO Box 220, Wellington, KS 67152 620-326-3356 Trustee Rep. -- Charles Riggs Alternate Trustee Rep. -- Cletas Rains Manager -- Cletas Rains Twin Valley Electric Cooperative, Inc.
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| PO Box 385, Altamont, KS 67330 620-784-5500 Trustee Rep. -- Bryan W. Coover Alternate Trustee Rep. -- Ron Holsteen Manager -- Ron Holsteen Victory Electric Cooperative Assn., Inc.
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| PO Box 1335, Dodge Cty, KS 67801 620-227-2139 Trustee Rep. -- Marvin Hampton Alternate Trustee Rep. -- Terry Janson Manager -- Terry Janson KEPCo Member Area Map
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| Operating Statistics Operating Expenses Wolf Creek O&M Nuclear Fuel end A&G 2.6%
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| KEPC O&M and 11.8%
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| A&, N4 I 5.3%
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| OeW. And AoLPurchaed Power 7 .1 % 64 .6%
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| 4a0 460 3M0 300 Peak Demand 160 so Yew 14ý - I --- - II
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| ates Sunflowr 12.2%45
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| ~ VkAPA Sources of Energy
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| .WoNCr~e&
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| 1.4WOO.W II Energy MOO~O Sales o
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| 05 96 97 a w 00 01 02 03 04 90 06 07 Yws I
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| 2007 KEPCo Highlights Continuedfrom page 5 load management program and by funding and assisting Members in the promotion of an energy efficient electric water heater and heating/cooling system rebate program. Since inception, KEPCo has issued over 5,000 heating/
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| cooling rebates and over 13,000 water heater rebates.
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| Sharpe Generating Station was credited by the Nu-clear Regulatory Commission as a back-up power source for Wolf Creek and supported two Emergency Diesel Generator maintenanceoutages while Wolf Creek was in operation. This effort will reduce the scope and duration SS arpeL of work required in future Wolf Creek refueling outages.
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| Staff assisted Members with the installation of Auto-mated Meter Reading (AMR) equipment. Several of the
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| * AMR systems use KEPCcs backbone network to deliver the meter data to Member offices.
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| IPAddressableMV-90 units were installed which allows KEPCo to call and download meter data at a fraction of what it would cost by any other method.
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| Staff provided technical consultation to Westar Energy during their wind generation acquisition process.
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| KSI Engineering, in its tenth year of operation, completed numerous projectsfor severalKEPCo Members and non-Members alike. These projects included distribution staking for storm-relatedFEMA restora-tion projects, substation design andproject management,construction work plans, work order inspections and sectionalizing studies, among others.
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| Kansas Electric Power Cooperative, Inc.
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| Financial Statements December 31, 2007 and 2006 Independent Accountants' Report Board of Trustees Kansas Electric Power Cooperative, Inc.
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| Topeka, Kansas We have audited the accompanying consolidated balance sheets of Kansas Electric Power Cooperative, Inc. (KEPCo) as of December 31, 2007 and 2006, and the related consolidated statements of margin, patronage capital and cash flows for the years then ended. These financial statements am the responsibility of the KEPCo's management. Our responsibility is to express an opinion on these financial statements based on our audits.
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| We conducted our audits in accordance with auditing standards generally accepted in die United States of America and the standards applicable to financial audits contained in Goverrment Auditing Sturtards, issued by the Comptroller General of the United States. Those standards require that we plan ard perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall firrancial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
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| As explained in Note 3, certain depreciation and amortization methods have been used in the prepiration of tme2007 and 2006 financial statements which, in our opinion, are not in accordance with accounting principles generally accepted in the United States of America, The effects on the financial statements of the aforementioned departure are explained in Note 3.
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| In our opinion, except for the effects of using [lieaforementioned depreciation and amortization methods as discussed in Note 3, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Kansas Electric Power Cooperative, Inc., as of December 31, 2007 and 2006, and the results of its operations and itscash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
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| As discussed in Note 10,KEPCo adopted Statement of Financial Accounting Standard No. 158, Ermployers Accorrti rgfor Defined Befefir Pensioc and Other Pvstretirnet Plans,as or December 31.
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| 2007.
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| In accordance with Govermnenr AuditintgStnat/arab, we also have issued our report dated April 9. 2008.
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| on our consideration of KEPCo's internal control over financial reporting and our tests of its compliance with certain provisions of laws. regulations, contracts and grant agreements and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Goernnmet Auditing Standards and should be considered in assessing the results of our audit.
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| April 9, 2008 Praxityx BWOSYttoteI tlfls
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| Kansas Electric Power Cooperative, Inc.
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| Consolidated Balance Sheets December 31, 2007 and 2006 Assets 2007 2006 Utility Plant In-service $ 224,863,485 $ 225,003,755 Less allowance for depreciation (122,771,314) (120,837,298)
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| Net in-service 102,0-92,171 104,166,457 Construction work in progress 19,671,233 6,550,342 Nuclear fuel (less accumulated amortization of $15,025,746 and $12,921,304 for 2007 and 2006, respectively) 7,53,91 Total utility plant 129,336,995 115,638,574 Restricted Assets Investments in the National Rural Utilities Cooperative Finance 5,466,712 3,219,847 Corporation Bond fund reserve 4,348,709 4,295,806 Decommissioning fund 10,185,163 9,245,665 Investments in other associated organizations 164,072 152,306 Total res~ridted assets 20,164,656 16,913,624 Current Assets Cash and cash equivalents 6,132,774 3,271,471 Member accounts receivable 8,787,049 8,021,333 Materials and supplies inventory 3,123,051 .2,983,476 Other assets and prepaid expenses 593,671 653,037 Total current assets 18,636,545 14,929,317 Other Long-term Assets Deferred charges Wolf Creek disallowed costs (less accumulated amortization of $11,877,898 and $11,120,734 for 2007 and 2006, respectively) 14,105,023 14,862,187 Wolf Creek deferred plants costs (less accumulated amortization of $18,779,517 and $15,649,598 for 28,169,276 31,299,195
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| * 2007 and 2006, respectively)
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| Wolf Creek decommissioning regulatory asset 4,247,845 4,114,385 Deferred Department of Energy decommissioning costs 74,712 Deferred incremental outage costs 1,092,847 3,535,349 Other deferred charges (less accumulated amortization of
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| $6,826,077 and $6,106,253 for 2007 and 2006, respectively) 3,098,957 3,597,661 Unamortized debt issuance costs 734,861 855,402 Other investments 282,415 248,686 Total long-term assets 51,731,224 58,587,577 Total assets $ 219,869,420 $ 206,069,092
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| Kansas Electric Power Cooperative, Inc.
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| Consolidated Balance Sheets December 31, 2007 and 2006ý Liabilities and Patronage Capital 2007 2006 Patronage Capital Memberships $ 3,200 $ 3,200 Patronage capital 22,194,144 19,409,487 Accumulated other comprehensive income (loss) (3,120,448)
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| Total patronage capital 19,076,896 19,500,687 Long-term Debt 154,387,397 142,272,490 Other Long-term Liabilities Wolf Creek decommissioning liability 17,328,228 16,332,466 Wolf Creek pension and post retirement benefit plans 5,409,857 1,954,177 Wolf Creek deferred compensation 718,868 635,695 Arbitrage rebate long-term liability 660,863 537,765 Other deferred credits Total other long-term liabilities 24,134,459 19,472,555 Current Liabilities Current maturities of long-term debt 11,950,139 11,162,495 Line of credit 3,521,028 Accounts payable 8,292,006 7,958,739 Payroll and payroll-related liabilities 304,110 284,661 Accrued property taxes 1,317,434 1,319,875 Accrued interest payable 406,979 576,562 Total current liabilities 22,270,668 24,823,360 Total patronage capital and liabilities $ 219,869,420 $ 206,069,092
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| Kansas Electric Power Cooperative, Inc.
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| Consolidated Statements of Margin December 31, 2007 and 2006 Liabilities and Patronage Capital 2007 2006 Operating Revenues Sales of electric energy $ 109,228,388 $ 110,707,844 Other 111,383 64,089 Total operating revenues 10,39771 110,771,933 Operating Expenses Power purchased 69,728,597 73,351,849 Nuclear fuel 2,745,855 2,382,257 Plant operations 9,289,461 9,072 ,478 Plant maintenance 3,312,698 3,062,210 Administrative and general 5,367,620 5,069,698 Amortization of deferred charges 4,483,341 4,588,219 Depreciation and decommissioning Total operating expenses 99,045,188 101,695,276 Net operating revenues 10,294,583 9,076,657 Interest and Other Deductions Interest on long-term debt, net of capitalized interest of
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| $529,876 - 2007 and $63,943 -2006 8,154,765 8,604,186 Amortization of debt issuance costs 120,542 125,431 Other deductions 115,567 108,761 Total interest and other deductions 8,390,874 8,838,378 Operating income 1,903,709 238,279 Other Income (Expenses)
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| Interest income 640,660 875,646 Other income (expenses) 152,288 (67,243)
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| Total other income 792,948 808,403 Net margin $ 2,696,657 $ 1,046,682 Kansas Electric Power Cooperative, Inc.
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| Consolidated Statements of Patronage Capital December 31, 2007 and 2006 Accumulated Other Patronage ýomprehensive Memberships Capital In come (Loss) Total Balance, December 31, 2005 $ 3,200 $ 18,450,805 - $ 18,454,005 Net margin - 1,046,682 - 1,046,682 Balance, December 31, 2006 3,200 19,497,487 - 19,500,687 Net margin - 19,497,487 - 2,696,657 Defined benefit pension plans Actuarial loss -- (3,031,867)
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| Prior service cost -- (22,769)
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| Transition obligation -- (65,812)
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| Balance, December 31, 2007 $ - ,0 $ 2219,44 $ (3,120,448) $ 221734
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| Kansas Electric Power Cooperative, Inc.
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| Consolidated Statements of Cash Flows December 31, 2007 and 2006 Liabilities and Patronage Capital 2007 2006 Operating Activities Net margin $ 2,696,657 $ 1,046,682 Adjustments to reconcile net margin to net cash provided by operating activities Depreciation and amortization 3,683,888 3,704,711 Decommissioning 937,014 1,458,328 Amortization of nuclear fuel 2,104,442 1,748,780 Amortization of deferred charges 4,385,787 4,588,218 Amortization of deferred incremental outage costs 2,810,796 2,557,796 Amortization of debt issuance costs 120,542 125,432 Changes in Member accounts receivable (765,716) 637,183 Materials and supplies (139,576) (156,089)
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| Other assets and prepaid expenses 25,638 120,250 Accounts payable 333,269 208,536 Payroll and payroll-related liabilities 19,449 20,971 Accrued property tax (2,441) 25,533 Accrued interest payable (169,584) 155,139 Restricted assets (52,903) (33,328)
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| Other long-term liabilities .545,694 (300,801)
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| Net cash provided by operating activities 16,532,95 15,907,341 Cash Flows From Investing Activities Additions to electric plant (14,730,493) (6,034,758)
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| Additions to nuclear fuel (4,756,258) (3,179,023)
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| Additions to deferred incremental outage costs (368,294) (4,078,059) investmnents in decommissioning fund assets (939,498) (1,292,261)
| |
| Other (2,258,632) 20,047 Net cash used in investing activities (23,053,175) (14,564,054)
| |
| Cash Flows From Financing Activities Net borrowing (payment) under line of credit agreement (3,521,028) 3,521,028 Principle payments on long-term debt (11,162,496) (10,464,348)
| |
| Utilization of RUS cushion of credit 3,526,341 Proceeds from issuance of long-term debt 24,065,046 Net cash provided by (used in) financing activities 9,381,522 (3,416,979)
| |
| Net increase (decrease) in cash and cash equivalents 2,861,303 (2,073,692)
| |
| Cash and Cash Equivalents, Beginning of Year 3,271,471 5,345,163 Cash and Cash Equivalents, End of Year $ 6,132,774 $ 3,271,471 Supplemental Cash Flows Information Cash paid during the year for interest $ 8,355,648 $ 8,385,104
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 Note 1: Nature of Operations and Summary of Significant Accounting Policies Nature of Operations Kansas Electric Power Cooperative, Inc. and its subsidiary (KEPCo), headquartered in Topeka, Kansas, was incorporated in 1975 as a not-for-profit generation and transmission cooperative (G&T). KEPCo is under the jurisdiction of the Kansas Corporation Commission (KCC) and was granted a limited certificate of convenience and authority in 1980 to act as a G&T public utility. It is KEPCo's responsibility to procure an adequate and reliable power supply for its 19 distribution rural electric cooperative members pursuant to all requirements of its power supply contracts. KEPCo is governed by a board of trustees representing each of its 19 members, which collectively serve more than 100,000 electric customers in rural Kansas.
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| System of Accounts KEPCo maintains its accounting records substantially in accordance with the Rural Utilities Service (RUS)
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| Uniform Systems of Accounts and in accordance with accounting practices prescribed by the KCC.
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| Rates The KCC has the authority to establish KEPCds electric rates under state law in Kansas. Rates are established to meet the times-interest-earned ratio and debt-service coverage set forth by the RUS. KEPCo's rates include an energy cost adjustment (ECA) mechanism, which allows KEPCo to pass along increases in certain energy costs to its cooperative members.
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| Principles of Consolidation The consolidated financial statements include the amounts of KEPCo and its majority-owned subsidiary, KEPCo Services, Inc. Undivided interests in jointly owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions have been eliminated in consolidation.
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| Estimates The preparation of consolidated financial statements in conformity with accounting principles generally ac-cepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the report-ing period. Actual results could differ from those estimates.
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| Utility Plant and Depreciation Utility plant is stated at cost. The cost of repairs and minor replacements are charged to operating expenses as appropriate. Costs of renewals and betterments are capitalized. The original cost of utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation.
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| The composite depreciation rate for electric generation plant for the years ended December 31, 2007 and 2006, was 3.07% and 2.98%, respectively.
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| The provision for depreciation computed on a straight-line basis for electric and other components of utility plant is as follows:
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| Transportation and equipment 25 to 33 years Office furniture and fixtures 10 to 20 years Leasehold improvements 20 years Transmission equipment 10 years Nuclear Fuel The cost of nuclear fuel in process of refinement, conversion, enrichment and fabrication is recorded as utility plant asset at original cost and is amortized to nuclear fuel expenses based upon the quantity of heat produced for the generation of electric power. The permanent disposal of spent fuel is the responsibility of the Depart-
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 ment of Energy (DOE). KEPCo pays one cent per net MWh of nuclear generation to the DOE for the future disposal service. These disposal costs are charged to nuclear fuel expense.
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| Decommissioning Fund Assets/Decommissioning Liability As of December 31, 2007 and 2006, approximately $10.2 million and $9.2 million, respectively, have been collected and are being retained in an interest-bearing trust fund to be used for the physical decommission-ing of Wolf Creek Nuclear Generating Station (Wolf Creek). The trustee invests the decommissioning funds primarily in mutual finds, which are carried at estimated fair value. During 2003, the KCC extended the esti-mated useful life of Wolf Creek to 60 years from the original estimates of 40 years only for the determination of decommissioning costs to be recognized for ratemaking purposes. In 2006, the KCC approved a 2005 decommissioning cost study, which increased the estimate of total decommissioning costs to $517.6 million in 2005 dollars ($31.1 million is KEPCds share). The study assumes a 4.4% rate of inflation and 7% rate of return.
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| KEPCo adopted Statement of Financial Accounting Standard (SFAS) No. 143, Accounting for Asset Retire-ment Obligations, on January 1, 2003. SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized and depreciated over the appropri-ate period as part of the cost of the related tangible long-lived assets.
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| SFAS No. 143 required KEPCo to recognize and estimate the liability for its 6% share of the estimated cost to decommission Wolf Creek, based on the present value of the asset retirement obligation KEPCo incurred at the time it was placed into service in 1985. On January 1, 2003, KEPCo initially recognized an asset retire-ment obligation of $11.7 million; utility plant in-service, net of accumulated depreciation, was increased by
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| $2.9 million; and KEPCo also established a regulatory asset for $3.9 million, which represents the amount of the Wolf Creek asset retirement obligation and accumulated depreciation not yet refunded.
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| The decommissioning study in 2005 increased the asset retirement obligation by approximately $1.5 million, utility plant in-service, net of accumulated depreciation by $.2 million and the regulatory asset by $1.2 million in 2006.
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| A reconciliation of the asset retirement obligation for the years ended December 31, 2007 and 2006, is as follows:
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| 2007 2006 Balance at January 1 $16,332,466 $13,916,214 Accretion 995,762 938,420 Increase from 2005 study - 1,477,832 Balance at December 31 $17,328,228 $16,332,466 Any net margin effects are deferred in the Wolf Creek decommissioning regulatory asset created pursuant to SFAS No. 71, Accounting for the Effects of Certain types of Regulation, and will be collected from members in future electric rates.
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| Cash and Cash Equivalents All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents and are stated at cost, which approximates fair value. Cash equivalents consist primarily of certificates of deposit.
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| Accounts Receivable Accounts receivable are stated at the amount billed to members and customers. KEPCo provides allowances for doubtful accounts, which is based upon a review of outstanding receivables, historical collection informa-
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 tion and existing economic conditions.
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| Materials and Supplies Inventory Materials and supplies inventory are valued at average cost.
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| Unamortized Debt Issuance Costs Unamortized debt issue costs relate to the issuance of the floating/fixed rate pollution control revenue bonds, mortgage notes payable to the National Rural Utilities Cooperative Finance Corporation (CFC) trusts, and fees for repricing the Federal Financing Bank (FFB) debt. These costs are being amortized using the effective interest method over the remaining life of the bonds and notes.
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| Cash Surrender Value of Life Insurance Contracts The following amounts related to Wolf Creek Nuclear Operating Corporation (WCNOC) corporate-owned life insurance contracts, primarily with one highly rated major insurance company, are induded in other invest-ments on the consolidated balance sheets.
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| 2007 2006 Cash surrender value of contracts $ 4,943,704 $ 4,693,922 Borrowings against contracts (4,943,704) (4,693,922)
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| Borrowings against contracts include a prepaid interest charge. KEPCo pays interest on these borrowings at a rate of 5.45% for the years ended December 31, 2007 and 2006.
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| Revenues Revenues are recognized during the month the electricity is sold. Revenues from the sale of electricity are recorded based on usage by member cooperatives and customers and on contracts and scheduled power us-ages as appropriate.
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| Income Taxes As a tax-exempt cooperative, KEPCo is exempt from income taxes under Section 501(c)(12) of the Internal Revenue Code of 1986, as amended. Accordingly, provisions for income taxes have not been reflected in the accompanying consolidated financial statements.
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| Reclassifications Certain reclassifications have been made to the 2006 fihancial statements to conform to the 2007 financial statement presentation. These reclassifications had no effect on net earnings.
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| Note 2: Factors That Could Affect Future Operating Results KEPCo currently applies accounting standards that recognize the economic effects of rate regulation pursu-ant to SFAS No. 71, Accounting for the Effect of Certain Types of Regulation, and accordingly has recorded regulatory assets and liabilities related to its generation and transmission operations. In the event KEPCo de-termines that it no longer meets the criteria of SFAS No. 71, the accounting impact could be a noncash charge to operations of an amount that would be material. Criteria that could give rise to the discontinuance of SFAS No. 71 include: (1) increasing competition that restricts KEPCO's ability to establish prices to recover specific costs, and (2) a significant change in the manner rates are set by regulators from a cost-based regulation to another form of regulation. KEPCo periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Any changes that would require KEPCo to discontinue the application of SFAS No. 71 due to increased competition, regulatory changes or other events may significantly impact the valua-tion of KEPCo's investment in utility plant, its investment in Wolf Creek and necessitate the write-off of regula-tory assets. At this time, the effect of competition and the amount of regulatory assets that could be recovered
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 in such an environment cannot be predicted.
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| The 1992 Energy Policy Act began the process of restructuring the United States electric utility industry by permitting the Federal Energy Regulatory Commission to order electric utilities to allow third parties to sell electric power to wholesale customers over their transmission systems. The Kansas legislature has not taken any significant action on industry restructuring that would have a'direct impact on KEPCo. Management will continue to monitor deregulation initiatives, but does not presently expect any actions that would be unfavor-able to KEPCo to be adopted within the next 12 months.
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| Note 3: Departures From Generally Accepted Accounting Principles Effective February 1, 1987, the KCC issued an order to KEPCo requiring the use of present worth (sinking fund) depreciation and amortization. As more fully described in Note 7, such depreciation and amortization methods constituted phase-in plans that did not meet the requirements of SFAS No. 92, Accounting for Phase-In Plans.
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| Effective February 1, 2002, the KCC issued an order that extended the depreciable life of Wolf Creek from 40 years to 60 years. This order also permitted recovery in rates of the $53.5 million cumulative difference between historical present worth (sinking fund) depreciation and amortization and straight-line depreciation and amortization of Wolf Creek generation plant and disallowed costs over a 15-year period. As more fully described in Note 7, such depreciation and amortization methods constitute phase-in plans that do not meet the requirements of SFAS No. 92. Recovery of these costs in rates is included in operating revenues, and the related amortization expense is included in deferred charges in the consolidated statements of revenues and expenses.
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| The effect of these departures from generally accepted accounting principles is to overstate (understate) the following items in the consolidated financial statements by the following amounts:
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| 2007 2006 Deferred charges $ 32,072,707 $ 35,636,341 Patronage capital $ (32,072,707) 35,636,341 Net margin $ (3,563,634) $ (3,563,634)
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| Note 4: Wolf Creek Nuclear Operating Corporation KEPCo owns 6% of Wolf Creek Nuclear Operating Corporation (WCNOC), which is located near Burlington, Kansas. The remainder is owned by the Kansas City Power & light Company (KCPL) 47% and Kansas Gas
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| & Electric Company (KGE) 47%. KGE is a wholly owned subsidiary of Westar Energy, Inc. KCPL is a wholly owned subsidiary of Great Plains Energy, Inc. KEPCos undivided interest in WCNOC is consolidated on a pro rata basis. Substantially all of KEPCo's utility plant consists of its pro rata share of WCNOC. KEPCo is entitled to a proportionate share of the capacity and energy from WCNOC, which is used to supplement a portion of KEPCds members' requirements. KEPCo is billed on a daily basis for 6% of the operations, main-tenance, administrative and general costs and cost of plant additions related to WCNOC.
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| WCNOC disposes of all classes of its low-level radioactive waste at existing third-party repositories. Should disposal capability become unavailable, WCNOC is able to store its low-level radioactive waste in an on-site facility for up to five years under current regulations.
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| Note 5: Investments in Associated Organizations Investments in associated organizations are carried at cost. At December 31, 2007 and 2006, investments in
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 associated organizations consisted of the following:
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| 2007 2006 CFC Memberships $ 1,000 $ 1,000 Capital term certificates 395,970 395,970 Subordinated term certificates 2,205,000 2,205,000 Patronage capital certificates 40,737 25,134 Equity term certificates 2,824,005 592,743 5,466,712 3,219,847 Other 164,072 152,306
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| $ 5,630,784 $ 3,372,153 Note 6: Bond Fund Reserve KEPCo has entered into a bond covenant whereby KEPCo is required to maintain, with a trustee, a bond fund reserve of approximately $4.3 million. This stipulated amount is sufficient to satisfy certain future interest and principal obligations. The amount held in the bond fund reserve is invested by the trustee in tax-exempt municipal securities, pursuant to the restrictions of the indenture agreement, which are carried at amortized cost.
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| Note 7: Deferred Charges Wolf Creek Disallowed Costs Effective October 1, 1985, the KCC issued a rate order relating to KEPCo's investment in Wolf Creek, which disallowed $26.0 million of KEPCds investment in Wolf Creek ($14.1 net of accumulated amortization as of December 31, 2007). A subsequent rate order, effective February 1, 1987, allows KEPCo to recover these disallowed costs and other costs related to the disallowed portion (recorded as deferred charges) for the period from September 3, 1985 through January 31, 1987, over a 27.736-year period starting February 1, 1987. Pursuant to a KCC rate order dated December 30, 1998, the disallowed portion's recovery period was extended to a 30-year period. Through December 31, 2001, KEPCo used the present worth (sinking fund) method to recover the disallowed costs, which enabled it to meet the times-interest-earned ratio and debt ser-vice requirements in the KCC rate order dated January 30, 1987. The method used by KEPCo through 2001 constituted a phase-in plan that did not meet the requirements of Statement of Financial Accounting Standard No. 92, Accounting for Phase-In Plans (SFAS No. 92).
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| Effective February 1, 2002, the KCC issued an order permitting recovery in rates of the $6.5 million cumula-tive difference between historical present worth (sinking fund) and straight-line amortization of Wolf Creek disallowed costs over a 15-year period. Such depreciation practice does not constitute a phase-in plan that meets the requirements of SFAS No. 92.
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| If the disallowed costs were recovered using a method in accordance with accounting principles generally ac-cepted in the United States, the costs would have been expensed in their entirety upon implementation of the KCC order, with a corresponding decrease in patronage capital.
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| Wolf Creek Deferred Plant Costs Effective February 1, 2002, the KCC issued an order permitting recovery in rates of the $46.9 million cumula-tive difference between historical present worth (sinking fund) depreciation and straight-line depreciation of
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 Wolf Creek generation plant over a 15-year period. Such depreciation practice does not constitute a phase-in plan that meets the requirements of SFAS No. 92. In 2002, this cumulative difference was reclassified from utility plant allowance for depreciation to deferred charges on the consolidated balance sheets to reflect the amount as a regulatory asset. Amortization of the Wolf Creek deferred plant costs is included in amortization of deferred charges and amounts to $3.1 million for each of the years ended December 31, 2007 and 2006.
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| If the deferred plant costs were recovered using a method in accordance with accounting principles generally accepted in the United States, the costs would have been expensed in their entirety upon implementation of the KCC order, with a corresponding decrease in patronage capital.
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| Deferred Incremental Outage Costs In 1991, the KCC issued an order that allowed KEPCo to defer its 6% share of the incremental operating, maintenance and replacement power costs associated with the periodic refueling of Wolf Creek. Such costs are deferred during each refueling outage and are being amortized over the approximate 18-month operating cycle coincident with the recognition of the related revenues. Additions to the deferred incremental outage costs were $0.4 million and $4.1 million in 2007 and 2006, respectively. The current year amortization of the deferred incremental outage costs was $2.8 million and $2.6 million in 2007 and 2006, respectively.
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| Other Deferred Charges KEPCo includes in other deferred charges the early call premium resulting from refinancings. These early call premiums are amortized using the effective interest method over the remaining life of the new agreements.
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| Note 8: Short-Term Borrowings As of December 31, 2007, KEPCo has a $14,625,000 line of credit outstanding with the CFC. This line of credit expires in March of 2008. There were outstanding borrowings of $0 and $3,521,028 at December 31, 2007, and December 31, 2006, respectively. Interest varies and was 7.15% at December 31, 2006 and 6.40%
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| at December 31, 2007.
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| Note 9: Long-Term Debt Long-term debt consists of mortgage notes payable to the United States of America acting through the FFB, the CFC and others. Substantially all of KEPCo's assets are pledged as collateral. The terms of the notes as of December 31 are as follows:
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| 2007 2006 Mortgage notes payable to the FFB at fixed rates varying from 3.61% to 9.206%, payable in quarterly installments through 2018 $ 78,787,354 $ 79,232,070 Mortgage notes payable to the Grantor Trust Series 1997 at a rate of 7:522%, payable semiannually, principal payments commencing in 1999 and continuing annually through 2017 40,840,000 43,340,000 Floating/fixed rate pollution control revenue bonds, City of Burlington, Kansas, Pooled Series 1985C, variable interest rate (ranging from 5.80% to 6.40% at December 31, 2007) payable annually through 2017 $ 24,700,000 $ 26,700,000 Mortgage notes payable and equity certificate loans to the National Rural Utilities Cooperative Finance
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 Corporation at fixed rates of 5.80% to 6.10%, payable quarterly through 2017. Currently KEPCo has approximately $67.6 millions of funds available to borrow, which mature in 2012 22,010,182 4,162,915 166,337,536 153,434,985 Less current maturities 11,950,139 11,162,495
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| $ 154,387,397 $ 142,272,490 Aggregate maturities of long-term debt for the next five years and thereafter are as follows:
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| 2008 $ 11,950,139 2009 13,159,154 2010 14,091,957 2011 15,188,130 2012 34,435,351 Thereafter 77,512,805
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| $166,337,536 Restrictive covenants require KEPCo to design rates that would enable it to maintain a times-interest-earned ratio of at least one-to-one and debt-service coverage of at least one-to-one, on average, in at least two out of every three years. The covenants also prohibit distribution of net patronage capital or margins until, after giving effect to any such distribution, total patronage capital equals or exceeds 20% of total assets, unless such distribution is approved by RUS. KEPCo was in compliance with such restrictive covenants as of December 31, 2007 and 2006.
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| In 1997, KEPCo refinanced its mortgage notes payable to the 1988 CFC Grantor Trust through the establish-ment of a new CFC Grantor Trust Series 1997 (the Series 1997 Trust) by CFC. This refinancing reduced the guaranteed interest rate payable on the mortgage notes to a fixed rate of 7.522% through the use of an inter-est rate swap that was assigned by KEPCo to the Series 1997 Trust. The mortgage notes payable are prepay-able at any time with no prepayment penalties. However, any termination costs relating to the termination of the assigned interest rate swaps is KEPCds responsibility. At December 31, 2007, the termination obligation associated with the assigned swap agreement to early retire the mortgage notes payable is approximately $7.3 million. This fair value estimate is based on information available at December 31, 2007, and is expected to fluctuate in the future based on changes in interest rates and outstanding principal balance.
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| KEPCo also is exposed to possible credit loss in the event of noncompliance by the counterparty to the swap agreement. However, KEPCo does not anticipate nonperformance by the counterparty.
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| Note 10: Benefit Plans National Rural Electric Cooperative Association (NRECA) Retirement and Security Program KEPCo participates in the NRECA Retirement and Security Program for its employees. All employees are eligible to participate in this program after one year of service. In the master multi-employer plan, which is available to all members of NRECA, the accumulated benefits and plan assets are not determined or allocated by individual employees. KEPCds expense under this program was $0.3 million and $0.2 million for the year ended December 31, 2007 and 2006, respectively.
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| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 NRECA Savings 401(k) Plan All employees of KEPCo are eligible to participate in the NRECA Savings 401(k) Plan. Under the plan, KEPCo contributes an amount not to exceed 5%, dependent upon each employee's level of participation and comple-tion of one year of service, of the respective employee's base pay to provide additional retirement benefits.
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| KEPCo contributed $0.1 million to the plan for each of the years ended December 31, 2007 and 2006.
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| WCNOC Pension and Postretirement Plans KEPCo has an obligation to the WCNOC retirement, supplemental retirement, and postretirement medical plans for its 6% ownership interest in Wolf Creek. The plans provide for benefits upon retirement, normally at age 65. In accordance with the Employee Retirement Income Security Act of 1974, KEPCo has satisfied its minimum funding requirements. Benefits under the plans reflect the employee's compensation, years of service and age at retirement.
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| Wolf Creek uses a measurement date of November 30 for its retirement plan and December 31 for its supple-mental retirement plan and postretirement plan (collectively "the Plans"). Information about KEPCds 6% of the Plan's funded status follows:
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| Pension Benefits Postretirement Benefits 2007 2006 2007 2006 Benefit obligation $ (11,469,649) $ (10,112,220) $ (1,097,210) $ (943,500)
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| Fair value of plan assets 7,157,002 6,110,880
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| $ (4,312,647) $ (4,001,340) $ (1,097,210) $ (943,500)
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| At December 31, 2007, KEPCo adopted Statement of Financial Accounting Standard No, 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans (FAS 158). FAS 158 required KEPCo to recognize a liability for the unfunded status of the Plans and adjust accumulated other comprehensive in-come for the transition obligation, prior service cost and net loss that had not yet been recognized as compo-nents of net periodic benefit cost at that date. The following table illustrates the incremental effect of applying FAS 158 on individual line items in the balance sheet at December 31, 2007.
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| Before Adjustment After Accumulated other comprehensive income (loss) $ - $ (3,120,448) $ (3,120,448)
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| Total patronage capital $22,197,344 $ (3,120,448) $ 19,076,896 Wolf Creek pension and postretirement benefit plans long-term liability $ 2,289,409 $ 3,120,448 $ 5,409,857 Total other long-term liabilities $21,014,011 $ 3,120,448 $ 24,134,459 Amounts recognized in the consolidated balance sheets:
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| 2007 2006 Other long-term liabilities Wolf Creek pension and postretirement benefit plans $5,409,857 $1,954,177 Amounts recognized in accumulated other comprehensive income (loss) not yet recognized as components of net periodic benefit cost consist of:
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| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 Pension Benefits Postretlrement Benefits 2007 2006 S2007 2006 Net loss $ (2,692,708) $ $ (339,159) $ -
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| Prior service cost (22,769)
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| Transition obligation l(2,u0ul (36,782)
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| $ (2,744,507) $ $ (375,941) $
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| Information for the pension plan with an accumulated benefit obligation in excess of plan assets:
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| Pension Benefits 2007 2006 Projected benefit obligation $ 11,469,649 $ 10,112,220 Accumulated benefit obligation $ 8,719,461 $ 7,958,220 Fair value of plan assets $ 7,157,002 $ 6,110,880 Other significant balances and costs are:
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| Pension Benefits Postretirement Benefits 2007 2006 2007 2006 Employer contributions $ 717,218 $ 608,460 $ 65,085 $ -
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| Benefits paid $ 230,966 $ 127,0809 $ 65,085 $ -
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| Benefits cost $ 955,522' $ 767,400 $ 150,168 $ 116,640 The estimated net loss, prior service cost and transition obligation for the defined benefit pension plans that will be amortized from accumulated other comprehensive income (loss) into net periodic benefit cost over the next fiscal year are approximately $209,000, $7,000 and $7,000, respectively. The estimated net loss and transition obligation for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income (loss) into net periodic benefit cost over the next fiscal year are approximately $28,000 and $7,000, respectively.
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| Significant assumptions used to determine benefit obligations include:
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| Pension Benefits Postretirement Benefits 2007 2006 2007 2006 Discount rate 6.15% 5.70% 6.05% 5.80%
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| Annual salary increase rate 4.00% 3.25% N/A N/A\
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| Expected return on plan assets 8.25% 8.25% N/A N/A 8.0% 9.0%
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| decreasing decreasing 0.5% per year 1.0% per year Assumed health care costs trend rate N/A N/A to 5.0% to 5.0%
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| WCNOC uses an interest yield curve to make judgements pursuant to EITF Topic No. D-36, Selection of Dis-count Rates Usedfor Measuring Defined Benefit Pension Obligations and Obligations of Postretirement Benefit Plans Other Than Pensions. The yield curve is constructed based on yields on over 500 high-quality, noncall-able corporate bonds with maturities between zero and 30 years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of WCNOC's pension plan and develop a single-point discount rate matching the plan's payout structure.
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| | |
| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned assets classes in the pension plan' s investment portfolio. Assumed and projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocation for each asset class, the overall expected rate of return for the portfolio was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses from plan assets.
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| In selecting the discount rate, fixed income security yield rates for corporate high-grade bond yields were considered.
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| The defined benefit pension plan assets are invested in insurance contracts, corporate bonds, equity securities, United States government securities and short-term investments.
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| The asset allocation for the defined benefit pension plan at the end of 2007 and 2006, and the target alloca-tion for 2008 by asset category are as follows:
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| Target Allocation Pension Plan Assets for 2008 2007 2006 Asset category Equity securities 65% 67% 63%
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| Debt securities 35% 28% 34%
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| Other 0% 5% 3%
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| 100% 100%
| |
| WCNOC's pension plan investment strategy supports the objective fund, which is to earn the highest pos-sible return on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors and manager style to minimize the risk of large losses. WCNOC delegates investment management to specialists in each asset class and, where appropriate, provides the investment manager with specific guidelines, which include allowable and/or prohibited investment types. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews.
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| KEPCo estimates cash contributions of approximately $800,000 will be made to the Plans in 2008.
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| Estimated future benefit payments for the Plans, which reflect expected future services, are as follows:
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| Pension Benefits Other Benefits 2008 $ 274,680 $ 80,640 2009 246,900 52,380 2010 285,360 57,060 2011 334,620 61,860 2012 391,020 65,880 2013-2017 3,176,400 415,800
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| $4708,~980 $ 733,620 Note 11: Commitments and Contingencies Litigation There is a provision in the Wolf Creek operating agreement whereby the owners treat certain claims and losses arising out of the operation of Wolf Creek as a cost to be borne by the owners separately (but not jointly) in proportion to their ownership shares. Each of the owners has agreed to indemnify the others in such cases.
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| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 Nuclear Liability and Insurance Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of 2005, KEPCo is required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently approximately $10.8 billion. This limit of liability consists of the maximum available commercial insurance of $300.0 million, and the remaining $10.5 billion is provided through mandatory participation in an industrywide retrospective assessment program. Under this retrospec-tive assessment program, owners are jointly and severally subject to an assessment of up to $100.6 million
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| ($6.0 million-KEPCods share) at any commercial reactor in the country, payable at no more than $15.0 mil-lion ($0.9 million-KEPCo's share) per incident per year, per reactor. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment also applies in excess of the worker radiation claims insurance. The next scheduled inflation adjustment is scheduled for July 1, 2008. In addition, Congress could impose additional revenue-raising measures to pay claims.
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| The owners of Wolf Creek carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($168.0 million-KEPCo's share). This insurance is provided by Nuclear Electric Insurance Limited (NEIL). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan man-dated by the Nuclear Regulatory Commission. KEPCo's share of any remaining proceeds can be used to pay for property damage, decontamination expenses, or if certain requirements are met, including nuclear decom-missioning the plant, toward a shortfall in the decommissioning trust fund.
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| The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from. accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, KEPCo may be subject to retrospective assessments under the current policies of approximately $1.6 million.
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| Although KEPCo maintains various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, KEPCds insurance may not be adequate to cover the costs that could result from a catastrophic accident of extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on KEPCds financial condition and result of operations.
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| Decommissioning Insurances KEPCo carries premature decommissioning insurance that has several restrictions, one of which can only be used if Wolf Creek incurs an accident exceeding $500.0 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the Nuclear Regu-latory Commission (NRC) and to pay for on-site property damages. Once the NRC property rule requiring insurance proceeds to be used first for stabilization and decontamination has been complied with, the prema-ture decommissioning coverage could pay for the decommissioning fund shortfall in the event an accident at Wolf Creek exceeds $500.0 million in covered damages and causes Wolf Creek to be prematurely decommis-sioned.
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| Nuclear Fuel Commitments At December 31, 2007, KEPCos share of WCNOC's nuclear fuel commitments was approximately $7.8 mil-lion for uranium concentrates expiring in 2017, $1.2 million for conversion expiring in 2017, $19.6 million for enrichment expiring at various times through 2024, and $6.3 million for fabrication through 2024.
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| Purchase Power Commitments KEPCo has supply contracts with various utility companies to purchase power to supplement generation in the given service areas. KEPCo has a five-year contract with Westar Energy, Inc., through May 2008 with minimum purchase commitments of 85 megawatts per year.
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| Kansas Electric Power Cooperative, Inc.
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| Notes to Consolidated Financial Statements December 31, 2007 and 2006 KEPCo has provided the Southwest Power Pool a letter of credit to help insure power is available if needed.
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| latan 2 Purchase Commitment Effective June 2006, KEPCo entered into an agreement, subject to RUS approval, to purchase a 3.53% own-ership in a coal fired generation facility. KEPCds estimated costs for the project were $70 million at December 31, 2007. Financing is currently being provided by CFC.
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| Note 12: Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instru-ments for which it is practicable to estimate that value as set forth in SFAS No. 107, Disclosures about Fair Value of Financial Instruments.
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| Cash and Cash Equivalents - The carry amount approximates the fair value because of the short-term matu-rity of these investments.
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| Decommissioning Trust Investments in Associated Organizations and Bond Fund Reserve - The fair value of these assets is primarily based on quoted market prices as of December 31, 2007.
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| Variable-Rate Debt- The carrying amount approximates the fair value because of the short-term variable rates of those debt instruments.
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| Fixed-Rate Debt - The fair value of the fixed-rated FFB debt and the fixed-rate Series 1997 Trust debt is based on the sum of the estimated value of each issue, taking into consideration the current rates offered to KEPCo for debt of similar remaining maturities.
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| The estimated fair values of KEPCos financial instruments are as follows:
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| December 31, 2007 Carrying Value Fair Value Cash and cash equivalents $ 6,132,774 $ 6,127,395 Investment in associated organizations (including investments in CFC) $ 5,630,784 $ 5,630,784 Bond fund reserve. $ 4,348,709 $ 4,531,910 Decommissioning fund $ 10,185,163 $ 10,185,163 Fixed-rate debt $141,637,538 $ 144,208,545 Variable-rate debt $ 24,700,000 $ 24,700,000 Note 13: Patronage Capital In accordance with KEPCo's by-laws, KEPCds current margins are to be allocated to members. KEPCo's current policy is to allocate to the members based on revenues collected from the members as a percentage of total revenues. If KEPCo's consolidated financial statements were adjusted to reflect accounting principles generally accepted in the United Stated of America, total patronage capital would be negative. As noted in the consolidated statements of changes in patronage capital, no patronage capital distributions were made to members in 2007 and 2006.
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| Westar Energy I 2007 Annual Report ...............
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| ...... ° °................. °o°°................. °oo. oo.............. °°°°o°°°............... oo°°°°°°o°.......
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| ==Dear Shareholders:==
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| 2007 was a watershed year for Westar Energy. In 2007 our focus shifted from planning to doing. For the past few years we have been planning for the growth of your company and your investment, working with regulators and public officials to improve the clarity and timeliness of how we recover our investments in the prices we charge and firming up our investment plans to meet our customers' growing need for electricity. In the years ahead, we will focus both on refining and executing plans to grow your company.
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| Throughout this annual report we share with you the various ways your company is growing for the future and how your management team here is executing our plans for making good utility investments. Specifically, you will see that our investment strategy is large and diverse. Our investment strategy is large because of the growing energy demands of our customers and the requirements of developing environmental regulations. It is not a stretch to say an environmental overlay now affects almost everything we do. It is diverse, certainly not in the sense that we are venturing off into some non-utility businesses, but rather in the sense that we are investing in. nearly every facet of electric utility operations. A diversified investment strategy is critical because the future of the. energy business is harder than ever to predict. Our strategy increases the probability that Westar will continue to succeed in uncertain times and reduces the probability that we will risk too much PLANNED CAPITAL INVESTMENT capital in just one area of our integrated business. Examples of this are ........... ..................................
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| (Dollars in Millions) our decision to defer construction of a new base load coal plant and our Wind $205.0 Generation Pealking Generation
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| $205.0 - $129.5 gas fired generation commitment to additional, more flexible, natural paired with wind energy and energy efficiency. Transmission . 8%
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| $542.6 Over the next few years we expect to double our investment in utility plants. Our expansion plan includes investments across asset types:
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| replacing equipment as it wears out; enhancing the environmental Replacement controls of our coal plants; building new gas peaking generators and new Equipment and Environmental Miscellaneous high capacity transmission lines; and making significant investments in $663.6 '$948.8 renewable, wind energy and energy efficiency programs. We hope you As consumer demand for electricity continues to grow we will take a few moments to review these projects in-more detail as we expect to nmeet that need in a variety Qf ways. Over tlte next
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| *fezv years we expect to double our investment in capitalto have highlighted them in the next few pages. serve our customners' imeeds.
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| We are pleased to report that all this planning and managing of major construction projects did not cause us to lose sight of current performance. We have maintained safety, reliability and strong financial performance as we implemented strategies for the future. ,2007 was another solid year for earnings and dividend growth, with dividends up 8 percent from their 2006 level. Your board of directors also just recently announced another increase in the quarterly dividend of 7.4 percent, which on an indicated annual basis now reflects a dividend of
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| $1.16 per share.
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| ................ Westar Energy I 2007 Annual Report Westar is proud to remain a basic utility. And our employees remain focused on the fundamentals of reliable electric service and on making our service area a great place to work and live.
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| " Our-power plants continued to operate safely and reliably. By way of example, in 2007, Wolf Creek operated at full output the whole year, and our largest coal units were available 86.9 percent of the time.
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| " We continued our quest toward ever improving service reliability and customer satisfaction. As measured by both frequency and duration of outages, our service levels improved.
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| " We improved the effectiveness of responding to customers, and expanded ways in which customers can get their needs met, whether through traditional conversations, automated call handling.or via Internet.
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| * Employees from all across Westar continue to volunteer, contribute and improve the quality of life in the communities we serve, large and small.
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| Part of managing for the future is developing upcoming leaders. Evidence of that is S, the smooth transition in the office of our CEO. In June we said good-bye and thank you to Jim Haines for having led Westar well for over four years and promoted one of our own. During the transition, we were also able to retain our entire senior management team, and seize opportunities to cross train, expand and develop the t talents of our senior leadership team.
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| Finally, nat ure dealt us quite a blow in December 2007. An ice storm caused the most widespread damage to our lines that we have ever experienced. At its worst, about 30 percent of our customers were without power, and many customers i saw their power restored only to be disappointed by yet another outage caused William B. Moore, left, president and cllief when another tree fell.into one of our lines. In total, we'made more than, 400,000 execnftixeofficer, and Charles Q. Chandler IV, customer restorations. We proudly thank our linemen and support team, which chair-man of the board.
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| included the assistance of nearly 2,000 dedicated craftspersons from across .the country, who came to help with the most rapid and safe storm restoration efforts of this magnitude in our history.
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| We were also pleased that the Edison Electric Institute recognized Westar Energy with its Emergency Assistance Award for times we lent a hand to other utilities in the wake of six winter storms in 2007.
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| 2008 will be. another active year for your company as we file for a significant increase in our rates to reflect the expenditures made since 2004. Thank you for your ownership in Westar Energy.
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| Charles Q. Chandler IV William B. Moore Chairman of the Board President & CEO 2
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| Westar Energy 1 2007 Annual Report ...............
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| Social, political and environmental developments are reshaping our industry.
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| It is time for new-thinking, new approaches.
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| Westar Energy, like all electric utilities, is operating in a rapidly changing world. Consumer use of electricity is growing at a pace that is beginning to draw down the reserves of power in the industry's supply network. This demand comes at a time when new power plant development is caught in the rising public and political debate about global-warming. The issues are far from settled, and rhetoric sometimes blurs the facts; the future is far from certain and long-term investments today may confront new risks and challenges yet unknown.
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| We believe the best course in this environment is to embrace these One of several stacks uncertainties, rather than attempt to judge or predict their outcome, to at the Emporia Energy Center.
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| ensure we navigate the turmoil and preserve the advantage Kansas has enjoyed over the decades in our energy investments and strategies.
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| Fundamentally, our approach is to keep our options open, invest in a range of proven and logical technologies, and adapt our plans as conditions continue to change. We are investing in wind and gas-fired generation, environmental improvements at our coal-fired plants and efficiency programs to meet our customers' immediate growing needs. Our approach is designed to delay the need for additional base load generation as long as it is prudent to do so in light Of costs and to let emerging technology develop. Base load needs have traditionally been met with coal-fired and nuclear generation, both of which involve high initial costs and are uncertain politically. During the past few years, the costs to build a coal plant have doubled.
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| By making thoughtful decisions, we can maintain the favorable rates Kansans enjoy and ensure reliable service3 3*
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| ................ Westar Energy I 2007 Annual Report First, we are.partnering with our customers to make sure we are all using energy Westar Energy is effectively and efficiently. Second, we have developed a carefully thought-out, flexible poised to meet investment plan to meet their growing needs.
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| the growing Our industry, is undergoing changes, and we are confident and ready to be part of electricity needs the future. During this time of growth, we expect our utility investment to double. As we discuss here, theways in which we expect to invest in our utility assets are varied.
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| of consumers. Despite all of the uncertainty, many of the decisions made in the past continue to serve us well and provide flexibility today. Our singular focus remains on the electricity needs of Kansas and our determination to help our state maintain its self-reliance and price advantage as we move ahead.
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| The Shawnee Service Center is home base to more than 50 employees.
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| Communities and industries around the world share responsibility for the environment. We need to work together for sound, science-based solutions.
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| Energy consumption is growing among all segments of our customer base - industrial, commercial and residential. Similar growth is happening around the world, and it impacts our energy supply and our environment.
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| In Kansas, we have seen growth in the number of residential customers we serve and in the amount of electricity they use. Homes are bigger and Tim Hunter,line foreman, and Blake Seib journeylnan lineman, unload poles tha*t most contain more fun or useful gadgets than just a few years ago. Our will be relocatedfor a publiC reasonable rates and -reliable service have helped the state attract new improvementprojectinShawnee e. business and encourage expansion of existing businesses. This growth is important to our state, but it also means increasing needs for electricity generation. It is important.that we take a thoughtful, balanced approach to meeting these growing needs.
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| Solutions must be sound, science-based and. economically feasible.
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| Success will require a renewed commitment to energy conservation, public policy recognition of the uncertainties we face and prices that support the level of investment needed to maintain our energy advantage in Kansas.
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| 4
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| Westar Energy I 2007 Annual Report ...............
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| Through energy Energy efficiency programs can help Kansas manage its own destiny during this uncertain time. With a new generation of tools available, energy efficiency efficiency we become programs can also be a cost-effective way to solve energy and environmental partners with our challenges. Along with building additional power plants to produce electricity, consumers in shaping it is our responsibility to help our consumers understand how their use impacts the larger picture. This is important with so much at stake environmentally and our energy and economically.
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| environmental future. Our education programs offer consumers from schoolchildren to retirees simple solutions to curb their energy use, to use energy more wisely and to reduce their impact on the environment. Programs targeting spikes in summer use help delay the need for plants that would only be used a few times during the hottest months. Encouraging the use of high-efficiency electric heat pumps saves consumers money and helps us use our power plants more cost-effectively by increasing their use during the winter.
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| AVERAGE ELECTRICITY USAGE AND COST AS A % OF HOUSEHOLD INCOME 3.00% 12.00 11.00 MWh Use per 2.50% 10.00 Residential Customer
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| -9.0 Source: WestarEnergy 2.00% 8.00 7.00
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| * Electricity as a %
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| of Average Kansas 1.50% .o00 Family Income 5.00 Source: USCensus Bureau 1... ,0and Westar Energy 1.00%,40 I'll I'll -,o 1,3 n IM M/r mv I!!l ny"j mori lil 1VW LSI ZUJO LUJ While the amount of electricity used per residentialcustomer (shown in blue) has increased, the percentage of household income thatgoes to pay for electricity (shown in red) has declined.
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| Smart meters enable smarter decisions.
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| Metering technology has also rapidly advanced in recent years. Smart meters, as they are often called, include communication devices that give consumers and utilities an accurate picture of when energy is being used and how the system is performing. Real-time pricing can help consumers better understand how to manage their energy use. Return signals allow us quickly to determine the scope of power outages and provide periodic reports of electricity use for billing. In addition, some utilities have employed this technology to allow customers to prepay for their service. Westar is evaluating advanced metering technology and may conduct a pilot to test its effectiveness.
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| 5
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| ............... Westar Energy 1 2007 Annual Report With a century invested in Kansas, helping customers, ensuring sound reliability and protecting our environment are so important they weave through everything we do.
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| ~~.....° .......
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| °.**,*.**.°.o....°.°.,.°..°.°.. ,...°..°....... °..........
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| We are committed to Kansas for the long haul, and our employees are part of the communities we serve. In recent years, we have been implementing new programs that have led to greater customer service and satisfaction. We have enhanced our online services, improved programs that support businesses of all sizes and implemented technology to provide customers more information should they experience an occasional power outage.
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| Our employee-led Green Team completed 53 projects in 2007. They included tree plantings in tornado-devastated Greensburg and across many Division linerforeman, other Kansas communities, construction and erection of osprey nest platforms preparesunderground at Big Hill Reservoir and wildlife rehabilitation pens in Hill City and Pittsburg, prmary cable that will completion of a bridge at the Battle of Black Jack Historic Site, and donation be used to service a new residentialdevelopment, of more than 400 bluebird, wood duck, bat and sparrow hawk nest boxes to groups across Kansas. All wood was recycled from used power poles.
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| As we enter a new phase in the utility industry, our commitment to being Steve Asmann, technical a basic electric utility and our commitment to our communities is steadfast. We specialistdesign, at the are maintaining our existing infrastructure and investing in new infrastructure Shawnee Service Center. as consumption continues to grow.
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| PLANNED CAPITAL EXPANSION Incremental
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| - $5.0Growth Billion . ............
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| 5i.5 1eplacement CapEx Sililon Approximate rate base Over about the next six years we expect to double our utility investment. 7Te first slice of ourgrowth chartshows existing investment and, with all such investments, how they depreciateover time. As we enter a new era of growth, we will also continue to maintainand look for ways to extend the life of our existing investments. 7Through sound management of these assets, we have been able to extend their umfil lives.
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| 6
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| apfttzi Enqg 2007 Annual Report Crews clean one of the stacks atJeffrey Energy Centeras part of the scrubberretrofit.
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| Contractorswork on the scrubber dewatering building at Jef ry Energy Center.
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| 44ý
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| '1*
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| j I
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| *1 FZIK ii I
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| ~ U Circulatingwater live replacementwork on unit 3 at Jeffrey Energy Center.
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| Screbber reaction tank constructionatJefrey Energy Center.
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| ............... Westar Energy I 2007 Annual Report Financial Measures 2007:
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| 2007 2006 FINANCIAL DATA (Dollarsin Millions)
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| INCOME HIGHLIGHTS Sales ..................................................... $1,727 $1,606 Income from continuing operations .............................. 168 165 Earnings available for common stock ............................. 167 164 BALANCE SHEET HIGHLIGHTS Total assets ................................................ $6,395 $5,455 A welder working on Common stock equity ........................................ 1,827 1,539 environmental upgrades Capital structure:
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| at Jeffrey Energy Center.
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| Common equity ........................................ 49% 49%
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| Preferred stock ......................................... 1% 1%
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| Long-term debt ......................................... 50% 50%
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| OPERATING DATA Sales (Thousands of MWh)
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| Retail ................................................. 20,124 19,558 W holesale ............................................. 10,026 7,418 Customers ................................................. 674,000 669,000 COMMON STOCK DATA PER SHARE HIGHLIGHTS Basic earnings per share ...................................... $1.85 $1.88 Dividends declared per common share ............................ $1.08 $1.00 Book value per share ......................................... $19.14 $17.61 STOCK PRICE PERFORMANCE Common stock price range:
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| High ................................................. $28.57 $27.24 Low ................................................. $22.84 $20.09 Stock price at year end ........................................ $25.94 $25.96 Average equivalent common shares outstanding (inthousands) ......... 90,676 87,510 Dividend yield (based on year end annualized dividend) ............... 4.2% 3.9%
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| 8
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| Westar Energy 1 2007 Annual Report UNITED STATES SECURITIES AND. EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K
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| "'"LFANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
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| OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2007 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
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| OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from' _to .
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| Commission File Number 1-3523 WESTAR ENERGY, INC.
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| (Exact name of registrant as specified in its charter) tr o Kansas " . "48-0290150 S(State or other jurisdiction ofdincorporatidn or organization) (I.R.S. Employer Identification Numbeir) 818 South Kansas Avenue, Topeka, Kansas 66612 (785j575-6300.
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| (Address, including Zip code and t6lephone nuinber, including area code, of registrant's principal executive offices)
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| Securities registered pursuant to Section 12(b) of the Act:
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| Common Stock, par value $5.00 per share . New York Stock Exchange
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| .: . First Mortgage Bonds, 6.10% Series due 2047 . .. New York Stock Exchange (Title of each'cldss) (Name of ýach exchange~tn which registered)
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| Securities registered pursuant to Section 12(g) of the Act:
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| Preferred Stock, 4-1/2% .Series, $100 par value (Title of Class)
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| Indkiate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act). Yes [ No Lii Indicate by check mark whether. the registrant is not required to file reports pursuant to Section 13 or Section 15(d). of the Act.
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| Yes n] No,'E- ....
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| Indicate by che&ck 'markwheIheer the registrant..(1)'has filed all reports required to be filed by Section 13 or 15(d) of the Secunities Exchange Act of 1934 during the preceding 12 months (or for'such shorter period that the registfant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [] NoD - .:
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| Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is hotcontained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or..inforrhation statements incorporated by,.reference in Part III of this Form 10-K or any amendment to this Form 10-K. X . ,
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| Indicate by &heck mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company (as defined.in Rule 12b-2 of the Act).
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| Check'one: Large accelerated filer 'n- Acceleiated filer '],"'
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| :Non-accelerated filer F] Smaller reporting company LI Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes LI No ,
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| The aggregate market value of the voting common equity held.by non-affiliates of the registrant was approximately $2,203,151,369 at June 29, 2007.
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| Indicate the number.of shares outstanding ofeach of the registrant's classes of common stock, as of the latest practicable date.
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| Common Stock, par value $5.00 per share . 97,750,463 shares (Class) (Outstanding at February 19, 2008)
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| DOCUMENTS INCORPORATED BY
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| ==REFERENCE:==
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| Description of the document Part of the Form 10-K Portions of the Westar Energy, Inc. definitive proxy Part I (Item 10 through Item 14) statement to be used in connection with the registrant's (Portions of Item 10 are not incorporated' ,9 2008 Annual Meeting of Shareholders . by reference and are provided herein)
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| .......... Westar Energy' 2007 Annual Report TABLE OF CONTENTS . FORWARDL0ObKING'STATEMENTS Page Certain matters., discussed in this Annual Report on Form 10-K are "fdrxnard1ilboking statements." The Private Securities Litigation Reform Act PART I of 1995 has established that these statements qualify for safe harbors from Item 1. Business .......... ... .. liability. Fohward-a1oking statements' 'ra include words like we "believe,"
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| Item 1A. Risk Factors ............ 20 '"anticipate," target,""expect,""pro forma,""estimate,""intend" and words Item 1B. Unresolved Staff Commen ts .. .ofsimilar meaning.
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| 22 .' objectives,, Forwardlooking statements describe our future plans, expectations or goals. Such statements address future events Item 2. Properties.............. ........ 22 and conditions concerning matters such as, but not limited to: amount, type 23- and timing of capital expenditures; earnings; cash flow; liquidity and capital Item 3. Legal Proceedings Item 4. Submission of Matters to a Vote resofrces; litigation; accounfiing matters; possible corporate restructurings, 23 acquisitions ..anid cdispositions; comphiance with debt and other restrictive of Security Holders ...... covenants; interest rates and dividends; environmental matters; regulatory PART II "';"matters;V-nud*lar ol* 15ations; and the overall economy of our service area and economic well-being of our customers.
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| Item 5.
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| Common Equity and Related What happens in each-caseicould vary materially from what we expect Stockholder Matters .......... ... 23 because of such things as: regulated and competitive markets; economic Item 6. Selected Financial Data. 24 and capital-market conditions, including the impactof changes in interest rates and the availability of capital; changes in accounting requirements Item 7. Management's Discussion.and "-oand oth r acc*ounting matters; changinKgweather; the impact of regional Analysis of Financial Condition-arid Results of'Oper Iations. .. ."-25 transmission organizations, and independent system operators, including the development of new market mechanisms for energy markets in which Item 7A. Quantitative and Qualitative we participate; rates, cost recoveries and other regulatory matters including Disclosures About Market Risk: ... .37 th~e ouitcdme of-our reqiest for reconsideration of the September 6, 2006, Item 8. Financial Statements and , Federal Energy Regulatory Commission Order; the'impact of changes and Supplementary-Datd. ... 39 downturns in the energy industry and the' market for trading wholesale Item 9.. Changes in and Disagreements .... energy; the outcome of the notice. of violation received on January 22, With Accountants on Accountin 2004, from the Environmental Protection Agency and other environmental and Financial Disclosure -. ... 73 frutters m including'possible future legislative or regulatory mandates related Item 9A. Controls and Procedures .. -73 ' to- emissions-legislative, of presently. unre'gulated gases or substances; political, judicial and regulatory developments at the municipal, state Item 9B. Other Information ........... ... 73 and federal level that can affect us or our industry, including in particular thoseerelating to environmental laws; the impact ofuour potential liibiliat PART III
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| -. . .to -David :C. Wittig 'and Douglas T. Lake for unpaid compensation and Item 10. Directors and Executive Officers benefits and the impact of claims they have made against us related to of the Registrant.......... ... 74 -the termination of.their employment and the publication of the report of 4 special committee of the board of directors; the impact of changes in Item 11., Executive Compensation.
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| . interest rates on pension and other post-retirement and post-employmient Item 12. Security Ownership of Certain benefit liability calculations, as well as actual and assumed investment Beneficial Owners and
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| ""efturiý Onninvested plan, assets; the' irhipact of chang~es 'in estimates Mýan gement .............
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| regardifig our Wolf Creek'Generating Station decommfiissioning obligation; Item 13. Certain Relationships and changes in regulation of nuclear generating facilities and' nuclear materials Related Transactions .......... and fuel, including possible shutdown or required modification of nuclear Item 14. Principal Accountant Fees generating facilities;, uncertainty regarding ,the establishment of interim
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| . : and Services ............
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| : 74. or permanent sites for spent, nuclear fuel storage and disposal; homeland security considerations; coal, natural gas, uranium, oil and wholesale PART IV electricity prides; availability and'timely provision of ecquipment, 'supplies, Itefn 15. Exhibits and Financial Statement labor and fuel we need to operate our business; and other circumstances Schedules ................... ... 74 affecting anticipated operations, sales and costs....
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| * Signatures........; ................. ,,, 80 These-lists 'are not allinclusive. because it is not possible to'predict all factors. This report should be read in its entirety. Noone, section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are
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| .not'obligated -toupdate any forward-looking statement to reflect events or circumstances after the date on which.such statement was made except as required by applicable laws-or reguiations..
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| 10
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| Westar.Energy I .2007 Annual Report ..............
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| a''
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| GLOSSARY OF TERMS The following is a glosgary of frequently used abbreviations or, acronyms that are found throughout this report.
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| Abbreviation or Acronym , Definition. Abbreviation or Acronym Definition '
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| 2005 KCC Or'der December 28, 2005,.KCC Order KCPL *. a, .Kansas City P9wer.& Light ,,,
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| Annual Report on Form, 10-K'for the ,., ... . Com m any ,(,.. , ,,. ,
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| Form 10-K',' a
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| * year ended December 31' 2007 KDHE ' Kansas Department of Health and AFUDC Allowance for Funds Used Durifg ,.!If - .. " Environment- , :. , r Construction ' KGE' Kansas Gas and Electric Company, Aquila Aquila, Inc. .- kV Kilovolt BNSF; Burlington Northern Santa Fe La Cygne La Cygne Generating Station BNYCMI BNY Capital Markeis, Inc. LTISA Plan Long-Terrh Incentive and Share CO 2 . Carbon Dioxide Awrd Planr'"-
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| Btu British Thermal Units iar,e Act. Medicare Prescrnption Drug
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| -a" Ifnprdveient and*.Moderzatiori Central States Central Interstate Low-Level * * .... Act of2003 *'
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| Compact. Radioactive Waste Compact COLI Corporate-owned Life Insurance MNBtu Millions of Btu .,1 DOE Department of Energy Moody's. Moody!s Investor's.Service .
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| DOJ Department of Justice, -MW '..... Megawatts "' .
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| DSPP . Direct Stock Purchase 'Plan MWh *- " ...,,''' Megaattn . ,i[ , hours'.
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| , , , 'aa " i , "
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| ECRR I. Environmffental Cost Recoverý Rider
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| 'NEIL . ;Nuclear Electric Insurance Limited Emerging Issuies Task Force NOx Nitrogen Oxide EITF EPA Environmental'Protection Agehcy@' NRC Nuclear Regulatory Commission Employee Retirement Incofme NSR Investigation- %''1 EPA.New:Source RevieW w.
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| ERISA Security Act of 1974 . :
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| SInvestigation FASB Financial Accounting Standards ONEOK 'ONEOK, Inc.'.
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| Board " .a . . PCB . . Polychilorinated Biphenyl February 200' 7 KCC February 8,2007, KCC Order- .PPA. , . ,, a, .......'PensiQn Protection Act of.2006 Order :!PRB , Powder RiverBasin.,
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| FERC Federal Eniergy Regulatory" Protectibn'On'< ' Protection O'n'e; Inc. '".,-
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| ... . Commission' ". ;> RECA " ': Retail energy cost adjustment' FIN 'Financial Accdunting Standards RSU" '.' , Restricted shore units: .'
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| Board Inteipretation No.
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| RTO a ,..... Regional Transrinssion Organation Fitch Fitch Investors Service
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| .Standard,&, tS&P P°or's Ratipngs. Group..
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| Forward sale Forward equity sale agreement agreement SAB. . - , Staff Accounting Bulletin Generally Accepted Accounting GAAP SEC a' Securities and Exchange '
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| Principles. Commission a.,. , ;
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| Section 114 . "' Section 114(a)'oftthe Clean Air Act' Guardian Guardian Intemational, Inc.,
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| IRC , Internal Revenue Code ., SFAS ." . Statmeinat of Financial Accouhting
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| 'Standards. ,
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| IRS Intemal Revenue Service SPP Southwest Power Pool IRS Appeals December 2007 tentatiPee' settlement
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| ,:",SS'CGP Southerm Sta rCental Gas Pipleline Settlement " with the IRS Office of Appeals ' so Sulfur Dioxide JPM
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| * J.P. Morgan Securities, Inc.
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| July 2006 Cot irt July 7, 2006, the Kansas Court of, .UBS., ...
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| **.. ,' UBS AG, London Branch Z. a Order Appeals Order VaR, ',... Valuerat-Risk July 2007 KCIC July 31, 2007, KCC Order WCNOC 'Wolf Creek Nuclear Oper6ting"'
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| S" Corportibf Order KCC Kansas Corporation Commission Wolf Creek Wolf Creek Generating Station-11
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| .............. Westar Energy I 2007,Annual Report PART I line to be approximately $150.0 million. In additio.n to this hline, ITEM 1. BUSINESS we plan to construct a new 345 kV line from our Rose Hill substation near.Wichita to the.Kansas-Oklahoma border, where we will interconnect with new facilities built by an Oklahoma-GENERAL v.7 based utility. The preliminary estimate of the total investment in We are the largest electric utility in Kansas. Unless the'dontext the line is approximately $70.0 million, which is subject -to otherwise indicates, all :references in this Annual Report on change ,pending selection of the final route and engineering Form 10-K to ;'the company,", ".we," "us," "our" and similar design, among other factors. On December 27, 2007, we filed an words are to Westar Energy, Inc. and its consolidated subsidiaries. application with the KCC. to request permission to site this line.
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| The term"Westar Energy"refers to Westar Energy, Inc., a Kansas The KCC has until April 25, 2008, to act on our application.
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| corporation incorporated in 1924, alone and not together with On January 11, 2008, we announced that we reached agreements its consolidated subsidiaries. with developers who wvill build three wind farms in Kansas We provide electric. generation, transmission and distribution totaling approximately 300 MWs. Under the terms of the agree-services to approximately 674,00.0 customers in Kansas. Westar ments, we plan to own approximately half of the wind generators Energy provides these services in central and northeastern at an expected cost of'approximately $290.0 million and to Kansas, including the cities."of Topeka, Lawrence, Manihattan, purchase energy produced by the wind farms under twenty year Salina and Hutchinson. Kansas Gas and Electric Company supply contracts for the other half. All three wind farms are (KGE), Westar Energy's wholly owned subsidiary, provides these expected to be producing energy by the end of 2008. -
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| services in south-central and solutheastern Kansas,- including Energy. Efficiency - .
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| the city of Wichita. KGE owrisla 47% interest in the Wolf Creek Energy efficiency is important to ciur plan. We believe that many Generating Station (Wolf Creek), a nuclear power plant located energy efficiency technologies can be deployed faster and at near Burlington, Kansas. Botbh Westar Energy and KGE conduct lower-, cost than supply-side options. Accordingly, weý view business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue,'Topeka, energy efficiencyas a prionrty energyresource.
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| Kansas 66612. For energy efficiency to have a meaningful impact we believe policymakers will have to aligrn incentives for utilities and their SIGNIFICANT BUSINESS DEVELOPMENTS customers. The KCC has opened two dockets to address how Kansas utilities- might deploy energy efficiency programs and New Generation and Transmission Construction Plans how such costs will be treated for ratemaking.
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| We are making and will continue to make significant investments in new generation, new transmission and air emission controls Changes in Rates at existing fossil-fueled power plants. These investments relate On December 28, 2005, the KCC issued an order (2005 KCC to new projects as well as previously announced projects. The Order) authorizing changes in our rates, which we began billing cost estimates for some previously announced .projects have in the first quarter of 2006, and approving various other changes increased due to rising prices of labor, materials and supplies. in our rate structures. In April 2006, interveners to the rate review filed appeals with the Kansas Court of Appeals challenging In August 2006, we.announced plans to build a new natural gas - various aspects of the 2005 KCC Order. On July 7, 2006, the fired combustion turbine peaking power plant near Emporia in Kansas Court of Appeals reversed and remanded for fur'ther Lyon County, Kansas. We expect the new plant, which we have consideration by the KCC three elements of the 2005 KCC named the Emporia Energy Center, to have an initial generating Order (July 2006 Court Order). The balance of the'2005 KCC capacity of approximately 310 megawatts (MW), with additional Order was upheld.
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| capacity to be added in a second phase to bring the total capacity to approximately 610 MW. We expect the total investment in the The Kansas Court of Appeals held: (i) the KCC's approval of a plant to be about,$3.18.0,million. Construction on the new plant transmission delivery charge, in the circumstances of this case, began in March 2007.The initial phase of the plant is scheduled violated the Kansas statutes' that authorize a transmission to begin operation in May of 2008.The second phase is scheduled delivery charge, (ii) the KCC's approval of recovery of termihal to begin operation in May of 2009. net salvage, adjusted for inflation, in our depreciation rates was not supported by substantial competent evidence, and (iii) the In .September 2006, we announced plans to build a 345 kilovolt KCC's reversal.of its prior rate treatment -of the La Cygne GkV) transmission line from our Gordon Evans Energy Center Generating Station (La Cygne) unit 2 sale-leaseback transaction northwest of Wichita, Kantsas, to a new substation near was not sufficiently justified and was thus unreasonable, Hutchinsonr, Kansas, then on to our Summit substation:near arbitrary and capricious.s.
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| Salina, Kansas, a distance totaling approximately 97 miles In-.
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| January 2007, we filed an application with the Kansas Corporation On February 8, 2007, the KCC issued an order (February 2097 Commission (KCC) to request permission to site the line. The KCC Order) in response to the July 2006 Court Order. The KCC granted our permit on May 16, 2007. We expect to c.omplete February 2007 KCC Order: (i) confirmed the original decision construction in late 2009. We expect the total investment in the regarding treatment of the La Cygne unit 2 sale-leaseback 12
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| Westar Energy I 2007 Annual Report transaction; (ii) reversed the KCC's original decision with:regard The capacity by fuel type is summarized below.
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| to the inclusi6n in depreciation rates of a component for terminal Capacity Percent of net salvage; and (iii) permits recovery of transmission related Fuel Type " . (MW) . ' Total Capacity costs in a manner similar to how we recover our other costs. On Coal ...... ...... ' . ............ ...... .. 3,461.0 . 56.0 November 30, 2007, we filed with the KCC to implement a Nuclear .... ........... ...... ....... . .... . . 545.0. 8.8 separate transmission delivery charge in a* mariner consistent Natural gas or oil. ... ............ 2,090.0 33.9 with the applicable Kansas statute. The February 2007 KCC Diesel fuel ......... .. * ............ 81.0 1.3 W ind . . . . .,: .. . . . . . . . . . *. . . . .... 1 .4 Order required us to refund to our customers' amounts we collected related to terminal net'salvage. *OnJuly 31, 2007, tho Total ............. 4........................... 6,178.4 ' 100.0 KCC issued an order (July 2007 KCC Order) resolving issues raised by us'and interveners following the February 2007 KCC Our aggregate 2007 peak system net load of 4,836 MW occurred Order.: The July 2007 KCC Order: (i) confirmed the earlier on August 15, 2007. This included 109 MW of potentially decision'concerning recovery of terminal net salvage and quan- initerriuptible load. Our net generating capacity, combined with tified the'effect of that ruling; and (ii) approveda Stipulation firm capacity purchases and sales and the ability to interru pt 109 and Agreement between us and the KCC Staff. The Stipulktion MW of load, provided a capacity margin of 13.5 %above *ystem and Agreement approved 'by the KCC quantified the refund peak respohsibility at ie ttimne of our 2007 peak systen'inAet load.
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| obligation related'to amounts previously collected fromi customers foý' transmission related costs and established the' amount of Under wholesale agreements, we provide firm generating transmission costs to be included in retail rates, prospectively. capacity.to other entities as set forth below.
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| Interveners filed petitions for reconsideration of'the July 2007 UtilityIa.'' " . .. . ' Capacity (MW). Period Ending
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| *KCCOrder on August 15, 2007. These petitions were denied by Midwest Energy, Inc. . ........... 130
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| * May 2008 the KCC on September 13, 2007. The interveners filed appeals Kansas Electric Power Cooperative .............. 187 .,. May 2008 with the Kansas Court of Appeals. On February 11, 2008, the Midwest Energy, Inc ........................... 125 May 2010 Kansas Court of Appeals issuedan opinion which.affirmed the Empire.District Electric Company. ..... ..... '. 1162 . .. . May 2010 July 2007 KCC Order. We filed ,new tariffs and a, plan for' ,,Oklahoma Municip'al Power Authority ......... :.. 60 . December 2013 implementing refunds that became effective on'A,ugust 29q, 2007 'Oneok Energy Services Co...:: ' . - 75. ';December 2015 Refunds were substantially completed in November... Mid-Kansas Electric Company, LLC...... ....... 174 January 2019 Total.*..... .) ..... ....... .: .':............. . 9 13 OPERATIONS -. . Under a wholesale agreement that expires in May 2027, we provide baseload capacity 'to'th. city of McPherson, Kansas, and McPherson 'p'rovidestpeaking General . " ' . . " ' "capdcity 'to us.' D'uring'2007, 'we Pr6vided approximately 84 MW. to, and Westar Energy supplies electric-energy at retail to approximately received approximately 151 MW from, McPherson. The amount pf base load capacityproriided to McPhersonis based on a fixed percentage of McPherson's 363,000 customers irn. central and northeast .Kansas and, KGE annual peak system load.
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| supplies electric. energy at retail, to approximately. 311,000 customers in south-central and southeastern Kansas. We -also Fossil Fuel Generation' ''
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| supply electric energy at wholesale to the electric distribution systems* f 35 cities in Kansas and four electric cooperatives in Fuel Mix Kansas pursuant to contracts of various length. We haveother The effectiveness of a,fuel to produce heat is measured in British contracts. for the *sale, purchase or exchange of wholesale thermal units (Btu). The higher the Btu content of a fuel, the less electricity with other utilities. In addition,.we. engage, in .energy fuel .it takes to produce electricity. We measure, the quantity of marketing and purchase and sel wholesale electricity, in areas heat consu mfed duIing the generation Of electriity in millicins of outside our retail service territory. Bfu (MMBtu)..."..... ...
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| In 2006, we implemented a retail energy'cosf adjustment (RECA) Based on .MMBt us, our 2007 fuel mix was.79% coal, 15 % nuclear that allows us to recover the cost of fuel cofisurned'ih generating and 6% natural gas, oil and diesel fuel. We expect in 2008 to electhcity andpurchaFse d. power needed to serv'e our 'retail use 'a higher percentag' ofP coal 'and 'a lower percentage of customers. Through the RECA, we bill our customers ofn a uranium because in 2008 i6 will refuel Wolf Creek.'We did not month ahead estimate.The RECA provides for an annual review refuel Wolf Creek "in 2007. Our fuel mix 'fluctudtes with the and reconciliation of estimated and actual fuel and purchased operhtibn of. Wolf Creek, fluctuations; in fuel' costs, plant power costs. The annual review.also affords the KCC a means to availability, ctistomrer demand and. the cost and availability' of determine.'the, pruden'ce 0f our fuel and, purchased power power iri'the wholesale market. "k' .
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| expenses, The first such review was completed in mid 2007 and Coal resulted in no adjustmentsi.
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| jeffrey"Energy Cen`ter: The three coal-fired units at JeffrLy Energy Generation Capacity Center have an 'aggregate capacity 'of 2,190 MW, of which we We have 6,178 MW of accredited generating capacity in service; own and-lease a combined 92% share" or 2,016 MW. We have a Coal .Westto of which 2,575 MW is owned or leased by KGE. See "Item 2. long-term, coal .supply contract with, Foundation Properties" for additional information on our generating units. supply coal to Jeffrey Energy Center from surface mines located 13
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| ............... Westar Energy I '2007 Annual Repoit in the Powder River Basin (PRB) in Wyoming. The contract per ton! The average delivered cost of all' coal ,bumed in the contains a-schedule of minimum annual MMBtu delivery Tecumseh units was -approximately $1.16 per MIMiBtu,, or $20.48 quantities. All of. the coal used at Jeffrey Energy Center' is per ton. . . ', .. .
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| purchased under-this contrat. The contract expires December 31, 2020. The contract provides for price escalation based on certain Natural Gas costs of production. The price for quantities purchased in excess We use natural gas, as. a primary fuel at our, Gordon Evans, of the scheduled annual minimum is subject to renegotiation Murray Gill, Neosho, Abilene and Hutchinson Energy Centers, every five, years to provide an adjusted price for the ensuing five in the gas turbine units at.Tecumseh Energy Centerand in the years that reflects then current market prices.The next re-,pricing combined.cycle units at the State Line facility and the Spring for those quantities over the *scheduled-annual minimum will Creek Energy Center. We can also use natural gas as a supple-Occur in2013., . . . ' ' . mental fuel in the coal-fired units at the Lawrence and Tecumseh Energy Centers. During 2007, we purchased 18.3 million MMBtu The Burlington Northern Santa Fe (BNSF) and Unrion "-cific of. natural gas for a total.cost of $119.5 million. Natural gas railroads tranisport-coal for Jeffrey Energy Center from Wyoming accounted for approximately 6% of our total MMBtu of fuel under a long-term ril transportation contact. The contract term burned- during 2007 and approximately 25%.of our total fuel continues through December 31, 203.Tl6 conItract price is subject expense. From time totime;-we maypurchase derivative contracts to' price escalation based on certain costs incurred by the rail in an effort to mitigate the effect of, high natural gas prices. For carriers. We expect increases in the cost, of transporting coal due additional information, on our exposure to commodity price to higher prices for the items subject to contractual escalation., risks,, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk.'
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| The average delivered 'cost of coal burned at Jeffrey. Energy Center during 2007 was approximately $1.39 per MMBtu,.or We 'i-aintain natural gjs transportation 'arr'fa+gements for the
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| $23.38 per ton. ' . Abilenfe Sad Hutchinson' Energy Centurs with Kansas Gas Service, 'a division 'of ONEOK, Inc. (ONEOK)I This contract La Cygne Generating Station: The two coal-fired units at La Cygne expires' April 30, 2008; We will be ienegotiating; this contract havean-aggregate'generating capacity of' 1,418 MW, of which, dtg'ig'the fist tuŽftet of 2008. We meet a portion 6f our natural we own orlease a150% share, or 709 MW. La Cygne unit 1 uses gas transportation requirements for the Gordon Evans, Murray' d'blended fuel mix containing approximately85% PRB coal and Gill, Neosho, Lawr&ence and Tecu'mseh Energy Centers through 15% Kansas/Missouri coal. La Cygne unit 2 uses PRB coal. The firm natural gas transportation capacity agreements with operator, of La Cyghe; Kansas City Power & Light Company Southern Star Central Gas Pipeline (SSCGP). We meet all Of the (KCPL), arranges coal purchases and'traiisportation services for natural gas transportation requirements for the State Line.
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| La Cygne. All of the La Cygne,unit 1 and La Cygne unit 2 PRB facility through a firm natural gas transportation agreement
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| 'coal is supplied through fixed pri'e Contracts through.2010 and with SSCGP. The firn'trarisportation agreeineht thft serves 'the is transported "uhder KCPL's Omnibus Rail -Tiansportation Gordon Evans, and'Murray 'Gill Energy Centers has been Agreement with the.BNSF and Kansas City Southern Railroad ,restrictuted and extended throtigh April 1; 2020.The agreement through December 31, 2010. As the PRB coal contracts expire, for the Neosho andrStat6 Line facilities extends through June 1; we anticipate that KCPL will negotiate new supply contracts or 2016'6We will meet a portion of'the natural gas'transportation purchase coal on the spot market. The La Cygne unit '1'KIansas/ requirements at*the Emporia Energy Center through firm Miss6uri coal ispurchased fromr time to time from' 'local Kansas natural gas transpOrtation cap'acitiy agreements with SSCGP.
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| and 'Missouri producers. , .. . The term' of the agreement Will be for 20'years commencing D~uring:007, the, average delivered cost-of all coal burned at La December .1/2008, and terminating December 1, '2028, which will':be re'newable for five-year terms' thereaftef." During the Cygne unit 1 was approximately $1.12 per MMBtu, or $18.8.1 period of April 1, 2008, through November 30, 2008; per ton. The average delivered cost of coal burned at La Cygne unit 2,was' approximately $0.99 per MMBtu, or $16.87 per~ton: transportation will be handled through a combination of firm and interruptible agreements. We meet'all of the natural gas Lawrence and Tecumseh Energy, Centers: ,The, coal-fired units traisportation requirements for the Spring Creek*Energy Center located at 'the. Lawrence. and Tecumseh Energy Centers have through an interruptible natural gas transportation agreement an. aggregate .generating capacity of.,774 MW. During 2005, with ONEOK Gas Transportation, LLC..
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| we began purchasing coal under a :contract with Arch Coal, n-i `k.
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| 0 .. 'clw.tr..tralg....s ' . t.
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| TInc., (Arch). The current -contract with Arch is. expected to provide 100% of the coal requirement for these energy centers Once 'tted with riatural gas, thestbair'nunits 'at our Gordon through 2010. Evans, Mrrnay, Gill, Neosho and Hutchinson Efiergy Centers have the capability to burn'#6 oil or natural gas. We can use #6 BNSF transports coal for these energy centers from .Wyon*ing oil as an emergency alternate fuel when no naturalgas supply is under a contract that expires in December 2008. , available. During 2007, we did not burn any #6 oil.
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| Durfing 2007,'the average delivered'cost of all coal burihied in the We also use #2 diesel to start some of our coal' generating Lawrence units was;approkimately $1.16 per MMBtu, Or $20.15 stations, asý a primary fuel in'the Hutchinson No..4 combustion 14
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| Westar Energy I:2007.Annual Report .............
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| turbine and in our diesel generators. We purchase #2'diesel in owners'pay operating costs equal.to their percentag6 ownership the.. spot-market. We maintain quantities in inventory that we in Wolf Creek. ' " . .
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| believe will allow us to facilitate ,economic dispatch of power, to satisfy emergency requirements and 'to protect against reduced in September 2006, Wolf Creek Nuciear Operating ,Cooration availability of natural gas foi limited periods. ,(WCNOC), the operating company for Wolf C(reek,&filed..,a request with the Nuclear Regulatory Commission (NRC) for, a During 2007, we burned 0.2 million MMBtu of oil at a total cost 20 year. extension of Wolf Creek's operating license. Currently, of $3.3,million. Oil accounted for' less than 1% of our total the operating license will expire in 2025. The NRCss milestone schedule for its review, of this, request projects a dlecision by. ate MMBtu of fuel burned during 2007 and approximately 1% of our total fuel expense. For additional information. on our 2008. The NRC may impose con ditions as part of any approval.
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| exposure to commodity price risks, see "Item 7A. Quantitative Based on the experience of other huclear plant operators, we and Qualitative Disclosures About Market Risk." believe that the NRC will'approve the request.
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| Other Fuel Matters Fuel Supp!y . ... .. ' .' '
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| The'table beow provides our weighted average cost' of fuel, The owners of Wolf, Creek: have on hand or under contract all of including transportation costs. the uranium and conversion services, needed to operate Wolf 2007 2006 2005 Creek through March 2011 and approximately 86% of~uranium and conversion services after that date through September 2018.
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| Per MMBtu:
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| The owners also 'have under contract 10_0%. of the uranium Nuclear ............................. $ 0.43 `6.41 $ 0.42 Coal .............................. 1.27 ' 1.25 1.20 enrichment .and' fabrication .required to operate Wolf Creek Natural gas .... .... ..... ........ .. 6.51 6.49 ' 8.53 through March 2025. . . -.
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| Oil............................... 15.18 9.19 4.97 Because of a' production delay at a miriefro which
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| , Wolf Crek Per MWh Generation: expected to receive future supplies of ur~anm, it is possibl& that Nuclear ............................ $ 4.46 $ 4.28 $ 4.34 Coal..... 13.92 13.69 13.20 contracted uraniuim deliveries scheduled 'for 2010 and some Natural gas/oil .... : ........ I........ 67.65 66.91 '68.19 years beyond could.be reduced, necessitating an increase in the All generating stations... . 15:51 14.94 15.36 amount of uranium planned for purchase in .those.,years. Wolf Creek's:. on-going ,operations, strategies, including .-previous Purchased-Power . - acquisition ofinventory, are expected to minimize'the impact of At tifnies;' we purchase electricity' instead 6f, generating it such reductions. ,-' . . ,' ,.'
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| ourselves.FactOrs thaf cause us to make such purchases include W& have entered into all uranium, uranium, conversion and planned 'and unscheduled outages at our generating plants, uranium enrichment arrangements,"as well as' thee fabrication prices *for- wholesale energy, extreme weather conditions 'and agreements, in the ordinary course of biisiness. We believe Wolf other' factors. Transnrission constraints may limit our ability to Creek is not substantimlly.depenaent on these agreements.
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| bring' ptirchased; electricity into our control area; potentially However, contraction' and consolidation amiong suppnielr of r~quiring us to curtail or interrupt Our customers as permitted these, commodities and.services, increasing worldwide Ademand, by our tariffs and terms and conditions' of service. Purchased past inventory draw-downs, and floodingb'f a key: mine'6f -a power for the year ended December 31, 2007, comprised leading industry supplier have introduced uncertainty -asto the appro. mately 19% '-f our total fdel and purchased power ability to replace, if necessarcy Volumes, under these, contractsin expenses. The weighted aveag6 cost 'of purchased power was the. event 'ofa protracted supply-disruption. 'We believe this 61.04 per' negawatt hour in' 2007, $54.90 per MWh in uncertainty. is ntot unique.in'the nuclear'industry.
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| 2006 a+d $59.05 per MWh in 2005. ' '
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| Radioactive Waste Disposal Energy Marketing Activities Under the Nuclear Waste Policy Act of 1982, the Department of We engage in both financial and physical trading' with 'the Energy (DO),is. responsible.Jor the permanent. disposal, of objective of increasing, profits, managing commodity price risk spent nuclear fuel. Wolf, Creek pays into a federal Nuclear Waste r'd, enhancing system reliability. We. trade electricity,, coal and Fund administered by the DOE-a quarterly fee, for. the fut.ure naturalrgs. Weuse a variety of financial instruments, including disposal of spent nuclear fuel. Our share of the feewas $4..4 million forw'ard con,iacts, .options and swaps, and we trade energy iný 2007,,$4.1 million in 2006 and $3.8. milion ;in 2005. and is commodity contracts.. ' ''.'
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| calculated as one-tenth of~a cent for, eachkilowatt-hour. of net Nuclear Gene'ratio '' , " ' nuclear generation delivered to customers. We include these General ' ' 1' costs in fuel and purchased power expense. .')
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| In 2002,, the Yucca Mountain site in Nevada 'was approved for Wolf. Creek is a 1,160 MW nuclear, power plant located near Burlington, Kansas. KGE owns a 47% interest in Wolf Creek, or the development of a nuclear waste repository for the, disposal 545 MK,which represents 9% 'of our total generating capacity. of spent, nuclear fuel and high level nuclear waste from the KCPL owns an equal 47% interest, with Kansas Electric Power nation's defense activities. This action allows the ,DOE to apply Cooperative, Inc. holding the remaining 6% interest. The co- to the NRC to license the project. The DOE announced in 15
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| ......... ;Westar Energy I '2007 Annual Report December 2007, that. it planned to submit a license application electric demand primarily with our other generating units and to the NRC no later than June 20, 2008. However, in January by purchasing power. As provided by the KCC,' we defer and 2008, DOE officials announced that that filing date was in amortize evenly the incremental maintenance costs incurred for jeopardy because of fiscal'year 2008 budget allocation reductions. planned refueling outages 'over the unit's 18 month operating The opening of theYucca Mountain site has been delayed many cycle. Wolf Creek is next scheduledfo be taken- off-line in the times arid could be delayed further due to litigation and other spring of 2008 for its sixteenth refueling and maintenance outage.
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| issue' related to the site as a permanent repository for spent nuclear fuel. Wolf Creek has on'-site temporary storage for spent An extended or unscheduled shutdown, of Wolf' Creek could nuclear f-61 'expected to be generated by Wolf Creek through cause us to purchase replacement power, rely more heavily bri 2025, the term of its existing operating license. our other generating units and reduce amounts of. power available for us to sell at wholesale.
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| Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories. The State of South The NRC evaluates, monitors and rates various inspection Carolina has announced that after June 30, 2008, the disposal findings and performance indicators for Wolf Creek based on site'at Barnwell, South Carolina, Will no longer accept waste their safety significance. Wolf Creek currently meets, all .NRC from generators other than those located in South Carolina, oversight objectives and receives the minimum regimen of Connecticut, and New Jersey, - the three states that make up NRC inspections. Although not expected, the NRC could im-the Atlantic Interstate Low-Level Radioactive Waste Manage- pose an unscheduled plant shutdown due to security or other ment Compact. We expect that another site in the state of Utah concerns. Those concerns need not be related to Wolf Creek will remain available to Wolf Creek. Should disposal capability specifically, but could be due to concerns about nuclear power become unavailable, we believe Wolf Creek is able to store its generally, or circumstances at other nuclear plants in which we low-level radioactive waste in an on-site facility. We believe that have no ownership.
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| a temporary loss of low-level radioactive waste disposal capability Nuclear Decommissioning woiild not affect Wolf Creek's continued operation.
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| Nuclear decommissioning is a nuclear industry term for the The Low-Level Radioactive Waste Policy Amendments Act of permanent shutdown of a nuclear power plant and the removal 1985 mandated that thevarious states, individually or through of radioactive components in accordance with NRC require-interstate compacts, develop alternative low-level radioactive ments. The NRC will terminate a'plant's license and felehase the waste disposal facilities. The states of Kansas, Nebraska, Arkan- property for unrestricted use when a company has'reduced the sas, Louisiana and Oklahoma formed the Central Interstate residual radioactivity of a nuclear plant to a level mandated by Low-Level Radioactive Waste Compact (Central States Com- the NRC. The NRC requires companies with nuclear plants to pact), and thie Central States Compact Commission, which is prepare formal financial plans to fund nuclear decommissioning.
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| respo*nsible for creating new disposal capability for the member These plans are designed so that sufficient funds required for states. The Central States Compact Commission selected nuclear decommissioning will, be accumulated prior to the Nebraska as the host state for the disposal facility. expiration of the license of the related nuclear power plant:Wolf Creek files a nuclear decommissioning and dismantlement study In 'December 1998, the Nebraska agencies responsible for with.the KCC~every three years.... - .
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| corisidering 'the developer's license application denied 'the application. Most of.the utilitiesý that had provided the project's The KCC reviews nuclear decormmissioning plans in two phases.
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| pre-construction financing 'and the Central States Compact Phase one is the approval of the revised nuclear decommission-Commission filed a lawsuit in federal court contending ing study, the current-yeai funding and-future fundi'ng Phase Nebraska officials acted in bad faith while handling the license two involves the review and approval by ithe KCC of a "funding application. In September 2002, the court entered a judgment schedule" by the owner of the nuclear facility detailing how it of $151.4 million, about one-third of which constitutes pre- plans to fund the future-year dollar amount of its pro rata share judgment interest, in favor of the Central States Compact of the plant.
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| Commission and against Nebraska, finding that Nebraska had acted in bad faith in handling the license application. In August In 2005, Wolf Creek filed an updated 'nucleai 'decommissioning 2004, following unsuccessful appeals of the decision, Nebraska site studywith the KCC. Based on the site studyyof decommission-and the Central States Compact Commission settled the case. ing costs, including the 'costs 'of decontamination, dismantling In August 2005,. we received $9.2 million in proceeds from the and site restoration, 'our share of sicl costs is estimated to' be Central States-Compact as a result of the settlement. $243.3 million. This amount compares to the 2002' site' sftdy estimate for decommissioning costs of $220.0 million. The site Outages study cost' estimate represents the estimate to decommission Wolf Creek operates on an 18-month planned refueling and Wolf Creek as of the .site study year. The actual nufclear maintenance outage'schedule. Wolf Creek was shut down for decommissioning costs may vary from the estimates because of 34 days in 2006 for its fifteenth scheduled refueling and main-changes in regulations or technology and changes in costs for tenance outage. During outages at the plant, we' meet 'our labor, materials and eqiilpment.
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| 16
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| Westar Energy I 2007 Annual Report Electric rates charged to customers provide -for recovery of these cost economic dispatch system. It also provides a ready market nuclear decommissioning costs over the life of Wolf Creek, for the economical purchase and sale of excess energy. maxi-which, as determined by the KCC for purposes of the funding mizing the :available transmission system. During 2007 the schedule, will be through 2045. The NRC requires that funds to company was an active participant in this market.
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| meet its nuclear 'decommissioning funding assurance require-Regulation and Rates ment be in our nuclear decommissioning fund by the time our license expires. We believe that the KCC approved funding level Kansas law gives the KCC general regulatory authority, over our will also be sufficient to meet the NRC minimum* financial rates, extensions and abandonments of service and facilities, the assurance requirement. Our consolidated results of operations classification of accounts,- the issuance of some securities and would be materially adversely affected if we are not allowed to various other rrnatters. We are also subject to the jurisdiction of recover in utility rates the full amount of the funding requirement. FERC, which has aufitirity over wholesale sales of-electricity, the. transmission of electric power and the issuance, of some We recovered in rates and deposited in an external trust fund securities. We are subject to the jurisdiction of the NRC for approximately $2.9 million for nuclear decommissioning in nuclear plant operations and safety.
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| 2007 and $3.9 million in 2006 and 2005. We record our invest-ment in the nuclear decommissioning fund at fair value. The fair FERC Proceedings-value approximated $122.3 million as of December 31, 2007, and Request for Change in Transmission Rates: On May 2, 2005, we
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| $111.1 million as of December,31, 2006. ' . filed applications with FERC that proposed a formula tra.nsmis-sion rate-providihg for annual adjuistments to our transmission Competition and Deregulation tafriff. This is consistent'with'our proposals filed with the KCC on The Federal Energy Regulatory Commission (FERC). requires May 2, 2005, to charge retail customers separately for transmission owners of regulated. transmission assets to allow third party servi&e through a transmission delivery charge. The proposed wholesale providers of electricity. nondiscriminatory access to FERC transmis*si6n rates, became effective, subject to refund,'
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| their 'transmission systems to.. transport electric power to December 1, 2005.rOn November 7, 2006,'FERC'issued an order wholesale customers. FERC also. requires us to provide reflecting a unanimous settlement reached by the parties to the transmission services to others under terms comparable to those proceeding. The settlement modified the rates we proposed and we allow, ourselves. In December .1999, FERC issued an order required us to refund approximately $3.4 million, which included encouraging the formation of regional transmission organiza- the amount we collected in the interim" rates since December tions (RTO). RTOs are designed to control the wholesale 2005 and interest on that amount.
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| transmission services of the utilities in their regions, thereby On December 28, 2007, we filed applications with FERC that facilitating compefitive wholesale power markets.
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| proposed changes to our formula transmission rate, which Regional Transmission Organization provides for annual adjustments to our transmission tariff. While We are a member of the Southwest Power Pool (SPP), the RTO the formula already allows, recovery of the prior year's actual in our region. On September 19, 2006, the KCC approved an costs, the changes,,if accepted by FERC, will allow us to include order allowingi~is t6 transfer functional'control of our trarfs- in our formula rate our anticipated transmission capital expen-mission' system to the SPP under its mermbership ,agreement dit.ures for the current year. We have requested the changes take and applicable tariff. The SPP coordinates the operation of otir" effect on June I; 2008. In additibn, we made a simulfaneous transmission system within an interconnected transmn'ssion filing requiesting authority for incentives related to new system that covers all or portions of eight states. The SPP colects transmission investments as permitted by FERC.
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| revenues for the use of each transmission owner's transmission On, November 6, 2007,, we. filed applications With FERC .that system. Transmission customers transmit throughout the entire proposed the use of a consolidated capital structure in our SPP system power purchased and generated for sale or bought formula transmission rate. On December 19, 2007, FERC issued for resale in the wholesale market. Transmissiorn capacity is "an order accepting' this charig& On January 28, 2008, we' filed sold on a first come/first served non-discriminatory basis. All applications with FERC requesting that this change be effective transmission customers are charged rates"applicable to the Jirneý1, 2007.' Accordingly, 'we ha'ýe iecorded a $3.7 million transmission system in the zone where energy is delivered, refund obligitionwhich includes the amount we haVe collected including transmission customers that may sell power inside since June 1,2007,.and interest on that.amount.
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| our certificated service territory.
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| On January 11, 2008, we filed a'request 'WithFERC for authority Real-Time Energy Imbalance Market' to0,1ssue shoftt-terri.,securities and to pledge mortgage bonds On February 1, 2007 the SPP implemented the real-time energy in' Oider to increase the size of oui're'volving credit facility to imbalance market as required by FERC toý"accommodate $750.0 million. On February 15, 2008, FERC granted ourrequest.
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| financial settlement of energy imbalances within the SPP region. See"IJferr 7TManagement's Discussiori and Analysis of Financial The real-time market system permits an efficient balancing of Condition and Results of Opeir'ations -- Liquidity and Capital energy production and consumption through, the use of a least Resources - Capital Resources" for more information."
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| ............... Westar Energy -'
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| 2007 Annual Report EnVironmental Matters excess of, their -allowances. may purchase 'allowances in the General market in which such allowances are traded. In 2007, we had We are subject to various federal, state'and*1ocal environmental SO2 allowances adequate to meet planned generation and we laws and regulations. Envirorimental laws and regulations expect- to have enough in 2008. In the future we may need to affecting power plants are overlapping, complex, and subject-to purchase.additional allowances and as a result our operating changes in interpretation and implementation and have tended costs -may increase. We expect to recover the cost of emission to become more stringent ox¢er time.These l'aws and regulations allowances through the RECA although there are no guarantees relate primarily to discharges inito the air, air quality, discharges we will be'able to-do so. The price of emissions allowances is of 'effluents 'into water, tlie use of water, arid.,'the handling determined by market forces and changes over:time.
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| disposal and clean-up of hazardous substanrces and wastes. On' Marc.h 15, 2005, the EPA issued the Clea, .AirMrcury Rule.
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| These. laws and regulations require Ia,ln*tiy'.and comple. The rule caps permanently, and seek1/2 to reduce, the amount of process for. obtaining, licenses, permits and approvals from mercury that may be emitted from coal-fired power plants. The governmental agencies for our .new,. existing or modifIeI rule requires implementation of reductions in two phases, the facilities. If we fail to comply with such laws, regulations, and first starting in, 2010. We received an allocation of mercury permits, or fail to obtain and maintain necessary -permnits-we emission- allowances, pursuant to the rule. Preliminary testing could be fined or otherwise sanctioned by regulators.ý We .have indicates that.-the expected allocation of -allowances will be incurred, and.will continue to incur capital and other expenditures insufficient to allow us to operate our coal-fired, units in to comply.with environmental laws and regulations. Certain of compliance with.the first phase requirements of the rule. If the these .costs are.. recoverable .through. th.e environmental cost allocated allowances are insuffici6nt,"r may need to purchase recovery, rider .(EQRR). established by the..2005 KCC Order, allowanices in the market; install additional :equipment- or take which allows for.-,the timely inclusionj. -n.- rates of capital othet 'actions t6 reduce our mercury emissions. However, on investments related.. directly to, environmental, improvements February 8, 2008, ýthe'U..S: District Court of Appeals, foi the required by the Clean Air Act as well as many.of the costs relating District of Columbia vacated the Clean Air MercuryRule. While to compliance with. other environmental laws and,regulations. the ultimate impact of this ruling 06 our operations is currently However, there can be no. assurance that we. will be able to unknown, we. believe that miercury emissions controls may be recoverall such costs from our customers or, that our business, required in the future and that the costs to comply with these consolidated financial condition or results, of operations wil not requirements may-be material. .' ' - ,, ' ,
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| be materially and adversely affected as a.result of costs to comply with existing or future environmental laws and regulations. On.August 29,:2007 we filed, an application with the KDHE to implement a plan..tO improve efficiency and to, -install new Air Emissions , ,, . , f .; equipment to reduce regulated emissions from Jeffrey Energy The Clean Air Act, state ,laws and implementing regulations Center. The projects outlined, in a proposed- agreement filed impose;, among otherthings, limitations on pollutants genefated with'the KDHE on August 30, 2007, are designed to meet during our operations, including sulfur dioxide (SO), particulate requirements of the Clean Air Visibility Rule and reduce matter and nitrogen oxides (NOx)... ' ". emissions of, our entire generating fleet by eliminating more than 70% of S0 2 and reducing nitrous, oxides and particulates Certain Kansas Department of Health and Environment between 50% and 65%. ., . .
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| (KDHE) regulations . applicable to our .generatin,g facilities prohibit the emission of. SO 2 in excess of prescribed levels. In gnvironriental requirements ha*ve been changing substantially.
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| order to meet these standards, we use low-sulfur coal, fuel oil Accordingly, we may be required to further reduce emissions of and natiý'ral ga's and have equipped our gerierating facilitieswifh presentl re,gulated gases'and substances, such as SO2, NOx, pollution' contrbl equipment., :, ' pirticulate' matter' and mercury and we may be required to re'duce or.liinit emissions of gases and substances not presently In addition,.we must comply w~th the provisions of the Clean regulated (e.g., carbon dioxide (CO)). Proposals and bills in Air Act Amendments of 1990 that require a two-phase reduction those respects'in'clude:
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| in certain emissions. ,We have installed continuous monitoririg and reporting- equipment in order to meeot.these requirements.. ii the EPA's-flational ambient air quality standards for particulate matter and ozone, I - I I Title IV of the Clean Air'/Act created. an' SO 2 allowance'ad
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| .- additional legislation introduced in the past few years in trading program as part of thefederal acid rain-program. Under Congress requiring reductions of presently unregulated gases the allowanceand trading program, the Environmental Protection
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| 'related primarily to concerns about climate change, and Agency (EPA) allocated annual SO 2 allowances for each affected mstate .Iegislati6n. introduded "recenitly that could require emitting unit. Ai, SO 2 ,allowance is. a limited, authorization: to mitigationo-f CO2 emissions. -
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| emit one ton of SO 2 during a ca lendar year. At the end of each year, each emitting.unit must have enough allowances to cover Based on currently, available inforrnation, we cannot estimate its emissions for that,,year. Allowances- are,.,tradable so that our, costs to comply with these proposed laws, but we believe operators of a'ffected units that are anticipated to emit SO 2 -in such costs could be material.
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| 18
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| Westar Energy 1 2007 Annual Repert Environmental Costs take other remedial a6tiohP"If settlrmehf discdssions fail,,DOJ We have identified thepotential for us to make up to $1.2 billion may consider whether to0pursUfe an enforcement actionag.ins~t of capital expenditures at out poWef plants for. ervironm'ental us in federal district court:Our ultimata costs to resolvethe NSR air emissions projects described above during approximately the Investigation could be material. We believe that costs related to next eight to ten years. This estimate could increase depending updating or installing emissions controls would qualify for on the resolution of the' EPA New Source Review Investigation recovery through the ECRR. If, however, a penalty is assessed (NSR Investigation)-described below. In addition to the capital against us, the. penalty could. be-.material and may not be investment, in the event we install new equipment as a result of recovered in rat~s.-We are notable to estimate the pdssible lobs the NSR Investigation, we anticipate that we would incur signif- or range of loss at this timie.'
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| icant annual expense to operate and maintain the equipment Manufactured Gas Sites and the operation of the equipment would reduce net production
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| 'We have been identifiedas'being resp'nsible -for clean.-iijUý f:a from our plants. The degree to which we will reed'to reduice number of former manufactured gas sites located in Kansas and emissions and the timing of'vhen such emissions controls may Missouri. We and the KDHE entered into a consent agreement be required is uncertain. Both the timing and the nature of in 1994 governingall future work at the Kanrsas sites: Under the required investments depend on specific' dutcomes that result terms of the consent agreement, we agreed to investigate and, if from interpretation of existing regulations, new regulations, necessary, remediate these sites. Pursuant to an environmental legislation and the resolution of-the NSR Investigation described.
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| indemnity agreement with ONEOK, the current owner of some below. In addition, the availability of equipmient and contractors of the' sites;,ONEOK assumed total liability for remediation of can affect the timing and ultimate cost of the equipment.
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| seven sites, and we share liability for remediation with ONEOK The ECRR allows for the timely inclusion in rates of capital for five sites. Our total liability for the five shared sites is capped expenditures tied directly to environmental improvements, includ- af"$3.8 million. We have sole.responsibility for remedialtion with ing those required by the Clean Air-Act. However, increased respect to three sites.
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| operating and maintenahce costs other thari expenses related to Our liability for the former manufactured gas sites identified in production-related consumables can berecovered only through Missouri is limited to $7.5 million by the terms of an environ-a change in base rates following a rate review.
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| mental indemnity agreement with the purchaser of our former New Source Review Investigation . Missouri assets.
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| Under Section 114(a) of the Clean Air'Act (Section 114), the EPA SEASONALITY-, ": '"; '"
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| is conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to the New As a summer peaking ptility,. our..sales are seasonal. The third Source Review permitting.program or New.Source Performance quarter typically accounts for' our greatest sales. Sales volumes Standards. These investigations focus on whethetr projects at are affected by weather c6nditions, the economy of our service coal-fired plants were routine maintenance or whether the projects were sfibstantial'modifications that could reasonably territory and the performance.of.our-customers .
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| have been expected to result in a significant net increase in emissions.The New Source Review prbgrarni requires companies EMPLOYEES '..............
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| to qbtain permits andy if necessary install contro!.equipment.to As 6f February 19, 2008, we: had-:2,323 employees. Our current address emissions when making a major modification,.r, a contract with Local 304: and Local '1523 of the Inteni-atibnal change in operation if either is expected to cause a significant Brotherhood of EIctrical Workers extends through June 30, 200&.
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| net increase in emission.. The contract cc&cefed 1,308 efiplbiee§ asrbf February 19; 200&
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| The EPA requested' information from us under Section 114 regarding projects and maintenance activities that have been ACCESS TO COMPANY INFORMATION conducted since 1980 at three coal-fired plants we operate. On January 22, 2004, the, EPA notified us that certain' projects Our Annual Reports on Form 10-K, Quarterly Reports on completed at Jeffrey Energy Center violated certaini requirements Form 10-Q and Current Reports on Form 8-K are available free of charge either through .our Internet website, at of the New Source Review program.
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| www.westarenergy.com or by respohding.to requests ad-We have been in discussions with the EPA and the Department dressed to our investor relations deart nt. These reports are of Justice (DOJ) concerning this matter in an attempt to reach a available as soon as reasonably prdchcable. after such material is settlement. We expect that any settlement could require~us to electronically filed with, or furnished to, the Securities and update or install emissions controls at Jeffrey Energy Center. Exchange Commission, (SEC) The information contained on Additionally, we might be 'equired to update or install emissions our Internet website is not part. of this document.
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| controls at our other coal-fired plants, pay fines or penalties,, or 19
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| ........... Westar Energy 1 2007 Annual Report EXECUTIVE OFFICERS OF THE, COMPANY' Name' Age Present Office Other Offices or PositionsHeld During the Past Five Years William4B. Moore 55' Director, Chief ExecutiVe Officer and President " Westar Energy, Inc.
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| '* (since July 2007): - President and Chief Operating Officer
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| , ',, ,.. -(March 2006 to June 2007)
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| Executive Vice President and Chief OperatingOfficer (Decermber 2002 to March2006Y James J. Ludwig 49 Executive Vice President, Public Affairs and Consumer Services Westar Energy, Inc.
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| (since July 2007) Vice President, Regulatory and Public Affairs
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| : "(March 2006 to June 2007)
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| Vice President, Public Affairs (January 2003 to March 2006)
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| Mark A. Ruelle 46 ExecutiveVice President and Chief Financial Officer :, Sierra Pacific Resources, Inc.
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| S*
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| (since.anuary 2003) ' President, Nevada Power Company
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| . (Jine 2001 to May 2002)
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| Douglas'R. Sterbenz - 44 Executive.Vice President and Chief Operating Officer Westar Energy,- Inc.
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| (since Ju! .2007) Executive Vice President, Genferaition and"Marketing (March 2006 to June 2007)-,,
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| Senior Vice President, Generation and Marketing (October 2001 to March 2006)
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| Bruce A.Akin -43 Vice Piesideht, Operations Strategy and Support Westar Energy, Inc.
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| (since July 2007) Vice President, Administrative Services
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| ., . ,, ..... . , .. (December 2001,to June2007)
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| Jeffrey L,Beasley 49 'Vice President, Corporate Compliance and internal Audit:. Westar Energy, Inc.
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| (since September 2007) - :+ Executive Director, Corporate Compliance and Internal Audit (September2006 to September 2007)
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| Director, Corporate Finanfce
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| . (March 2005 to September 2006)
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| Director, Accounting-Services (June 2003 to March 2005)
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| Director, Budget and Performance Reporting (January 1999 to June 2003)
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| Larry D. rick 51 Vice President, General Counsel and Corporate Secretary. Westar Energy, Inc.
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| (since February 2003) ' Vice President and Corporate Secretary.
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| (December 2001 to February 2003)
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| Michael Lennen , 62. Vice President, Regulatory Affairs Morris, Laing, Evans, Brock &Kennedy, Chartered
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| *.(since July 2.007) Partner (January 1990 to July 2007)
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| Lee Wages 59 Vice President, Controller (since December 2001)
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| Executive officers serve at thepleasure of the board of directors. Our Revenues Depend Upon Rates Determined by the KCC There. are no family relationships, among any of the executive The KCC reg lates many aspects'f our'business and operations, officers, nor any arrangements or understandings between any including the rates that we charge customers for retail electric executive officer and other persons, pursuantlto :which he was service. Retail rates are set by the KCC using a cost-of-service appointed as an executive officer. approach that takes into account historical operating expenses, fixed obligations and recovery of and a return on capital ITEM 1A. RISK FACTORS investments. Using this approach, -theKCC sets rates at a level Like other companies in our industry, our consolidated financial calculated to, recover such. costs and a permitted return on results vil be impacted by weather, the ec6nomy, of our service investment. Other parties to a rate review or the KCC staff may territory and the energy use -of b.oir customers. The value of contend that our rates are excessive. Effective January 2006, our common stock and our' crediti(,ortliiness will "*be affected the KCC authorized changes that left our base rates virtually by national and international macroeconomic trends, general unchanged but approved various changes to our rate structure market 'conditions and the expedtations of the investment that alldw some Adjustment.to our prices.The KCC approved the community, all of which are largely beybnd our control. In RECA, which allows us'to recover cost of fuel for generatioi -and addition, the following statements highlight risk factors that purchased power expense (less margirns earned on wh6le'ale may:affect our consolidated finanicial condition and results §ales). It also authorized us to implement' the ECRR, which of operations. These are not intended to be an exhaustive allows us to change our rates to reflect the impact of capital discussion of all such risks, and the statements below must be expenditures made to upgrade our equipment to environmental read together with factors discussed elsewhere inthis document standards required by the Clean Air Act.
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| and in our other filings with the SEC.
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| 20
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| Westar Energy 1 2007 Annual Report ..............
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| Our Costs May Not be Fully Recovered in Retail Rates to install new emission confrol systems at Jeffrey.Energy Center Except to.the extent the KCC permits us to mddify our prides by and at certain of our other coal-fired power plants.
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| using specific adjustments and riders such as the RECA and.the Our activities are subject to extensive and changing environ-ECRR, once established by the KCC, Our rates generally remain mental regulation,.by federal,, state, and local. governmental fixed until changed in a subsequent rate review. We may apply authorities,'particuaaily relating to air emissions. In addition to to change our rates or intervening parties may request that the laws currently in effect, numerous laws and regulations have KCC review our rates for possible adjustment, subject to any been enacted and proposed relating' to increasing national and limitations that may have been ordered by the KCC.
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| international concern about possible global' warming caused by Equipment Failures and Other External Factors,' the atmbsphericoreleaseý of COiand othergases by industrial anrd Can Adversely Affect Our Results other sources, including the utility industry. On Noyember,15, The generation, and transmission of -electricity requires the 2007, the governors, of six Midwestern states, including Kansas, use of expensive and complicated equipment. While we have signed the Midwest Greenhouse Gas Reduction Accord, under maintenance programs in place, generating plants are subject which' the member states will, .among other things, establish to unplanned outages because of equipment failure.. In these greenhouse gas -reduction targets, and develop a marketrbased events, we must either produce 'replacement 'power from' our and multi-sector cap-and-trade mechanism to help achieve other, usuallyless efficient, units or purchase power from others such targets. In addition, on October 18,2007, the.KDHE denied an application by an unrelated.utility for an air quality permit for atunpredictable and potentially higher cost in'order to meet our sales, obligationsd"Iri addition, equipment failure can'limit, our two new proposed coal generators .in Western Kansas in part ability to make opportunistic sales to wholesale customers." because of concerns about the increase in CO 2 and emissions and the potentia'l[ill effects. those, plants might have on the Fuel .Deliveries Can Be Interrupted or Slowed and environment and health. The KDHE noted that the decision Transmission Systems May Be Constrainedcl, constituted a first step in emerging policy to address existing Coal deliveries from-the PRB region of Wyoming, the primary and future C02.emissions in Kansas. The Midwest Greenhouse source for our coal, can be interrupted or can be slowed due to Gas Reduction 'ccord or other. new or changed laws and rail traffic congestion, equipment or track failure, or due to regulations, as well as third party litigation that may be -brought loading problems at the mines. This may require that we against us or our competitors, could result in requirements to implement coal conservation efforts and/or take other compen- install costly equipment, increase our operating expense,;reduce sating measures. We experienced these problems arnd conserved production from our plants or take other actions we'are unable' coal to varying degrees in 2005 and 2006. These measures may to iden'tify at this time.
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| include, but are not limited to, reducing coal consumption by revising normal dispatch of generation units, purchasing power The degree to which we may need to reduce emissions and or using more expensive power to serve customers and the timing of when ,such, emissions' control equipment m'niay decreasing or, if necessary, eliminating opportunistic wholesale be required is uncertain. Both: the .tinihg 'and the nAtiire of sales. In addition, deci~ions or mistakes by.other utilities may required investments depen'd on specific outcomes that result adversely affect our ability to use transmission lines to deliver or from interpretation of existing regulations, new regulations, import power, thus subjecting us to unexpected expenses Ior to legislation, and the resolution of the'NSR Investigation described the cost and uncertainty of public policy initiatives.These factors, above. Although we expect to riecover'in our rates most of the along with the prices and price volatility, of fuel and wholesale costs that w'e incur to comply with environmental regulations, electricity are largely beyond our control. Costs that are not we can provide'no assurance that we will be able to filly anrd recovered through the RECA could have a material adverse timely recover such' cos'ts&6r the costs of any failure to comply effect on our consolidated earnings, cash flows and, fin ancial with laws and regulations. Failure to recover these associated position: We engage in energy marketing transactions to reduce costs couIld'have armatidial adverse'effect on our consolidated risk from market fluctuations, enhance system reliability and financial~statements. ., . -
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| increase profits. The events mentioned above could reduce 'our Accounting Regulations Unique' to Public Utilities ability to participate in energy marketing opportunities, which Could Change '
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| could reduce our profits.
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| We currefitly apply'the accountingprinciples of Statem'eht"of We May Have Material Financial Exposure Relating Financial Accounting Standard (SFAS) No. 71, "Accounting to Environmental Matters for the Effects of Certain Typ'eg of Regulation," to our regulated On January 22, 2004, the EPA notified us that certain projects business.As of December31, 2007,we had recorded $533.8 million completed at Jeffrey Energy Center violated certain New Source of regulatory assets, het'of fegulatory liabilities. In the event Review permitting requirements under the Clean Air Act. This we determined that. we could no longer apply' the principles notification was delivered as part of an investigation by the EPA' of SFAS 'Nod. 71, either as: (i) a result of the establishment of regarding maintenance activities that have been conducted retail competition' in our service territory; (ii) a change in the since 1980 at Jeffrey Energy Center. The costs .to resolve this regulatory approach for se.ttinrgrates'froin'cost-based ratemaking investigation, or any related enforcement, action, could be to another form of ratemaking; or (iii)"6ther regulatory actions material and could include fines and penalties as well as costs that restrict cost ,recoery to a 'level insifficient to recover c6sts, 21
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| ............... Westar Energy I 2007 Annual Report we-would be required. to record a charge against income in the dilute the.value of our'shares. of our common, stock and cause
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| 'amount of the remaining unamortized: net,,regulatory assets. the market price of our common stock-to .,fall., These factors Such an action would materially reduce our shareholders'equity. could hinder our access to capital markets and.limit.0r delay our We periodically 'revieiv'tl&e criteria to rihsure.thecontinuing .abilityto carry out our capital expenditure program.
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| application 'ofSFS No. 71"is appropnate. Based upon current Further, 'our recovery of capital'e-xpenditiures depenids in large evaluation of the' 'vanrous 'fadors that are expected to impact degre'e on the outcome of retail aInd wholesale rate Oroceedings, ftire cost rie6overy, we beliee that 'our'-regfilatory assets are Decisions made by.the KCC or FERC, or delays in making such probable of reco~ry. '
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| decisions, could have a mateiial impact orn our consolidated We. Face Financial, Risks'Associated With Wolf Creek! financial statements.., .. , *. ,.-, -
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| Risks" of substantial',liability' arise 'fror*i the - 'wnership and o;0eration of niklearfacilities, includin among'ithers, structural ITEM lB. UNRESOLVED STAFF COMMENTS prdblems at'a nuclear facility, the storage,'handling and disposal N*,oe.
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| 6f' radioacti1/2 miaterials,;limitati6hs oh the 'amoUnts and types of' insuranice coverage commercially Vvailable,; uncertainties ITEM .2. PROPERTIES With Iresp~ef to the cost and teihnblogical aspects of nuclear decomnmissioning at the endj6f' their useful lives and costs 'Unit Capacity (MW)'By Owner or measures associated With' public safety./In the event of an Unit' Year' -'Principal Westar 'Total Name/Location , . No. Installed , Fuel ' Energy ,KGE 'Company extended or unscheduled 'oiutage at Wolf Creek, wecwould be Abilene Energy Center:.,, .- ' ,.
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| teqriuied 'to generate pow-'er'from more costly generating units, Abilene, Kansas PUrchase power in the o8pen market to replace the power Combustion Turbine,., 1. 1973. Gas 72:0 - 72.0 normally Produ ced at Wolf Creek ahid'we would hive less Gordon Evans Energy Center: '..'
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| power available for sale into the wholesale markets. If We were Colwich, Kansas Steam:Turbines , ' 1: ' 1961 Gas-Oil *"'d 152.0' " 152.0 riot' permitted by the KCC to0 recover th'e'se costs, such everits ,I :'. -.. , 2 -1967 Gas-,Oil 374.0 374.0 consolidated .--
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| Would likely have an adverse impact 'on'6ur Combustion Turbines 1 2000., Gas 74.0 - 74.0 finandial condition. 2 2000 Gas ''72.0 - 72.0 3' 2001
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| * Gas') .150:0 ' '150.0 Our Planned Capital Expenditures Are Significant Diesel Generator. I- 1969 Diesel'. -' 3.0 3.0 ToOur.Results.Of Operations,,: . '
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| Hutchinson.Energy Center: '
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| Hutchinson, Kansas During the period from '2008 through :2010' and .for the Steam Turbine 4 1965 Gas - Oil 170.b - 170.0 immediate years beyond, we plan to continue significant capital Combustion Turbines 1' 1974 Gas' . - 51.0 - 51.0 2,. 1974 Gas 51.0 - 51.0 e enditures toward large projects including the expansion and 3 1974 Gas 56.0 -- 56.0 modemrnzation of our generation fleet and transmission network. 4 1975 Diesel 75.0 -- 75.0 Our alnticipated c'apital expenditunrs for the period from 2008 'DieselGenerator' ' '1 '1983 Diesel' ' 3.0 - 3.0 through'2010, inciuding- costs"of 4 emnoval, are approxinmately Jeffreli Erergy Center (92%):- " ,
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| St. Marys, Kansas, ' . ,
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| $2.5 billion. Estimated gosts for these capital /rojects have Steam Turbines , ld)
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| I (. 1978 Coal 526.0 146.0 672.0 increased, in some cases significantly, as a result. of rising 2I( 1980 'Coal " 526.0 146.0 672.0 demahnd'foi material, equipnment and tabor. In'addition,,dela's "', " 3 (d 1983 Coal ' '526.0 ' 146.0 '672.0 Wind.Turbines' ". 1Id) 1999 '-= , , 0.5. 0.2 0.7 i .engineerineg. and construction himes can occur 'throtighout '2,() 1999 -- 0.5 0.2 0.7 burindustry. Because 6ur capital'expeinditure program is large in LaCygne Station (50%):
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| comparison to our revenues and.assets,cost incre'ases or delays La Cygne, Kansas, could materially affect 6ur conis0lidated fina-ncial stater6mnts. Stear Turbines ' 1 *' 1973 1:' Coal " - 368.0 368.0 2,),.1977 Coal - 341.0. 341.0' In addition, in order to fund our capital expenditure program; Lawrence Energy Center:.,'
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| Lawrence,, Kansas
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| * we rely to a large degree on access to our short-term credit Steam Turbines '' 3 1954 Coal 49.0 - 49.0 facility and fo l6eng-tlrf" capita'l "-T*arkets foi debt and equity 4 '1960 . Coal 110.0' . - " 110.0 as sources of liquidity for capital requirements not satisfied by 5 1971 Coal. "' 373.0 - 373.0 the cash flow fron'm' our op'eration's T.'Tie secured 'debt of Westar Murray Gill Energy Center:
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| Wichita, Kansas. ; ,
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| Energy and KGE is rated. iniyegtment grade bý all three of the Steam Turbines 1 1952 Gas t - 39.0 , 39.0 best known rating agencies, and'the'uinsecu'red debt of Westar 2 1954 Gas-.Oil - 63.0 63.0 Energyvnd KGE is rated in-estm&it grade by two of the three 3 1956 Gas-Oilf 95.0 95.0 4 1959 Gas- Oil 90.0 90.0 best known .rating agencies, but we cannot assure t "hat'such Neosho EnergyCenter: I debt will,.continue 'to be rated inýýstmien grade. If the rating '.Parsons, Kansas ..
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| agencies were to downgrade Westar Energy's or KGE's'secured Steam Turbine 3 1954 Gas'- Oil 67.0 67.0 or unsecured debt, our bo0rowing costs and the interest rates Spring'Creek Energy Center:
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| Edmond, Oklbh6m'a '
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| we pay on short-term*ýn'd long-term debt .wquld likely increase, Coýnbustion.Turbines
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| * I 2001(l ' Gas,:, );70.0 - 70.0 p'ossibly significantly. Further, mirket disruptiori scould increase , 2' 20011) Gas,. 68.0 - 68.0 our cost of borrowing or adversely affect our ability to access 3 2001 I Gas 66.0 - 66.0 financial markets. Additional issuance of equity securities could 4 2001 IC Gas 68.0 - 68.0
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| | |
| Westar Energy 1;2007 Anndal Report
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| 'Unit Capacity (MW) ByOwner PARTII SUnit Year" ** Princip al Westar Total ITEM 5. MARKETF10OR REGISTRANT'S'COM!'ION EQUITYý"-"
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| Name/location , .. No. Installed Fuel :,.Energy . KGE: Company -AND RELATED STOCKHOLDERMATTERS State Line (40%): . . * . . .
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| ..Joplin,, Missouri . . ** , * , -
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| STOCK PERFORMANCEGRAPH " '
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| CoPInned Cycle . 2-1 () 2601 Gas 65.0 665.0 2-2(a) 2001 Gas 65.0 -- 650 The following performance graph compares .the performance of 2-3(l) .2001. Gas 74.0 - 74.0 our common stock during the period that began On.December 31, Tecumseh Energy Center: ' *. . . :.- 2002,..and ended on December 31, 2007;' to the Standard &
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| Tecimseh, Kansas ., Poor's 500 Index and the Standard & Poor's,Electric Utility Index.
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| Steam Turbines 7 1957' Coal 74.0 - 74.0 8 1962 Coal 130.0 - 130.0 The graph assumes a $100 investment in our common stock Combustion Turbines 1 1972 Gas 19.0 - 19.0 and in each of the indices at,.the.beginning of-the period and-a 2 1972 Gas 19.0 - 19.0 reinvestment of dividends paid on such investments throughout Wolf Creek Generating Station (47%): ., fý', the period. .7. ' " -... "
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| Burlington, Kansas Nuclear 1W 1985 Uranium 545.0 545.0 CUMULATIVE TOTAL RETURN Total 3,603*0 2,575.4 6,178.4 , Based upon an initial investment of $100 on December 31, 2002 with dividends reinvested ' '" .
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| "'We'ointlyown Li Cygne unit 1 generatingunit (50%), WolfiCreek Generating Station (47%) and State Line (40%). Unit capacity amounts reflect our $350 ownership only.
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| OIn 1987, KGE entered into a sale-leaseback transaction involving its 50%
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| interest in the La Cygne unit 2 generatingunit.
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| $250 (1)We acquiredSpring Creek Energy Center in 2006. .
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| 0 We acquired an 8% leasehold interest in Jeffrey Energy Center in 2007, which,,
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| brought our total interest to 92%. Priorto 2007, we owned 84% of all units at Jeffrey Energy Center Unit capacity amounts reflect our_92% interest. $150C
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| $100 We own and have in service approximately 6,100 miles of transmission lines, approximately 23,700 miles of overhead $50 ..... . , . ..
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| distribution lines and approximately 3,900 miles of undergrouind
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| $0 distribution lines. Dec-02 Dec-03 Dec-04 Dec-05 Dec-06 Dec-07 Substantially all of our utility properties are encumbered by first. ____Westar Energy Inc.
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| priority mortgages pursuant to which bonds have been issued, Electric Utilities 0
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| and are outstanding. S -. . . -S&P 500 Dec-2002 Dec'.26003Dec-2004 Dec-200S Dec-2006ýDec-'20(07 ITEM 3. LEGAL PROCEEDINGS Westar Energy Inc ...... $100 $214 $252 $246 $310 $323 Information on other legalproceedings is set forthinNotes 3,14,16 S&P 500 ............ $100 $129 $143 $150 $173 $183 and 17 of the Notes to Consolidated Financial Statements,"Rate S&P Electric Utilities .... $100 $124 $157 $185 $228 $280 Matters and Regulation,""Commitments and Contingencies -
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| STOCK TRADING New Source Review Investigation," "Legal Proceedings" and "Potential Liabilities to David C. Wittig and Douglas T. Lake," Our common stock is listed on the NewYork Stock Exchange respectively, which are incorporated herein by reference. and traded under the ticker symbol WVR. As of February 19, 2008, there were 24,742 common shareholders of record. For ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF information regarding quarterly common stock price ranges SECURITY HOLDERS for 2007 and 2006, see Note 22 of the Notes to Consolidated Financial Statements,"Quarterly Results (Unaudited)."
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| None.
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| DIVIDENDS Holders of our common stock are entitled to dividends when and as declared by our board of directors. However, prior to the payment of common dividends, we must first pay dividends to the holders of preferred stock based on the fixed dividend rate for each series.
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| Quarterly dividends on common and preferred stock have historically been paid on or about the first business day of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews our common stock dividend policy from time 23
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| | |
| ................ Westar Energy I 2007 Annual Report to time. Among the factors the board of directors considers Our articles of .incorpdration restrict the payment of dividends in determining our dividend .policy are earnings,, cash flows, or the making of cither distributions'6n' Odf~c6mmon stock capitalization ratios, regulation; competition and financial loan while any preferredshares remain outstanding unless we meet covenants. During 2007 our board of directors declared four certain capitalization ratios and other conditions. We were not quarterly dividends, each at $0.27 per share, reflecting an annual limited by any such restrictions during 2007. We provid6 further dividend of $1.08 per share. On February 20, 2008, our board information on these restrictions in Note 19 of the Notes to of directors declared a quarterly dividend of $0.29 per share on Consolidated Financial Statements, "Common and Preferred our common stbck payable to shareholders on April 1, 2008. The Stock." We do not expect these restrictions to have-an impact indicated annual dividend rate is $1.16 per share. on our ability to pay dividends on our common stock.
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| ITEM 6. SELECTED FINANCIAL DATA Year Ended December 31, 2007 2006 2005 2004 .' 2003 (InThousands)
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| Income Statement Data:
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| Sales ... .................. ...... ............................. $ 1,726,834 $ 1,605,743 - $ 1,583,278 $ 1,464,489 $ 1,461,143 Income from continuing operations , .. 168,354 165,309 134,868 .100,080, 162,915 Earnings available for common stock ......................... ....... 167,384 . 164339 ,134,640 177,900.,, 84,042 As of December 31, 2007 2006 2005 2004 2003 (InThousands)
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| Balance Sheet Data: -
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| * Total assets ......................................................... $6,395,430 $ 5,455,175 $ 5,210,069 $ 5,001,144 $5,672,520 Long-term obligations and mandatorily redeemable preferred stock," ............ 2,022,493 1,580,108 1,681,301 1,724,96.7 2,259,880 Year Ended December 31, 2007 2006 2005 2004' 2003 Common Stock Data:
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| Basic earnings per share available for common stock from continuing operations $ 1.85 $ 1.88 $ 1.54 $ 119 $ *2.24.
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| Basic earnings per share available for common stock ....................... $ 1.85 $ 1.88 , $ 1.55 . $ 2.14 , , $ 1.16 Dividends declared per share ...................................... $ 1.08 $ 1.00 $ 0.92 $ 0.80 $ 0.76 Book value per share ................................................. $ 19.14 $ 17.61 $ 16.31 $ 16.13 $ 13.98 Average equivalent common shares outstanding (in thousands)(bc) 90,676 "" :87,510 86,855 82,941' ' 72,429
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| (,)Includeslong-term debt, capital leases, affiliate long-tm debt and shares subject to mandatory redemption.
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| (b)In 2004, we issued and sold approximately 12.5 million shares ofcommon stock realizing net proceeds of$245.1 million.
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| ()In 2007, we issued and sold approximately 8.1 million shares of common stock realizing net proceeds of $195.4 million.
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| 24
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| | |
| Westar'Energy I 2007 Annual Report ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS wholesale sales. We sold'"10:0 million' MVNh of electricity" to OF FINANCIAL CONDITION AND RESULTS OF wholesale customers for the year ended December 31, 20Q7ý OPERATIONS compared'to 7.4 million. MWh last yekr. We were able to 'sell more electricity to our wholesale custonrers this year due to our INTRODUCTION not having had to conserve coal and our hot having a planned We are the largest electric utility in Kansas. We produce, transmit refueling outage at Wolf Creek'as we'did last year.
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| and sell electricity at retiail in Kanisas and at wholesale in a muilti" Increased Capacity and. Future Plans state region in the central United States under the regulation of On January 11, 2008, we announced that we 'reached' the KCC and FERC.
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| agreements with developers' who will build three wind farms In Management's Discussion and Analysis, we discuss our in Kansas totaling approximately 300 MWs. Under the terr's'of general financial condition, significant changes that occurred the agreements, we plan to'own approximately half of the wind during 2007, and our operating results for the years ended generators at an expected cost of approximately $290.0 million December 31, 2007, 2006 and 2005. As you read Management's and purchase energy produced by the wind farms under twenty Discussion arfd Analysis, please refer to our consolidated year supply contracts for the other half. All three wind farms are' financial statements and the' accompanying notes, which expected to be producing energy by the end of 2008.
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| contain our operating results.
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| On April' 1; 2007, we completed the .purchase of Aquila,' Inc.'s (Aquila) 8% leasehold, interest in Jeffrey Energy' Center for
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| ==SUMMARY==
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| OF SIGNIFICANT ITEMS
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| $25.8 million and agsumed the related 'lease obligdtion. This Overview lease expires on January 3, 2019,'and' has a purchase option Several significant items have impacted or may impact us and at the end'of the lease terim Based onhcurrent ecorinmic and our operations since January 1, 2007: other conditions, we expect to exercise the purchase option.
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| Based upon 'these expectations, we recorded'a capital lease of n Our gross margin for the year ended December 31, 2007, $118.5 million.
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| increased compared to the prior'year due largely to increased wholesale sales. See "- Increased Gross Margin" below for In September 2006, we announced plans to build a 345 kV additional information; transmission line from our Gordon Evans Energy Center a We estimate that we incurred approximately $72.0 million northwest of Wichita, Kansas, to a new, substation near in maintenance costs and capital expenditures to restore our Hutchinson, Kansas, then on t6 our Sulmmit substation near electric distribution and transmission systems as a result of a Salina, Kansas, a distance totaling approximately 97' miles.'-In "severe ice storm that occurred in December 2007. We deferred January 2007, we filed an application with the-"KCC to request
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| $53.8 million of these costs as a' regulatory asset, which we permission to site the line. The KCC grantdd 6ur*-permit on will ask for recovei' of in our next rate cases that are planned May 16, 2007. We expect to complete constructionin late 2009.
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| for 2008; We expect. the total investment in the line to be approximately m We issued 7.6 million shares of common stock for net $150.0 million. In addition to this line, we plan to construct 'a' proceeds of $193.8 million through Sales Agency Financing new 345 kV line from our Rose Hill substation near Wichita to Agreements with BNYCMI'and a forward sale agreement and the Kansas-Oklahoma border, where we will interconnect with
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| $325.0 million in first mortgage bonds as part of our efforts to new facilities built.by an Oklahoma-based utility. The prelim, raise the capital needed to fund our construction projects. We inary estimate of the total investment in the line is approxi'mately expect to continue to issue equity and debt as external funds $70.0 million, -which is subject to .change pending- seldction of are needed to complete planned capital investments; the final route and engineering design, among other factors. On w We started construction on a 610 MW peaking power plant and December 27, 2007, we filed an application' with the KCC to are expanding our'transmission network. We also announced request permission to site this line. The KCC has until April 25, agreements with developers to build app5roximately 300 MW 2008, to act on ourapplication: . ' -
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| of wind generation of which we will either own or enter into supply contracts related thereto. See "- Increased Capacity In August 2006, we announiced plans to build a new natural.gas-and Future Plan" below for additional information; fired combustion turbine peaking power plant nehr.Emporia in aChanges in Federal income tax law allowed us,.to recognize Lyon County, Kansas. We expect the new plant, which we have
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| $11.8 million in tax benefits from the utilization of a net operat- named theEmporia Energy Center, to have an initial generating ing loss~that had not previously been applied against income. capacity of approximately 310 MW,' with additionalcapacity to be added in a second phase, bringing the total .capacity to Increased Gross Margin approximately 610 MW. We expect the total investment in the Our, net income was $168.4 million and $165.3 million for the plant to be about $318.0 million. Construction on the .new years ended December 31, 2007 and 2006, respectively. Our gross plant began in March 2007. The initial phase of the plant is margin for the year ended December 31, 2007, increased compared scheduled to begin operation in May of 2008. The second phase.
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| to the previous year due primarily to significant increases in is scheduled to begin operation in May of 2009., .
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| 25
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| : .. Westar Energy I ý2007. Annual Report CRITICAL ACCOUNTINGESTIMATES.; The following table shows theannual irmhpact of a 0.5% change in our pension plan discount rate, salary scale and rate of return Our disctission: and 'analysis of financial, condition and on plan assets.
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| results 'of 61*rati.ns ar'e based' on our 'consolidated financial statements, whikh havxe been prepared "in conformity with Annual Annual , Annual Change in Change in Change in generally accepted accoun'trig principles,(GAAP): Note 2 of Projected Pension Projected Change in. Benefit Uability/ Pension the Notes to CInsolida:fted Osina~ficial St atements "Summary Actuarial Assumption Assumption Obligation , ,Asset ' Expense of Significant Accounting Policies,'"contains a-summary of our (In Thousand s) significafit accounting policies, ,many of which require the use Discount rate ............... 0.5% decrease $45,071 $45,071 $4,409 of estimates and assumptions, by management. The policies 0.5% increase (42,194) (42,194) (4,307) highlighted below have an impact on our reported results that Salary scale .... .'.. ........ 0.5% decrease (12,067) (12,067) (2,370)'
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| may be material due to the lexvels of judgment and subjectivity 0.5% increase 12,310 12,310 2,440 necessary to-account for uncertain matters or, their susceptibility Rate of return on plan assets ... 0.5% decrease - ' - 2,603 to. change.. ' , 0.5% increase - -- ' (2,603)'
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| Regulatory Accounting We recorded pension. expense of approximately $21.4 million in We currently apply accounting standardsr for our regulated both 2007 and 2006 and $12.2 million in 2005. These amounts utility operations that' recognize, the -economic effects of rate reflect the pension expense of Westar Energy and our 47%
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| regulation in accordance with SFAS NQ., 71. Accordingly, we responsibility for the pension expense ofWolf Creek.The increase haye recorded, regulatory assets and liabilities when required- by in pension expense from 2005 to current levels is due primarily a regulatory order or based on regulatory precedent. Regulatory to the amortization of investment losses from prior years that assets represent incurred. costs,that have been deferred because, are recognized on a rolling.four-year average basis and changes they are. probable of future recovery in utility rates. Regulatory in assumptions including lower returns on assets, increases in liabilities -represent probable. future reductions in revenue or salaries and updated mortality tables. Pension expense for 2008 refunds to customers.
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| is expected to be. approximately $23.0 million.
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| The deferral of costs as regulatory assets is appropriate only when the future recoyery of such costs is probable. In assessing The following table shows the annual impact of a 0.5% change in the discount rate and rate of return on plan assets on our probability, we consider such factors as specific regulatory orders, post-retirement benefit plans other than pension, plans.
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| regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed to be probable, Annual Annual Annual Change in Change in we would record a charge, against income in the amount of the Change in Post- Projected related regulatory assets. . , ,Change in Projected Benefit retirement Liability/
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| Post-retirement Actuarial Assumption Assumption Obligation . Asset Expense Pension and Post-reti'rement' Benefit Plans (InThousands)
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| Actuarial Assumptions ..... - -
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| Discount rate ............... 0.5% decrease $7,615 $7,615 $437 We and Wolf Creek calculate our pension benefit' aind post- 0.5% increase (7,228) (7,228) (448) retireinent mediclý:ben'efift obligatioins' and related costs using Rate of return on plan assets ... 0.5% decrease, - ..- 285 actuarial concepts within 'the guidance provided 'by SFAS 0.5% increase' ' - -. , (285)
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| No. 87, "Employers''Accounting for 'Pensions", SFAS 'No. 106, "Employers"Acc6unting for 'POst-retirement 'Betnfits Other Revenue Recognition - Energy Sales Than Pensi6ns" and SFAS No.' 158, "Employdrs'Accounting for WTe record revenue as electricity is delivered. Amounts delivered Defined Ben'efit Pension and Oth&r Post-retirement Plans -An to individual customers are determined through the systematic Amendment of FASB Statements No. 87, 88,106, and 132(R)." monthly readings of customer meters. At the end of each month, In accounting for our retirement plans:and other post-retirement the electric usage from the last meter reading is estimated and benefits, we make assumptions regarding the valuation of corresponding unbilled revenue is recorded.
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| benefit oblig'ationis and the perf0rnancfe b'f plan 'assets. The The accuracy of the unbilled' revenue 'estimate is affected by r~p6rted' costs of our'pensi6n plan*'are imipacted b5}estimates factors that include' fluctuations in energy demands, weather, regarding earnings on plan 'assets, contribitions 'to the plan, line losses and changes in the composition of customer classes.
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| discount rates tised to deterrn."ine our prdjected'benefit obligation We had estimated unbilled revenue of $43.7 million as of and pension costs and employee demographics 'including age, December 31, 2007, and $38:4 million as of December'31, 2006.
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| comperisatiori levels and erni'loyteiit periods:.A'change in any of these assumptions could have a significant impact on future We account for energy marketing derivative contracts under the costs, which may be reflected as an increase 'Or decrease in net mark-to-market method of accounting. Under this method, we income' in the current an~nt future periods, or on the amount of recognize changes in the portf0lio -alue as gains dr losses in the related iabilities' reflected on our consolidated balance sheets or period of change. With 'the exception of a fuel supply contract may also require cash 6ont'iutions. and a cIapacity sale contiact, which are recorded as regulatory 26
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| | |
| Westar Energy I 2007 Annual Report .............
| |
| liabilities, we include the net mark-to-market change insales on and liabilities. We recognize the future taxbenefits to' the extent our consolidated statements of income. We record the resulting that realization of' such benefits is more likely than not. We unrealized gains and ilgsses as energy. maTketinig long-term or amortize defefred 'inrvestment tax credits over the lives' of the short-term assets and liabilities on our consolidated balance related properties. " - ,
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| sheets as appropriate. We use quoted market prices to value our energy marketing derivative contracts when such data .is We record deferred'tax assets for capital losses, operating losses and tax credit carryforwards. However', when we believe "we available. When market prices are¬ readily av~ilable or det6f-minable, we use alternative approaches, such as model pricing. do not, or will not have sufficient future capital gain income or Prices used to value these transactions reflect our best estimate taxable income to realize the benefit of the capital loss, operating loss or tax credit carryforwards, we reduce the deferred tax assets of the fair value of our contracts. Results actually achieved from by 4 valuation' allowance' We recogoize a valuation allowance these activities could vary materially from intended results and if we determine, based' on available evidence that it is unlikely could affect.our consolidated financial results.
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| that we will realize some portibn, or all of the'deferred tax asset.
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| The tables below show the fair value of energy', marketing We'report the effect of a'change in' the valuation allowance in contracts that were outstanding as of December 31;,2007, their the current period tax expbnse.
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| sources and maturity periods.
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| As of January 1, '2007, we account for uncertainty in income Fair Value taxes in accordarice with Financial Accounting Standards Board of Contracts (FASB) Interpretatiob No. (FIN) 48.The application of income tax (in Thousands) law is inherently complex. Laws and regulations in this area are Net fair value of contracts outstanding as of December 31, 2006 .......... - $20,625 voluminous and are often -ambiguous. As such, we are required Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period .............. ,(9,948) tO make many'subj&tive assumptions and judgments regarding Changes infair value of contracts outstanding at the . our income tax exposures. Interpretations of' and guidance beginning and end of the period ...................I ............. 9,407 surrounding ihicome tax laws and regulations chainge over'time.
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| Fair value of new contracts entered into during the period ............... 21,418 As such, changes in our subjective assumptions and judgments can materially affect amounts recognized' in the consolidated Fair value of contracts outstanding as of December 31, 20070) ........ . $41,502 financial statements. See Note'll to the Notes to Consolidated
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| ()Approximately $34.Omillibn of the fair value of energy marketing 'ontracts, Finanial Stat'ements, "Income Taxes,"for additional detailof our which is conprised of a fuel supply'contract and a capadity sale coiztract, is recognized as a regulatoryliability. .-
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| uncertainty in income taxes.
| |
| Asset Retirement Obligations The sources of the fairvalues of the financial instruments related We calculate bui asset retirement obligations anrc related costs to these contracts as of December 31, 2007, are summarized in using the 'guidahce provided by SFAS No. 143; "Accounting the following table.
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| for Asset Retirement Obligations".and FIN 47, "Accounting for
| |
| '- Fair Value of Contracts at End of Period Conditional Asset Retirement Obligations."
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| Maturity Maturity Total Less Than Maturity Maturity !Over We, estimate our asset.retirement.obligations based on the fair Sources of Fair Value FairValue 1 Year 1-3 Years 4-5 Years ' 5 Years value of the asset retirement obligation we incurred at the time (InThousands) the related long-lived asset was either acquired, placed.in service Prices provided by other . . or when regulations establishing the obligation become effective.
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| external sources (swaps and forwards) . . $31,323 $.9,910 $13,677 $ 4,039 $ .3,697 In:determining our asset retirement obligations, we make Prices based on option " .
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| pricing models (options assumptions regarding probable disposal costs.A change in these assumptions could have a significant impact on our asset retire-and otherY)) ......... 10,179 5,151 6,581 (803) (750)
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| Total fair value of contracts ment obligations reflected on.our consolidated balance sheets,.
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| outstanding...... .. . -41502 '$15,061 $2.0,258 $ 3,236 $ 2,947 Contingencies and Litigation "
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| 6")Options are priced using a series of techhiques; suMh as the-Black option'pricing We are currently involved in certain legal proceedings and, have model. estimated the, probable cost for the resolution of these claims.
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| These estimates, are. based on an analysi' of potential results, Income Taxes assuming a combination of litigation and settlement strategies.
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| We use the asset and liability method of accotiiiting fori income It is possible that our future results could be materially affected taxes as required by SFAS No. 109, "Accounting for Income by changes in our assumptions. See "- Future Cash Require-Taxes." Under the asset and liability method, we recognize ments" and Notes 16 and 17 of the Notes to Consolidated deferred tax assets and liabilities for the future tax consequences Financial Statements, "Legal Proceedings" and "Potential Lia-attributable to temporary differences between the financial bilities to David C. Wittig and DouglasT. Lake," for more detailed statement carrying amounts and the tax basis of existing assets information.
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| 27
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| | |
| .............. Westar Energy I 2007 Annual Report OPERATING RESULTS 2007 Compared to 2006 We evaluate operating results based.on earnings per share. We Below we discuss our operating results for the year ended have various classifications of sales, defined as follows: December 31, 2007, compared to the results for the year ended December :'31, 12006. Changes- in .result9 of operations are as Retail: Sales of energy made to residential, commercial and follows.
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| industrial customers..
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| Year Ended December 31, 2007 2006 Change %Change Other retail: Sales of energy for'lighting Oublidcstreets and . (InThousands; Except Per.Share Amounts) highways, net of revenue subject to refund., SALES:
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| Residential ............. $ 491,163 $ 486,107 $ 5,056 1.0 Tariff-based wholesale: Sales of energyto electric cooperatives, Com mercial'.... ..... .... .. 448,368 438,342 10,026 2.3 municipalities and other electric utilities, the rates for.which Industrial. 264,566 - 266,922 (2,356) (0.9) are generally based on cost as prescribed by FERC tariffs.This Other retail. ...... (18,133)" (32,098) 13,965 43.5 category also includes changes in valuations of contracts that -Total Retail Sales 1,185,964 . 1,159,273 ' 26,691 2.3 have yet to settle, the sales from which will be recorded as Tariff-based'wholesale ....... 218,647 '195,428 , 23,219 11.9 tariff-based wholesale. Market-based wholesale ....... 161,796 .105,768 ,.56,028 53.0 Energy marketing... ...... 36,978 35,562 1,416 4.0 Market-based wholesale: Includes: (i) sales..of energy. to Transm ission( ). .............. 97,717 83,764 13,953 16.7 wholesale customers, the rates for which are~generally based Other ......... -.. : ........ .25,732- 25,948 (216) (0.8) on prevailing market prices as allowed ,by FERC approved Total.Sales '.....I .......... 1,726,834 '1,605,743 121,091 7.5 market-based tariff, or where not permitted, pricing is based on incremental cost plus a permitted margin and (ii) changes OPERATING EXPENSES:
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| in valuations for contracts that have yet to settle, the sales of Fuel and purchased power ..... 544,421- 483,959 60,462 12.5 which will be recorded as market-based wholesale. Operating and maintenance .... 473, 525 463,785 9,740 2ý1 Depreciation.and amortization.. 192,910 180,228 12,682 7.0 Enerjy marketing: Includes: (i) transactions based on market Selling, general and prices with volumes not related to the- production of our administratiye .... ......... 178,587 .7586 7171,001 4.4 generating assets or the demand of our retail customers; '(ii) Total Operating Expenses .... 1,389,443 1,298,973 90,470 7.0 financially settled products and physical transactions sourced INCOME FROM OPERATIONS. 337,391 306,770 30,621 10.0 outside our control area; (iii) feesý we earn for 'marketing OTHER INCOME (EXPENSE):
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| services that we provide for third parties; and, (iv) changes Investment earnings .......... 6,031 9,212 (3,181) (34.5) in valuations for contracts that have"yet to settle that are not Other income... .... : ... 6726 18,000: (11,274) (62.6) recorded in tariff- or market-based wholesale revenues. Other expense .... : ...... (14,072) (13;711)'.:, (361) (2.6)
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| Transmission: Reflects transmission revenues, incl6ding those Total Other (Expense)
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| Incom e ................ . (1,315) . 13,501 (14,816) (109.7) based on a tariff with the SPP. -
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| Interest expense .'*:.. 103,883 98,650 5,233 5.3 Other: Miscellaneous electric revenues including 'aicillary INCOME FROM CONTINUING service revenues and rent from electric property leased'to OPERATIONS BEFORE others. INCOME TAXES ' 232,193 221,621 10,572 4.8 Income tax expense ............ 63,839 56,312 7,527 13.4 Regulated electric utility sales are significantly impacted by NET INCOM E.."............... 168,354 .. 165,309 .3,045 1..8 such things as rate regulation,'customer conservation 'efforts, Preferred dividends ............ 970 970 -
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| wholesale demand, the economy of our service area 'and EARNINGS AVAILABLE FOR competitive forces. Our wholesale sales are impacted by, among COMMON STOCK ........... $ 167,384 1 164,339 $ 3,045 1.9 other factors, demand, cost and availability of fuel and purchased BASIC EARNINGS PER SHARE ..... $ 1.85 $, . 1.88 $ (0.03) (1.6) power, price volatility, available .:generation capacity arnd transmission availability. Changing *veather affects the n'amount toTransmission:Includes an SPPnetwork transmissiontariff.In 2007, our SPP of electricity our customers use. Hot summer'temperatures and network transmission costs were $82.0 million. This amount, less $9.2 million cold winter temperatures 'prompt more 'demand, especially. that was retained by theSPP as administrationcost, was returned to us as among our residential customers. Mild weather serves toreduce. revenue. In 2006, our SPPnetwork transmissioncosts were'$76.0 million with an administrationcost of $10.1 million retained by the SPP customer demand.
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| 28
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| Westar Energy I-2007 Annual Report The following fable.reflects changes in electricsales volumes, as fuel expense compared with 2006. Purchased'power expense measured bythodisands of MWh of electficify. No sales volumes increased $6.8 million over 2006 due primarilyto higher prices, are shown for energy marketing, transmission or other. Energy but were largely offset by a 4% reduction in purchased volumes.
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| marketing activities are unrelated to the amount of electricity In 2007 through the RECA, we deferred for future recovery we generate at our generatingplants. $26.7 million of fuel and purchased power costs as a regulatory Year Ended December 31, 2007 2006 Change %Change asset compared with $6.9 million in 2006.
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| (Thousands of MWh) Operating and maintenance, expense increased $9;7 million Residential.............. ....... ,677 6,456 221 3.4 compared to last year. This was due primarily to higher Commercial ...................... . 7,537 7,185 352 4.9 maintenance costs of $8.7 million for our power plants, electrical Industrial ... ................... 5,819 5,824 (5) (0.1) distribution system and transmission system and a $6.0 million Other retail ....................... 91. 93 (2) (2.2) increase in SPP network transmission costs that are in large part Total Retail ..................
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| * 20,124 19,558 , *.566 2.9 recovered through higher transmission revenues.
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| tariff-based-wholesale ......... ... 6,360 "5,505
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| - 855 15.5 Market-based wholesale . . .. .. 3,666 1.1913 1,753 91.6 Depreciation and amortization expense increased $12.7.million Total . ....... 3150 26,976' 3,174- 11.8 compared to last year. This was due principally to depreciation expense associated with a higher plant balance including the capital lease associated with the purchase of Aquila's 8%
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| Retail sales were $26.7"i'millibn higher for. the year ended leasehold interest in Jeffrey Energy Center.
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| December 31, 2007, due principally to increaseg in other irtail, commercial and residential sal~s."Other retail sales increased The $7.6 million increase in selling,. general and administrative
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| $14.0 million due primarily to decreases in refund obligations. expense was due primarily to a $6.2 million increase in employee Commercial aid residential sales increased'a comrbined $15.1 benefit costs and a $6.0 million -increase in labor Costs. This million 'due primarily to cooler weather, during the winter increase was partially offset by reduced legal fees associated
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| 'months, and customer growth in our service- territory. When with matters having to deal with former management.
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| measured by heating degree days, the we ýth'r during 2007 was 16% c6oler.than during .006. - Other income decreased $11:3 'Million compared to last year due primarily to our having $0.7million from COLI proceeds Tariff-based wholesale sales were $23.2 million higher than this year compared to0$16.4 million in proceeds from COLI last last year, due principally .to increased. sales volumes .that were year. Partially offsetting this decrease was $4.3 million of equity primarily the result of additional sales, from the long-term allowance for funds used during construction (AFUDC) for the sale agreement entered into in 2007 with Mid-Kansas Electric year ended December 31, 2007. We recorded no equity AFUDC Company, LLC. The average price per MWh for these sales, for the same period last year.
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| however, was' about' 3 % lower-than the same period last year. Income tax expense increased $7.5 million compared to last Market-based wholesale sales were $56.0 million higher than year due primarily to decreases in the utilization of previously last year,' due principally to. increased sales. volumes that were unrecognized capital loss carryforwards to offset realized capital primarily the result of,coal coriservation efforts and.a scheduled gains and decreases in non-taxable income from COLIL The refueling outage at Wolf Creek, both of which occurred last increase was partially offset by increased tax-benefits from the year and did not recir: this year: The 'average price per MWh utilization of a net operating loss that had not previously been for thege sales;, however,' was about 13 % lower than'the same applied against income for other carryback or carryover yeais.
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| period last year.
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| Fuel and purchased power expense increased $60.5 million compared .to' last year. The change in' fiel and' purchased power expense resulted from a number of'factors, indluding:
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| the volufueý of'power we produced and purchased, prevailing market priceý and contract provisions that "allow for price changeS: We used 12% more fuel in our generating plants in 2007, due primarily to our riot having had t6 conserve coal this year as'we'did last year. This resulted 'in $53.6 million higher 29
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| Westar Energy: I 2007 Annual Report 2006.Compared to 2005 ...... Year Ended December 31, 2006 '" ' - 2605'' -n-' iCh'ange 6y'Change BeloW we discuss our operating results for the year ended (Thousands of MVWh)
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| December 31, 2006, compared to the results for the year ended Residential............. . :..: ' 6,4 56 6;384 ' ' 72 1.1 Deceniber '31, 2005.'Changes in results of operations are as Commercial ............ ..... 7,185 `7,151 '," 34 0.5 5
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| follows. ' . Industrial ....................... 5,824 ,581"' ... 243 . 4.4 Other retail ..... -............ ... -- 93 101 - (8) (7.9)
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| Year Ended December 31, 2006 2005 Change %Change Total Retail .. ............. 19,558 " 19,217 341 1.8 (InThousands, Except Per Share Amounts)
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| Tariff-based wholesale. ............ 5,505 5,490 15 0.3 SALES:
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| Market-based wholesale ........... .1,913 2,950 (1,037)' (35.2)
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| Residential ............. $ 486,107 - $ "458,806 $27,301 6.0 Com mercial ................. 438,342 , A04,590 33,752 8.3 Total .......................... 26,976 27,657 (681) (2.5)
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| Ind ustrial .. . .............. 266,922: 242,383 24,539 10.1 Other retail ................. .(32,098) 376 (324474) The increase in retail sales reflects the change in rates, including Total Retail Sales ........... 1,159,273 1,106,155 53,118 4.8 the effect of implementing the RECA, and warmer weather.
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| Tariff-based wholesale ........ 195,428 185,598 9,830 5.3 When measured by. cooling- degree days, the weather during Market-based wholesale: ....... 105,768 145,875 (40,107)' (27.5) 2006 was 2% warmer than durihg 2005 and approximately 16%
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| Energy malketing ............. 35,562 46,842'ý 11,280) (24.1) warmer thait the" 20-year a(Vrage, The increase in industrial
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| -Transmission(,)............ 83,764 76,591 7,173 9.4 sales was. due' primarily to adqditional oil refinery ,load. The Other ..................... 25,948 ' .22,217 3,731' 16.8 change in other retail, sales, reflects the recognition in. 2006 of Total Sales. ............... 1,605,743 1,583,278 22,465 1.4 revenue subject to refund, of which: (i) $19.9 million is'due to OPERATING EXPENSES: the, difference between estimated fuel and purchased power Fuel and purchased power ..... ..483,959 528,229 (44,270) (84) costs billed.to our customers and actual.fuel and purchased
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| : Operating and maintenance .... 463,785 437,741, 26,044 5.9 power costs.. incurred forT our. Westar. Energy, customers; (ii)
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| Depreciation and amortization.. 180,228 150,520 29,708 19.7 $3.3 million.is due to amounts associated with a transmission Selling, general and delivery charge ,approved by the KCC in its 2005 Order; (iii) adm inistrative ..... ......... * . 171,001 " , 166,060 4,941 3.0, $4.0 million collected for property taxes in excess of.our.actual
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| - Total Operating Expenses'. t.. 1,298;973. 1,282i550 16,423' property taxes obligations; and (iv) $16.4 million related to 1.3 INCOME FROM OPERATIONS. . 306,770 ... 300,728 "'6,042 2.0 amounts We collected ir* rates related to terminal 'nt salvage OTHER INCOME (EXPENSE): that.the February 2007 KCC Order requires us to refund. The Investment earnings ....... 9,212 11,365 (2,153)' (18.9) revenue subject' to -refund was partially offset'by 'our having Other income ............... '18,000 9,948 8,052 80.9 stopped accruing' for rebates t6 customers'in December 2005.
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| Other expense .............. (13,711) (17,580) 3,869 - 22.0 We made tariff-based sales in 2006 at. an average price that
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| .Total Other Income ........ . 13,501. . 3,733 .9,768 261.7 was about 5% higher than the price of these sales in 2005. We Interest expense........... 98,650 109,080 .(10,430) . (9:6) attribute about $1.3 million, or, 14%, of the increase in tariff'-
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| INCOME FROM CONTINUING based wholesale. sales' to higher prices reflecting an adjustment OPERATIONS BEFORE; fof our fuel costs as permitted in FERC tariffs. ,,
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| INCOME TAXES .......... .,221,621 . 195,381*:., 26,240.. 13.4 Income tax expense ............. 56,312. 60,513, (4,201) (6.9) Our market-based wholesale sales and sales yolumes decreased INCOME FROM CONTINUING in 2006 due pnimarily to:our having conserved coal inventories, OPERATIONS ............... 165,309 134,868 30,441 22.6 but the average price per MWh that we received for,these.sales Results of discontinued in 2006 was about 7% higher than in 2005.
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| operations, net of tax ......... - 742 (742) '(100.0)
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| NET INCOM E................. 165,309 135,610 29,699 21.9 The change in fuel and purchased power expens&is the result of Preferred dividends ............ 970 970 - - changing volumes produced and purchased,. prevailing market EARNINGS AVAILABLE FOR prices and contract.provisions that allow for price changes. We COMMON STOCK ........... $ 164,339 $ 134,640 $29,699 22.1 burned about 4.%,less fuel in our gefnerating plants in 2006, due BASIC EARNINGS PER SHARE ..... $ 1.88 $ 1.55 $ 0.33 21.3' primarily to our haying conserved coal inventories. We also used less expensive generationt. In addition, during 2006 ,we deferred w Transmission: Includes an SPP network transmission tariff In 2006, our SPP as a regulatory, asset.$6.9. million for. the difference -between network transmission costs were $76.0 million. This amount, less $10.1 million the estimated fuel and purchased power costs that we billed that was retained by the SPP as administrationcost, was returned to us as revenue. In 2005, our SPP network transmission costs were $66.2 million with our KGE customers and our higher actual fuel and purchased an administrationcost of$5.5 million retainedby the SPP power costs that we are allowed to collect under the terms of Sb)Change greaterthan 1000%
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| the RECA. As a result, our fuel expense was $45.5 million lower in 2006 than in 2005. We also experienced a $1.2 million increase The following table reflects changes in electric sales volumes, as in our purchased power expense due primarily to our having measured by thousands of MfWh of electricity. No sales volumes purchased 9% greater volumes than in 2005.-
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| are shown for energy marketing, transmission or other. Energy marketing activities are unrelated to the amount of electricity we generate at our generating plants.
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| 30
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| Westar Energy 1 2007 Annual Report ............
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| We experienced an increase in our operating and maintenance -Thefair, market value of. energy marketing contracts increased expense due primarily to four factors: (i) the amortization of $20.9.million.:to,$41:5 million af'December'31, 2007. This was
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| $10.7 million of previously'deferred storm restoration expenses due primarily to favorable changes in marketvalues of contracts as authorized by the 2005 KCC Order; (ii)a $9:9 million increase entered into in 2007, in addition to contracts outstanding the, in SPP'network transmission costs; (iii) a $4.7 million increase in entire period.
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| taxes other than income taxes due primarily to higher property taxes; and (iv) an increase in maintenance expenses for outages Regulatory. assets, net of regulatory liabilities, increased .to at La Cygne and the'Gordon Evans Energy Center. These higher $533.8 million,at Decemberi31, 2007, .ftrom $476.0 million at expenses were partially, offset by a $5.4 million reduction in December 3,1,2006.Total regulatory assets increased $66.0 million the lease expense related to La Cygne unit 2. Operating and due primarily to the accumulation and deferral for future maintenance expense in 2005 included a $10.4 million -loss recovery of $53.8. million in costs related t0 restoring our electric as a result of the decrease in the present value ,of previously distribution-and transmission systems from dam.age,sustained disallowed'plant'costs associated with the original construction. as a result of the December 2007 ice storm,Also significantly con-tributing to, the increase in regulatory assets was a-$25.8 million of Wolf Creek due to the extension of the recovery period.
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| increase in fuel. costs deferred for future recovery. Total regulatory We experienced an increase in our depreciation and amortization liabilities increased $8.1 million to. $141.6 million due primarily expense of $29.7 million. This increase was due primarily to the to. a $14.4 million increase to mark-t97market gains recognized reduction of depreciation expense'of $20.1 million in ,2005. due on our coal supply contract for Lawrence and TecumsehEnergy to the establishment of a regulatory asset for the differences centers. Removal costs, ,indreased regulatory liabilities, an between the depreciation rates we used for financial reporting additional $11.8 miljion as a result of amounts collected and,.not purposes and the depreciation rates authorized by the KCC for yet spent to retire assets which we are not legally obligated to the period of August 2001 to March 2002. Provisions of the 2005 retire.The increases were offset due to our refunding f6 customers KCC Order allowed us to record this regulatory asset:'' $39.4rmillion, of w~hich $19.7'million was redofded asa regulatory" liability as 'of'December 31i 2006; -as required in-the Februar*
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| Selling, general and administrative expenses increased, due 2007KCC Order. " '.', , " .
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| primarily to increased employee pension and benefit costs. We increased our borrowings under the Westar Energy revolving Partially offsetting these increases were lower legal fees associated with matters having to deal with former, management and a credit facility.' As. a 'result.- our' short-term deb't -increased decline in insurance costs. $20.0 m illion. , ... .. ' . . ..
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| Other income increased due primarily to, COLI.,We received Iong7term debt, net of current maturities increased $326.5 million
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| $16.4 million in income from COLI in ,2006 compared ,to due principally tO the.issuance of $325.0 million of first mortgage
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| $7.2 million in 2005. Associated with our having terminated.an bonds as discussed in detail,in Note. 10 of the Notes. to accounts receivable sales facility, we experienced a $3.9 million Consolidated Financial Statements, "Long-Term Debt."
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| decrease in other expense. ,
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| Obligatid*di nd r'capital leases 'incre'as~d $111.5 milli6nr dte Interest expense decreased due primarily to a $16.7 million primaril"' t0 our' as sumirng Aquila's"8% le'asehold inter'est in reduction in interest expense 6 n long-term debt due primarily Jeffrey 'Energy Center as discuss6d in detail ih Note20.of the to a lower long-term debt' baance and lower interest rate' Notes t6 Consolidated Financial Statements, "Leases." '"
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| resulting from the refinancing activities discussed in detail in Other long-term liabilities increafsed $77.4 million due primarily
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| "- Liquidity and Capital Resources'- Debt Financifigs." This to, the, recognition ofuncertain tax liabilities, including interest, decline Was partially offset by. aft increase of $6.3 million"in pursuant to the adpptionýof FIN 48..
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| interest expense on short-term debt due to increased borrowirigs under our revolving credit facility. Common stock aitd ptaid-in (ca16i 'increIased $208.8' million due principally to the issuance of :7.6 million shares, of common The decrease in income tax expense is due primarily to the stock for', riet prodeed's of $193.8 million:through Sales Agency utilization of previously unrecognized capital loss carryforwards Financing Agreements with BN*YCMIandYa forward, sale to offset realized capital gains and increases in non-taxable agreem ent. - ,, *, -.. , .. -, . .; . ., ,:,
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| income from COLI. * ;*,
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| * 4* ':, '2 , . " * ' , ..
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| LIQUIDITY AND CAPITAL RESOURCES ','..
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| FNWANCIAL CONDITION * ," . , ' . .. .. ,.fl * ' .. * , .. . i Overview, *,
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| A number of factors affected amounts recorded on our balance sheet as of December 31, 2007, compared to December 31, 2006. We believe we will have sufficient cash to fund future operations; pay debt maturities and dividends.from a combination of'cash Inventories and supplies increased $44.6 million due primarily on hand, cash. flows from operations and access to debt,.and*
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| to a $30.6 million increase in coal inventory that resulted,largely equity capital markets.. Our available sources of funds include:
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| from our having placed into service additional railcars that cash, Westar, .nergy's revolving credit .facility 'arid access to' allowed for more frequent deliveries. capital markets. 'Uncertainties affecting our ability to meet these 31
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| ......... Westar Eriergy ' 2007 Annual Report cash requirements include, among others: factors affecting sales On April ,12, 2007, we entered into a Sales Agency Financing described in "Operating Results" above, economic, conditions, Agreement. with BNY Capital Markets, Inc. (BNYCM1). As regulatory actions, conditions in 'the capital markets and of July 12, 2007, we had sold $100.0 million of common stock compliance with environmental regulations. (3,701,568 shares) through BNYCMI, as. agent, pursuant to the agreement. We received $99.0 million in proceeds.net of a Capital Resources commission paid to BNYCMI equal to 1% of the sales' price of As of December 31, 2007, we had $5.8 million in unrestricted all shares it sold under the agreement. We used the proceeds cash ,nd, cash equivalents: In addition, Westar Energy, has a to. repay borrowings underf our revolving -credit,facility, which
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| $500.0 million revolving credit facility against which $180.0 million is the primary liquidity facility for acquiring capital equipment, had been borrowed and $45.5 million of letters of credit had and any remainder was used for working capital and general been issued. This left $274.5 million available'under this facility. corporate purposes..
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| On January 11, 2008, we filed a request with"FERC for authority to issue tshort-term 'securities and to pledge mortgage bonds On August 24, 2007, we entered into a subsequent Sales Agency in order to increase the size of our revolving credit facility to Financing Agreement with BNYCMI. Under'the terms of the
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| $750.0 million. On February 15, 2008, FERC granted our request agreement, we may offer and sell shares of our common stock and on February 22, 2008, a syndicate of banks in our credit from time to time through BNYCMI, as agent, up to an aggregate facility increased their commitments, Which in the aggregate of $200.0 million for a period of no more than three years. We total $750.0 million. As of February 22, 2008, $270.0 million had will pay BNYCMI a commission equal to 1% of the sales price of been borrowed and $55.0 million of letters of credit had been all shares sold under the agreement. As of December 31, 2007, issued, leaving $425.0 million available'undei this facility. we had sold $20.0 million of common, stock (783,745 shares) through BNYCMI. We received $19.8 million in proceeds net of The Westar Energy and KGE mortgages each contain provisions commission paid to BNYCMI. We used the proceeds to repay restricting the amount of first mortgage bonds that can be issued borrowings, under our revolving credit facility, which is the by each entity. We must comply with such restrictions prior to primary liquidity facility for acquiring capital equipment, and any the issuance of additional first mortgage bonds or other secured remainder was used for working capital and general -corporate indebtedness.' purposes. Pursuant to the same progiam, in the period January 1, 2008, through February 19, 2008, we sold an additional 75,177 The Westar 'Energy mortgage prohibits additional first mortgage shares for $1.9 million, net of commission.-
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| bonds from being issued, except in connection with certain refundings, unless Westar Energy's unconsolidated net earnings On November 15, 2007, we entered into a forward equity sale available for interest, depreciation and. property retirement agreement (forward sale agreement) with UBS AG, London (which as defined, does not include earnings or losses attributable Branch (UBS), as-forward purchaser, relating to 8.2 million to the ownership of securities of subsidiaries), for A-period of 12 shares of our common stock: The forward sale agreement consecutive months within 15 moriths 'preceding the issuance,, provides for the sale of our comm'oh stock within approximately are not less than the greater of twice the annual interest charges twelve months at a stated settlement price. In connection with
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| -on,and 10% of the principal amount of, all first mortgage bonds the forward sale agreement, UBS borrowed an equal number outstanding after giving effect to the proposed, issuance. In of shares of our common stock from stock lenders and sold the addition, the issuance of bonds is subject to limitations based on borrowed shares to J.. Morgan Securities, Inc. JPM) under the amount of-bondable property additions. As of December 31, an underwriting agreement among Westar Energy, JPM and 2007, based on an assumed interest rate of 6%, $408.0 million UBS Securities, LLC, as co-managers for the underwriters. The principal amount of additional first mortgage bonds could be underwriters subsequently offered the borrowed shares to the
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| *issued under the most restrictive provisions in the mortgage, public at a price per share of $25.25..
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| except in connection with certain refundings.
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| The use of a forward sale agreement allows us to avoid equity T;e ,KGE mortgage prohibits 'additional first. mortgage bonds market uncertainty by pricing a stock offering under then
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| ,from being isstied, except in connection with certain refundings, existing market conditions, while mitigating share dilution by unless KGE's net earnings before income; taxes and before postponing the issuance of stock until funds are needed. Except provision for retirement and depreciation of property for a in specified circumstances or events that would require physical period of 12 consecutive months within 15 months preceding share settlement, we are able to elect to 'settle the forward sale
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| -the issuance are not lessthan either '.two and one-half times agreement by means of a physical share, cash or net share the annual interest charges on, or 10% of the principal amount settlement and are also able to elect to settle the agreement of, all KGE first mortgage bonds outstanding after giving effect in whole, or in part, .earlier than the stated maturity date at
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| ,to the proposed issuance. In addition;the issu'iance of bonds is fixed settlement prices. Under a physical share or .net share subject to limitations based on the amount of bondable property settlement, the maximum number of shares that are deliverable additions.' As 'of December' 31, 2007, based "on, an assumed under the terms of-the' forward sale agreement is limited to interest rate: of 6%, approximately $820.1 million principal 8.2 million shares:'
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| amount-of *additionalKGE first mortgage bonds could be issued under the moit restrictive provisions in the mortgage.
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| 32
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| Westar Energy 1 2007 Annual Report .............
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| On December.28, 2007, we delivered 3.1 million newly issued In 2005,. we received cash primarily from the issuance of long-shares of our common stock tQ,UBS,, and received proceeds of term debt and we used cash primarily to retire long-term debt
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| $75.0 million as partial settlement of the forward sale agreement. and pay dividends.
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| Additienally,;on February 7, 2008;w6 delivered 2.1 million shares and received proceeds of $50.0 million as partial settlement of Future-Cash Requirements the forward sale agreement. Assuming gross share settlement Our business requires significant capital investments. Through of all remaining shares under the forward sale agreement,Iwe 2010,we expectwewill need cash.primarilyforutility construction could r'eceive additional aggegate proceeds of approximately programs designed to improve facilities,providing electric service;
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| $75.0 million, based on a forward Iprie of $24.25 per share for which include but are not limited' to expenditures for future 3.0 million shares. Proceeds from these'offerings were used to peaking capacity needs, construction of new transmission lines repay borrOwings under Our revel"ng credit facility, which is arid for, compliance with environmental regulations. We expect the pfiniray li quidity facility for acquiring capitals equipment, to meet these 'cash' ieeds with' internally generated cash flow,-
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| and a inemairider vws used for working cpital and general borrowings under Westar Energy's revolving credit facility and corporate purposes. through the issuance of.securities in the capital markets.
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| Cash Flows from Operating Activities We have incurred and expect to continue to incur material costs Cash flows from operating activities decreased $9.2 million to to comply with existing and future environmental laws and
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| $246.8 million in 2007,'from $256.0 million in 1006. During 2007, regulations, all of which are subject to changing.interpretations as compared to 2006,we paid approximately $48:3 million more and amendments. In addition, the current focus On the effect of air fOr natural gas used, in our power plants, $29.8 millihn more emissions on the global environment could result in significantly for coal inventory and $29.4 million more in customer refunds. more stringent laws and regulations or interpretations thereof Offsetting these amounts were a $10.1 million reduction in that could affect our company and'industry in particular. These La Cygne unit 2 lease payments, $9.0 million less in voluntary laws, regulations" and interpretations could' result in more contfibutions to our pension trust and cash realized from higher stiingent te-rms iri our existing operating permits or a failure to gross margins. During 2006, we also used $'65.0 million related obtain new permits, could cause there to be a material increase to the termination of our accounts receivable sales program. in our capital or operational costs and could otherwise have a material effecit oA'our operations. ' - ' '
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| Cash flows, from operating activities decreased $97.9 million to $256.0 million in 2006, from $353.9 million in 2005. During While we believe we, can generally recover environmental 2006, we used $72.4.million to pay Federal and,.state income costs through rate increases, there, is no guarantee.that we will taxes. and made a $20.8 million contributioni to our. defined be able to do so. In addition, we may be subject. to significant benefit -pension trust. During 2005, we used approximately fines and penalties in connection with the NSR Investigation or
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| $33.1 million for system restoration costs related to the ice storm Other matters, and such fines and penalties cannot be recovered that affected our service territory in January 2005. We received through rate infcrdases. '
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| $57.4 million in tax refunds during 2005.
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| Capital expenditures for 2007 and anticipated..capital expendi-Cash Flows used in Investing Activities tures for 2008, through 2010, including many environmental In. general, cash used for investing purposes relates to the costs and costs of removal, are shown in the following table.
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| Actual growth and improvement of our electric utility business. The 2007 2008 2009 2010 utility business is capital intensive and requires' significant investment in plant on an annual basis. We spent $748.2 million (InThousands) in 2007, $344.9 million in 2006 and $212.8 million in 2005 on net Generation:
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| additions to utility property; plant and equipment. This increase 'Replacements and other.... $ '45,271 $ 98,200 $136,800 " $133,100.
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| Additional capacity ...... .. ' 189,757 96,500 56,400 ',12,300 is due primarily to our having begun construction on several Wind generation ......... 79,195 205,000 ' - -
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| generation and transmission projects and our having purchased Environmental ........... 207,781 198,400 206,200 :259,000 other generating facilities'during 2007. Nuclear fuel .......... ' 38,168 ' 18,100 ' ''20,000 ;'".33,900 Cash Flows'used in Financing Activities Transmission ..... ........ 70,651 '148,100 228,600. . 165,900 Distribution:
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| We received net cash flows from financing activities of Replacements and other ..... 34,797 35,600 84,800 92,100
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| $502.8 million'in 2007. In 2007, proceeds from the issuanice of New customers ........... 60,521 57,000 .59,200 61,600 long-term debt provided $322.3 million ýnd proceeds from the Other .................... 22,015 31,300 28,300 23,100 issuance of common stock provided $195.4 million. We-used Total capital expenditures .. $748,156 *$888,200 $820,300 $ 781,000 cash' topay $89.5. million in dividends.
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| In 2006, we received net cash flows from financing activities of We prepare these estimates for planning purposes and revise
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| $12.8 million. In 2006, an increase in short-term debt was' the out estimates from time to time. Actual expenditures will principal source of cash flows from financing activities. Cash differ, perhaps materially, from our estimates due to'changing from financing activities was used to retire long-term debt and environmental requirements, changing costs, delays in engineer-to pay, dividends. ing, construction or permitting, and other factors discussed 33
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| ............. Westar Energy ] 2007 Annual Report above in "Item IA.. Risk Factors",We and our generating.plant 2008; a syndicate of banks in our credit facility increased their to-owners periodically evaluate these estimates, -and,this may commitments, which in the .aggregate total $750.0 million. As result in frequent and possibly material changes in :actual of February 22, .2008, $270.0 million had been borrowed and costs. In addition, these amounts do not include any estimates $55.0 million of letters of credit' had been issued, 'leaving for expenditures that may be incurred`ýs`a Te'*uit of' the NSR $425.0 million available under this facility._.-.,',.; ,
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| Investigation or for potentially new envirofimental requirements relating to merddii and CO emissions. ' Addefault by Westar Energy or KGE under other indebtedness totaling more than $25.0,million is a -default under this'fa'ibity.
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| Maturities of long-term debt as of December 31, 2007, are as Wetar Energy is required to 'maintain a consolidated indebtedness follows. ... . . . . to consolidated capitalizatioh ratio not greater than 65% at all Yeai times. Available liquidity un 'er the facility is not impacted by a
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| , ' ' Principal Amount S"'"' (InThousands) decline in Westar Energy's credit,ratings. Also,, the facility does 2008 .. .'.. . .. . .
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| 2.0.08
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| .. i.... ..' .. . .*.. .'. .. '. . . . .'.-' . .'. .'. -.. . $$ 55588 not contain a material adverse effect clause requiring Westar 2009 ..... ....... 145,684 Energy to represent, prior to each borrowing, that no. event 2010 .... . .. .. .. .. . .. .. .. .. . .. .. .. .. .. . .. .. .. .. . .. .. .. 633 resulting in a material adverse effect has occurred.
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| 20 11 " . . . . . N..........
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| .... 28 On June 1, 2006, we refinanced' $100.60 million of pollution Thereafter ... " . . . .. ' ". .'* ... ".1,746,243 control bonds, which* were t6 'n ature in 2031. We replaced this Total long-term debt maturities ....
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| ' . " $1,893,146 issue with two new pollution control bond seres of $50.0 nillion each. One series carries an interest rate of 4:85% and mniatures in Debt Finan.,cings. 2031. The second series carries a variable interest rate and also On August 14, 2007, KGE enteredinto ,a bond purchase mature's in'2036 '''' '"
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| agreement. for. the private.,placement of its firstmortgage On',iJanuary 17; 2006, we': repaid $100.0. million aggregate bonds.. Pursuant.. to the. agreement,, on,,October.,d5, 2007, principal' amount of 6.2% first mortgage'-bonds with cash on KGE issued $175.0 million principal amount of, 6.53% first hand and borrowings under'the revolving credit facility..
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| mortgage bonds maturing in. 2037 in a private placement to an institutional investor. Proceeds fromthe.offering were used Debt Covenants to repay borrowings under our revolving credit facility, which Sorie'of Our debt instruments contain restrictions that' require is the lpriffiary liquidity fa4llity for a'cquiring capital equipme,nt, us tb maintain leverage ratios as defined in the agreements. We and any remainder was used foE working capital4 and general calculate tlhese ratios in accordance with our credit agreements.
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| corporate purposes. .. " .....
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| These ratio6s are 'used solely to' d'termine compliance with our On May 16, 20.07, Westar Energysold $150.0 million aggregate various debt "covenants. We were in compliance,'with' these principal amount of 6.1% Westar Energy first.mortgage, bonds covenants'as of December 31, 2007.
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| maturing in 2047. Proceeds from the offering were used to CreditRatings repay borrowings, Uindier our' fevolving ciedit facility, which is Standard & Poor's Ratings Group (S&P), Moody's Investors the primary liquidity facility for acquining, capital equipment, Service (Moody's) and ''itcl Investors Service (Fitdlh) are and any remainder was used.for working capital and general indepenrdeht credit-ratihg*agencies that rate our debt securities.
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| corporate purposes.-'
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| These:iatirigs' indicate the 'agencies' assessment of our ability to On February 2, 2007, Westar Energy exercised its right to request pay interest and principal when due on our securities.ý a one-year extension of the termination date for the commit-ments, of the lenders under the reyolving credit facility dated In September 2007, S&P upgraded its credit ratings for Westar March 17,.2006. Effective March 16, 2007, $480.0 million of the Energy's first mortgage bonds/senior secured debt.securities. In commitments of the lenders under the revolving credit facility May 2006, Moody's upgraded its credit ratings for our.securities terminate on March 1-7, 2012. The remaining $20.0 million of the as shown in the table below and changed its outlook for our commitments terminate on March 17, 2011. So long as there is ratings to stable. In March,2006, Fitch upgraded its credit ratings no default or event of default under the revolving credit facility, for our securities as shown in the table below and changed its
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| ;Westar Energy may elect to extend the term of the credit.facility outlook for our ratings to"stable.- '' ' , . .
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| for 'up to aft additional year, subjeft to lender participation. The As of Februar 19, 2008, ratings with these agencies are ,as fa'cility allowý us to borrow up to an aggregate amount of shown in the table below.
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| $500.0. million, including letters of credit up to a maximum Westar Energy Westar Energy KGEFirst aggregate amount of_$150.0 million. On January 11, 2008, we First Mortgage Unsecured ., Mortgage filed a request with FERC for authority to -issue short-term Bond Rating Debt Bond Rating securities,:andto pledge mortgage bonds in .order'to increase S&P .... .......... . ,BBB , BB+. BBB the size. of our revolving credit facility to $750.0 million. On Moody's .... ,...8................... .Baa2 , Baa3 . ,Baa2 February 15; 2008, FERC granted our request and on February 22, Fitch ............................. . BBB BBB- .. BBB 34
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| Westar Energy I 2007 Annual Report In. general, less favorable credit ratings- make debt financing Contractual Cash Obligations. .-
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| more costly and imore difficult to obtain on terms that are The following table summarizes the, projected future cash economiclly .favorable'to us..Westar. Energy and KGE.have payments for our contractual obligations existing' as of credit rating- conditions under the, Westar Energy revolving December.31, 2007.
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| credit agreement that affect the cost of borrowing but do not trigger a default. We may enter into hew credit agreements'that *. ,2008.. 2009-2010 .,Total 2011-2012 Thereafter (InThousands) ...
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| contain credit conditions, which.could affect our liquidity and/or Long-term debt() .... $1,893,146 $, , 558 .$1.46;3.17.$ 28 $1,746;243 ourvborrowingcosts..":.. : . . ..
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| Interest on long-term Capital Structure ,
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| debt().... : ....... 2,069,862 103,934 197,466 187,070 1,581,392 As of December 31, .2007 and 2006,. our capital structure Adjusted long-term debt.... ,.. 3,963,008 ,104,492 343;783. 187,098 3;327,635 excluding short-term debt was as follows:.
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| Pension and
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| "" . , 2007 2000 post-retirement
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| '1 , , .'
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| benefit expected Common equity...: ............................... 49§ .%
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| . ' 49% contributionsc). 33,100 '33,100 . -
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| Preferred, stock. , . .. ....... . . . 1% 1% Capital leases' . 201-,230 17-;637 -132,335- 26,867 :124,391 Long-term debt .... ... ............................ 50% 50% Operating lersese)" 567,548 48,067 93,046 90,965.'ý' 335,470 Total ...... ......... ....... 100% 100% Fossil fuel(' ......... 1,596,217 269,661 396,597 358,511 571,448 Nuclear fuel* .... ':. 330,621 19,780 '50,73'6 i'3'49064: 225,201 Unconditional purchase OFF-BALANCE SHEET ARRANGEMENTS obligations ...... 608,235 489,780- '106,192 12,263:'2 -
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| Unrecognized income Forward Equity Transaction ,. . .tax benefits including interest(' ......... 4,946 4,946 On Novernber 15, 2007, we entered :into a forward sale Total contractual ,
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| agreement relating to 8.2. million shares of our common stock.
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| obligations, including .
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| The use of a forward sale agreement allowed us to avoid equity adjusted long-term . . ., ,
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| market uncertainty by pricing a stock offering under then current debt .......... $7,304,905 $987,463 $1,022,689 $710,608 $4,584,145 market conditions, while niiiigating share dilution by postponing (')See Note 10 of the Notes to Consolidated FinancialStatements,,'Long-Teri the issuance of stock until funds were needed. On December 28, Debt,"for individual long-term debt maturities.
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| 2007, we delivered 3.1 millioin newlyissued shares of our common (')We calculate interest on our variable rate debt based on the effective interest stock to UI3S, and received proceeds of $75.0 million as, partial rate as of December 31, 2007.
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| settlement of -the forward sale agreeriient. Additionally,: on "'Pension 'and post-retirement' benefit &xpected contributions represent the February. 7, 2008, we delivered 2.1 million shares and received minimum funding requirements under the Employee Retirement Incbme SecuritiesAct of 1974 plus additionalamounts as deemed fiscally appropriate.
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| proceeds. of $50.0 million as partial settlementof the forward These amounts forfuture periods are not yet:known. SeeNotes 12-2and 13 of sale agreement. Assuming gross share settlement of all remain- the Notes to ConsolidatedFinancialStatements "Employee Benefit Plans,"and ing shares under the forward sale agreement, we could ,receive Wolf Creek Einployee .Benefit Plans, for .additonal information regahrding additional aggregate proceeds of approximately $75.0 million, pensions.
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| *` Includes principal and'ihterest oh capitaltleases, including the 8% le tasehold, based on a forward price of $24.25 per share' for 3.0'million'shar&s.
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| interest.inJeffrey Energy Center that was pu'rchased in 2007. ' ' "
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| As of December;31, 2007, we, did not, have any additional off- le),Includes the La Cygne unit; 2"lease,,office, space, operating,facilities, office balance sheet-financing arrangements, other than our operating equipment, operating equipment, :rail . car leases and other, miscellaneous commitments.
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| leases entered into'in the. ordinary, course of business. For Y)Coal and naturalgas commodity and transportationcontracts , ,,.
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| additional information on our operating, leases, see Note 20 of WP Uranium concentrates, conversion, enrichment,fabrication and spent nuclear the Notes to Consolidated Financial Statements,"Leases." fuel disposal. ' " ' "
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| (')We have an additional $79.4 million of unrecognized incomý taif benefits, CONTRACTUAL OBLIGATIONS AND including interest, that are not included in this 'table' becau'se' "ecu'not COMMERCIAL COMMITMENTS reasonably estimate the' timing of the cash pamiyinnts':t6 "trxingauthoriiies assuming those unrecognized tax benefits are settled at the amounts recognized In the course of our business activities, we enter into a variety of pursuant to FIN 48 as of December 31,2007; ' -, " ' :
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| 7 obligations and commercial commitments. Some of these result in direct obligations reflected on our consolidated balance sheets Commercial Commitments, . ' :. .
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| while others are commitments, some firm and some based Our commercial commitments existing as of D cember 31,2007; on uncertainties,., not'reflected in our underlying consolidated consist of outstanding letteis of credit that expire iin 2008, sorhie financial statemients. The obligations listed below include of which automatically renew mannually. The letters of 'credit are amounts' for on-going needs for which contractual obligations comprised of $30.7 million related ,to our energy marketing and existed as of December 31, 2007. trading activities, $1.0.9 million related to worker's compensation and $4.9 million related to' other, Operating activities for a total outstanding balance of $46.5 million.
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| 35
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| ........ Westar Energy I 2007 Annual Report OTHER INFORMATION discussed in greater detail in Note 2 of the Notes to Consolidated Financial Statements, ",SUmmary of Significant Accounting Stock Based Compensation Policies-- RegulatoryAccounting." We believe that-it'is probable Effective January 1, 2006, we adopted SIAS No. 123R using the that our.;regulatori assets will be' recovered in the future.
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| modified prospective transition method. Since 2002, we have used restricted share unit§ (RSU) exclusively fqr our stock-based Asset Retirement Obligations ."
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| compensation awards. Given the characteristics of our stock-based Legal Liability ..
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| cormpensation awards, -the adoption of SIAS No. 123R did not In accordance with SIAS No. 143 and FIN .47, we have have a material impact on our consolidated results of operations. recognized legal obligations associated with the disposal of Total unrecognized compensation c0*st related to RSU awards long,-lived assets that result from the acquisition, 'construction, was $8.9 million as of December 31,2007. We expect to recognize develidomeht' or normal operation of such aslsets. Concurrent these costs over a remaining weighted-average period of' 2.4 with the recognition of thee'. liability, the estimýited c6st .of an years: Upon adoption of.SFAS No. 123R, we were required to asset retirement obligation is capitalized and depreciated 'over charge $10.3 million of unearned stock compensation against the remaining life of the asset.
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| additional paid-in capital.There were no modifications of awards We initially recorded asset retirement obligations at fair value for during the years ended.December 31, 2007, 2006 or 2005. the estimated cost to decommission Wolf Creek (our 47% sha'te),
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| Prior to the adoption of SFAS No. 123R, we reported all tax dispose. of asbestos insulating material at our power plants, benefits resulting from the vesting of RSU awards and exercise remediate ash disposal ponds and disp6se of polychlorinated of stock options as operating cash flows in the consolidated biphenyl (PCB) contaminated oil.
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| statements of cash flows. SFAS No. 123R requires cash retained As of December 31, 2007 and 2006, we have recorded asset as a result of excess tax benefits resulting from the tax deductions retirement obligations of $88.7 million and $84.2 mnillion, respec-in excess of the related compensation cost recognized in the tively.: For additional information on 0iir legal asset retirement financial statements to be classified as cash flows from financing obligations, see Note 15 of the Notes to Consolidated Financial activities in the consolidated statements of cash flows. Statements, "Asset Retirement Obligations." '
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| Pension Obligation: ".. "
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| ,,Non-Legal Liability - Cost of Removal We made an, $11.8 million voluntary pension 'contribution to We recover in rates, as a component of.depreciation,, the costs the Westar Energy pension trust in 2007. We currently expect to dispose of utility plant assets that" do. not represent legal to make a voiuu'itary contribution to the 'pension trust of an retirement obligatiohs As of December 31, 2007 and 2006, we estimated $15.2 million in 2008. We may make additional had $25:2 million and $13.4 million, respectively, in amounts contributions into. .the pension trust in 2008 depending on collected) but unspent, fot.remoyal costs classified as a regulatory how the funded status of the pension plan changes, regulatory liability. The net-amount related to non-legal retirement costs treatment for the contributions and' conclusions reached as canfluctuate based on amounts recovered in rates compared to there is m"r .re.cclarity with respect tO the.Pension Protection Act removal costs incurred. .
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| of 2006 (PPA). The United States Treasury Department is in. the process of developing implementation guidance for the PJpA; Guardian International Preferred Stock,',
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| however, it is likely.the'PPA will accelerateminimum funding On March 6, 2006, Guardian was acquired, by Devcon requirements beginning in 2009. We may choose to pre-fund International Corporation in a mergeir. In conrfection with this some 6f the anticipated required funding.' merger, we' received approximately $23.2 million for 15;214 shares of Guardian Series D preferred stock and 8,000 shares of Customer Refunds and Rebates Guardian Series' E'preferred stock-held' of record by us. 'We We refunded $39.4 million to customers in 2007 related to beneficially owned 354.4 sharesý of the Guardian 'Series D the remand of the 2005 KCC Order. We also made rebates to preferred stock and 312.9 shares of the Guardian Series E cusfomers.of $10.0 million during the"year ended December 31, preferred stock. We recognized .ý'a' gai,.,of , approximately 2006, in accordance with a July 25, 2003, KCC Order.
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| $0.3 million as a result of this trahs~ction.-Certain 'current and Impact of Regulatory Accounting former officers beneficially owned the remaining shares. Of We currently apply accounting standards that recognize the these shares" 14,094 shares of Guardian S6rie' D'prefered stock economic effects of rate regulation and record regulatory assets and 7,276 share's of Gudrctian Series E'preferred stock were and liabilities related to. our electric utility operations. If we beneficially owned by Mr. Wittig and Mr. Lake. The ownership determine that we no longer meet the criteria of SPAS No. 71, of'the shares beneficially owrned by either Mr. Wittig or Mr. Lake, we may have a. material non-cash charge to earnings. as well as related dividends, and now the cash received for the shares, is disputed and is the subject of the arbitration proceeding As of' December 31, 2007, w4 had recorded regulatory assets with Mr. Wittig and Mr. Lake discussed in Note 17, "Potential currently subject to recovery in f~ture rates of approximately Liabilities to David C. Wittig and DouglasT. Lake."As a result of
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| $675.5 millihon and regulatory liabilities 'of $141.6 million as this transaction, we no longer hold any Guardian securities.
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| 36
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| Westar Energy 1 2007 Annual Report New Accounting Pronouncements - Interest Expense.
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| We expect interest expense to increase significantly over the next SFAS No, 159 - The Fair Value Option for Financial Assets and Financial Liabilities several years as'we issue new debt securities to fund our capital e4lenditures program. We believe the increase in interest expense In February 2007, FASB released SFAS No. 159, "The Fair will be recovered from our customers in future rate proceedings.
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| Value Option for' Financial Assets and Financi'al l'iabilities -
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| Includting an amendment to FASB Statement No. 115."'SFAS Wholesale SalesMargins No. 159 permits entities to choose to measure many financial The terms. of the. RECA require that we include, as a credit to instruments and certain other items at fair value. A business recoverable fuel costs beginning in April of each year, an amount entity shall report unrealized gains and losses on items for based on the average of the margins realized from market-based which fair value option has been elected in earnings at each wholesale sales during the iinrriediatelyprior three-year period subsequent reporting date. SFAS No. 159 is effective for fiscal ending June 30. Effective April .1,2007, we'began crediting our years beginning, after November 15, 2007, with the cumulative retail customers an annual amount of $40,'million. Beginning effect of the change in accounting principle recorded-as an on April 1, 2008, we Will begin crediting our' retail customers adjustment. to opening retained earnings. We adopted- the an annual 'amount of: $51.5 millibn. If is possible that we will guidance effective January 1,. 2008. The adoption of SFAS not realize market-based wholesale sales mafgins at least equal No. 159 did not have a material impact on our consolidated to the' ainciunt of the credit. This would ad'ersely affect our financial statements. financial results."
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| SFAS No. 157 -- Fair Value Measurements In, September 2006, FASB released SFAS No. 157, "Fair Value ITEM 7A. QUANTITATIVE'AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Measurements." SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands -Our fuel procurement and energy marketing."activities involve disclosures about fair value measurements. SFAS No.. 157 ýis primary market risk exposures, including commodity price effective for fiscal. years beginning after ,November 15, 2007, risk, interest rate risk and credit. risk. Commodity price risk is with the cumulative effect of the change in accounting principle the potential, adverse pricei impact related to purchase or sell recorded as an adjustment to opening retained earnings..We of electricity and fuel pr6curement. for our generating-.units.
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| adopted the guidance effective January 1,' 2008. The adoption of Interest rate risk is the potential adverse. financial impact SFAS No. 157 did not have a material impact on our consolidated related to changes in interest rates., Credit risk is the potential financial statements. adverse financial impact resulting from non-performance by a counterparty of its contractual obligations.
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| FIN 48 - Accounting for Uncertainty in Income Taxes We adopted the provisions ofFIN 48, "Accountingfor Uncertainty Market Price Risks in Income Taxes - an Interpretation of FASB Statement No. 109" We engage in physical and financial trading activities with the as of January 1, 2007. The cumulative effect of adopting FIN. 48 goals of reducing risk from market fluctuations, enhancing was an increase of $10.5 million to the January 1, 2007, retained system reliability and increasing profits. We procure and trade earnings balance. electricity, coal, natural gas and other energy related products by utilizing energy commodity contracts and a variety of financial Allowance for Funds Used During Construction instruments, including forward and futures contracts, options AFLTDC. represents .the cost of capital .used to finance utility and swaps.
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| construction,. activity. AFUDC is computed by applying, a composite rate to qualified construction work in progress. The Prices in the wholesale power markets often are extremely amount of AFUDC capitalized as a construction cost is credited volatile. This volatility impacts our cost of power purchased and to other income (for equity funds) and interest expense (for our participation in energy trades. If we were unable to generate borrowed funds),on the accompanying consolidated statements an adequate supply of electricity for our customers, we would of income, as follows: attempt to purchase power from others. Such supplies are not always available. In addition, congestion on the- transmission Year Ended December 31, 2007 2006 2005 systefh-can limfit 6ur abilify-to make purchases from (or sell
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| ." II (InThousands) into), the wholesale markets. The inability tr6 mnake wholesale Borrowed funds.... ....... . ........ $ 13,090 '$ 4,053 $. 2,655 purchases'may require thaftx)e interrupt orcurtail services to our Equity funds. . ........... .. ..... ..... 4,346
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| * custofmers. Net ope'n'iositiofrs exist, of are established, due to Total; ..................... .. . $ 17,436 $ 4;053 $ 2,655 the o9igination of new trarisactionsý and our assessment of, and Average AFUDC Rates .. . * " 6.6% 5.3% '4: '2%* response' to, chahging market conditions. To the'extetit we have opefn positioiis, we are' exposed to changes in market prices.
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| We expect both AFUDC for borrowed funds and equity funds to Additional factors that affect our commodity price exp osure are fluctuate over the next several years as we add capacity, expand the quantity and availability of fuel used for generation and the our transmission system, make environmental improvements quantity of'electricity customers consume. The. availability and and begin to recover the related costs in rates. deliverability of generating fuel, including fossil and nuclear 37
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| ......... WestarEnergy 1 2007 An6ual Report fuels, can vary significantly from one period to the. next. Our credit risk control mechanisms that we believeare'appropriate, customers' electricity usage could also vary from year to year such as requiring counte~rparties to issue letters of credit or based on the weather or other factors. The loss of revenues .or parental guarantees iri,'.dr favor and entening ihto master higher costs associated with such conditions could be, material netting agreementý with counterparties that allow for dffsetting and adverse to our consolidated results of operations and. exposures. There can.be no assurance that the employment of financial condition. Our risk of loss is mitigated through the VaR, crdtit'piactic* or other risk managdmenf tools we employ use of the RECA and similar adjustment mechanisms that we will eliminate possible losses.
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| maintain for many of our wholesale salds contracts and tariffs.
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| Interest Rate Exposure Hedging Activity We have entered into various fixed and variable' rate debt In an effort to mitigate market risk associated with fuel pro- obligations. For details, see Note 10 of the Nctes to Consolidated curement and energy marketing, we may use economic hedging Financial Statements; "Long-Term Debt." We compute and arrangements to reduce our exposure to price~changes. We may present information about the sensitivity to changes'in interest use physical. contracts and financial derivative instruments to rates for Variable rate debt and current maturities of fixed rate hedge the.price of a portion of our anticipated fossil fuel.needs debt'by assuming a 100 basis point change in the current interest or excess generation sales. At the time we enter, into these rate applicable to such debt over the remaining time'the debt is transactions, we are unable to determine the hedge value until outstariding:
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| the agreements are actually settled. Our future exposure to changes in prices will be dependent on the market prices and We had approximately $452.5 million of variable rate debt and the extent and effectiveness of any economic, hedlgin.,aprrange- current maturities of fixed rate'debt'as of December 31,:2007. A ments into which we enter. . '100 basis point change in. interest rates' applicable to this debt would impact income before income taxes on an annualized Commodity Price Exposure. basis by approximately $4.5 million. As of December 31,2007, We manage ,and measure the market price risk exposure 'of our we.'had $271.9 million of variable rate bonds,.insured by bond trading portfolio using a variance/covariance value-at-risk (VaR) insiifers.. Interest rates payable under these'.,bonds are-set 'at model. In, addition to VaR, we employ ýadditional, risk control periodic auctions. Recent conditi6ns in the credit markets have processes such as stress testing, daily loss limits, credit limits decreased the demand of'auction 'bonds. generally and'.have and position limits. We expect to use similar control processes caused our borrowing costs to increase. Additionally; 'should in '2008. The user of VaR requires assumptions, including the those bond insurers'experience a decrease in credit 'ratin'g, such selection of 'a confidence level for potential losses and 'the event would most likely increase our boriowing costs as well.
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| estimated holding period. We express VaR as a potential dollar In addition, a decline in interest rates generally can serve to loss based on a 95% confidence level using a one-day holding increas'e our pension and post retirement 6bligatins and affect period. It is possible that actual results may differ m'arkedly investment returns.
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| from assumptions. Accordingly, VaR may not accurately reflect our levels of exposures. The energy trading and market-based Security Price Risk wholesale portfolio VaR amounts for 2007 and 2006 were We maintain trust funds, as required by the NRC and Kansas state as follows:-.' laws, to fund certain costs of nuclear plant decommissioning.
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| As of December 31, 2007, these funds were comprised of 70%
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| 2007 2006 equity securities, 27%' debt securities and 3% sash a'id 'cash (InThousands) eqivibalents.The fafr value of these funds was $122.3 million as of High ...... ......................... ........ .. $ 1,966 $ 2,178 L ow.......... ...... .. ............. ......... .. 176 ' 449 Decermbei 31,'2007, and $111.1'million as of December 31,2006.
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| Average .... ......... 639 . 1,089 By *ma`intaining a diversified portfolio of securities, we seek to maximize the returns to fund the decommissioning obligation We have considered a variety of risks and costs associated with within alceptable risk toleranices.' However, debt and equity the future contractual commitments included in our trading securities in the portfolio are exposed to price fluctuations'in the portfolios. Th6se risks include valuation and marking of illiquid capital markets. If the value of the securities diminishes, the cost pricing locations and products, interest rate movement and the of funding the.obligation rises. We actively monitor the portfolio financial condition of our counterparties.: We may use swaps or by benichmarking the performance of the investments against other financial instruments to manage.in,terest rate risk. We have relevant indices and by maintaining and periodically reviewing exposure to counterparty, default risk with, our retail, wholesale the asset allocation in. relation to established policy targets.
| |
| and energy marketing activities,. including participation in Our exposure to equity price market risk is, in part, mitigated regional transmission organizations.;We maintain credit policies becamie we' are *urrently allowed to recover decommissioning intended-to reduce overall credit risk..We employ additional costs in the rates we charge our customers.
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| L 38
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| | |
| Westar Energy 112007 Annual Report ............
| |
| ITEM 8. FINANCIAL STATEMENTS AND MANAGEMENT'S REPORT ON . . .. .
| |
| SUPPLEMENTARY DATA INTERNAL CONTROL OVER FINANCIAL REPORTING We are responsible for establishing and maintaining adequate TABLE OF CONTENTS PAGE internal control over financial reporting.: Internal control.over Management's Report on Internal Control financial reporting is defined in Rules 13a-15(f) promulgated Over Financial Rep0ting ............... ... 39 under'the Securities Exchange Act of 1934 as a6rocess designed by, or under the supervision of, thecompany's principal executive.
| |
| Reports,of Independent Registered Public.
| |
| and principal finandial officers and'-effected bý the cormpany's Accounting Firm '.. 40 board Of'directors, management and other persohinel, to provide Financial Statements: reasonable 'assurance regarding the reliability of financial reportingand the preparation of financial statements for exftiml Westar Energy, Inc: and Subsidiaries: purposes in accordance with generally accepted accounting Consolidated Balance Sheets, as of principles and includes those policies'and procedures that:
| |
| December 31, 2007 and 2006'........... 42
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| * Pertain to the maintenance of records that in reasonable detail' Consolidated Statements of Income. accurately and. fairly reflect, the transactions aid dispositions for the years ended'December 31, 2007, :
| |
| of the assets of the company; , . .
| |
| 2006 and 2005 ..........
| |
| , 43 " Provide reasonable assurance that transactions are recorded Consolidated Statements of Comprehensive~ as 'necessary 'to l&eAm'it pr~paration'of'finiancial statenrfent' in Income-for the years ended accordance' with, gendrally accepfed 'accounting principles, December 31, 2007, 2006 and 2005 .............. 44 'and..thatfreceiptsand expenditures'of-the company are being Consolidated Statemfents of Cash'Flows" made only iri accordance With 'authorizations of management for the years ended Decemiber:31j 2007,' and directors'of the'cofnpany; and
| |
| * 2006 and 2005 ..... ' ..... '.. 45 m Provide reascriablei aisurance regardirng prevention or timely Consolidated Statements of Shareholders'.-., detection "of un'auth'orized aciquiisition; use or disposition of Equity for the years ended December 31, the 'company's assefs'that could'have a material effect'on'the 2007,. 2006 and 2005 ....... 46 financial 6tatements:' ' ' ' . ' '
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| Notes to Consolidated Financial Statements......': 47 Because of its inherent limitations, internal control over financial Financial Schedules: ............................ reporting may not prevent or detect misstatements, -Projections of any evaluation of effectiveness to future periods are subject to Schedule 11-Valuation and Qualifying Accounts . .: 79 the risk that' controls' may' become inadequate becau'e of, changes in'i cdnditions,'or that the degree of co'mpliance with the SCHEDULES OMITTED policies or'procedure's may deteriorate. .
| |
| The following schedules are omitted because of the absence of We assessed the effectiveness of;. our. interal control over the conditions under which they are requ'red or the information financial reporting as of December 31, 2007. In, making this is included on our consolidated, financial statements and assessment, weused the. criteria set forth by the Committee of schedules presented: .
| |
| Sponsoring Organizations of, the. Treadway,. Commission in I, III, IV, andV. Internal. Control-Integrated Framework. Based on the assess-ment, we believe. that; as of December 31, 2007, our internal control over financial. reporting is effective based on those criteria. Our independent registered public accounting firm has issued an audit report on the company's internal control over financial reporting.
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| 39
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| | |
| ............. Westar Energy I 2007 Annual Report REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Westr Energy, Inc.
| |
| Topeka, Kansas We have audited the internal control over financial reporting of (2) provide reasonable assuriance that transactions are recoided Westar Energy, Inc. and subsidiaries (the "Company") as of as necessary to permit. preparation of financial statements in December 31, 2007, -basedz on criteria established in -Internal accordance with generlly accepted acc6urting principles, and Control - Integrated Framework issued by the Committee of that receipts and expenditures of the company are being made Sponsoring Organizations of the Treadway Commission. The only in accordance with authorizations of managemenit.an.d Company's management is responsible for maintaining effectiye directors of the company; and (3) provide reasonable assurance internal control over, financial reporting and for its assessment regarding prevention or timely detection of unauthorized of the effectiveness of internal contrql over financial reporting, acquisition, use, or disposition of the company's assets that including the accompanying management's report on internal could have a material effect on the financial statements.
| |
| control over financial reporting. Our responsibility is to express aii opinidih on tlie"Company's internal control over financial Because of the inherent limitations bf, irterrial control over reporting based on our audit. financial reporting, 'including the 'possibility of collusion or improper management override of controls, material misstate-We conducted our audit in accordance with the standards of the ments due to error or fraud may not be prevented or detected on Public Company Accounting Oversight Board (United States). a timely basis. Also, projections of any evaluation of the effec-Those standards require that.we plan and perform. the audit to tiveness of the internal control over financial. reporting to future obtain reasonable assurance about whether effective*internal periods are subject to the risk that controls may become control over financial reporting was maintained inmall material inadequate because. of changes in conditions, or that the degree respects. Our audit included obtaining, an. understanding of of compliance with the policies or procedures may deteriorate..
| |
| internal control over financial reporting, assessing the risk that a material weakness exists, testing. and.evaluating the design and In our opinion, the Company maintained, in-all material respects, operating effectiveness of internal control based on the assessed effective internal control'over financial reportingas of December 31, risk, and performing such other procedures as we considered 2007, based on the criteria established in Internal Control -
| |
| necessary in the circumstances. We' believe'that our' auidit Integrated Framework issued by the Committee of Sponsoring provides a reasonable basis for our opinion. . Organizations of the Treadway Commission.
| |
| A company's internal control over financial reporting is a process We have also- audited, in accordance with the standards of the designed by, or under the supervision of, the company's principal Public Company Accounting Oversight Board (United States),
| |
| the consolidated financial statements and financial, statement executive and principal financial officers, or persons performing similar functions, and effected by the company's board of schedule as of and for the year ended December 31, 2007 of the directors, management, and other personnel to provide reason-' Company arid our report'dated February 28, 2008 expressed an able assurance regarding the reliability of financial reporting unqualified opinion on those financial statements and financial and the preparation of financial statements for external purposes statement schedule and included explanatory paragraphs regarding in accordance with'generally accepted accounting principles. A the Company's adoption of new accounting standards.
| |
| company's- internal control over financial reporting includes Is! Deloitte & Touche LLP those policies and procedures that (1) pertairi to the maintenance of records that, in reasonable detail, accurately and fairly reflect Kansas City, Missouri the transactions and dispositions of the assets of the company; February 28, 2008 40
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| | |
| Westar.Energy 1.2007 Annual Report. ...........
| |
| REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the. Board of Directors and Shareholders of Westar Energy, Inc.
| |
| Topeka, Kansas We have audited the accompanying consolidated balance sheets United States of America. Also, in our opinion, such financial of Westar Energy, Inc. and subsidiaries (the "Company") as of statement schedule; when considered in relation'to the basic December 31, 2007 and 2006, and the related consolidated consolidated financial statements taken as a whole, presents statements of income, comprehensive income, shareholders' fairly, in all material respects, the information set forth~therein.
| |
| equity, and cash flows for each of the three years.in the period ended December 31,2007.' Our audits also included the financial As discussed in Note 2 to the consolidated financial statements, statement schedule listed in the Index at Item 15. These financial the Company adopted Financial Accounting Standards. Board statements and financial statement schedule are the responsi- (FASB) Interpretation No. FIN 48, "Accounting for Uncertainty bility of the Company's management. Our responsibility is to in Income Taxes -- an interpretation of FASB Statement No.109" express an opinion on these financial statements and financial as of January 1, 2007T statement schedule bas'ed on our audits. As discussed in Note 12 to the consolidated financial statements, We conducted our audits in accordance with the standards of in 2006, the Company adopted Statement of FinancialAccounting the Public Company Accounting Oversight Board (United Standard No. 123(R), "Share-Based Payment,"and Statementfof States). Those standards require that we plan: and perform the Financial Accounting Standard No. 158,"Employers'Accbunting audit to obtain reasonable assurance about whether the financial for Defined Benefit Pension and' Other Postretirement Plans."
| |
| statements are free of material misstatement. An audit includes We have also audited, in accordance with the standards of the examining, on a test basis,,evidence supporting the amounts Public Company Accounting Oversight Board (United States),.
| |
| and disclosures in the financial statements. An audit also the Company's internal control over financial reporting as of includes assessing the accounting principles used and significant December 31, 2007, based on the criteria established in Internal estimates made by management, as.well as evaluating the 'Control - -Integrated Framework issued by the Committee of overall financial statement presentation. We believe that our Sponsoring Organizations of the Treadway Commission and audits provide a reasonable basis for our opinion. our report. dated February 28, 2008 expressed an unqualified "
| |
| In our opinion, such consolidated financial statements present opinion on Company's internal control over financial reporting.
| |
| fairly, in all material respects, the financial position of Westar Energy, Inc. and subsidiaries as of December 31, 2007 and 2006, Is/ Deloitte &Touche LLP and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in Kansas City, Missouri conformity with accourting principles generally accepted in the February 28, 2008 41
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| | |
| ....... WestariEnergy Iý'.2007 Annual,Report MECYAD CRIC01-- IRW A-fK1Cr%1 lrA'rCr% DAI ARld-C CLICE C ý ý'_ : , 1:
| |
| As of December 31, 2007 200f (Dollars in Thousands)
| |
| ASSETS CURRENT ASSETS:
| |
| Cash andcash equivalents ............................. .............................. $ 5,753 $ 18'196 Accounts receivable, net of allowance for doubtful accounts - .
| |
| $5;721 and $6,257, respec vely ................................... '179,859
| |
| .of
| |
| ................ 195,7 5 In-zentories and supplies net .. d: Y)'" .... .".. . . 192533 147,930 Energy marketing contracts . .......... ............... .... '57,702 67,267 Tiixes receV able . ... .... ...... 71...........................,.......
| |
| 71,111, 15,142 Deferred tax assets .... ..
| |
| 853 Prepaid expenses . .. . .. .' . .. ....................... ... 31,576 29,620 Reguilatoryassets '......... ............. 98,204 S -58,777 O ther ................................ .................. . 15, 15,0115
| |
| : 5. 19,076 Total Current Assets 667,679 536,720 PROPERTY, PLANT AND EQUIPMENT, NET ........... ......................................... 4,803,672 4,071,607 OTHER ASSETS:. * . .. , ... . . . . . . . . ....
| |
| Regulatory assets ,., ............. 77,256 55d,703
| |
| *Nuclear decommissioning ,rust. . . .................... .. : 122;298 111,135 Energy marketing contracts ...................................... 34,088 11,173
| |
| .,.!:O ther _,.. . ............... ............................. 190,4 37 173,837 i Total Other Assets . . ..... ...... . ........ .. .. . ........ 924,079 846,848 TOTAL ASSETS. .......... "................. .... '.'. . . ... ...... .... ... $6,395,430 $ 5;455,175 LIABI'ITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: . B , "
| |
| Current maturities of lonrg 2 term debt. ,'. ;. ,.".."." .. $ 558 Short-term.debt ::ý ......... :o ....... ... .............. 180,000
| |
| .-Accounts payable ..- , ... ,.. . ..... ....... ....... .... 278,299 150,424, Accrued taxes ................................................................. 47,37 102,219 57,281 Energy marketing contracts ................... ........................................ 42,641 Accrued Aiinterest cc ter u ste .. ... .. .. ................ ...... . .............. =................. ..- 4 1,4 16 41,416. 32,928 Deferred tax liabilities ............................................ ........ 2,310 Regulatory liabilities ................... ý.i ........ ..... 32,932 49,836 Other ........................ . . ,. :. ....... . .. , ,119 237 ,*.
| |
| :. .110,488 Total Current Liabilities ............................... ........................ 744,763 663,176 LONG-TERM LIABILITIES:
| |
| Long-term debt, net .......... : ....... ......... ................ : ...................... 1,889,781 1,563,265 Obligation under capital leases....... ............ ................... 123,854 12,316 Deferred incom e taxes ................................................................ 897,293 906,311 Unamortized investment tax credits.................................................. 59,619 61,668.
| |
| Deferred gain from sale-leaseback ............ "......................................... 119,522 125,017 Accrued employeebenefits ....................................................... 283,924 246,930 A sset retirem ent obligations ........................................................... 88,711 84,192 Energy m arketing contracts ................... : ................ .......... ............... 7,647 534 Regulatory liabilities ................................................................... 108,685 83,664 Other.................................. ..................................... 217,927 140,536 Total Long-Term Liabilities ........................................ ......... 3,796,963 3,224,433 COMMITMENTS AND CONTINGENCIES (see Notes 14 and 16)
| |
| TEM PORARY EQUITY (See Note 12) ......................................................... 5,224 6,671 SHAREHOLDERS' EQUITY:
| |
| Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares .............................................. 21,436 21,436 Common stock, par value $5 per share; authorized 150,000,000 shares; issued 95,463,180 shares and 87,394,886 shares, respectively .............................. 477,316 436,974 Paid-in capital.................... ............. I .. .................................. 1,085,099 916,605 R etained earnings ................. .................................................... 264,477 185,779 Accumulated other comprehensive income, net ............................................ 152 101 Total Shareholders'Equity ...... .................................................... 1,848,480 1,560,895 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY .............................................. $6,395,430 $5,455,175 42 The accompanying notes are an integral part of these consolidatedfinancial statements.
| |
| | |
| Westar Energy.. I 2007, AnnuahReport ............
| |
| WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF INCOME . .. '... .
| |
| Year Ended December 31, .. 2007 2006 ., '. ,2005 (Dollars in Thousands, Except Per Share Amounts)
| |
| SALES...................................... .............. $1,726,834 $ 1,605,743 $ -.1;583,278.
| |
| OPERATING EXPENSES:
| |
| Fuel and purchased power................................. 544,421 'A:483,959 - " '.528,229 Operating and mainterfance .................. ................... 473,525 .. " . 463,785 , .. - 437,741 Depreciation and amortization ................ ...................
| |
| * 192,910 . ....;180,228 *.: :',*." ,150,520 Selling, general and administrative ............ .............. 178,587 .. ., . 171,001 , 166,060 Total O perating Expenses ..................................... 1,389,443 .,. 1298,973 . . 1,282,550 INCOM E FROM OPERATIONS .. ......................................... 337,391 306,770 ' 300,728 OTHER INCOME (EXPENSE):...........
| |
| 6,031 ... .9,212 ' ,.,',:. ' - 1,-1,365,
| |
| ,Investment earnings. . . ........... .....
| |
| Other incom e ................................................. 6,726 18,000 9,948 Other expense ................................................. (14,072) (.13,711) (17,580)
| |
| Total Other (Expense) Incom e .................................. (1,315) 13,501 3,733 Interest expense................ 103,883 98,650 109,080 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES ......... 232,193 221,621 195,381 Income tax expense . 63,839 56,312 60,513 INCOME FROM CONTINUING OPERATIONS ............................. 168,354 165,309.. '134,868 Results of discontinued operations, net of tax .......................... - -- 742 NET INCOME ............................ ................ 168,354 165,309 135,610 Preferred dividends 970 970 970 EARNINGS AVAILABLE FOR COMMON STOCK......................... $ 167,384 $ 164,339 $ 134,640 BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (SEE NOTE 2):
| |
| Basic earnings available from continuing operations .............. $ 1.85 $ 1.88 $ 1.54 Discontinued operations, net of tax.......................... - -- 0.01 Basic earnings available ......................................... $ 1.85 $ 1.88 $ 1.55 Diluted earnings available from continuing operations ............ $ 1.83 $ 1.87 $ 1.53 Discontinued operations, net of tax.......................... - 0.01 Diluted earnings available ................................ $ 1.83 $ 1.87 $ 1.54 Average equivalent common shares outstanding ...... : ................ 90,675,511 87,509,800 86,855,485 DIVIDENDS DECLARED PER COMMON SHARE ...................... $ 1.08 $ 1.00 $ 0.92 43 The accompanyingnotes are an integral part of theseconsolidatedfinancial statements.
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| | |
| ............. Westar Energy I 2007. Annual.Report WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME,'
| |
| Year Ended December 31, 2007 2006 . 2005 (Dollars in Thousands)
| |
| NET INCO ME ............. ... ................. ...... $ 168,354 $ '.165,309 $ 135,610-
| |
| .OTHER COMPREHENSIVE INCOME (LOSS):
| |
| Unrealized holding gaini(loss) on' marketable securities arising during the period ......... " ............... 51 . *(57) .'. 45 Minimum pension liability adjustment ................. "v- - *31,841 '., (68,321)
| |
| Other comprehensive income (loss), before tax .............. 51 31,784 (68,276) N Income tax (expense) behefit related to items '
| |
| 27,176 I
| |
| of other comprehensive income .......... ... .............. (12,666), .
| |
| Other comprehensive income (loss), net of tax ................ 51 19,118 ... . .(41,100)
| |
| COMPREHENSIVE INCOME ................ $ 168,405 $ 184,427 $ 94,510 44 The accompanying notes are an integralpart of these consolidatedfinancial statements.
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| | |
| Westar Energy 1, 2007.Annual Report ............
| |
| WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2007 2006 . 2005 (Dollarsin Thousands)
| |
| CASH FLOWS FROM'(USED IN) OPERATING ACTIVITIES:
| |
| Net income ......................... .............. $ 168,354 $ 165,309 $ 135,610 Adjustments to reconcile net income to net cash
| |
| , .; provided by operating activities:
| |
| Discontinued operations, net 4 tax ........ (742)
| |
| Depreciation and am ortization ...................................... 192,910 180,228 150,520.
| |
| * Amortization of nuclear fuel ................................. 16,711 13,851 13,315' Amortization ofdeferred gain from sale-.easeba'ck .... .... ...... (5,495) (5,495.)- .(8,469)
| |
| Amortization of corporate-owned life insurance ........................ 13,693 .16,265
| |
| .15,336..
| |
| 3,219*
| |
| N on-cash com pensation .......................................... 5,800 3,389 Net changes in energy marketing assets and liabilities .................... 7,647 (7,505) 5,*799 Accrued liability to certain former officers....... ................. 931 3,813 2,018 Gain on.sale of utility plant and property ... :. ............. (570)
| |
| Net deferred income' taxes and credits............. .... ... 14,084 (4,203) .25,552, Sfock based compensation excess tax benefits ........... ...... ........ (1,058),- (854)
| |
| Allowance for equity funds useld duifnfg .con1strucion. (4,346)
| |
| .Changes in working capital items,-nef of acquisitions and dispositions:
| |
| A ccounts receivable................ ........... .......... : .............. (15,926) (55,148) (32,179)
| |
| Inventori&4 and supplies . .......................................... (44,603) (46,112) " 22,745
| |
| " Prepaid expenses and other ........... . .................... ...... (72,212) (4,095) (65,635)
| |
| A ccounts payable .... ............................... ............... 59,488 22,625 6,929-A ccrued taxes ............................. : ........... "...
| |
| Other current liabilities ................. ... (50,027) (13,160) 91,938 (50,179) (5,708) . (20,876)
| |
| S'20,374 Changes in other assets.......... (54,668) 19,412
| |
| .Changes in other liabilities ............ .......... ....... 65,712 (25,127) ý(12,492)
| |
| Cash flo1/2sý from operating activities 246,816 255,986 353,891 CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
| |
| Additions to property, plant.and equipment " (748,156) (344,860) (212Z814)
| |
| ,4,346 Allowance for equity funds used during construction .........................
| |
| Investment in-cdrporate-owned life insurance ........... ... .. (18,793) (19,127) (19,346)
| |
| - Purchase of securities within the nuclear decommissiohifig trust fund .. -(240,067) (345,541) (372,426)
| |
| * 'Sg.fe'ofsecurities within the nuclear decommissioning trust fund .......... 238,414 341,410 367,570 Proceeds from investment"-in corporate-o'wried life insurance " 544 22,684 10,997 Proceeds frtorm sale of plant and property . . -- 1,695' -.
| |
| Proceeds froffi other investments .................. . 1,653 53,411 13,990 Cash flows used in investing activities. .". . ".. (762,059) (290,328) (212,029)'
| |
| CASH FLOWS FROM-(USED iN) FINANCING ACTIVITIES:
| |
| Short-term debt, net ........... .......... ...................... .. ....... 20,000 160,000 . .
| |
| Proceeds froin long-term debt ...... ...................... ............. 322,284 99,662, , 642,807.
| |
| .Retirem*nts'of long-term debt. .................... .. .........
| |
| E (25) .(200,000) (741,847)
| |
| Repayment of capital leases......... ... ........................... (5,729) ,.(4,813) (4,898)'
| |
| Borrowings against cash surrender value of corporate-owned life insurance .... 61,472 59,697 58,039 Repayment.of borrowings against cash surrender value of corporate-owned life insurance......................... (2,209) (24,133) (13,026)
| |
| Stock based. compensation excess tax benefits ...................... ..... 1,058 854 -
| |
| Issuance of common stock, net ................... 195,420 2,394 5,584 Cash dividends paid................................... ...... (89,471) (80,894) (74,593)
| |
| Cash flows from (used in) financing activities ... ................ 502,800 12,767 (127,934)
| |
| CASH FLOWS FROM DISCONTINUED OPERATIONS:
| |
| Cash flows from.investing activities .. ........... . -- . 1,232 Cash from discontinued operations. ................ ......... -- 1,232 NET (DECREASE) INCREASE INCASHAND CASH EQUIVALENTS. ............. (12,443) (20,343) 13,928 CASH AND CASH EQUIVALENTS:,
| |
| Beginning of period ................ I .......................... 18,196 .38,539 24,61.1 End of period .. .................... I.....
| |
| ........................ . $ 5,753 $ 18,196 $ 38,539 45 The accompanyingnotes are an integral part of these-consolidatedfinahcialtstatements.
| |
| | |
| .......... Westar Energy I 2007 Annual Report WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Accumulated Cumulative . other - Total preferred Common Paid-in Unearned' Retained comprehensive Shareholders' stock stock , capital compensation earnings (loss) income Equity (Dollars in Thousands) . -
| |
| Balance at December 31, 2004 ............ $ 21,436 $430,149 $ 912,932 - $(10,361) $ 55,0531- '1$,` 113 . $1,409,322
| |
| ,135,610'. 135,610 N et incom e .......................... 11 2 "1r71 Issuance of common stock, net .......... 4,028..., 10,1~1 .-. - 17,199 Preferred dividends, net of retirements ... - 'iyIu) (970)
| |
| Dividends on common stock ............ "- (79,706) (79,706)
| |
| Grant of restricted stock ................ 2,986 (2 986) . - .-.
| |
| Amortization of restricted stock ......... -- 3,019 3,019 Forfeited restricted stock ............... 71 -- 71 Stock compensation and tax benefit. (6,006). . . , .. . .. ... 7 ,(6,006)
| |
| Unrealized gain on marketable securities ......................... -.. " ,. -. , 45 45 Minimum pension liability adjustment ... .. (68,32.1) (68,321)
| |
| - .. 7,17.. 2,17 Income tax benefit .................... "<. --... . . ... . - -. " .. : . ' -- , : 27,176 ' 27,176 Balance at December 31, 2005 ........... 214436 434,177, 923,083 (10,257) '109,987 (40,987) '1,437,439 N et incom e .......................... 2,.97.- 165,309 - , 165,309 Issuance of common stock, net ........... 2,797 9,585. . . .--.. ,, 12,382 Preferred dividends, net of retirements ... (970) (970)
| |
| Dividends on common stock ............ - -- . . .... . , (88,547) (-88,547)
| |
| Reclass to Temporary.Equity ............. - -- -- (6,671) --. - (6,671)
| |
| Reclass of unearned .compensation ...... ,-- -- (10,257). 10,257 -.
| |
| Amortization of restricted stock ......... -- -- 2,956 -- -- ' - . 2,956 Stock compensation and tax benefit ...... __ -- (2,091) - - -- , (2,091)
| |
| Unrealized loss on marketable securities . .(57) (57)
| |
| Minimum pension liability adjustment ... 31,841 31,841
| |
| ... . . -: . (12,666) -. (12,666)
| |
| Income tax expense ...................
| |
| Reclass to regulatory asset. ............ . .... 21,970 21,970 Balance at December 31, 2006 ........... '21,436 436,974 916,605 - 185,779 101 1,560,895 N et incom e .......................... - -- 165,623- 168,354 168,354 Issuance of common stock, net .......... - 40,342' 165,623 205,965 Preferred dividends, net of retirements ... , , . , ., (970)
| |
| Dividends on common stock ............ 7 .. 153 , ' . (99,153)
| |
| Reclass to Temporary Equity .... :....... - -- 1,447 ' , 1,447.
| |
| Amortization of restricted stock ......... " - "5,116 - - 5,116 Stock compensation and tax benefit ..... -- - '(3;692) ... , . (3,692)
| |
| Unrealized gain on marketable securities ............. ........... 51 51 Adjustment to Retained.
| |
| Earnings - FIN 48 ................. 10,467 * ' - "10,467 Balance at December 31, 2007 ........... $ 21A436 $477,316 $1,085,099 ' $ $ 264,477' $ 152 '$1,84:8,480
| |
| '7J 46 The accompanying notes are an integralpart of these consolidatedfinancialstatements.
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| Westar Energy I.2007 Annual Report WESTAR ENERGY, INC. Regulatory Accounting NOTES TOdCONsOLIDATED FINANC IA.L" STATEMENTS' We apply accounting standards for our regulated' utility
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| : 1. DESCRIPTION OF BUSINESS operations that recognize the economic effects of rate regulation in accordance with Statem'ent of Financial Accounting Standards We are the' largest electric utility in Kansas.'Udnless the dontext (SFAS) No. 71, "Accounting for the Effects of Certain -Types of 6therwis'e indicates'" all references in this Annuai"Report' on Regulation," arid, "accordirgly, hdve recorded regulatory assets Form 10-K to "fhe 'company," "we" us," "our" and similar and liabilities when required by a regulatory order or based on words aie'to Westar Energy, Inc. and.itsconsolidated subsidiaries'. regulatory precedent. ' .. .
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| The term"Westar Energy"fefers to Westar Energy,-Inc., a Kansas corporation incerdorated i.i:1924* alone and not fogetheý with Regulatory assets: .represent incurred costs that have been its'cohsolidafed subsidiaries!. deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent probable future reductions We provide electric generation, transmission and distribution in revenue or refunds to customers through the rate.- making services to approximately;67.4,000 customersdn Kansas. Westar process. Regulatory assets and liabilities reflected,,on our Energy. provides these, services in central and northeastern consolidated balance sheets-are as follows.
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| Kansas, including-,the cities. of Topeka, Lawrence, Manhattan, As of December 31, "' 2007' 2006 Salina and Hutchinson. Kansas Gas and Electric, Company (InThousands)
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| (KGE), Westar Energy's wholly owned subsidiary, provides these Regulatory Assets:
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| servics in s6uth-ce'ntral:and southeastern Kansas, includirin Am'oiunt due from c6stomers fofiuture " " ' -' "
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| the city of Wichita.'KGE ownns" a 47% ihterest. in the Wolf'Cfe'ek f.income'taxes, net...... .. .... '..... $151,279 '$160,147 Generating Station (Wolf Creek), a nuclear power plant;Jocated Debt reacquilsition costs ....................... " .91,110 97,342 near Burlington Kansas. Both.Westar Energy and KGE conduct Deferred employee benefit costs . ................. 202,545', 189,226 business using the name Westar Energy. Our corporate Disallowed plant costs ............................ . 16.650 16,733 headquarters is located at 818 South Kansas Avenue, Topeka, 2002 ice storm costs ..... ........... 9,998 14,897 Kansas 66612* 2005 ice storm costs.. ......... ................ 17,626 24,540 2007 ice storm costs ............................ 53,838 Asset retirement obligations........................ 20,071 19,312 2.,
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| ==SUMMARY==
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| OF SIGNIFICANT-ACCOUNTING POLICIES Depreciation ................................... 64,665 58,863 Principles of Consolidation Wolf Creek outage. .. . .............. ........ 6,984 14,975 Retail energy cost acjustment ................. ...... 32,794 6,950 We prepare our consolidated financial statements in aclcordance Other regulatory assets . ............ 7,900 6,495 with generally accepted accqunting principles (GAAP) for the United States of America. Our.consolidated financial statements Total regulatory assets .......................... $675,460 $609,480 include all operating divisions and majority owned subsidiaries Regulatory Liabilities: .' . '
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| * for which we .maintaincontrolling interests. Undivided interests Fuel supply and capacity sale contracts. ' .... $ 34,042 $ 12,794 injointly-,ored generaion facilities are included on a propor- Nuclear decommissioning ...................... , 56,006 48,793 tionate basis. Jitercompany accounts and transactions have Retail energy cost adjustment ................ . 6,015 , 19,884 been eliminated in consolidation. In our opinion; all adjustments, State Line'purchased power ................... .. 5,001 .6,623 consisting only of normal recurring adjustments considered Terminal net salvage .............. I............ . 15. 16,439 necessary for a fair presentation of the financial statements, Removal costs . ........ ... 25,157 13,355 have beenincluded. Other regulatory liabilities ... ..... ...... 15,381 15,612 Total regulatory liabilities ... ,,. .... ... $141,617 $133,500 Use of Manajgement's Estimates When we prepare our consolidated financial statements, we are Below we summarize the nature and period of recovery for each.
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| required to make estimates*'atid assumptions that affect'the of the regulatory assets listed in the table above.-
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| reported amounts of asse'ts, liabilities,, revenues and expenses, and related disclcisu're o'f contngent assets and liabilities at the m Amounts dUe from customers for future income taxes, net: In date of our consolidated financial statdmrents and the reported accordance'with various rate orders, we have reduced rates to amounts of revenues and' expenses duringthe reporting peiiod. t ax benefits associated with certain tax deductions, We evaluate our estimates on an on-going basis,,includingthose thereby passing on these benefits to customers at the time we related'to' bad 'debts, inventones, valuation of commodity con- receive them. We believe it is probable that the net future
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| -1increases in income taxes pýyable will be recovered frm tracts, depreciation, unbilled revenue, investments, valuation of our energy marketing poirfolio, intangible assets, forecasted fuel ,customers when tliese temporary taxbenefits reverse in future costs included in our retail energy cost adjustment (RECA) billed ,penods. We have recorded a regulatory asset for these amounts.
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| to customers,qincome taxes, pension and' o-h ' post-retirement We also have recorded a regulatory liability for our obligation and post-employment benefits, our asset retirement obligations to customers for taxes recovered from customers in earlier including decommissioning -of Wolf Creek, environmental periods when corporate tax rates were higher than the current issues, contingencies and litigation. Actual results may differ tax rates.'The benefit will be returned to customers as these from those estimates under different assumptions or conditions. temporary differences reverse in future periods. The tax-47
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| .......... Westar Energy I 2007.Annual Report related regulatory assets and liabilities as well as unamortized associated with these maintenance and. refueliiý, outages are investment tax credits are also temporary differences for which deferred and amortizedover the period of time between, such
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| ,deferred income taxes have been provided. These items are planned outages.
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| measured by the expected cash flows to be received or settled wRetail energy cost adjustment: We, are 'alldwed' to adjUst our
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| .through future rates. retail prices to reflect changes in the cost of fuel and purchased
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| " Debt reacquisition costs: This includes costs incurred to reac- power ne eded to serve our customers. This item represents quire and refinance debt. Debt reaccjuisition costs are amortized the difference in the actual cost of fuel consumed in producing over the term of the new debt. . I . electricity and the cost of purchased power and amounts we
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| " Deferred employee benefit costs: Employee benefit costs in- have collected from customers. We expect fo. recover in our clude $203.4 million,. less $3.1 million fornapplicable taxes, for rates, this shortfall over a one year period. We havetwo retail pension and post-retirement benefit obligations, pursuant to jurisdictions, each of which has a unique RECA and a separate SFAS No. 158, "Employers' Accounting for Defined Benefit. cost of fuel. This can. result in our simultaneously reporting Pension and Other Post-retirement Plans An Amendment
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| - both a regulatory asset and a regiulatory liabili for this item.
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| of FASB Statements No. 87, 88,106, and 132(R)"and $2.2 million 0 Other regulatory assets: This item, includes various regulatory for post-retirement expenses in excess of amounts paid. We assets that individually are small -in relation' to "the total will amortize to expense approximately $19.7 million during '.%egulatory asset'balande.' Other regulatory, assets have various 2008 for the'benefit obligation. The post-retirement expenses recovery periods, most of which range from three to five years.
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| are recovered over a period of five years.
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| " Disallowed plant costs: In 1985, the. Kansas Corporation Below we summarize the nature and period of.amortization for each of the regul4tory liabilities listed in the', table above.
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| * Commission (KCC) disallowed certain costs associated with the original construction of Wolf Creek. In 1987, the KCC m Fuel supply and .capacity sale contracts: We'use mark-to-authorized KGE to recover these costs in rates over the useful market accou'ntlng ýfor some of our fuel'supply and capacity
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| .life of Wolf Creek. sale contracts. This item iepiesents the non-cash net.'gain m 2002 ice storm costs: We accumulated and deferred for future position on fuel supply and capacity sale contracts that' are recovery costs related to restoring our electric distribution marked-to-ma'rket in accordance with the requirements of system from the damage it suffered as a result of an ice storm SFAS No. 133, "Accounting for Derivative Instruments and that occurred in January 2002. The KCC authori2.id us to Hedging Activities."'Under the RECA, fuel 'supply contract accrue carrying costs on this item.' As allowed by "the market gains accrue to the benefit of our customers.
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| December 28, 2005, KCC Order (2005. KCC Order),.in 2006 n Nuclear decommissioning: We hý8%'a:a legal obligation to Westar Energy began recovering $7.7 million over a three year decommission Wolf Creek at the end of its, useful life. This period and KGE began recovering $11.7 million over a five amount,:represents the difference. between the fair value of year period. We earn a return on this asset. our asset retirement obligation and the. fair value of the assets m2005 ice storm costs: We accumulated and deferred for future in our decommissioning trust. See"Note-6,"Financial Invest' recovery costs related to restoring. our electric distribution ments and Trading Securities"and Note 15, "Asset Retirement system from the damage it sustained as a result of an ice storm 'Obligations," for informatiori regardi8 g our Nidlear Decom-that occurred in January 2005.The KCC authorized us to accrue missionihgTrust Fund and our asset retirement' obligation.
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| carrying costs on this item. As allowed by the 2005 KCC Order,
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| * Retail energy 'cost adjustment: We are allowed to 'adjust our in 2006 Westar Energy began recovering $5.6 million over a retail prices t6 reflect changes in the coit of fuel and purchased three year period and KGE began recovering $253 milli6n power' needed',t6" serve *our customers. We bill customers over a five year period. We earn a return on this asset. based on our estimated costs.This item represents the amount m 2007 ice storm costs: We accumulated and deferred for future we 'collected from customers that was in excess of our actual recovery costs related to restoring our electric transmission cost of fuel and purchased power..We will refund to customers and distribution systems from the damage it sustained as a this excess recovery over done year period. We have two retail result of an ice storm that occurred in December 2007 Recovery jurisdictions, each of which has a unique RECA and a ýeparate of this asset will be considered during the 2008 rate reviews: cost offuel. This can res6dlf in .our simultaneously reporting
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| " Asset retirement obligations: This represents amounts associ- both. a regulatory asset and a"'re'iato ry liabilfity for this item.
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| ated with our asset retirement obligations"as disc ussed in " State Lin e purchased power:This iepresents' amounts received Note 15', "Asset Retirement Obligations." We r~cover this item from customers in excess 'of costs incurred' under Westar over the life of the utility plant. . Enhrgy's purchased power agreemrnit with Westar Generating,
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| " Depreciation: This represents the difference between the Inc., a wholly owned subsidiary..
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| 'iwegrlatorideprecia'on expense and the depreciation explrise " Terminal net salvage: This represents amounts collected in we record for'financial reporting purposes. We earn a return rates for terminal'.net salvage. Pursuant to the February 8, on this asset. We recover this item over the life of the related 20'07, KCC Order (February 2007 KCC Order), the KCC utility plant. 'ordered us to refund amounts previously collected. We
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| " Wolf Creek outage: Wolf Creek incurs a refueling and maninte- fefunded this amount during 2007.
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| nance outage approximately every 18 months. The expenses 48
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| Westar Energy I 2007 Annual -Report I Removal costs:,This.represents amounts collected, but unspent, - Depreciable livesof property, plant and.equipment are'as follows.
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| for costs.to dispose of utility planftassets that do not represent Years legal retirement obligations. The, liability.will be discharged as Fossil fuel generating facilities " . ..........15 to 75 removal costs are incurred.
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| Nuclear fuel generating facility .. .... .............. 40 to 60 0 Other regulatory liabilities: This includes various regulatory Transmission'facilities...... 45 to 65
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| 'liabilities that infdividually"are relatlvelyjsmall in relation to the Distribution facilities ....... . ............................... .. 19 to 65 total regulatory liability balance: Other regulatory liabilities Other ................. '.. . ............................ to 35 will be credited over various periods,.most of Which range from one to five years. In the 2005 KCC Order, the KCC approved a change in our depreciation rates. This change increased our annual deprecia-Cash and Cash Equivalents .,'-
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| tion expense by approximately $8.8 million. -
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| We consider investments that are highly liquid.and that have maturities of three months or less when purchased to be cash
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| * Nuclear Fuel equiva ents. We record as property, plant and equipment our share of the
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| " cost of nuclear fuel used in the process of refinement, conversion, Inventories and Supplies enrichment and fabrication..We reflect this at original cost and We state in'ventories and supplies at average cost. amortize such amounts to fuel expense.based on the quantity of heat consumed during the generation of electricity, as measured Property, Plant and Equipment in millions of British thermal units (MMBtu). The 'accumulated We record the value of property, plant and equipment at cost. amortization of nuclear fuel in the reactor was $36.4 million as For utility plant, cost includes contracted services, direct labor of December 31, 2007, and $19.6 million as of' December 31, and materials, indirect charges for.engineering and supervision, 2006. Spent nuclear fuel charged to fuel and purchased power and an allowance for funds used during constructi&io(AF UC). expense was $21.7 million, in .2007, $18.8 million in. 2006 and AFUDC represents the. cost -of..capital used to finance utility $18.0 million in 2005. . '.'., .
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| construction activity. AFUDC is computed by applying a composite rate to .qualified constructioli work in pr6gr~ss. The Cash Surrender Value of Life Insurance amount of AFUJDC capitalized as a construction cost is credited We recorded on our consolidated balancesheets in other long-to other income (for equity funds) and interest expense (for term assets the following amounts related to. corporate-owned borrowed funds) on the accompanying consolidated statements life insurance policies (COLD.
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| of income as follows: .
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| Year Ended December 31, 2007 - 2006 2005 As of December 31,. 2007
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| * 2006 (InThousands)
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| (InThousands)
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| Borrowed funds................ ...... $ 13,090 $ 4,053 $ 2,655 Cash surrender value of policies.................. $1,117,828 . $1,053,231, Equity funds ............... * ........... 4,346 - -
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| Borrowings against policies ........ .............. (1,031,155) (971,892)
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| Total ........ ............... ... $ 17,436 $ 4,053 $ 2,655 'Corporate-owned life insurance, net-....,.... . ... . $ 86,673 $ 81,339 Average AFUDC Rates ....... .......... 6.6% . 5.3%' 4.2%
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| We record income for increases in .cash surrender value 'and We charge mahintenance costs and replacement of minor items death proceeds. :We offset against policy income the interest of property to expense as incurred, except for maintenance
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| 'expense that we: incur on policy loans: Income recognized from costs incurred for our refueling outages at Wolf Creek. As death proceeds is highly variable from period to period. Death authorized by regulators, we-amortize these'amounts'to expense benefits approximated $24 million in 2007,. $18.9 million in ratably over the 18-month period between such, scheduled 2006 and $9.5 million in 2005.
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| outages. Normally, when a unit of depreciable property is retired, we charge to accumulated depreciation the original cbost,'less Revenue Recognition - Energy. Sales salvage value.' We record' revenue as electricity is delivered. 'Amounts delivered to individual customers are determined through the systematic Depreciation monthly readings of customer meters. At the end of each month, We depreciate utility plant using a straight-line method, at rates the electric usage from the last meter reading is estimated and based on .the,;estimated- remaining useful lives of the assets. corresponding unbilled revenue is recorded.
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| These rates are based on an average annual composite basis using group rates thatapproximated 2.7.% in both 2007 and The accuracy, of the unbilled revenue estimate is affected by 2006 and 2.5% in 2005. factors that include fluctuations in energy demands, weather, line losses and changes in the composition of customer classes.
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| We had 'estimated unbilled revenue of .$43.7 million .as -of December 31,2007, and $38.4 million as of December 31, 2006.
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| 49
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| . WestarEnergy I 2007 Annual Report We account for energy marketing derivative contracts runder the stock. based compensation, plans,and the'.physical, settlement;of mark-to-market method of accounting. Under this method, we a forward sale ,agreement..The dilutive effect of shares issuiable recognize changes in the portfolio value as gains or losses in the under. our stock-based, compensation plaxhs and'forward sale period of change. With the exception of a fuel'supply contract agreement is computed using the treasurystockomethod.
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| and a capacity sale contract, which are recorded as ir gulatfoy liabilities, we include the net mark-to-market change in sales The following table reconciles the weighted average number of on our consolidated statements of income. We record the equivalenit comm~onshares outstanding used to compute basic and diluted eami's per.share'I, resulting unrealized gains and l6sseg§as energy marketing long-term or ,short-term assets and liabilities on our consolidhted Year Ended December 31, 2007 ,.;'.- 2006 ' ' 2005' balance sheets-as appropriate. We use quoted market prices to DENOMINATOR FOR BASIC AND" . .
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| value our energy marketing derivative:c'ontracts when such data DILUTED EARNINGS PER SHARE:
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| is available. When market prices are not readily available or Denominator for basic earnings - '' ''
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| determinable, we use alternative approaches, such as model per share - weighted'average ....- . * .. . 6... .
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| equivalent shares ................. 90,675,511 87,509,800'.., 86,855,485 pricing. Prices! ssed to value these transactions reflect otr best Effect of dilutive securities:
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| estimate of the fair Value of our contracts. Results actually adhieved Employee stock options ............. 952 3.7 88?. ' 1,750 from these activities could vary materially from intended resfits Restricted share units .. . 517,694 589,352 552,423
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| ýnd could affect our consolidated financial results. Forward sale agreement ............ 66,686 - -
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| Income Taxes *. Denominator for diluted earnings per share - weighted average . ,
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| We use the asset and liability method of accounting for income equivalent'shares ................. 91,260,843 88,099,940 87,409,658 taxes as :required by SFAS NO. .109, "Adcounting for Income Potentially dilutive shares not.'., ,,
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| Taxes." Under. the asset and liability method,.,we' recognize included in the denominator 15808. ' 243 deferred tax-assets and liabilities for the future tax consequences becuse'they are arntidilutive.' 748903 attributable to temporary differences between the 'financial statement carrying amounts and the tax basis of existing assets Supplemental Cash Flow Information "
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| and liabilities. We recognize the future tax'benefits to the extent Year Ended December 31, 2007,;','- .2006' . 2005.1, that realization of such'l benefits'is more likely thari not. We
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| , '. - . . , .. (inThqusands) amortize deferred investment tax credits over the li-ýes of the CASH PA IDFOR: '' .. . . . .'.
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| related properties. Interest on financing activities, , . , .
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| net of amount capitalized .......... :.. $ 84,291 $ 88,872 $ 87,634 As of January 1, 2007, we account for. uncertainty° in income Income taxes . ..... :.' ...... 74,970 72,407.'. .: 772 taxes in accordance with Financial Accounting Standards-Board NON-CASH INVESTING TRANSATIONS:
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| (FASB) Interpretation No. (FIN) 48. The application of income Jeffrey Energy Center . .. . ..-
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| tax law is inherently complex. Laws and regulations in this area 8% leasehold interest . .......... 118,538 - -
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| are voluminous and are often ambiguous. As such, we are Other property, plant and required to make many subjective assumptions and judgments 6!,equiprmentl'idditions.., .,. . . 100,039 29,134 10,800 regarding our income tax exposures. Interpretations of and NON-CASH FINANCING TRANSACTIONS: ;, "i' " .-
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| guidance surrounding-income tax laws and regulations change Issuance of common stock for reinvested dividendsand RSUs.. .. . .. .. ,I0 553 ' 10,094, 11,728 over time: As such, changes in our subjective assumptions and Capital leas~efor Jeffrey Energy Center.-.. ',, ,, .
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| judgments can materially. affect amounts recognized in the' 8% leasehold interest ... .. . 118,538 - -
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| consolidated financial statements. See Note 11 to the Notesto Other assets acquired through capital leases. 3,228 4,491 3,716 Consolidated Financial Statements, "IncomeTaxes," for additional detail of our uncertainty in income taxes. New Accounting Pronouncements ' ' '
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| Sales Taxes .. . . , *SFAS No.; 159 -,The Fair.Value Option for Financial-,
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| We account for. the collection and' remittance .of sales tax on a Assets and Financial Liabilities net basis. As a result, these -amounts are not. reflected in the In February 2007, FASB released SFAS No. 159, "The FairValue consolidated statements of income. ' Option for Financial Assets and Financial Liabilities _ Including an."amehdment tO FASB.'Statement No. 115." SFAS No:. 159 Dilutive Shares ''
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| permits entities to'choose to ineasuremany finaincialiinstrumnents We report basic earnings per share applicable to equivalent and certain''other items at fair value. A business entity'shall common stock based on the weighted average number 'f report unrealized gains and losses on items for which' fair value common shares outstanding and shares issuable in connection option has been elected in earnings at each subsequent reporting with vested- restricted' share units (RSU) during the period date. SFAS No. 159 is effective for fiscal years beginning after reported: Diluted earnings per- share include the effects of November 15, 2007, with the cumulative effect of the change in potential issuances of common shares 'resulting from the accounting principle recorded as. an adjustment to opening assumed vesting of all outstanding RSUs, the exercise of all retained earnings. We adopted the guidance effective January 1, outstanding stock options issued pursuant to the terms of our 2008. The adoption of SFAS No. 159 did not have a material impact on our consolidated financial statements.
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| so
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| Westar Energy I 2007 Annual Report ............
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| *SFAS No. 157 - Fair, Value Measurements and Agreement between us and the KCC Staff. The Sfipulation In September 2006, FASB released SFAS No. 157, "Fair Valdi and Agreement approved by the KCC quantified the refund Measurements." SFAS -No. 157 defines fair value, establishes a. obligation related to amounts previously collected from custom-framework for measuring fair value in GAAP, and expands eis for transrfiission r~lated costs and established the amount Of disclosures about fair value measurements. SFAS No. 157 is transmission costs to be included in retail rates, prospectively.
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| effective for fiscal years beginning after November 15,. 2007, .Interveners filed petitions for reconsideration of flte July 2007 with the cumulative effect of the change in accounting principle .KCC Order on August 15, 2007. These petitions were denied'by recorded as an adjustment to opening retaj.ned earnings. We the KCC on September 13, 2007. The interveners filed appeals adopted the guidai.e'effective January 1, 200'8. The adoption of with the Kansas Court of Appeals. On February 11, 2008, the SFAS No. 157 did riot have a material impact on our consIolidated Kansas Court of Appeals issued an -opinidnwhich affinrmed! the financial statements. . July 2007 KCC Order. .We filed new tariffs ''and d 'plan for implementing refunds that became effective on August 29,2007.
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| : 3. RATE MATTERS AND REGULATION Refunds were substantially completed in November.
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| Changes in Rates, . FERC Proceedings * ,
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| On December 28, 2005, the KCC issued rn order (2005 KCC,. Request for Change in Transmission'Rates .
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| Order) authorizing changes in our rates, which we began'billing On May 2, 2005, we filed applications with the Federal Energy in the first quarter of 2006, and approving various other changes Regulatory Commission (FERC) that proposed a formula' in our rate structures. InApril 2006, interveners to the rate review transmission rate providing 'for annual adjustments to our filed appeals with the Kansas Court of Appeals challenging transmissiOn tariff. This is consistent with otir proposals filed various aspects of 'the, 2005 KCC Order. On July 7, 2006, the wiith the KCC on May 2; 2005; ,to chdirge retail customers Kansas Court of Appeals. reversed and remanded for further separately for transmiisson' service through a transmission consideration by the KCC three elements of the 2005 KCC delivery charge:The prolos~d FERC tfansmission rates became Order (July 2006 Court Order). The 'balance' of the 2005 KCC effective, subject to refund, December 1, 2005:On November 7, Order was upheld.'-. 2006, FERC'is'ued ancrder, reflecting a unanimous settlement reached by the parties to the proce'ding."The settlement The Kansas Court of Appeals held:, () the KCC's approval of a modified the rates we' proposed and required us to refund transmission delivery charge, in the circumstances of this case, approximately, $3.4 million,' which included the amount we violated the ,Kansas statutes that* authorize a transmission
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| ,delivery charge, (ii) the KCC's approval of recovery of terminal collected in the interim rates since December 2005 and interest on that amount.
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| net salvage, adjusted for inflation, in our depreciation rates, was not, supported by substantial competent evidence, and (iii), the On December 28, 2007, we filed applications with FERC that KCC's reversal ofits prior .rate treatment of the,La Cygne proposed changes to our formula transmission., rate, which Generating Station,(La Cygne) unit 2 sale-leaseback transaction provides for.annual adjustments.to our transmission tariff. While was not sufficiently justified aind was thus unreasonable, arbitrary the formula already allows recoyery:of the prior yearg's actual and capricious. .. costs, th e changes, if accepted by FERC, will allow us to include in our formula rate our anticipated transmission capital On February 8, 2007,.the..KCC issued an order (February 20.07 expenditures for the current year.We have requested-the changes KCC Order) in response to the July 2006 Court Order. The take effect on June 1, 2008. In addition, we made a simultaneous February 2007 KCC Order: (i) confirmed the original decision filing requesting .authority for incentives related "'to new regarding treatment, of, the. La Cygne unit 2 sale-leaseback transmission investmenrts as permitted by FERC.
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| transaction; (ii) reversed the KCC's original decision wiih regard to the inclusion in depreciation rates of a component for terminal On November. 6, 2007, we filed 'applications with FERC that net salvage; and (iii)'permits recovery of transmission related :proposed the use of a consolidated capital structure.in our costs in a manner similar to how we-recover our other costs; On formulatransmission rate. On December 19, 2007, FERC issued November 30, 2007,; we filed with the KCC to, implement a an order accepting this change. On January 28, 2008,-,we filed separate transmission 'delivery charge in a manner consistent applications with FERC requesting that this change be effective with the applicable Kansas statute. The February 2007 KCC June1, 2007. Accordingly, we have recorded a,$3.7 million refund Order required..us to refund.to our.-customers amounts we obligation,. which includes the amount we have collected since collectedrelated to terminal net salvage; -On July 31,,2007i the June 1, 2007,, and' interest on that amount.
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| KCC issued an order (July 2007 KCC Order) resolving issues raised by us and intervenersfollowing the February 2007 KCC ,Rate Review Request ' ' ' '
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| Order. The July 2007 KCC .Order: (i) confirmed the earlier We will file 'a request'for a rate review with the KCC during decision concerning recovery of terminal net salvage and 2008, based on a test y~ar consisting of the 12"months ended quantified the effect of that ruling;'and ii) approved ' Stipulation Deceinber 31, 2007.
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| 51
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| Westar Energy 1'2007 Annual Report
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| : 4. ACCOUNTS RECEIVABLE SALES PROGRAM by creating a re!ationship in which gains- or losses on derivadtive
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| ."instruments are expelcted to counterbalance the losses or gains We terminated our accounts receivable sales program in March on the assets, habilities or anticipated transactipns exposed.to 2006. Th6 amounts sold to the bank and commercial paper such market risks. 'We use derivative instruments as, -risk conduit were $65.0 million as of December 31, 2005. We recorded management. tools consistent with our business plans and this activity on the consolidated statements of cash flows for the prudent business practices and for energy marketing purposes..
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| year ended December 31, 2005, fn the "accounts receivable, net" line of cash flows from operating activities. We use. derivative financial and phynsical imstr'uments primarily to manage risk as if relates to'changes in th6 prices of commodi-5.- FINANCIAL INSTRUMENTS, ENERGY MARKETING AND ties including 'natural'gaS, oil, coal and elecrishity. We classify RISK MANAGEMENT derivative' insfrument' used to mfianage comrimodity price risk inherent in fossil fuel and-electricity purchases and sales as Values of Financial Instruments energy marketing contracts on our consolidated balance sheets.
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| We estimate the fair value of each class of our financial We report energy marketing c'0ntradts representing unrealized instruments for which it is practicable to estimate that value as. gain positions as ass-ets; energy marketing contracts representing set forth in SFAS No., 107 "Disclosures about Fair Value of unrealized loss positions are reported as liabilities.
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| Financial Instruhients." ... .S '
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| Energy Marketing Activities .,.
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| Cash and cash equivalents, short-term borrowings and variable-We 6ng'age in both firianicial, and physical trading.to increase rate debt are carried at cost, which approximates fair value. The pe6fit'ma niane 'our coinmodityp-ice risk.and enhafc6 Systerm nuclear decommissioning trust is recorded at fair value, which is reliabiliy.' We trade electricity, c6'al 'and natural gas. We use"a estimated based on the quoted market prices as of December 31, variety' of financial instruments,"including .for~vafd cofitracts,.
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| 2007 and 2006. See Note 6,"Financial Investments and Trading option's and' .V aps, and 'wetrade enerI gy cormmodity contracts.
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| Securities,". for additional information about our nuclear decommissioning trust. The fair value of fixed-rate debt is Within' the trading,.portfolio, we 2take certain 'positions to estimated based on quoted market prices for the same or similar economically hedge a portion of physical sale or;.,purchase issues or on the current rates offered for instruments of the same contracts and we take certain positions to take advantage of remaining maturities and redemption provisions. market trends and' c.6nditions.. With the exce ftion" of a fuel The recorded amounts of acounts r&ceivable and other current supply contract ahd a capacity sale cdntract, which r.e recorded financial instruments approximate fair value. as' regulatory liabilities" we-'include the net criark-to-market change in sales 6n' our consolidated §tatements df. infcome. We We base estimates of fair value on information available as of believe financial'instruments help us manage our confradttal December 31, 2007 and 2006. These fair value estimates have commitmrents, reduce. our e)pogure io chinsges in cash market not been' comriprehensively revalued for the purpose' of these prices and take advantage 6f selected iiarket op '6rtnities.We financial statements since that date and current estimates of fair iefer to these tfansactions as'energymarketirig activities. '
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| value may differ from the amounts below. The carrying values.,
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| and estimated fair values' of our financial instruments 'ate as We are involved in trading activities to reduce risk from market shown in the table below. fluctuations, enhance system reliability and increase profits: Net Carrying Value open'positi ns exist, or are established, due.tb the origination Of Fair Value new ttan'acti6ns andi6ur assessment of, and resp 6ose to, chang-As of December 31, , 20074) 2006 2007(l) .2006 ing Mritket conditions. To the extent we hav'e open positions, we (in Thousands) are expo ed' to the risk that'chingin'g'market'prices'coufd ha,'e Fixed-rate debt, net of a material, adverse impact on our consolidated financial position current maturities ....... $1,619,381 $1,294,405. $1,586,407 . $1,277,497 or results of operations. ". " ' ' " .
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| 22
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| ' This amount does not include an equipmentfinancing loan of $1.8 million.
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| We have considered a number of~risks and costs associated with
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| .the future-contractual commitments included. in. our, -energy Derivative Instruments portfolio. These. 'risks 'include credit "risks associated., with ,the We are exposed to market risks from changes in commodity financial condition, of counterparties, product location (basis)
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| ,ricesand interest'rates that could affect-our consolidated results differentials and.other. risks. Declines in the creditworthiness of of operations and financial con'ditidn. We manage d ur exposure our counterparties could heive a material adverse impact on our to these market risks through our regular 'operating and overall exposure to. credit risk. We maintain credit policies with financing activities and, when deemed appropriate, economically regard to bur counterparties that, in management's view, reduce hedge a portion of these risks through the use of derivative our overall credit risk. , .;
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| financial instruments. We use the term economic hedge to mean a strategy designed to manage risks of volatility in prices-or rate We. are also, exposed to commodity price changes., We use movements on some assets, liabilities or anticipated traiisactions derivative contracts for non-trading purposes and a mix of 52
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| | |
| Westar Energy 1 2007. Annual Report various fuel types primarily to 'reduce. exposure relatiW..to the Available-for'Sale Securities .. I . I" - ,
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| volatility of market and commodity prices. The wholesale power We hold investments in debt and equity securities in' a trust fund market is extre'ely iVolatile in price anid supply. This volatility for the purpose of funding the decommissioning of Wolf Creek.
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| impacts our costs'of p6wer purchased and our participation in We -'have- classified these -investments in ;debt 'and eqciity energy trades. If we wereý,ufiab i to generate an adeqtuate supply,- securities as available-for-sale 'and have recorded all such of electnicity forourcustomers, We would pturchase power in the investmef-ts at their fair market'Value as of December 31,'2007 wholesale market to .thee&xtent it is available, subject to possibI6 and 2006. Investments by the nuclear decommissioning' trust transmissio n conr;straints, and/or impleentt curtailment cIr fnd are allocated 70%/o to equity securities, 27% to fixed-income interruption procedures as permittedI in our tariffs and terms securities and 3% to cash and cash equivalents. Fixed-income and conditions-of.service... .. incestments are limited to U.S. goveInment or agency securities, municipal bonds, or corporate securities. Using the specific We use various fossil fuel types, including coal, natural gas and identification method to determine 'cost,, the gross, realized
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| *oil .'to operate-our plant'i:A .ighifitant portion of- our coal
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| .gains on those sales were $5.7 million in 2007, $7:5.million in requirements are purchased, under long-term contracts.
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| 2006 and $3.2 million in 2005. We"rieflect net realized ,and Additional factors that affect our. commodity price exposure are unrealized gains and losses in regulatory liabilities onour the quantityand availability of fuel usedfor generation and the consolidated balance sheets. This. reporting is consistent--with quantity of electricity customers consume. Quantities of fossil the method we use to account for the .decommissigning- costs fuel used for generation varyý from year toý year based on recovered in rates. Gains or losses on assets in the trust funid availability, price and deliverability of a given fuel type as well as could result -in lower or -higher funding requiremenlts for planned and unscheduled outages at our facilities that use fossil decommissioning costs, which we believe would be reflected 'in fuels 'and the nuclear' refueling schedule. Our customers' electric rates paid by otir customers. , ,.
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| electricity, usage* qco.pla als0 vary. from yefar to year based on The following table presents the costs and fair values of weather or otheir factors........ . investments in debt' and eequity securities in the' nuclear The prices we 'use to value price risk ma nagement'activities ,decommissioningtrtust fund as of December 31, 2007 ahid'2006.
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| reflect our estimnate Of fair value's considering various factors, Changes in the- fair value of the trust fund are recorded 'as an including closing exchange and'`o*'r-the*'dounter quotations, increase or decrease - to the regulatory liability recorded in time value of money and price volatility factors underlying the connection with the decommissioning of Wolf Creek.
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| commitments. We adj6st prices to reflect thie potential impact of Gross Unrealized "
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| liquidating Our p6sition in an-orderly marner over a re.asonable Security Type Cost Gain Loss Fair Value period of time under present market condiibrns'. We consider a -* -. (InThousands) number of risks'and costs associated With the future cdntfactual -2007: .
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| commitments iiclfuded'in our energy portfolio., including credit Debt securities .....- .......... $33,705 $ 450 $- (528) $- 33,627 risks ass'ociated with the' fin*6cial conditiihi"of couinterýarties Equitysecurities---------*.. 69,505 19,031 - (2,971) . .85,565 and'the' 'time'valu'. of money..We contitsuously monitor the Cash equivalents ............. - 3,106 - - - ' ' 3,106 portfolio and valiY'6tit daily based On present market conditions. Total ...................... $106,316 $19,481 $(3,499) $122,298 2006:
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| 6.. FINANCIAL INVESTMENTS AND TRADING SECURITIES Debt securities ............... $36,947 S. 349 $ (168) $ 37,128 Equity securities .............. 57,202 13,754- (1,288) 69,668 Some of our investments in debt andequsty' secunties are subject Cash equivalents ............. 4,339 - - 4,339 to the requirements of SFAS No. 115, "Accoiihting ,for Certain Total ...................... $ 98,488 $14,103 $(1,456) $111,135 Investments in Debt and Equity Securities."We report thesýe investments at fair value and we use the specific identification method to determine their cost for computing realized gains or The following table presents the costs and fair values of losses. We classify these investments as either trading securities investments in debt securities in the nuclear decommissioning or available-for-sale securities as described below. trust fund according to their contractual maturities.
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| As of December 31, 2007 Cost Fair Value Trading Securities (In Thousands)
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| We have investments in trust assets securing certain executive Less than 5 years ....... ........ ........... $ 5,820 $ 5,881 benefits that are classified as trading securities. We include any 5 years to 10 years ................. 5,035 5,092 unrealized gains or losses on these securities in investment Due after 10 years ................. ................. 11,870. 12,020 earnings on our consolidated statements of income. There were Sub-total ............. - ............. ........... 22,725 22,993 an unrealized gain of $2.8 million as of-.December 31, 2007, an Fixed Incom e Fund ................................. 10,980 10,634 unrealized gain of $1.7 million as of December 31, 2006, and an Total... $33,705 $33,627 unrealized loss of $0.3 million as of December 31, 2005.
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| 53
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| Westar Energy I 2007 Annual Report The following table presents the fair value and the gross unrealized &8JOINTOWNERSHIP OF UTILITY PLANTS losses of the available-for-sale, securities held in the, nuclear Under joint ownership agreemeTts with other utilities, we have decommissioning trust fund that were not.deemed to be other-undrVLided ownership' 'interests in four electric generating than-temporarily impaired, aggregated by investment category stations. Energy generated'and operating expenses are divided and the length of time that.individual securities have been-in a on'the same basis as' ownership with. each owner reflecting its continuous unrealized loss.positioni at December 31, 2007.
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| respective costs in its statements of income. Informationi relative Less than 12 Months to our ownership interest inh'hese facilities as of December 31, 12 Months or Greater Total 2007, is sho0vnin the table below.
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| Gross Gross Gross -
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| Fair Unrealized Fair, -Unrealized Fair Unrealized Our Ownership as of December 31, 2007.
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| . - ' Value Losses Value -Losses Value Losses (InThousands) -
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| Construction Owner-
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| - In-Service * . .. Accumulated Work in - Net ship Debtsecurities, .... $13,781 $ (488) $ 849 $ (40) $14,630 $''(528) Dates .... Investment .Depreciation Progress.. MW Percent EquitysecuritiesI.'. " 11,758 (2,488) 565 (483) 12,323 (2,971) '.Do.llarsin Thousands)
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| Total.'. $25,539 $(2,976) $1,414 $(523) $26,953 $(3*499) LaCygne unit 1. June 1973 $ 269,618 $ 129,068 $ 1,825 368.0 50 Jeffrey unit 1*.... ,July 1978 " 326;539 '176,606 75ý539 672.0, 92.
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| jeffrey.unit2(l). .. May 1980K,. 318,898'. , 156,603. 42,183 672.0, 92
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| : 7. PROPERTY, PLANT AND EQUIPMENT . Jeffrey unit 3T(.. May 1983 ... 471,736 ,. 220,432 63,678 672.0 92..,
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| Jeffreywind.le) .. May 1999 .966 - , , 392 . . - 0.7 92 The followingis a summary of our property, plant and equipment Jeffrey wind 2(1ý.... May .1999 , 966-, 392 - ,0.7. 92.
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| balance.. . . : * .,- 1 . . .
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| * Wolf CreekKc . Sept. 1985 1,417,485' 647,489 26,517 545.0, 147 State Line(d) ...... June 2001 106,994 28,113 149 204.0 40 As of December 31, 2007 . . 2006 (In Thousands) ,
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| Total........... . ,. $2,913,202 $1,359,095" $209,891 3,134.4 Electric plant in service................ . .. , $6,452,522. $6,066,954 ("Jointly owned with Kansas City Power & Light Compahy (KCPL)
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| Electric plant acquisition adjustment .... ...... . 802,318 802,318 (bWJointly owned with Aquila,,Inc. .
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| Accumulated depreciation ............ . (3,142,550) (2,979,159)
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| (°Jointly.owned with KCPL andKansasElectric Power Cooperative, Inc.
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| 4,112,290 3,890,113 (daJointly owned with Empire District.Electric Company Construction work in progress .......... ......... 630,782 142,351 Nuclear fuel, net ............... .... . 60,566 39,109 Amounts and capacity presented above represent our share. We Net utility plant... . ... ......... ........ 4,803,638 4,071,573 include in operating expenses on our consolidated statements Nonifutiiity plant in service . . .. ..... .-...... 34 " 34 of income our share of, operating expenses of the above plants, Net property, plant and equipment .... ........ $4,803,672 $4,071,607 as, w..e ts such. expenses for a 50% .'undivided. interest in La Cygne, unit 2 (representing 341, megawattsof capacity), sold We'recorded depreciation expense on utility property, plant and *andleased back to KGE in 1987:,Our share of other transactions equipment of $170.0 million in 2007, $159.9 million in 2006 and associated with the plants, is- included in the. appropriate
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| $130.1 millionih2005. classification on our consolidated financial statements.
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| In 2007, we purchased an 8% leasehold interest in Jeffrey Energy Center and assumed the related lease obligation. We recOrded a capital lease of $118.5 million related to this transaction. This increased Our interest in Jeffrey Energy Center to 92/. Am6ond ts presented' ab6ve' do -not include. this capital lease 'or related
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| . 1; , . 1, . 1 .' " ; ,
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| delreciatioft . ..
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| 54
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| Westar-Energyl 2007, Annual:Report ............
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| : 9. SHORT-TERM DEBT 10. LONG-TERM DEBT Outstanding Debt
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| -A syn'didate of banks' pro'vides us a'revolving cre~dit' facili ' on a committed basis totaling $500.0 million. Effective March 16, The following table summmarizes our longterm. debt outstanding.
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| 20-07 $480:0 milhon of the commitments of the lenders under the revofing credit facility terminate on March 17, 2012. The As of December 31, 2007 2006' (InThousands) remaining $20.0. million of the commitments terminate on March 17, 2011. So long as there is no default or event of default Westar Energy under the revolving credit facility, we may elect to extend the First mortgage bond series:
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| term of the credit facility for one year. This one year extension 6.000% due 2014 ....................... 250,000 $ 250,000 5.150% due 2017 .............. . 125,000 125,000.
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| can be requested twice during the term of the facility, subject fb 5.950% due 2035 .. ....
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| .. ."..." 125,000 125,000 lender participation. The facility allows us to borrow.,up to an 5.100% due 2020 ...... 250,000. 250,000 aggregate amnount 'of $500.0 million, including letters of credit
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| * 5.875% due 2036 .. ............ ......... *150,000 '150,000 up to a-maximum aggregate amount-of $150:0 million. As of 6.100% due 2047 ..... ........ .. :'. .. .... '"150,000 " -
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| December 31,;2007,, we had b6rrowings of!$180.0 million and 1,050,000 900,000
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| $45.5 million of letters of credit outstanding under this facility.
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| On January 11, 2008, we filed a request with FERC for authority Pollution control bond series:
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| Variable due'2032, 4.35% as of December31, 2007; to issue short-term securities and to pledge mortgage bonds 3.65% as of Deieinber 31, 2006. .45,0001 '45',0600 in order, to increase, the size of our revolving credit facility. to Variable due 2032;"4.35%'as of December31, 2007;
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| $750.0 million. On February 15, 2008, FERC granted.our request 3:55% as of December 31, 2006 ............. 30,50.0 30,500 and,. on February 22, 2008; a syndicate of- banks in our credit 5.000% due 2033..'.'.' .. 58,340s %58,340 facility increased their commitments, which in the aggregate "133,840 `133,840 total $750.0 million. As of February 22, 2008, $270.0 million had UtLl~er II*-LerIII deb :
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| been borrowed and $55.0 million of letters of crediihad been ,.4.360% Equipment financing loan due 2010 .... 1,825 issued, leaving $425.0 million available under this facility. 7.125% unsecured senior notes due 2009 ........... 145,078 145,078 Inf6rmation regarding our short-term borrowings is as follows. 146,903 145,078 KGE ,,, ' " ", , ', . , :,
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| As of December 31, '2007 . 2006
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| : "(Dollars First mortgage bond series: -
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| in Thousands) 6,,ý.530% due 2037. ...... ............ 175,000, .
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| Weighted averageshort-term debtK outstanding during the year: ....... . ... $157,372 $122,392 '175,000. Ib. "
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| Weighted daily average interest rates Pollution control bond.series:
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| during the year, excluding fees ..................... 5.83% 5.71% 5.100% due 2023 ............................ 1.3,463 13,488 Varible due 2027, 5.25% as~of December 31, 2007; Our interest- expense on short-term debt was' $9.7 mil in "ot3.50%/ as of December 31,'2006.' .:...:.: 21,940 21,940 2007, $7.6 million in 2006 and $1.3 million in 2005. 5.300% due 2031 ... . ................. 108,600 108,600 5.300%'due 2031-.::..' . :. 18,900!,': 18,900, Variable due 2031, 5.00% as of December 3.1-2007;'
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| 3.47% as of December 31, 2006 ............... 100,000; 100,000.
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| Variable due 2032, 5.25% as of December 31, 2007;
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| 'tv3.45% as of December 31:,-2006 .............. , 1.4500 14,500:
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| -Variable due 2032, 4.50% as of December 31, 2007;.
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| .44% as of December 31, 2006............ 10,000 10,000 4.850% due 2031 .. .............. ....... 50,000 .50,000 Variable due 2031, 5.25% as of December 31, 2007; 3.85%"as 6f Decimber 31, 2006 ........ ...
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| 50,000 5d,0ooo 387,403 387,428 Total~long-term debtk.. "........... . " i893,146" . 1,566,346 5 5 Unamortized debt discount .. (2ý807), (3;081)
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| Long-term debt doe Within one year .'.... I ....... : ' ' (558)' " -
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| Long-term debt, net ........................... $1,889,781 .; *1,563,265-r1)We dmortize d~bt disuount over the term of the reipectiveissue.,
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| * 1 , ,, , ' * '. ". '; - ' . . .
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| 55
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| I
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| ............ Westar Energy I 2007 Annual Report The Westar Energy mortgage and the* KGE -mortgage each Maturities .'...
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| contain provisions restricting the amount, of, first mortgage Maturities of long-term debt as of December 31, 2007,, are as bonds that could be issued by each entity. We must comply with follows. .. . . .
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| such restrictions prior to the issuance of additional first mortgage Year ' " "' Principal Amouni bonds or other secured indebtedfiess.
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| .(InThousands)
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| The amount of Westar Energy's first mortgage bonds authorized 2008 ............ ................... ............. : 558 by its Mortgage and Deed ofTrust, dated July 1, 1939, as supple- 2009 ......... .............. ' '. 145,684 mented, is unlimited subject to certain limitations as described 20 10 ...... .. ..... . ............... , 633 20 11 . .. .. .. .....: . .. .. .. . .. . . ...-. . .. .. .. . .... .. .. . - .. . ,. , 28 below.The amount of KGE's first mortgage bonds authorized by Thereafter ......, ....................... 1,746,243 the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2.0 billion, unless Total long-term:debt maturities. .... .. .... :: ' $1,893,i46 amended. First mortgage bonds are secured by utility assets.
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| Amounts of additional bonds that may be issued are subject to Our'interest expense on long-term debt was $94.2 million in property, earnings and certain restrictive provisions, except in 2007, $91.0 millionr in 2006 and $107.8 milliont in 2005..
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| connection with 'certain refundings, of each mortgage. As of December 31, 2007, based on an assumed interest rate of 6%, 11. TAXES
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| $408.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Income tax expense (benefit)"%is composed of the following Westar Energy's mortgage. As of December 31,2007, based on an components.
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| assumed interest rate of 6%, approximatelyf $820.1 million prin- 2007 , 2006 2005 Year Ended December 31, cipal amount of additional KGE first mortgage bonds could be (InThousands) issued under the most restrictive provisions in KGE's mortgage. Income TaxExpense (Benefit) from.
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| Continuing .Op'irations: .. '
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| On October 15, 2007, KGE issued- $175.0 million principal Current income'taxes:
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| amount of 6.53% first mortgage bonds maturing in 2037 in' a Fed eral .. . . . . .. . . . .. . . .. . . .. ... . .. . $40,648 $46,211 $ 30,132 private placement to an institutional investor. Proceeds from the State . .. ... .... . ......... .... . "9,107 .14303 '4:92'9 offering were used to repay borrowings under our revolving Deferred income taxes:
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| credit facility, which is the primary liquidity facility for acquiring Federal ..... ......... .. ............ 9,962 (1,150) 24,831 capital equipment, and any remainder was' used for working State . .. .. .. . .. .. .. ... .. .. .. . .. .... 6;240 578 . 3,511 capital and general corporate purposes. Investment tax credit amortization ........ (2,118) (3,630) .... (2,790)
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| Income tax expense from On May 16, 2007, Westar Energy sold $150.0 million aggregate continuing operations ...... ........ 63,839 56,312. ' 60,513 principal amount of 6.1% Westar Energy first mortgage bonds Income Tax Expense from .
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| * maturing in 2047. Proceeds from the offering were used to repay Discontinued Operations:'
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| borrowings under our revolving credit facility, which 'is the Current income taxes:
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| primary liquidity facility for acquiring capital equipment, and Federal... .......... .... ........ -29 any remainder was used'~for, working capital and general State... - -- 7 corporate purposes. Deferred income taxes:
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| Fed eral .. . . . . .. . . .. . . . .. . .. . . . .. . . - '370 On June 1, '2006, we refinanced $100.0 million 'of pollution 84 State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - --
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| control bonds, which were to mature in 2031. We replaced this Income tax expense from issue with two new pollution control bond series of $50.0 million discontinued operations ........... $- -- $ ,490 each. One series carries an interest rate of 4.85% and matures in $63,839 $56,1312 $ 61,003 Total income tax expense.
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| 2031. The second series carries a variable interest rate and also matures in 2031.'
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| Deferred tax assets and liabilities are reflected on our consolidated On January 17, 2006, we repaid $10010 million aggregate balance sheets as follows.
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| principal amount of 6.2% first mortgage bonds with cash on December 31, 2007 2006 hand and borrowings under the revolving credit facility.
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| . (inThousands)
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| Debt Covenants Current deferred tax assets .. ........ $ - $ 853 Current deferred tax liabilities .................... 2,310 -
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| Some of our debt instruments contain restrictions that require Non-current deferred tax liabilities ................. 897,293 906,311 us to maintiain-leverage ratios as defined in the agreements. We calculate these ratios in accordance with our credit agreements. Net deferred tax liabilities ....................... $899,603 $905,458 We use these ratios solely to determine compliance with our various debt covenants. We were ,in compliance with these covenants as of December 31, 2007.
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| 56
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| Westar Energy I 2007 Annual Report ............
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| The tax effect of the temporary differences and carryforwards The effective income tax rates -are computed by.dividing total that comprise our deferred tax assets and deferred tax liabilities Federal and state income taxes by the sum of such taxes and net are summarized in the following table. income. The difference between the effective tax rates and the Federal statutory income tax rates are as follows.
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| December 31, 2007, 2006 (InThousands) Forthe Year Ended December 31, 2007 2006 2005 Deferred tax assets: Statutory Federal income tax rate Deferred gain on sale-leaseback ............... $ 52,616 $ , 54,978 from continuing operations .............. 35.0% 35.0% 35.0%
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| Accrued liabilities ........................... 29,248 * . 30,531 Effect of:
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| Disallowed costs ........................... 15,301 15,955 State income taxes ................ I.... 4.4 -' 4.4 2.8:
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| Long-term energy contracts .................. 8,262,, 9,314. Amortization of investment tax credits........ (0.9) .(1.6) (1.4)
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| Deferred employee benefit costs ............... 82,752 , 77,155 Corporate-owned life insurance policies..". .. (5.8) .- '(8.3) (6.9) 1 . .. . .. .. .. .. . .. .. ..
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| Capital loss carryforwardl 216,626 . 219,795 Accelerated depreciation flow through Other(i 93,796 . 74,963 and amortization.................. 2.1 ' 1.4 1.2 Net operating loss utilization ....... I....... (5.1) . (0.9) (0.2)
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| Total gross deferred tax assets ............. . . . 498,601 . 482,691 Capital loss utilization.. (........
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| 1(.2) (4.0) (0.8)
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| Less: Valuation allowance101 . . . . . . . . . . . . . .. .. ..
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| 220,146 223,227 Other .............. .................. (1.0 ) . (0.6 ) 113 Deferred tax assets ....................... $ 278,455 $ 259,464 Effective income tax rate from Deferred tax liabilities: ". . continuing operations................. 27.5 %.' 25.4% 31.0%
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| Accelerated depreciation................... $ 644,707 $> 642,493 Statutory Federal income tax rate Acquisition premium ....................... 219,985 227,999 from discontinued operations ..... .. . -% -% 35.0%
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| Amounts due from customers for Effect of: . -
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| future income taxes, net................. . 151,279 .. 1,1 State income taxes. . -- -- 4.8.
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| Deferred employee benefit costs ............... 79,693 74,111 Effective income tax rate from Other ................................... 82,394 .60,172 discontinued operations ........... ........ % -- % 39.8 %
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| .Total deferred tax liabilities .................. $1,178,058 $1,164,922 Net deferred tax liabilities ....................... $ 899,603 $ 905,458 We file income tax returns in the U.S. Federal jurisdiction, and various states and foreign jurisdictions. The income tax returns
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| (-)As of December 31, 2007 we have a net capital.loss of $544.6 million available we filed will likely' be audited by. the*Internal Revenue Service to offset anyfuture capital gains through 2009. However as we do not expect to realize any significant capital gains in the future, a valuation allowance of (IRS) or other.taxing authorities. With few exceptions, the statute
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| $216.6 million has been established. In 'addition, a valuation allowance of of limitationrswith respect to U.S. Federal, state and local, or
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| $3:5 million has been establishedfor certain deferred tax assets related to the non-U.S. income tax examinations by tax authorities are closed write-down of other investments. The total valuation allowance related to for years before 1995:
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| the deferred tax assets was $220.1 million as of December 31, 2007, and
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| $223.2 million as of December 31, 2006. The net reduction in valuation The IRS has examined our Federal income tax returns for the allowance of $3.1 niillion was due primarily to capi.tal-gh'ns realized iti 2`007.
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| See the discussion below regardingthe filing of amendbd Federal-incometax years 1995 through 2002 We reached a tentative settlement returnsfor years 2003 and 2004. . . . with the%IRS Office of Appeals ORS Appeals Settlement) in
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| ¢")As of December 31, 2006, we had available general business tax credits of December 2007.:The principal issues-related to the method for
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| $0.5 million generatedfrom affordable housing partnerships in which we sold capitalizing and allocating overhead costs, .the carry back of the majority of our interests in 2001.*Thse tax credits expire beginmnmg 2019 capital losses and net operating losses and,the deduction ofand through 2025.. We believe these tax credits will be fully utilized on the 2007 credit for research' and development costs. The 'IRS Appeals tax return.
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| Settlement was approved by the Joint Committee on Taxation and accepted by the IRS in February 2008. As a result, we will In accordance with various rate orders, we have reduced rates to receive a tax refund of.approximately $18.8 million, excluding reflect the tax benefits associated"with certain tax deductions*.
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| interest.The Federal statute of limitations for years 1995 through We believe it is probabfe that the net future increases in income 2002 remains open until 90 days after either the IRS or we send taxes payable will b6 recovered from customers .when these the prescribed notice ending the agreement. We believe that the temporary tax benefits reverse. W&have recorded a. regulatory statute of limitations for the affected years will close within the asset for these amounts. We. also have recorded, a regulatory next 12 months.
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| liability for our obligation to reduce rates charged customers for deferred taxes recovered from customers at corporate tax rates The IRS is currently examining our Federal income tax returns higher than the current tax rates. The rate reduction will occur as for years 2003 and 2004. On December. 21, .2007, we filed the temporary differences resulting in the excess deferred tax amended Federal income tax returns for years 2003 and 2004.
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| liabilities reverse. The tax-related regulatory assets and liabilities The amended returns change the original Federal income tax as well as unamortized investment tax credits are also temporary characterization of the loss we incurred on the sale of Protection differences for which deferred income taxes have been provided. One, Inc. (Protection One) in 2004 from a capital loss to an The net deferred tax liability related to these temporary ordinary loss. The characterization of the loss as either capital or differences is classified above as amounts due from customers ordinary affects our ability to carry back and. carry forward the for future income taxes. loss to tax years in which the loss can be deducted. The IRS has 57
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| ............. Westar Energy I 2007 'Annual Report challenged the position reported on the amended returns and As of' December. 31,.2007, the amount of,. unrecognized tax the ultimate outcome cannot be predicted at this time. If the re- benefits that, if recognized, would favorably impact our effective characterization of the tax loss is ultimately upheld, the loss tax rate, is $172.2 million (net of tax). Included in -the FIN 48 would be available, for carry back to- year 2003 and carried liability at December 31,2007, are $33.4 million (net of tax) of tax forward 20 years to offset future taxable income. In addition, positions, whicl 'if recognized, would favorably impact 'our under the terms of our tax sharing agreement, we reimburse effective in come tax rate.
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| subsidiaries for current tax benefits used in our consolidated, tax With the adoption of FIN 48,. we changed our practice of return. Under a settlement agreement relating to the. sale including interest related to income tax uncertainties in income transaction, we agreed to reimburse Protection One an amount tax expense. Effective January 1, 2007, interest is classified equal to 50% of the tax benefit attributable to the net operating as" interest, expense and accrued interest liability. We' had loss carryforward arising from the sale. As shown.below, we
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| $13.5 million and $18.9 million accrued foi in't'erest related to have not recognized tax benefits related to the amended returns.
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| income tax liabilities at December 31, 2007, and January 1, 2007, The IRS has not paid us a refund and, thus, the unrecognized tax respectively. There were no penalties accrued at December 31, benefits related to this uncertain tax position do not constitute 2007, or January 1'1,2007, and no penalties were' recognized liabilities. We believe that it is reasonably possible that the during 2007.
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| examination of years-2003 and 2004 will be completed by the end of 2008. We have extended the statute of limitations for As of December 31, 2007 and 2006, we maintained reserves, of these years until December 31, 2008. $5.2 million and $6.9 million, respectively, for probable assess-ments of taxes.other than income taxes.
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| Our 2007, 2006 and 2005 income tax returns are subject to audit by Federal and state taxing authorities.
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| : 12. EMPLOYEE BENEFIT PLANS We adopted the provisions of FIN 48 as of January 1, 2007.
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| The cumulative effect of adopting FIN 48 was. an increase of Pension
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| $10.5 million to the January 1, 2007, retained earnings balance. We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. For the At January 1, 2007, the amount of unredtngize'd tax benefits' and majority of our 'Iemployees; pension benefits are based on years the FIN 48 liabili''were $50'2"in"illion. Durrg the yeai 2007, the of service and'ctthe eniployee's compensation during' the '60 FIN 48 liability increased to $70.8'milion and the 'amount of highest paid consecutive months out of 120 before, retirement.
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| unrecognized tax benefits increased to $209.6 nrilion. The. net Our fundingpolicy for the pension plan is to contribute amounts increase in FIN 48 liability is prifnacly attributable 'to the sufficient to meet the minimum' funding requirements under deductions related to the December 2007 ice "storm. It 'is the ErmploYee Retirement Income Security Act of 1974 (E.RISA) reasonably possible that a reduction of unrecognized tax benefits and the Intemal' Re&enue Code plus additional amounts as in the range of $39.9 million to $178.7, million may occur in the considered appropriate., Non-union employees hired after next 12 months due to the expiration of the statute of limitations December 31,_2001, 'are covered by. the same defined benefit with respect to years '1995 through 2002 and' developments plan with benefits derived from a cash bialance account formula.
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| pertaining to the examination :of:years-2003 and 2004.-A We also mainftain a non-qualified Executive Salary Continuation reconciliation of the beginning and ending amount of unrecog- Plan' for' the beriefit of certaifn'currefi'and 'retired officers.
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| nized tax benefits is as follows: '' '. "' '
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| 6InThousands)
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| Iri addifiori 're providing pensibn beniefits, we provide certain post-retirement health -care and life insurance benefits 'for FIN,48 liability at January 1,2 0 0 . 7".. ... .... I .. ....... . $'50,211' Additions based on tax positions substantially all retired employees. The cost of post-retirement
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| . :':. . behneits 'are accrued during an employee's years of service and
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| ,'related to the current year ............ 21,660" Additions for tax positions of prior years .. ... .'..... .... . .. 5,197 recoveied thfbugh .rates. We fund the portion 'of net periodic post-nrtire'ent b'enefitecosts' that are includ'd iri rates.
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| Reductions for tax pdsitions of prior years................... :.... .....
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| Settlem ents . . . . :... . ... .. . . . .. . . . .. . ...... ... . ... .. ... .. . . . . .. (6,235)
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| As a co-owner of Wolf Creek, we-are indirectly responsible for FIN48 liability at December 31, 2007 .................. 70,833 47% of ,the liabilities, and' expenses' associated with the Wolf Unrecognized tax benefits related to am ended returns filed in2007 ................................. 138,778 Creek pensiori and post-retirement.'plan's.' See Note 13, "Wolf Creek, Employee 'Benefit ;Plans" for information about Wolf Unrecognized'tax benefits at December 31, 2007 . $209,611 Creek's'benefit plans:', .' '
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| 58
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| | |
| Westar Energy 1 2007 Annual Report ............
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| The following tables summarize the status. of our pension and other post-retirement benefit plans: Pension Benefits Post-retirement Benefits As of December 31, 2007 2006 2007 2006 Pension Benefits Post-retirement Benefits (Dollars in Thousands)
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| Asof December 31, 2007 2006 2007 2006 Pension Plans With a Projected (InThousands) Benefit Obligation InExcess Change in Benefit Obligation: of Plan Assets:
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| Benefit obligation, Projected benefit obligation. .. $578,191 $551,728 $ - '$ -
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| beginning of year .......... $ 551,728 $549,132 $ 124,546 $128,185 Accumulated benefit Service cost . . :............. 9,641 9,178 1,548 1,492 obligation .............. 497,169 483,511 Inierest cost................. 32,418 30,522 7,574 6,875 Fair value of plan assets ...... 468,188 451,824 - -
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| Plan participants' contributions. . - 4,164 3,380 PensionPlans With an Accumulated:
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| Benefits paid ............. * (28,450) (28,345) (11,481) (11,306) Benefit Obligation InExcess (5,994) of Plan Assets:
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| Actuarial losses (gains) .... '. . 12,718 (8,759) (4,080)
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| - .13,778 ' Projected benefit obligation.. $578,191 $551,728 $ - $ -
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| Amendments ................ . 136 -
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| Accumulated benefit Benefit obligation, end 6f years. $ 578,191 $ 551,728 '$134,135 $ 124,546 obligation .............. 497,169 483,511 - -
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| Change inPlan Assets: Fair value of plan assets ...... 468,188 451,824 - '
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| Fair value of plan assets - Post-retirement Plans With an beginning of year. -........ $ 451,824 $ 422,300 $' 52,778 ' $ '44,196 Accumulated Post-retirement Actual return on plan assets.. : 31,208 35 302 " .. 3,215 3,374 Benefit Obligation InExcess of Plan Assets:
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| Employer contribution ....... 11,800 20,750 12,400 12,200 Accumulated post-retirement Plan participants' contributions. . - -- 4,030 3,380 benefit obligation ........ $ - $ - $134,135 S 124,546 Part D Reimbursements ....... - -- 814 677. Fair value.of plan assets.. .. - - 61,423 52,778 Benefits paid ............... (26,644) (26,528) (11,814) (11,049) Weighted-Average Actuarial Fair value of plair assets, Assumptions used to end of year. ...... ...... $$468,188 $451;824 $ 61,423' $ 52,778 Determine Net Periodic Funded status, end of year. Benefit Obligation:
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| $(110,003) $ (99,904) $ (72,712) $ (71,768)
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| Discount rate ............. 6.25% 5.90% 6.10% 5.80%
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| Amounts Recognized in the Compensation rate increase . . 4.00% 4.00% - -
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| Balance Sheets Consist of:
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| Current liability:. :..-. ......... ' $ (1,838) $ (1,930) $ (130)$ - We use a measurement date of December 31 for our pension Noncurrent liability... ..... !. (108,165) (97,974) (72;582) (71,768) and post-retirement benefit plans.
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| Net amount recogrnized.... $6110,003) $ (99,904) $ (72,712) $ 171.768)
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| We use an interest rate yield curve to make judgments pursuant Amounts Recognized in Regulatory Assets Consist of: to Emerging Issues Task Force (EITF) No. D-36, "Selection of Net actuarial loss .......... $ 114,325 $102,172 $ 19,636 $ 26,570 Discount Rates Used for Measuring Defined Benefit Pension
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| 'Prior service cost ............ 11,517 13,926 12,858* 17' Obligations and Obligations of Post Retirement Benefit Plans Transition obligation ........... S. -- 19,979 23,909 Other Than Pensions." The yield curve is constructed based on Net amount recognized ..... $ '125,842 $116,098 $ 52,473 $ 50,496 the yields on over 500 high-quality, non-callable' corporate bonds with maturities between zero and 30 years. A theoretical spot rate curve constrffcted from this yield curve is then used to discount the annual benefit cash flows of our pension plan and develol* a'single-oin0nt discount rate matching the plan's payout structure.
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| We amortize the prior service cost (benefit)' on a straight-line basis over the average future service of the active employees amendment. The net actuarial loss subject to amortization. is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan, without application of.the amortization corridor described in SFAS No.
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| 87, "Employer§"Accounting for Pensions" and SFAS No. 106, "Employers' Accounting for Post-retiremenrt Benefits Other Than Pensions."
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| 59
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| Westar Energy I 2007 Annual Report Pension Benefits The estimated amounts that will be :amortized from regulatory Year Ended December 31, 2007 2006 2005.
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| assets into net periodic benefit cost in 2008 are as follows:
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| .(Dollars
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| - inThousands) *, , '-, ". '-, Other Pension Post-retirement Components of Net Periodic Cost (Benefit): Benefits . Benefits Service cost ......................... $ 9,641 $ 9,178 $ 6,735' (InThousands)
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| Interest cost ......................... 32,418 30,522 28,764 Actuarial loss ....................... .... ...... $ 8,340 $ 1,404 Expected return on plan assets ......... (38,506) (35,939) (36,272)
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| Prior service cost .................. ... .... 2,545 1,412 Amortization of unrecognized:
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| Transition obligation.'. * .............. . - 3,930 Transition obligation, net .............. - - -
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| Prior service costsi(benefit)... i......... . . 2,545 2,892 2,761 Total ...... ................. . ..... .. $10,885 $ 6,746 Actuarial loss, net ................... 7,864 8,759 5,347 Net periodic cost ..................... $13,962 $15,412 $ 7,335 We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets: asset classes in the plans' investment portfolio. Assumed Current year actuarial (gain)/loss .......... $20,017 $ - $ - projected rates of return, for each asset classwere selected after Amortization of actuarial loss ........... .. (7,864) - - analyzing long-term histcrical eiperience and future expecta-Current year prior service cost ........... 136 - - tions of the volatility of the various asset classes. Based on target Amortization of prior service cost ......... (2,545) - - asset allocations for each asset class, the overall expected rate of Amortization of transition obligation ...... - - -
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| return for the portfolio was developed, adjusted for historical Total recognized in regulatory assets ....... $ 9,744 $ - $ - and expected experience of active portfolio management results Total recognized in net periodic cost compared to benchmark returns and for the effect of expenses and regulatory assets ................ $23,706 $15,412. $ 7,335 paid from plan assets.-
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| Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit): In December 2003- the Medicare Prescription Drug Improvement Discount rate ........................ 5.90% '5.65% 5.90% and Modernization-Act of 2003 (Medicare Act) became law.The Expected long-term return on plan assets*.. 8.50% 8.50% 8.75% Medicare' Act infroduced 'a prýschpti6n drug benefit under Compensation rate increase ............. 4.00% 3.50% 3.00% Medicare-as well as a federal subsidy beginning in 2006. This subsidy will be paid to sponsors of retiree health care benefit Post-retirement Benefits plans that provide a benefit that is at least.actuariallyequivalent Year Ended December 31, :, 2007 2006 2005 to Medicare. We believe our retiree health care benefits plan is at (Dollars inThousands) least actuarially equivalent* to Medicare and is eligible for the Components of Net Periodic C6st (Benefit):
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| federal subsidy. We adopted the guidance in the third quarter of Service cost .......... .......... ' $ 1,548 $ 1,492 $ 1,615 2004. Treating the future subsidy under the Medicare Act as an Interest cost .... . ................ 7,574 6,875 7,049 actuarial experience gain, as required by the guidance, decreased Expected return on plan assets' .......... (3,827) (2,971) (2,552) the accumulated post-retirement benefit obligation by approxi-Amortization of unrecognized: mately $4.6, million in both 2007 and 2006. The subsidy also Transition obligation, net............... 3,930 3,931 3,931 decreased the net periodic post-retirement benefit cost by Prior. service costs/(benefit) .............. . 937 (415) (467) approximately $0.6 million for both 2007 and 2006.
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| Actuarial loss, net ......... 1,503 .. 2,001 1;934 For measurement purposes, the assumed annual health care Net periodic cost . :............. 11,665 $10,913 ' $ 11,510 cost growth rates were as follows.
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| Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets: As of December 31, 2007 2006 Current year actuarial (gain)/loss..........$ (5,431) $ - $ - Health care cost trend rate assumed for next year ............ 8.00% 9.00%
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| Amortization of actuarial loss ............ (1,503) - - Rate to which the cost trend rate is assumed Current year prior service cost ........ ' 13,778 - to decline (the ultimate trend rate) ..................... 5.00% 5.00%
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| Amortization of'prior service cost . . ' '(937) - Year that the rate reaches the ultimate trend rate ........... 2014 2011 Amortization of transition obligation ...... (3,930) ' -
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| Total recoghized in regulatory assets ...... ' $ 1,977 $ - "$ -
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| The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth Total recognized in net periodic cost and regulatory assets ............... : $13,642 $10,913 $ 11,510 rates would have effects shown in the following table.
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| Weighted-Average Actuarial Assumptions One-Percentage- One-Percentage-
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| ,used tO Determine Net Periodic Cost Point Increase Point Decrease (Benefit):
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| Discount rate.................... 1 5.80% 5.65% ' 5.90% (InThousands)
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| Expected long-term return on plan assets*.. 7.75% 7,75% 8.25% Effect on total of service and interest cost .......... $15 S $ (18)
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| Compensation rate increase ............. - - - Effect on post-retirement benefit obligation ......... 144 (249) 60
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| Westar Energy I 2007 Annual Report ............
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| The asset allocation for the pension plans and the post- In September 2006, FASB released SFAS No. 158. Under the retirement benefit plans at the end of 2007 and 2006, and the new standard, companies must recognize a net liability or asset target allocations for 2008, by asset category, are as shown in the to report the funded status of their defined benefit pension and following table. other post-retirement benefit plans on theirbalance sheets, On Target Allocations PlanAssets.
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| December 31, 2006, we adopted the recognition and disclosure provisions of SFAS No.. 158. The effect of adopting SFAS No:
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| Asset Category 2008. 2007 2006 158 on our financial condition at December 31, 2006, has been Pension Plans:
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| Equity securitie '. ... " .... . " 65% 67% . 62% included in the accompanying consolidated finaticial statements.
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| Debt securities ........................ 35% 29% 35%
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| We received an accounting authority order from the KCC to Cash ..... ...................... 0% - 5% 4% 3%
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| recognize as a regulatory asset the pension and post-retirem'nt liabilities that otherwise would have been charged to-other Total ..... 1.....................
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| 100% 100%
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| comprehensive income.
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| Post-retirement Benefit Plans:
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| Equity securities ...................... 65% , 60% , .. 64% The incremental effect of adopting the provisions of SFAS No.
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| Debt securities ...... ...... .......... 30% 29% 28% 158on our statement of financialposition at December 31,2006, Cash....... ...... ... .... 5% .. . 11% 8% including the effect on our portion of-Wolf Creek's pension and Total 100%.... 100% post-retirement plans, are. presented in the following table. The adoption of SFAS No. 158 had no effect on our consolidated We manage pension and retiree welfare plan assets in accordance statement of income for the year ended December 31, 2006, or with the "prudent investor" guidelines contained in the ERISA. for,any prior period presented.
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| The plan's investment strategy supports the objective of the Incremental Effect of Applying SFAS No. 158 funds, which is to earn the highest possible return onplan assets on'Individual Line Items in the Consolidated consistent 'with a 'reasonable and prudent level of risk. Balance Sheet as of December 31, 2006 Investments are diversified across classes, sectors and manager Before SFAS After SFAS style to minimize therisk of large losses. We delegate investment No. 158 Adjustments . No. 158, management to specialists in each asset class and where (InThousands) appropriate, provide the investment manager with specific CURRENT ASSETS:
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| guidelines, which include allowable and/or prohibited invest- Regulatory assets .......... $ $ 17,582 $ 17,582 ment types. Inv~stment risk is measured and monitored on an Total Current Assets ....... ........ - 7,582 . :, 17,582-Qngoing'basis through quarterly investment portfolio reviews OTHER ASSETS: . '
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| and annual liability measurements.
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| .Regulatory assets .- , 68,732 ' 168732' The following table shows the expected cash flows for the Other ................. ....... 14,412 . (14,412).' , ,-
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| pension plans and post-retirement benefit plans for future, years. Total'Other Assets ......... ...... 14,412 .: 154,320 168,732 Pension Benefits Post-retirement Benefits' TOTAL ASSETS ........... ...... 14,412 171,902 186,314 To/(From) To/(From) CURRENT LIABILITIES:
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| To/(From) Company To/(From) Company Other ................... ........-
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| Expected Cash Flows Trust Assets Trust Assets 2,467 2,467 (InMillions) Total Current Liabilities ..... ........- 2,467 2,467.-
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| Expected contributions: LONG-TERM LIABILITIES:
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| 2008 )............. ..... $ 15.2 $ 1.8 $12.6 $ 0.1 Deferred income taxes ....... ........ (16,948) 11,466 (5,482)
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| Expected benefit payments: Accrued employee benefits.... ...... 71,274 135,999 207,273 22008 '.. ........ . . . .. $ (26.5) $ (1.8) . $ (8 0) $(0 .1)
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| Total Long-Terrm Liabilities... . . 54,326 ". 147,465 201,791 2009 ................. .. (26.5) (1'8) (8.3) (0.1) 2010 .................... (26.8) (1.8) (8.5) (0:1) SHAREHOLDERS' EQUITY:
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| 2011 ................ (27.4) (1.8) (8.7) (0:1) Accumulated, other comprehens ive (loss),.
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| 2012 .................... (28.2) (1.8)' (8.8) (0.1) incom e, net .............. ......... (21,97d) 21,970 -
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| 2013-2017 ............ (167.5) (9.1)- (49.1) (0.7) Total Shareholders' Equity... . (21,970)1 21,970' -
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| "'We expect to make a voluntary contribution of $15.2 million to the Westar TOTAL LIABILITIES AND Energy pension trust in 2008. SHAREHOLDERS' EQUITY .......... $ 32,35.6 $171,902 $204,258 61
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| ............. Westar Energy I 2007 Annual Report Savings Plans . I ; :I No. 123R. Since 2002, we have used RSUs exclusively for our We maintain a qualified 401(k) savings planin which most of stock-based compensation awards. RSUs are valued in the same our employees participate. We match, employees' contributions manner under.SFAS Nos. 123 and 123R. .
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| in cash up to specified maximulm limits. Our contributions to The table below shows compensation expense and income tax the plans dre deposited with a trustee. and are invested at the benefits related to, stock-based compensation arrangements direction of plan participants into one or more of the investment that are included in our net income.. .
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| alternatives we provide under the plan. Out contributions were
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| $5.6 million in 2007, $4.8 million in,2006 and $4.1 million in 2005: Twelve Months Ended December 31, 2007 2006, 2005 (InThousands)
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| Stock Based Compensation Plans, Compensation expense .................... $ 5,735 $ 3,395 $4,560 We have a long-term incentive and share award plan (LTISA Income tax benefits related to stock-based Plan), which is a stock-based compensation plan in which .compensation arrangements ............... 2,281 1,350 1,814 employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate The incremental amount of stock-based compensation expense employees and directors: Under the LTISA Plan, we may grant that was disclosed and not included in our consolidated awards in, the form of stock options,dividend equivalents, share statements of income for the year ended December 31, 2005, appreciation rights, RSUs,performance shares and performance was not material to our consolidated results of operations.
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| share units, to plan participants. Up to five million shares of RSU awards are grants that entitle the holder to receive shares common stock may be granted under the, LTISA Plan. As of of common stock as the awards vest. These RSU awards are December 31, 2007, awards of 3,981,261 shares of common defined' in' SFAS No.' 123R as 'ndnveste'd' shares and do not stock had been made under the LTISA Plan. Dividend equiva-include restrictions once the awards have vested. We measure lents accrue on the awarded RSUs. Divideid'equivalents are the right to receive cash equal to the value of dividends paid on our the fair value of the RSU awards based o n' the market pti~e common stock...
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| of the underlying common stock as of the date. of grant and recogfiize that cost as an expense 'in theýconsolida"ted statement Effective January 1, 2006, we adopted SFAS No. 123R, "Share- of income over the requisite service p ~erod..The requisite service Based Payment," for stock-based compensation plans. Under periods range from one to ten years. RSU aiwards issued' after SFAS No. 123R, all stock-based compensation is measured at adoption of SFAS No. 123R with only service conditios 'that the. grant date, based on the fair value of the award, and is have a graded vesting schedule will be recogri.zed as an expense recognized as an expense in the consolidated statement of in the consolidated statement of income on a.straight-line basis income over the requisite service period. On March 29,2005, the over the requisite service period for the entire, award. Awards Securities and Exchange Commission (SEC) staff issued Staff issued prior to adoption of SFAS No. 123R will continue to Accounting Bulletin (SAB) No. 107 on Share-Based Payment to be recognized as an expense in the consolidated statement'of express the views of the staff regarding the interaction between income on a straight-line basis over the requisite service period SFAS No.123R and SEC rules and regulations as well as provide for each separately vesting portion of the award. -
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| staff's view on valuation of stock-based compensation arrange-ments for public companies. The SAB No. 107 guidance wyas During the year ended December 31, 2007, our RSU activity was taken into consideration with the implementation of SFAS as follows:
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| No. 123R. As of December 31, 2007 2006 2005 We adopted SFAS No. 123R using the modified prospective Weighted- Weighted- Weighted-Average Average Average transition method. Under the modified prospective transition Grant Date Grant Date Grant Date Shares Fair Value Shares Fair Value Shares Fair Value method, we are feqUired to record stock-based compensation (InThousands) . (InThousands) (InThousands) expense for all awards granted after the adoption date and for the unvested portion of previously granted awards outstanding Nonvested balance, beginning of year. 933.4 $20.82 1,094.5 $18.54 1,298.4 $17.50 as of the adoption date. Compensation'cost related to the Granted .......... 413.8 26.76 160.3 23.91 135.5 22.04 unvested portion of previously granted awards is based on the Vested ........... (308.5) 20.53 (306.6) 14.96 (336.0) 13.28 grant-date fair value estimated in accordarice with the original Forfeited .... (54.5) 26.79 (14.8) 21.56 (3.4) 20.43 provisions of SFAS No. 123. Compensation cost for awards Nonvested balance, gratited after the adoption date are based on the grant-date fair end of year. ::.. 984.2 23.11 - 933.4 20.82 1,094.5 18.54 value estimated in accordance with the provisions of SFAS 62
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| Westar Energy) .2007 Annual Report ............
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| Total hnhfiognized coffi &n-sation 'Cost related to RSU awaids 13. WOLF.CREEK EMPLOYEE BENEFIT PLANS" was $8.9 million das f 'December 31, 2007. These costs .are Pension and Pbst-retirement Benefits.
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| expected to be recognizedover a remaining weighted:average period of 2.4 years. Upon adoption of SFAS No.,123R,, we were As a co-owner of Wolf Creek, KGE is indirectly responsible for required to charge $10.3 million of unearned stock compensation '47% of the liabilities and expenses associated with the Wolf against additional paid-in capital. The total fair value of shares Creek pension and post-retirement.plans. KGE accrues its 47%
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| vested during the years'ended December 31,,2007, 2006:and of the Wolf Creek cost of pension and posti-retirement benefits 2005, was $8.3 million, $7.2 million and $7.5 million, respectively. during the years an employee provides service. The following There were no modifications of awards during the yearsi,ended tables summarize the net periodic"costs for KGE's 47% share of December 31, 2007, 2006 or 2005. the Wolf Creek pensi6n and posti*etirement benefit plans.
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| Pension Benefits Posi-retirement Benefits SFAS No. 123R requires that forfeitures be estimated over the vesting period, rather 'than being recognized as a reduction of As of December 31,' '2067 2006 2007 2006 compensation expense, when the forfeiture actually occurs.- (InThousands)
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| The cumulative effect of'the use of the estimated forfeiture Change in Benefit Obligation: ' . ' .
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| method for prior periods upon adoption 9of SF*AS No.: 123R.was Benefit obligation, , -
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| beginning of year .......... $ 79,213 $ 71,537 $ 7,391 $ 7,005 not material. .
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| Service cost .................. 3,436 3,245 234 248 RSU awards that can be settled in cash upon a change in control Interest cost ................ 4,696 4,293 -- ' 435' ; 412 were reclassified from permanent equity to temporary equity Plan participants' contributions.. - - 294 ' ' ' 253 Benefits paid ............... (1,809) (1,185) (509)' ' '(610) upon adoption of SFAS No. 123R. As of December 31,.2007, we Actuarial'losses/(gains) .. .... 2,071 1,278 '' '(114) ' 83 had $5.2 million of temporary equity on our consolidated balance Amendments ............... ' 34 45 '
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| sheet. If we 'determine-it. is' probable that these awards will -be Curtailments, settlements and settled in cash, the awards will be reclassifi0d as a liability. special termination benefits... 2,205 - '865' ' .-
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| Stock options granted between 1997, ahd 2001 are completely Benefit obligation, end of year.. $ 89,846 $ 79,213 $ 8,596 $ 7,391 vested and expire 10 years from the date of grant. All ,77,290 Change in Plan Assets:
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| outstanding options are 'exercisable. There were, r0o'6ptions 'Fairvalue of plan assets, '
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| exercised and 83,190 6ptions forfeited dtiring the 5ear ended beginning of year .......... $ 47,869 $ 39,752 $ - $
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| December 31, 2007. We c'currently have no plan 'to issue new 'Actual return on planass'ets 3,314 ' , 4,346 ' -
| |
| Employer contribution ''.' 5,618 4,766 '' - ' ', -
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| stock option awards.
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| Benefits paid ". (1,809) (995) - -
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| Another component ofthe LTISA Plan is the Executive Stoclk for Fair value of plan assets Compensation prograrni, Where in the past eligible -employees end 6f year $ 54,992 $ 47,869 '$' -' '
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| were entitled to receive deferred stock in lieu of current, cash Funded status . . .. $-(34,854) $ (i1,344) $ (8,596) .'$ (7,39.)
| |
| compensation, Although this plan. was discontinued in 2001, Post-measurementdate dividends will continue to be paid to plan participants ontheir adjustments :. '.f' ' ' 1,072' 1,164' : -
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| outstanding plan balance until distribution. 'Plan participants Accrued post-retirement ' "
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| were awarded 4,214 shares of, common stock for dividends in benefit costs . .. $,(33,782)' $ (30,180) '$ (8,596) .$ (7,391' 2007, 4,407 shares in 2006 and 3,936 shares in 2005:;.Participants Amounts Recognized in the -
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| received common stock distributions of.505 shares' in 2007, Balance Sheets Consist of:' '
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| 1,936 shares in 2006 anrd 12;271 shares in 2005. Currehtliability: ....... $ (168) "$,,"(190) $ (632)($ -(347)
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| Noncurrentliability ...... ..... (33,614) (29,990) .-. (7,964) ' ' (7,044)
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| Prior to the adoption,-of SFAS No. 123R, we ,reported all tax' Net amount recognized. $ (33 782) $.(30,180) $ (8,596)..$. (7,391) benefits resulting from the yesting of RSU awards, and-exercise Amounts Recognized in of stock Opti6i*ia'S o6e'rating cash flows in the consolidated Regulatory Assets Consist of:
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| statements of cash flows. SFAS 'No. 123R requires cash' retained Net actuarial loss . . $ 2112, 2 0$ 19;397 $ 3,127 $ 2 5311 as a result of excess tax benefits resulting from the tax deductions Prior ervice cot. ..... . . 178' 202' in excess of the related 'compensation cost 'recognized -in the Transition obligation.'...... 227" 284' 288 "
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| A' ,346 financial statements to be classified as cash'flows fromnfinancing Net amount recognized.. $ 21,525 $ 19,883 $ 3,415 $ 2 877 activities in the consolidated statements of'cash-flows, 2",
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| 63
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| ............ Westar Energyl .2007 Annual Report
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| .... ' ;Pensionr Benefits. Post-retirement Benefits ' Pension Benefiti' As of December 31, 2007 , 2006 2007 .... 2006 Year Ended December 31,. -" "'007' ' 2006 ' 2005 q-(Dollars inThousands) Components of Net'Periodic Cost S . (Dollars inThousands)
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| Pension Plans With a Projected Benefit Obligation In Excess $ 3,436" $ 3,245' Service cost ".'.. . .
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| ....... .. .:' .'. $ 2,820 of Plan Assets:' -, .'" .
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| Interest cost : .. ..... ...... .. .... 4-696 ''4,293 3,730'
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| -Projected benefit obligation .. .$ 89,846", $ 79,213 $ _, $ . _ '* (3:1.14)
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| 'Expected 'return on:plan assets. . (4,101)," (3,428),
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| Accumulated benefit . . ,
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| Amortization of unrecognized :
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| obligation ......... ... 68;302, 62,339 ',,
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| 'Transition'obligation, net%. ..... ',. ...... '57 . 57 57 Fair value of plan assets .... 54,992' 47,869, --
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| Prior service costs ................... 57T 31 131 Pension Plans With an Accumulated 1,340 Actuarial loss, net ......... ........... 1,855 1,.813 Benefit Obligation In Excess ,
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| of Plan Assets: , ' - - Curtailments, settlements 'and special Projected benefit obligation .- -$-89,846 $ 79,213 $ - $. - termination benefits ......... i...: .:. 1,486 - , . -
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| Accumulated beiiefit Net periodic cost'.....'.....'...'.::.. . . $ 7,486 $ 6,01i 1 $ 4,864' obligation .............. 68,302 62,339"' '- * -
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| Other Changes in Planh Assets and Benefit Fair value of plan assets ..... 54,992 47,869, * - -
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| Obigatons .Recognized inRegulatory Assets:
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| Post-retirement Plan's With an Current year actuarial loss .......... $ 3,578 $ - $ -
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| Accumulated Post-retirement Benefit Obligation InExcess Amortization of actuarial loss ........ "... (1,855). - --.
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| of Plan Assets: 'Current year priorsei:vice cost . ' : "34'.
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| Accumulated post-retirement ,Amortization'oi prior service cost....-. (57) , -. , ' -
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| benefit obligation ........ $ - $ - $ 8,596, $. 7,931 Amortization of transition obligation ..... ' (57). "'-'
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| Fair value of plan assets ......
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| Total recognizedin regulatory assets....... $ 1,643 $'$ -- $ -
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| Weighted-Average Actuarial Assumptions used to Total recognized innet periodic cost . , , .
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| Determine Net Periodic and regulator* assets .':
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| . ....... $ 9,129 $ 6,011 $ 4,864 Benefit Obligation: Weight ed-Average Actuarial Assuriiptions.
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| Discount rate ............. 6.15% 5.70% . 6.05% 5.80% ..used to Determine Net Periodic;Cost:
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| Compensation rate increase .. 4.00% 3.25% , * - -. - Discount rate. '. . ... 5.70% 5.75% . 6.00%
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| Expectedilong-term ret.urn on planassets .. :. 8.25% ,,. 8.25% . 8.75%
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| Compensation rate increase*...,, .', ' " 3.25%,- -325% 3.00%
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| Wolf Creek uses a measurement date of December 1 for the majority of its pension and post-retirement benefit, plans..
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| Post-retirement Benefits Wolf Creek uses an' interest rate yield curve to make judgments Year Ended December 31, 2007 . 2006 2005 pursuant to EITF.Topic No. D-,36, "Selection 'bf Discoun~t Rates
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| (")""lars inThousands)
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| Used for MeasuningDefined Benefit Pension Obligations and Componrients0of'NetPeriodic- Cost:
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| Obligations of Post Retirement Benefit Plans Other Than Serice'cost,. .. .. :. .... . ' $ :234 : $ 248 $ ' '238 Pensions." The yield curve is constructed based on the yields on Interest cost ...... . . "'- 435 ',' 4i2' ,- .384 over 500 high-quality, non-callable corporate bonds with Expected return on plan assets . . ' . " -- . .. ,
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| maturities, between zero and 30. years. A theoretical spot rate .Amortization of unrecognized: -
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| curve donstructed from thig Yield ctirve is then used to discount Transition obligation, net .. . ... .... ,- .58 , 58 ' '58 the annual benefit cash flows of Wolf Creek's pension .,plan Prior service costs ...........
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| 'Actuarial ldsi, net. . 191 ' 196. , 170 and develop a single-,point discount rate matching the plan's payout structure. : . Curtailments, settlements and special
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| - termination benefits :,J.... 259, The prior service cost is amortized.on a straightline basis over Net periiodiccost :.... ...... $ 1177 $94' ' $ 850 the average future service of the active 'employees :(plan Other'Changes in'Plan Assets and Benefit participants) benefiting under the plan at the time' of the '-Obligatidns Recognized in Regulatory Assets: ,
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| amendment: The net actuarial loss subject to amortizationr is Currenteauactuarial loss $ 786 ' $ ,- -
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| 'amortized on a straight-line basis over the average future ser.vice Amortizition of actuarial loss ..... ' (191)'. . -
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| of active plan participants- benefiting under the plan, without Current,year, prior service cost
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| . -7 .
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| application of the amortization corridOr'descri;ed in SFA'S Nos. Amortizationof prioirservice. cost.:'.',
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| 87 and 106. Amortization of transition obligation (58) - -
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| Total recognized in regulatory assets ...... $ 537 $ - -$
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| Total recognized in net'periodic cost and regulatory assets $ 1,714 $ 914 $ 850 Weighted-Average Actu-arial Assumptions used to Determine Net Periodic Cost:. ',.
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| Discount rate.... .................. 5.80% 5.75% 6.00%
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| Expected long-term return on pLan assets.' ' - - -
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| Compensation rate increase..,............- - -
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| 64
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| | |
| Westar Energy 1 2007 Annual Report . ..........
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| In January 2007, Wolf Creek Nuclear Operating Corporation Target Allocations" Plan Assets offered a selective retirement incentive to certain employees. Asset Category 2008 2007 2006 The incentive increased the pension benefit for eligible Pension Plans:
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| employees who elected retirement. This resulted in $1.5 million Equity securities . . "."
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| .. . 65% 67% 63%
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| in additional pension benefits and $0.3 million in.additional Debt securities.. 35% 28% 34%
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| post-retirement benefits for the year ended December 31, 2007. .Cash .................. ............. 0% 5% 3%
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| The estimated amounts that will be amortized from regulatory Total .............................. 100% 100%
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| assets into net periodic benefit cost in 2008 are as follows:
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| The Wolf Creek pension plan investment strategy supports the Other Pension Post-retirement objective of the fund, which is to earn the highest possible return Benefits Benefits on plan assets consistent with a reasonable and prudent level of (in Thousands) risk. Investments are diversified across classes, sectors and Actuarial loss. ............ . . $ 1,640 $ 219 manager style, to maximize returns and to minimize the risk of or service cost 57 -
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| large losses. Wolf Creek delegates investment managenment to Transition obligation ................. ..... .. ... 57 58' specialists in each asset class and where appropriate, provides Total ..................... $ 1,754 $ 277 the investment manager with specific guidelines, which include allowable and/or prohibited investment types. We measure and The expected long-term rate of return on plan assets is based on monitor investment risk on an ongoing basis through quarterly historical and projected rates of return for, current and planned investment portfolio reviews.
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| asset classes in the plans' investment portfolio. Assumed Pension Benefits ., Post-retirement Benefits projected rates of.return for each asset class were selected after To/(From) , To/(From) analyzing long-term historical experience and future expecta- To/(From) Company ,iToI(From)i Company Expected Cash Flows Trust Assets , ,. Trust,. Assets tions of the volatility of the various asset classes. Basedion target (In Millions) asset allocations for each asset class, the overall expected rate of return for the portfolio was developed, adjusted for historical Expected contributions:
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| 2008 ................... $ 5.3 $ 0.2 $ - $ 0.6 and expected experience of active portfolio managen-fent results Expected benefit payments:
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| compared to benchmark returns and for the effect of expenses 2008 .................... $ (2.0) $(0.2) . $ - $(0.6) paid from plan assets. 2009 ... ... ,... ,,. (1.7) (0.2) (.0.4)
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| For measurement purposes, the assumed annual health care 2010 ................. I (2.0): (0.2) - (0.5) 2011 ... ..... :.......... (2.4) ' (0.2) - (0.5) cost growth rates were as follows.
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| '2012 .................. (2.9) (0.2) - (0.5)
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| As of December 31, 2007 2006 2013-2017 .............. (24.2) (0.8) , - (3.2)'
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| Health care cost trend rate assumed for next year ............ 8.0% 9.0%
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| Rate to which the cost trend rate is assumed Savings Plan to decline (the ultimate trend rate) ...................... .5.0% 5.0%
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| Wolf Creek maintains a qualified 401(k) savings plan in which Year that the rate reaches the ultimate trend rate . ..... 2014 2011 most of its employees participate. They-match employees' The health care cost trend rate affects the projected. benefit contributions in cash up to specified maximum limits. Wolf obligation. A 1% change in assumed health care costq growth Creek's contribution to the plan is deposited with a trustee and
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| 'is invested at the direction of plan participants into one or more rates would have effects shown in the following table.
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| of the investment alternatives provided under the plan. KGE's One-Percentage- , One-Percentage- portion of expense associated with Wolf Creek's matching Point Increase Point Decrease contributions was $0.9 million in 2007, $0.9 million in 2006 and (InThousands)
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| $0.9 million in 2005.
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| Effect on total of service and interest cost ........ $ (6) $ 5 Effect on the present value of the'projected '
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| benefit. obligation .................... I......... 1(44) 33 14. COMMITMENTS AND CONTINGENCIES The asset allocation for the pension plans at the end of 200)7and Purchase Orders and Contracts 2006, and the target allocation for 2008, by asset category are as As part of our ongoing operations and construction program, shown in the following table. we have purchase orders and contracts, excluding fuel, which is discussed below under ".- Purchased Power andFuel Commit-ments,"* that have, an unexpended balance of approximately
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| $818.2 million as of December 31, 2007, of which $608.2 million has been committed. The $608.2 million commitment relates to purchase obligations issued and outstandingat year-end. ,
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| 65
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| ......... Westar Energy 1 2007 Annual Report The yearly-detail of the aggregate amount of required paymfiits OnMarch 15, 2005; the EPA issued.the Clean Air Mercury Rule.
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| as.of December 31, 2007, was as follows.' The rule caps permanently,' and seeks to reduce, the amount of mercury that may be emitted from coal-fired power plants. The Committed Amount rule requites implementation of reductions in two phases, .the (in Thousands) first starting in 2010.. We 'received an allocation of mercury 2008.. $489,780 emission allowances: pursuant to the rule., Preliminary testing 2 0 09.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 3 ,28 1 indicates that the expected allocation of allowances will be 2010 ......... ....... 12,911 Thereafter ..... 7 ..... ................ : ........ : ........... 12,263 insufficient to aOlW ius to operate our coal-fired 'iufits in complianice'with the first phase requirements of the rule. If the Total amount comm itted ..... :$.. ......... . ....... . ....... . .... . $608,235 allocaf*d allowances are insufficient, we may need t6 purchase allowances in: the market, install additional equipment or take Clean Air Act other actions, to reduce our mercury emissions. However, on We must 'comrply with the Clean Air Act, state 'laws and February 8, 2008,..the U.S. District Court of Appeals for the implemerifihg re'gulations that impose, 'among other things, District of Columbia vacated the Clean Air Mercury Rule. While limifatir6ns '6n' pollutants generated during our ope'ra'tions, the ultimate impact of this ruling on our operations is currently incluhing sulfur dioxide (SO 2), particulate matter and nitrogen unknown, we believe that mercury emissions controls may be oxides (NOx)v. In 'ddition, we must comply with the piovisions required: iný the future and that the costs, to comply with these of'the Clea'fAir AcAmeridments of 1990 that require a two- requirements may be material.
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| lhasl reduction in certain' emiissions. We have in stalled contin'-
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| uous monitoring and reporting equipment in order to 'meet New Source Review Investigation .
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| týese-requiremen.ts. Under Section 114(a) of the Clean AirAct (Section 114); the EPA is 'cOndtlcting investigations' nationwide to determine whether Environmental Projects m'odifications at coal-fired power plants are subject to the'New We have identified the potential for us to make up to $1.2 billion Source Review permittting pr6 gram or New Source Performance of capital expendituies at our power plants for environmental Staridards:.These investigý:tions' focus on 'whether pfojects'at air emissions projects during approximately the next eight to ten coal-fired "plants were routine maintenance or whether the years. This estimate could increase depending on the resolution project9 were substantial' m'odifications that could reasonably of the EPA New Source Review Investigation (NSR Investiga- have been expected to result in a significant net'increase' in tion) described below. In addition to the capital investment, in emissions. The New Source Review program requires companies the event we install new equipment as a result of the NSR to obtain permits and, if necessary, install control. equipment to Investigation, we anticipate that we would incur significant address emissions when making a major modification or a annual expense to operate and maintain the equipment and the change in operation if.either is expected to cause a significant operation of the equipment would reduce net production from net increase in emissions.
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| our plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required The EPA requested information from us under Section 114 is uncertain. Both the timing and the nature of required invest- regarding projects and maintenance activities -that have been ments depend on specific outcomes that result from interpretation conducted since 1980 at three coal-fired plants we operate.'On of .existing regulations, new regulations, legislation and the January 22, 2004, the EPA notified us that certain projects resolution of the NSR Investigation described below. In addition, completed at-Jeffrey Energy Center violated certain requpiirements the. availability of equipment and contractors can affect the of th' New Source Review program. , .'
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| timing and ultimate cost of the equipment. We have been in discussions with .the EPA and the Department The environmental cost recovery rider (ECRR) allows for the of Justie.,(DOJ'c'nbeming this matter in an attempt to reach a timely inclusion in rate's of capital expenditures tied directly to settlement. We expect that any settlement could require us to environmental improvements, including those required by the update or install emissions controls at Jeffrey Energy Center.
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| Additionally, we might be required to update or install emissions Clean Air Act. However, increased operating and maintenance costs other than expenses related to p0oduction-related con- controls at our other coal-fired plants, pay fines or penalties, or take other remedial ac'tion.'If settlemerft discussions fail, DOJ sumables can be recovered only. through a change in base -rates may donsider-whether't& pursue an enforcement action against following a rate review.
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| us in federal'district court. Our ultimate costs to resolve the NSR On Auigust 29, 2007, we, filed an application with the Kansas Investigation could be material. We believe' that costs related to Department of Health and Environment (KDHE) to implement updating or installing emissions controls would qualify for a plan toý improve efficiencay and; to install new equipment to recovery through the ECRR. If, however, a penalty is assessed Center. The reduce regulated 'emissions from. Jeffrey Energy against us, the penalty could be material and may not be projects outlined in a proposed agreement filed with the KDHE recovered in rates. We are not able to estimate the possible loss on August 30, 2007,: are designed to meet requirements' of the or range of loss at this time.
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| Clean Air Visibility Rule and reduce emissions over our entire generating fleet by eliminating more than 70% of SO 2 and reducing nitrous oxides and particulates between 50% and 65%.
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| 66
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| Westar Energy 1'2007 Annual Report .... ...
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| Manufactured Gas Sites schedule; will be through 2045. The,NRC requires, that funds to We have been-identified as being respohsible for clean-ups of a meet its nuclear, decommissioning funding 'assurance require-number of formermanufactured gas site's located' in Kansas'and ment be in our-nuclear decommissibning fund by the time our Missouri. We and the KDHE entered into a 'consent agreýrment license expires. We believe that the KCC:approved funding level in 1994 governing all future work at the Kinsas sites. Under the will also be. sufficient to 'meet the NRC .minimiim financial terms of the consent agreement, we agreed to inVestigate and, if assurance requirement. Ourlconsolidated results of operations.
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| necessary, remediate these' Sites. Pursuant to an environmental would be materially. adversely. affected if we are not allowed to indemnity agreement with ONEOK, Inc. (ONEOK), the cufrrent recover in utility~rates the full amount of the funding requirement.
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| owner of some of the sites, ONEOK assumed total liability for We recovered in rates and deposited jn an external trust fund remediation of seven sites, and vWe share liability for remediation approximately $2.9 million for nuclear decommissioni0 - ii 2007 with ONEOK for five sites. Our total liability for the five shared and $3.9 million in 2006 and 2005. We recorid our investment in sites is capped at $3.8 million. We' have sole responsibility fdr the 'nuclear decommmissiohing fund at fair value. The fair value remediation With respect to three sites: aIpproximated $122.3 million' as 6f December 31,"20*07, and Our liability for the former manufactured gas sites identified in $111.1 million as of December'31, 2006.
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| Missouri is limited to $7.5 million by the terms of an environ, Storage of Spent Nuclear Fuel" ,
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| mental indemnity -agreement with the purchaser of our former Under the Nuclear Waste Policy Act of 1982,the Departmenf of Missouri assets.
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| Energy (DOE) is responsible for the perm.anent disposal of Nuclear Decommissioning spent nuclear fuel. As required byjfeder'l flw, the Wolf Creek Nuclear'decommissioning is' a nucfear industry term for the co-Iowners entered into a standard contract with thý 'DOE in permanent shutdown of a nuclear power plant and the removal 1984 in which the DOE piomised tobegin accepting fro9m of radioactive components in accordance with the Nuclear commercial nuclear power plants their used nuclear fuel for Regulatory Commission (NRC) requirements. The NRC will ter- disposal beginning in early 1998. In return, Wolf Creek pays into minate a plant's license and release the property for unrestricted a federal Nuclear Waste Funid admlufistered by'the DOE a quar-use when a company has reduced the residual radioactivity of a terly fee for the future disposal of spent nuclearr'fuel. Oui share nuclear plant to a level mandated by the NRC.The NRC.requires of the fee was $4.4 million in 2007, $4.1 milion in 2006"and companies with nuclear plants to prepare formal financial plans $3.8 million in 2005 and is calcul~ated a's one-tenth of a cen't for to fund nuclear decommissioning. These, plans are designed each kilowatt-ho'ur of net nuclear generation delivered to cus-so that sufficient funds required for nuclear decommissioning tomers. We include these disposal costs in fuel and purchased will be accumulated prior to the expiration of the license of power expenses..
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| the, related nuclear power plant. Wolf Creek. files a nuclear rin-2002, the Yucca Mountain site in Nevada was approved, for decommissioning and dismantlement study with the KCC every the development of a nuclear waste repository'for the disposAl three years. ,
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| ." ... o'fspent 'nUclear' fuel and high level nuclear-Waste from the The KCC reviews nuclear decommissioning plans in two phases. nation's':defense activities.' This action allows'the DOE to apply Phase one is the approval of th6 revised nuclear decommission- to the NRC to license the project. The DOE announced in ing study, the current-year. funding and future fu.nding. Phase December 2007, that it planned' t6 submit a license ap5plication two involves the review and approval by the KCC of a,"fund- *fto'fhe"NRl' no'later than June-30, 20088. However,' in January ing schedule" by the owner of the nuclear facility detailing how 2008, POE 'officials'.announced that that filihg'date w*as ih it plans to fund the future-year dollar amount of its pro rafa jeopardy because' of fiscal year 2008 budget allocatido reductions.
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| share of the plant. The '"ipening,'6f the Yucca Mountain site has -beeii celayed many time§ 'and could be delayed further due' to litigation and In 2005, Wolf Creek filed an updated nuclear decommissioning other issues related to the site as a Permanerit repository for site study with the KCC. Based on the site study of decommission- speni nuclear fuel. Wolf Creek has on-site temporary storage for ing costs, including the costs of decontamination, dismantling spent nuclear fuel e'pected to be geri'rated by W6of Creek a'd site restoration, our share of such costs is estimated to be through 2025.'
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| $243.3 million. This amount compares to the 2002 site study Nuclear Insurance estimate for decommissioning costs of $220.0 million. The site study cost estimate represents the estimate to decommission We maintain nuclear insurance for Wolf Creek in four areas:
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| Wolf Creek' as of the site study year. The actual 'nuciear liability, worker radiation, property and accidental outage. These decommissioning costs may vary from the estimates because 'of policies'contain certain industry'stahnard exclusions, ifhcludinrg changes in regulations, technology and chainges4 in costs for but not'limited to, ordinar' wear and fear and war."Both'the labor, materials.and equipment. ,
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| nuclear liability and property insurance prografm' 'subscribed to by members of the nuclear power generating industry'include Electric rates charged'to ctstomeirs provide for recovery of these industry aggregate limits for noh-ceitified acts, as defined by the nuclear dec6mmissioning costs over the life of Wolf Creek, Terrbrismn Risk Insurance Act, of terrorismn-related losses, includ-which, as determined by the KCC for purposes -of the funding ing replahement power costs. An iuidustry agiegate limit of 67
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| ..... .. Westar Energy ' 2007 Annual Report
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| $300.0 million exists forliability claims, regardless of the 'iumber Although we maintain various insurance policies to provide of non-certifiedacts affecting Wolf Creek or any other nuclear coverage*for potential. losses and -liabilities resulting from an energy liability policy, or the number of policies in place. An" accident or an extended oui~tage, our insutrance coverage may not industry aggregate limit of $3.2 billion. plus any. reinsurance .be adequate, to cover .the costs that. could result from a, recoverable ,by Nuclear- Electric Insurance Limited (NEIL), our catastrophic. accicdent pr extended outage at Wolf Creek. Any
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| *insurance provider,- exists for property claims, including acci-. substantial losses not covered by insurance, to. the extent not dental outage power costs for acts of terrorism affecting Wolf recoverable through rates, would have a material, adverse effect Creek or any other nuclear energy facility property policy within on our consolidatedfinancial-condition and results of operations.
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| twelve months from the date of the first act. These limits are the Purchased Power and Fuel Commitments maximum amount to be paid'to members who sustain losses or damages fromn these types of terrorist acts. For certified acts of To supply a portion of the fuel requirements for our generating te rrism, the individual policy limits apply. In addition, industry- plants, we have entered into various commitments to obtain wide retrospective assessment krograms (discuised below) carn nuclear fuel and coal. Some of these contracts contain provisions apSply once these insurance' programs have been exhiusted. for price escalation and minimum purchase commitments. As of December 31, 2007, our share of. Wolf Creek's nuclear 'fuel Nuclear Liability Insurance commitments were approximately $61.1 million for uranium Pursuant to the Price-Anderson Act, which was" reauthonzed concentrates expiring in 2016,$9.3 million for conversion expiring through December 31, 2025, by the Energy Policy Act of 2005, in 2016, $153.4 million for enrichment expiring at various times we are required to insure against public liability claims resulting through 2024 and $50.0 million for fabrication in 2024.
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| from nuclear incidents to the full limit of public liability; which is As of Decemb er' 31, 2007, our coal and coal transportation currently approximately $10.8 billion. This limit of liability.
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| c6nsists 'of 'the maximum available commercial insurance of contract commitments in 2007, dollars under the remaining terms of the contracts were approximately $1.4 billion. The
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| $300.0 'million, and the remaining $10.5 billion is provided largest contract' expires in 2020, with the remaining contracts through mandatorypaitcipatioqnih an industry-wide retrospec-expiring at various times through. 2013.
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| tive assessmient program. Under this retrospective assessment program, the 6-2-,ners of' Wolf"Creek Nuclear Operating As of December 31, 2007, ou: r'natural gas transportation commit-C&4opration (WCNOC) can be assessed a total of $100.6 million inents in 2007 dollars Linder the remaining terms of the contracts (cur share is $47.3 million), payable at no more than $15.0 million were approximately $166:8 million. The natural gas trarisporta-(our share is $7.1 million) per.incident per year, per reactor. Both tion'contracts provide firm service t6's'e~veral of our natural gas the 'total arid yearly assessment are subject to 'an inflation burning facilities and expire at various times through 2028.'
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| adjustment based on the Consumer Price Index and apAiicable premium taxes. This assessment also applies in excess of-our We have entered into power purchase agreements with the worker radiation claims insurance. The next scheduled inflation owners' of two, separate wind powered electric generating adjustment is scheduled for July 1,.2008. In addition,. Congress facilities located in Kansas with a combined capacity of 146 MW.
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| could impose additional revenue-raising measures to pay, claims.. The agreements have a term of 20 years and provide for our receipt-and purchase 'of the energy Oroduced at a fixed price ýer Nuclear'lProperty Insurance . -
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| unit of output. We estimate"'that'our annual cost for energy.
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| The owners of Wolf Creek carry decontamination liability, purchased" 6m:' these'" wind' farms 'wvill be" approximately premature nuclear decommissioning liability and property $21*.0 rriillion. We expect the facilities'to be in service'bythe end damage insurance for Wolf Creek totaling approximately of 2008.: .
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| $2.8 billion (our share is $1.3 billion). This insurance is provided by NEIL. In the event of an accident, insurance proceeds must, .15. ASSET RETIREMENT OBLIGATIONS first be used for reactor stabilization and site .decontamination in accordance with a plan mandated-by the NRC. Ourshare.of Legal Liability , -
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| any remaining proceeds can be used to pay for property damage In: accordance with SFAS -No. 143, "Accounting. for Asset or decontamination expenses or, if certain requirements are Retirement Obligations" and FIN 47, 'Accounting for Condi-met, including nuclear decommissioning the plant, toward a tional Asset Retirement Obligations", we have recognized legal shortfall in the nuclear decommissioning trust fund.. obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development.or normal Accidental Nuclear Outage Insurance operation of such assets. Concurrent with the recognition of the The owners also carry additional insurance with NEIL to cover liability, the estimated cost of an asset retirement obligation is costs 'of replacement power and other extra expenses incurred capitalized and depreciated over the remaining life of the asset.
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| during a prolonged outage'resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any We initially recorded asset retirement obligations at fair value of the nuclear plants insured under the NEIL policies, we may for the estimated cost to decommission Wolf Creek (our 47%
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| be subject to retrospective assessments under the current policies share). dispose of asbestos insulating material at our power of approximately.$25.7 million (our share is $12.1 million). plants, remediate ash disposal pqnds and. dispose. of poly-chlorinated biphenyl (PCB) contaminated oil.
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| 68
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| Westar.Energy I 2007 Annual Report ............
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| The following table summfarizes our -legal asset 'retirement " Non-Legal Liability - Cost of Removal 9'' .'
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| obligations included on our consolidated balance sheets in. - We-recover in rateý;as a icomponent of depreciation, the costs to lofig-termý iiabilities. dispose 'Qf' utility ,planit assets that do not 'represent legal As of December 31, , 2007 " 2006 retirement obligations. As of December 31;'2007 and 2006, we (InThousands),' , had" $25.2 million and' $13.4 -million, respectivel , int amounts Beginning asset retirement obligations ............ $ -,84,192 $ 129,888 collec'ted, bit urispe'nt, fot removal costs classified asa'regulatory Liabilities incurred .. ... .. .. ....... 85 . 218 liability.'The nPt amount related to non-legal-retiremenit costs Liabilities settled ....... .. ........... , ..... (987) . '(737.)
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| Q. can'flucttiate based 'or/amounts'recOvered in rates~conmpared to Accretion expense .... .................. .5,421 8,327 q,
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| remOval'costs iricurred' ' - ' -
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| Revision to nuclear'decommissioning . .. .
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| * ARO.Liability:.. ....... -- '53,504)
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| : 16. LEGAL PROCEEDINGS - " "
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| 'Ending asset retirement obligations ............ $ 88711 $ 84,192.
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| We' and,' our subsidia-ies are involved ''in various 'legal, In September 2006, WCNOC, the, operating company for-Wolf. - environmental and "regulatory' proceedings; -We believe' that Creek, filed a request -for a 20 yvjr extension of Wolf Creek's adequate "provisions have .been made and accordingly believe operating license with the NRC. Currently, the opera ting license that the' ultimate. dispositioh 'of such matters- will. not 'have a will expire in 2025. The NRC's milestone schedule for its review material adverse effect on'our consolidated finsancial statements:
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| "-*' .,. . -v ,' '
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| * of this request projects a decision by late 2008. The NRC may See also Notes'14 and .17 for, disc'ussionoof allegecld violations of impose experience conditions as part of any'alPrVal. Based o6.the the Clean Air Act, and potential liabilities to David C.'Wittig~anid of other nuclear' plant operators, we 'believe that the Douglas T. Lake-:
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| NRC will ultimately approve the request:l Therefore, we d'ecreased our asset retirement obligation, by $5315 million to reflect the' revision in our estimate of the timing t6fehcash 'flox*s that we 17. POTENTIAL-LIABILITIES TO-,DAVID C. WITTIG will incur to satisfy this obligation. -, . - AND DOUGLAST. LAKE "'" ' ... - - -
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| In March 2005, the FASB issued FIN 47 The inttrpretatiori
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| .David C .ttig, our former chairman of the board, president clarified the term "conditional- asset retiremrent obligation" as and chijef executive officer,'resigned from .all -of his positions used'in SFAS NO. 143. Conditional asset retirement obligation. with us and our, a-ffiliates on. November,.,22, 2002. On. May 7, 2003, '6ur board of directors:deterniined that the employment of refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of Settement~are conditional Mr. Wtti~gwas .terminated as, of November 22,. 2002, for cause.
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| on a future event that may or may not be within the control of Douglas T. Lake, our.-former 'executiVe vice.,president, chief the eritity. We, determined the conditional ass'et retiremfient strategic, officer and- ember, of :the board, was 'pla*ed on' obligations that are within the scope of FIN! 47'to 'iiiclu'de administrative leave Ifromi all of his, positions with us and- our disposal of asbestos insulating material at ouf power plants, affiliates on.December 6i.2002..On June. 12, 2003,.our board.of remediation of ash disposal ponds and the. disposal.,of PCB- direc6tors termiiiated the employment of-Mr. Lake for cause.
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| .On:June 13, 2003,-we filed a demand for'arbitration with' the, contamihnated oil. We -adopted the provisions of FIN.47 for the ,
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| year ehdedDecember'31, 2005.-:. . .' .- - ,. , "Am Ie n' Arbfi'*aition 'Associationi 'asserting 'claims againsit
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| .Mr.Wittlg and'Mr* Lake ansmig out of theirprevious employmednt The amount of the -retireinmnt obligatior?:relat'ed' 4to-.aObestos
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| -cisp6sal was recorded as of 1990, the date when the Entiron-with us. Mrý Wittig and Mr. Lake filed counterclaiins against us Emnission-,
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| mfiental Protectioii AgeIncy published the "National in the arbitration- alleging substantial d.amages, related- to the Standards for Hazardous Air Pollutants: Asbestos -NESHAP termiha'i6-n'of their eriiplOy-6ni ent and the- publihcaation of the Revision; Final Rule." '
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| rfpott 6fa' special committee of Our boaid of direcors. We ifit~nid to vigorously defend against'-these clais. The arbitration has We'operate, as permitted by the state6f Kaiisas, ash landfills at ben stayed' pending final' resolutionof crimiinal charges filed byj several of our power plants: The ash laiidfillsretirement the .United States Attorhny's', Offic" against' Mr.ý Wittig and obligation was' deterniined based upon the date each lahtdfill. Mr. Lake in u~s. District' Court in .the District of' Kansas. On was'oiginally placed'in service. Septe"bher 12, 20051, a jur nviced Mr. Wittig and Mr. Lake 'on the cha6rgs relevant to eac6 f thern. Oh Janiuary 5, 2007, these PCB-contaminated, oil is contained within company electrical,
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| 'cbrivicticns were Ov'eturned .by U.S. Tenth Circuit Court 'of equipment, primarily transformers. The PCB retirement-obliga-Appeals ifo1o10wing appe*a*ls. by Mr.`Wittig, and Mr. Lake. On tion was determined based upon the' PCB regulationsl'"tft ArliT30, 2007, the governmentt ainounlcedithat lt had'dededdd' originally became. effective in 1978. -,-' : " " * ',
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| to retry ýertainycnargs against Mt. Wiffig and Mr. Lake'and'the The recording of the oblikaii6n for re~ulated operatioris has no retrial. is currently schheduled to. com fience on September 9, income statement impact due to the deferral of the adjustmnOts' 2008. We are uniable'to.pre dic'thte ltirtate impahct Of thi s atter through the establishment of a regultory assgt pursIuant to on our consolidated financial statements. .' " -
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| SFAS No. 71.
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| 69
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| Westar Energy I 2007 Annual Report As of December 31, 2007, we had accrued :liabilitiesitotahlig 18. GUARDIAN INTERNATIONAL PREFERRED STOCK
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| $76.0 million for compensation :not .yet paid to Mr. Wittig and On March 6,2006, Guardianwas acquired byDevcon International Mr. Lake under various agreements and plans. The compensation' Corporation in a merger. In connection with this. merger,, we includes' RSU awards, deferred vested, .shares, deferred. RSU received approximately $23.2 million for 15,214 shares' of awards, deferred vested stock for compensation, executivesalary Guardian Series D preferred stock and 8,0,00 shares of Guardian continuation plan benefits, potential obligations -related to the Series' E preferhed"'stock held of record' by us. We6 beneficially cash. received for Guardian -International, Inc.. (Guardian) owned 354.4 shares of the Guardian Series D preferred stock preferred stock, and,, in the case of Mr., Wittig, .benefits arising and, 312.9 shares of the Guardian Series E preferred stock. We from a split dollar life insu ance agreement. The amount of our recognized a gain of approximately $0.3 million as a result .of obligation to Mr. Wittig related t6 a split dollar life insurance this transaction. Certain current and forfie"rofficer's bneficially agreement is subject to adjustment at.,the end of each quarter owned the remaining shares. Of these shares, 14,094 shares of based on the total return to our shareholderdsirronmi the date 'of Guardian Series D preferred stock and 7,276 shares of Guardian that 'agreement. The total return considers-the change in our Series E preferred stock were beneficially owned by Mr. Wittig stock ,price and accumulated, dividends. These compensation-arid Mi] Ihake. The'otiinership 'o'f the' shares benefidially owned related accruals ,are included in loing-term liabilities on the by eithef Mr. Wittig or 'Mr. Lake, as Wiell as related dividends, consolidated balance sheets'with,,a portion recorded as a' and'fiow thie cash'received'fbr the .sharle's, is disputed and'is'the component of paid in capital.The amount accrued will increase subject 8f the'-arbitration proceeding with Mr. Wittig arid Mrf.
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| annually for future dividends on deferred RSU awards and Lake idisctssed ini'Note 17,"Poferitial Liabilities to David C.
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| increases in amounts that may be due under the executive salary A.". Wittig and Douglas T. Lake."As A re'slt 'of this trahsaction, we continuation plan. '
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| rio l*nger hold ýn Gu aitdia '''s'cuIties' '
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| In addition, through December 31, 2007, we have accrued
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| $7.3 million for legal fees and expenses incurred by Mr.,Wittig 19..COMMON AND PREFERRED STOCK and Mr. Lake' that are recorded in'Accquntsý.payable "on our consolidated balance sheets. These legal fees and expenses were Activity in Westar Energy's stock acdofints for'each'of the thriee incurred by Mr."Wittig'and Mr'.Lake in the defense of the,criminal years ended December 31 is as follows:
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| charges filed by the'United"'Stdtes Atdmrey's Office and the Cumulative, subsequent apoeal of' c6nvicti66n 'on th&ge- charges. We have preferred Common, stock shares stock shares filed law.suitS against Mr. Wittig and.Mr,.Lake claiming'that the Balance'at Ddcembe*r31, 2004 ...... 214,363 86,029,721 legal-.fees andt epeinses they hav& incbifted :re unreasonable Issuanceof commo'n stock .... .: '... '" -- 805,650 and excessive and we have asked- the"'courts to detdrmirie the amount of the legal fees and expenses that were reasonablyk' Balance at December 31, 2005 . 214,363 ' 86,835,371 incurred and'vhich we have an obligation'to pay, 'as well'as'the Issuance of common stock .. .................... 559,515 amountof the legal fees and expenses tlhat'we have anfobligation Balance'at December 31 2006 ....-. :...-........ ....... 214,363 87,394,886 to advance 'in the future. The U.S. District Court in the lawsbit Isshance of'com'nbn stock* .... ' - '' 8,068,294 against Mr. Lake'orderedi.us to pay approximately $3.2 million of Balanc4,atDecem6er,31,2007. . .. ...... ...
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| . ' 214,363 '95,463,180 the. past unpaid fees and expenses and directed us to advance'.
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| future fees and expe elate8i taes totrne retrial onda current basis at counsel's customary hourly rates. We, appealedthi's order to WestarEneigy's articles,.of incorporation, as, amended, provide the U.S: Tenth'fircuit'Court of Appeals and 'asked for a stay of for 150,000,000 authorized shares of common stock. As of th'e portion of th ordei related t6 the .payre f -past unpaid December,31, 2007, we had 95,463;180' shares issued and outstanding;: . . ,, .,
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| fees, and expenses. On October 18, 2007, the U.S. Tenth CifcUit Court of.Appeals denied our request'for a stay of the poirion of. Westar Energy has a direct stock, purchase plan (DSPP). Shares
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| ,the order related to the payment of past unpaid fees" and' sold' pursuant to the .DSPP may be either original issue shares or expenses. Pursuant to the D.'strictCourt's order, we ,hayepaid shares. purchased, in the open market. During 2007, a total of approximately $3.2 million of Mr. Lake'S'past unopaid 'fees and .482,981 shares were issued by Westar Energy.through the DSPP expenses and we have paid approximately $0.9 million for fees and other 'stock based 'plans operated under the 1996, LTISA and expenses incurred by Mr. Lake in 2007. The issueson appea Plan. As of December 31, 2007, a total of 4,339,963 shares were other than'our request forda stay retafinih pending befof 't'heýU.S. available under the DSPP registration statement:
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| Tenth Circdit Coui't of Appeals. The lawsuit against ML Wittig is pendinig in Sha`wnee' Count'yi, Kansas 'DistrictCourt. A2sp.c'ial Common Stock Issuance .' . ,.. '
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| master appointed by the Distfrict Court submitted ai rapo-f in On April 12, 2007, we entered' into a Sales Agency Financing Noyember'"2007 finding that $2.5 *iillio'n6f the le'gal'fees'-and 'Agreement with BNY 'Capital Markets,, Inc. (BNYCMI). As of expenses incurred by Mrý Wttig'were 'reasonable and should be July i2 2007, we hard sold $100.0 .'million of common stock paid by us. We submitted obljections tothe report and the matter (3,701,)568 sh7dres) through BNYCMI, as agent, pu'rs.uant to the is now being reviewed by the Distridt Court.We expect to ii-'r; agreement. We-feceived' $99.0 million in proceeds net of'a substantial additional expenses for legal fees and expenses that commission paid to BNYCMI equal to 1% of the sales price of will be incurred by Mr. Wittig and Mr. Lake, but are unable to all shares it sold under the agreement. We used the proceeds to estimate the amount for which we may ultimately be responsible. repay borrowings under our revolving credit facility, which is the 70
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| Westar Energy I 2007 Annual Report primary liquidity facility for acquiring capital equipment, and any which is the primary liquidity facility for acquiring, capital remainder was used for working capital and general corporate equipment, and any remainder was used for working capital purposes. and general corporate purposes.
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| On August 24, 2007, we entered into a "ubsequent Sales Agency Preferred Stock Not Subject.to Mandatory Redemption Financing Agreement with BNYCMI. 'Under the' terms of the Westar Energy's cumulative preferred stock is redeemable in whole agreement, we may offer and sell shares of our common stock or in part on 30 to 60 days' notice at our option:'The table -below from time to time through BNYCMI, as agent, up to an aggregate shows our redemption amount for alseries of preferred stock not of $200.0 million for.a period of no more than three years. We subject to mandatory redemption as of December 31, 2007:.
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| will pay BNYCMI a commission equal to 1% of the sales price of Total.
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| all shares sold under the agreemen.t. As, of December 31, 2007, Principal Call Cost we had. sold $20.0 million of common, stock (783,745 shares) Rate Shares Outstanding *Price Premium /" to Redeem through BNYCMI. We received $19.8 million in proceeds net of (Dollars in Tho6s~nd§)' , ,
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| commission, paid to BNYC.MI. We used the proceeds to repay 4.500%' 121,613 $12,161 " 108.00% $ 973- ',, $13,134 borrowings under our revolving credit, facility, which is the 4.250% 54,970 5,497 101.50% ' 82 : 5,579 primary liquidity facility for acquiring capital equipment, and 5.000% 37,780 3,778 102.00% 76 - 3,854 any remainder was used for working capital and general $21,436
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| $. $1,131 $22,567, corporate purposes. Pursuant to the same program, in the period January 1, 2008, through February 19,2008, we sold anadditional The provisions of Westar Energy's articles of incorporation, as 75,177 shares for $1.9 million, net of commission. amended, contain restrictions on the payment of dividends or the making of other distributions on its common stock while On November 15, 2007, we entered into a forward equity sale any preferred shares remain outstanding unless certain capital-agreement (forward sale agreement) with UBS AG, Londofi Branch ization ratios and other conditions are met. If the ratio of the (UBS), as forward purchaser, relating to 8.2 million shares of our capital represented by Westar Energy's common stock, including common stock. The forward sale agreement provides for' the premiums oii'its capital stock and its surplus accounts, to its sale of our.common stock within approximately twelve months total capital ard its surplus accounts at the end of the second at a stated settlement price. In connection with the forward sale month immediately preceding the date of the proposed payment agrementt, UBS borrowed an eqcial number of shares 6f our cif 'dividends,' 'adjusted to reflect the proposed payment common'stock from stock lencdei§'and sold the borrowed shares (capitalization'ratio), will be less than 20%, then the payment of to J.R Morgan Securities, Inc. (JPM) unider an'underwriting
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| ,the dividends on its common stock shall not exceed 50% of its agreement amongWestar EnergyiJPM and UBS Securities; LLC, net income available for. dividends, for the 12-month period
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| .s;Cb--m'anagers for the underwriters. The underwriters sub-ending with and including the second month immediately sequently offered the borrowed shares to the publiCat a:price precedihg the date of the proposed payffierint.If the capitalizati6n per share of $25.25.
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| ratio is 20%.or more but less than 25%; then;the payment of The use of a forward sale agreement allows us to avoid equity dividends -..on its common stocký, including, the proposed market uncertainty by pricing a stock offering under theft existing payment, shall not exceed 75% of its net income. available for market conditions, while mitigating share dilution by.postponing dividends for such .12-month period.. Except .to the ,extent the issuance of stock until funds are needed. Except in specified permitted above, no~payment or other.distribution maybe made circumstances or events that would require physical share that would reduce the;capitalization ratio to less than 25%. The settlement, we are able to elect to settle the forward sale agree- capitalization ratio is determined based on the unconsolidated mentby means of a physical share, cash or net share settlement balance sheet for Westar Energy. As of.December 31, 2007, the and are also able to elect to settle the agreement in whole, or in capitalization ratio was greater than 25%.
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| part, earlier than the stated maturity date at fixed. settlement So long as there are any outstandirig shares of Westar Ene!gy prices. Under a physical share or net share settlement, the prefeired stock, Westar Energy shall not without the.consent of maximum number of sharesithat are deliverable under the terms a majority of the shares of preferred stock or if more than one-of the forward sale agreement is limited to 8.2 million shares.
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| third of the outstanding shares of preferred stock vote negatively On December 28, 2007, we delivered 3.1.mnihon newiy'issued and without the consent of a percentage of anyandall classes shares of our common stock to UBS; and'received proceeds of required by law and Westar Energy's articles -of incorporation,
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| $75.0 million as partial settlement of the forward sale agreement. declare or pay any dividends- (other than .stock dividends or Additionally, on February 7, 2008, we delivered 2.1 ,million dividends applied by the. recipient to the' purchase'of additional shares and received proceeds of $50.0 million as partial settle- shares) or make any other distribution upon common stock ment of the -forward sale agreemuent..; Assuming gross share unless, immediately after such distribution or payment the sum settlement of all remaining shakes under the forward sale of Westar Energy's capital represented by its outstanding agreement, we could receive additional aggregate proceeds of common stock and its earned and any capital surplus shall not approximately $75.0 million, based on a forward price of $24.25 be less than $10.5 million plus an amount equal to twice the per share for 3.0 million shares. Proceeds from these offerings annual dividend requirement on all the then outstanding shares were used to repay borrowings under our revolving credit facility, of preferred stock.
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| 71
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| ............ Westar, Energy I 2007 Annual Report
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| : 20. LEASES Capital Leases.
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| We identify capital leases based on 'criteria in SFAS No. 13, Operating Leases "Accounting for Leases." For both vehicles and computer We lease office buildings, computer equipment, vehicles, rail equipment, new leases are signed each month based on the cars,"a generating facility and other property and equipment.
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| terms of master,lease agreements. The lease term for vehicles is These leases have various terms and expiration'dates ranging from 5 to 14 years depending on the type of vehicle. Computer from 1 to 22 years. equipmeiit has either a two- or.four-year term.
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| In determining lease expense, we recognize the effects of On April 1, 2007, we completed the purchase of Aquila, Inc.'s scheduled rent increases on a straight-line basis over the (Aquila) 8% leasehold interest in Jeffrey Energy Center for minimum lease term. The rental expense associated with the
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| $25.8 million and assumed the related lease obligation. This La, Cygne unit 2 operating lease includes an offset for the lease expires on January 3, 2019, dnd has a purchase option at amortization of the deferred gain on the sale-leaseback. The the end of the lease term. Based on current economic and rental expense and estimated commitments are as follows for other conditions, we 6xpect to exercise the purchase option.
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| the La Cygne unit 2 lease and other operating leases.
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| Based upon these expectations, we recorded a capital lease of Total $118.5 million:.
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| Y e LaCygne Unit 2 Operating Year Ended December 31, Lease() Leases Assets recorded under capital leases are listed below.
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| (InThousands)
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| Rental expense: December 3t ' 2007' 2006 12005 ....... .................. ..... .......... $ 23,481 $ 34,239 (InThousands) 2006 ............. ......................... 18,069 32,10 7 Vehicles................................ ........ $ 27,132 $30,009 2007 ............. ............. ........... 18,069 . 35,267. Computer equipament and software...... .......... 5,212 . 4,950 Future commitments: . - Jeffrey Energy Center 8% interest ......... ......... 118,538 -
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| 2008 .... .................................... $ 32,892 $,.48,067 Accumulated amortization ........................ (20,576) (18,115) 2009 ............................... ... . . 32,964. 47,176 Total capital leases ....................... .. $130,306 $16,844 2010 ... : ........... ...... ...... ....... I .. 33,041 45,870 2011 .............. .................. ...... . 33,122 43,800 2012 ........ .. ... "* .......... . ........ . 33,209 47,165 Capital lease, payments are currently treated as operating leases Thereafter............................... 289,475 .335,470 for rate making pu.rposes. Minimum annual rental payments, excluding administrative costs- such as property taxes, insurance Total future commitments :... ...... ............ $454,703 $567,548 and maintenance, under capital leases are listed below.
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| * The La Cygne unit'2 lease 'amountsare includled in ,the total operating leaies Total capital
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| .column. Year.Ended December 31, ' , Leases (in Thousands)
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| On June 30, 2005, KGE and the owner of La Cygne unit 2 200 8 .. . .. .. .. .... . ... . ... . . .. .. .. .. .. .. . .. .. .. . .. .. ... . . .. $ 17 ,637 ameinded certain terms of the agreement relating to KGE's lease 20 09 ... .. .. .. .. . ... .. . ... ... .. .. . ... . ..I .. ... . . ... . .. . .. 16,7 57 of La Cygne unit 2, including an extension of the lease term. The 2010 . .................. " . .... 15,578 2012.. .. .... 11,378 lease was entered into in 1987 with an initial terrfi ending in 2 0 11 . . .. . . . . . :.....
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| . ,.... . . :. . 1*.". . . ... . . .. :. , . , 1, 7 September.2016. With the June 30, 2005, extension; the term'of the lease will expire in September 2029. Upon 'expiration of the Thereafter .... ..... ....... .. ........... I .............. . 124,39 1 lease term in 2029, KGE has a fixed price'option to purchase 201,230 La Cygne unit 2 for a price that is estimatedto be the fair market Amounts iepresenting imputed interest ............................ (69,076) value of the facility in 2029. KGE can also elect to renew the Present value of net minimum lease payments under capital leases ...... 132,154 lease at the expiration of the lease term in 2029. However, any Less current portion.. .. . ....... ........ .... (8,300) renewal period, when added to 'the initial lease term, cahnot Total long-term obligation under capital leases .... ................. . $123,854 exceed 80% of the'estimated useful life of La Cygne unit 2.
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| On June 30; 2005,-KGE caused the owner of La Cygne unit 2 to refinance the debt used by the owner to finance the purchase of 21., DISCONTINUED OPERATIONS - Sale .of Protection One and Protection One Europe the facility.,The savings resulting from extending the term of.the lease and refinancing the debt will reduce KGE's annual lease In 2006, we received proceeds of $1.2 million that was released expense by approximately $10.8 million. .; from an escrow account arising from the sale of Protection One Europe, a security business we sold on June 30, 2003. In 2005, we recorded approximately $0.7 million in income in our results of discontinued operations due to the resolution of indemnifi-cation issues With the sale of the Protection One'Europe security business. . .
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| 72
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| Westar Energy I 2007,Annual Report ............
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| Results of discoritinued operations are, presented in the table ITEM 9. CHANGES IN AND DISAGREEMENTS WITH below. ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Year Ended December 31, T, , 2005(*
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| (InThousands, None.
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| Except Per
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| . . Share.Amounts)
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| SalesSsl $ - ITEM 9A. CONTROLS AND PROCEDURES Costs and expenses ........................ .................. Under the supervision and with the partidpation bof 6ibr Earnings from discontinued operations before income taxes .............- management, including -our chief executive officer and our Estimated gain on disposal. . ... . ".".. . .... 1;232 chief financial officer, we have evaluAted the effectiveness of the Incom e tax expense ........................................... 490 desigi' and operation of 6ur disclosutr cdntrols' aind procedures Results of discontinued operations .............................. "$ 742 as defined'in Rule 13a-15(e) of tfhe Scurities Eichange Act of Basic results of discontinued operations per share .......... ......... $ 0.01 1934. These controls "and procedures are designed- t6 ensure that material information relatiih;g to the company' and its Diluted.results oi discontin'ued operations per share... $ 0. 01 subsidiaries'is communicated to the chief executive officer and faýAmounts are relatMd to the resolution of indemnification issues asiociatedwith the chief financial officer: Based on that evaluation, our chief the sale of Protection One Europe. executive officer anid our chief financial officer concluded that, as of December 31, 2007, our disclosure controls and procedures are effective to ehsure that infornation required to be disclosed
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| : 22. QUARTERLY RESULTS (UNAUDITED) by us in reports that we file or ssubmit under the Securities Our electric business is seasonal in nature and, in our opinion, Exchange Act of 1934 is accumulated and communicated to comparisons between the quarters of a year do not give a true the chief executive officer and the chief financial officer, and indication of overall trends and changes in operations. recorded, processed, summarized ,and teported within, the time periods specified in Securities and Exchange Commission 2007 First Second Third Fourth rules and forms. Disclosure controls and procedures' include, (InThousands, Except Per Share Amounts) without limitation', c6ntrols and Oiocediireýdesignbdto ensure Sales .................... $370,306 $415,178 $548,496 $392,854 thaf information required t6 be disclosed by an issuer in the Net income ............... 30,175 32,708 91,706 13,765 reports that it files or submits under the Act is accumulated Earnings available for common stock ........... 29,933 32,466 91,464 13,523 and communicated to the issuer's management, including its Per Share Datale): principal executive and principal financial officers,' or persons Basic: performing similar functions, as appropriate to, allow timely Earnings available....... $ 0.34 $ 0.36 $ 0.99 $ 0.15 decisions regarding required disclosure.
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| Diluted:
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| Earnings available ....... .$ 0.34 $ 0.36 $ 0.99 $ 0.14 There were no changes in our internal control over financial Cash dividend declared reporting during the': fourths.quarter, ended; December: 31, per common share ........ $ 0.27 $ 0.27 $ 0.27 $ 0.27 2007, that have materially- affected, or are.reasonably likely to Market price per common share: materially affect, our internal control over finaincial reporting.
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| High ................... $ 28.54 $ 28.57 $ 26.44 $ .26.83 Low ................... $ 25.23 $ 23.81 $ 22.84 $ 24.29 See "Item 8. Financial Statements and S 6pplementary Data' for Managemext'sAniiual l'epot On Intemal Control Over Financial
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| " Items are computed independentlyfor each of the periods presented and the sum of the quarterly amounts may not equal the totalforthe year.
| |
| Reporting and the Independent Registered' Public Accounting Firm's report.withrespect: to management's assessment of the effectiveness of intemal control over financial reporting.
| |
| 2006 First Second Third Fourth (InThousands, Except Per Share Am6unts)
| |
| Sales . .. . . . . . . . .. . . . . . . . . $340,023 . .$406,622 $515,947. . $343,152 ITEM 9B. OTHER INFORMATION Net incom e ........ ...... .26,838 35,365,, , 90,034 13,073:..
| |
| Earnings available for N one. , " , , ....
| |
| common stock ........... 26,596 35,123 89,792 12,831 Per Share DataW4:
| |
| Basic:
| |
| Earnings available ....... $ 0.30 $ 0.40 $ 1.03 $ 0.15 Diluted:
| |
| Earnings available ...... $ 0.30 $ 0.40,, $ 1.02 . $ .0.15 Cash dividend declared per common share ........ $ 0.25 $ 0.25 $ 0.25 $
| |
| * 0.25 Market price per common share:
| |
| High ................... $ 22.05 $ 22.39 $ 24.60 $ 27.24 Low ......... .......... $ 20.09 $ 20.40 $ 21.50 $ 23.20
| |
| ( Items are computed independentlyfor each of the periods presented and the sum of the quarterly amounts may not equal the totalforthe year.
| |
| 73
| |
| | |
| ............. Westar Energy I 2007 Annual Report PARTIII . ." -. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS, OF THE REGISTRANT The informatiot* required by Item 12 will be set forthdinour 2008 The information concerning directors required by Item 401 of Proxy Stateifienf under the capfions "Beineficial Ownership Regulation S-K will be included under the caption"Election of of Votin g Securities" arid "Shares Authorized For Issuance Under' Equity Compensation Plans," and that information is Directors" in our definitivd Proxy Stateirtent for our 2008 Anhual incorporated by reference in this Form 10-K.
| |
| Meeting of Shareholders to be filed pursuant t9 Regulation 14A (the 2008 Proxy Statement), and that information is incorporated by reference in this Form 10-K. Information concemnngexective ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS officers required by Item 401 of Regulation S-K is located.under Part I, Item. 1 of this Form 10_K. The informatioii. required by Not applicable.
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| Item 405,of Regulation S-K ,concerningcompliance with Section 16(a) of the Exchange Act will be, included under the caption ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES:..
| |
| "Section 16(a) ;Beneficial.Ownership. Reporting Compliance" in our; 2008 Proxy Statement, and that information is incorporated The information required by Item 14 will be set.forth in our 2008 by reference in -this Form, 10-K..The information required by Proxy Statement under the. captions, ;ridependent'Registered Item 406, 407(c)(3), (d)(4) and (d)(5) of Regulation S-K will be Accounting Firm Fees" and "Audit Committee Pre-Approval included undernthe caption "Corporate Governance Matters"in Policies and Procedures," and that information is incorporated our 2008 Pro~,Statement, and that information is incorporated by reference in this Form 10-K. ' : . .
| |
| by reference in this Form 10-K.,
| |
| ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 will be set forth in our 2008 Proxy Statement urider the captions "Compensation Discussion and Analysis," "Compiensation Committee Report," "Compensafion of Executive Officers, and Directors,", and !"Compensation Committee. Interlocks. and Insider Patcipaton" and that information is incorporated by reference in this Form 10-K..
| |
| PART IV ....
| |
| ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES FINANCIAL STATEMENTS INCLUDED HEREIN Westar Energy, Inc.,
| |
| Management's Report on Intemal Control Over Financial Reporting "
| |
| Reports~of Independent Registered Public Accounting Firm . ' , . .. . ;"
| |
| Consolidated Balance Sheets; asof December 31, 2007 And 2006.
| |
| Consolidated Statementsof Income for the years ended'December 31, 2007, 2006 and 2005 Consolidated Statements of Comprehensive Income for the Y~ars ended Decemb&r 31,'2007, 2006 arfd 2005 Consolidated Statements ofCa6sh.Flowsfor the years ended December 31,2007, 2006 and 2005 Consolidated Statements of Shareholders' Equity for,the years "endedDecember 31,"2007, 2006 and 2005 Notes to Consolidated Financial Statements SCHEDULES Schedule 11-Valuation and Qualifying Accounts Schedules omitted as not applicable or not required under the Rules of Regulation S-X: II1, IV, andV 74
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| | |
| Westar.Energy I 2007 Annual Report ............
| |
| EXHIBIT INDEX .'. ,;''.*.,
| |
| All exhibits marked "I"are incorporated herein by reference. All exhibits marked by. an asterisk are management contracts or compensatory plans or arrangements required tobe identified by Item. 15(a)(3) of Form 1bO-K.All exhibits marked "#"are filed with this Form 10-K.
| |
| Description .
| |
| 1(a) - Underwriting Agreement between WestarEnergy, Inc, and Citigroup Global Markets Inc. and Lehman , I Brothers Inc., as representatives of the several underwnters, dated January 12 2005 (filed as Exhibit 1.1 to the Form 8-K filed on January 18, 2005) 1(b) - Underwriting Agreement between Westar Energy, Inc. and Barclays Capital and Citigroup'Global Markets, Inc., I as representatives of the several underwriters, dated June 27, 2005 (filed as Exhibit 1.1 to the Form 8-K filed on July 1, 2005) 1(c) - Sales Agency Financing Agreement, dated as of April 12, 2007, between Westar Energy, Inc. and BNY Capital I Markets, Inc. (filed as Exhilit 1.1'to the Form 8-K filed bn'Apii 12,ý'2007) .. . ' -
| |
| 1(d) Sales Agency Financing Agreement, dated as of August 24, 2007, between Westar EnergkInc. and BNY Capital I Markets, Ihc. (filed as Exhibit'l.1 to the Form 8-K filed onAugust 27, 2007Y.
| |
| 1(e) - Underwriting Agreement, dated November 15, 2007, among UBS Secu.rities LLC and J.P Morgan Securities I Inc., as representatives of the underwriters named therein, UBS Securities LLC, in its capacity as agent for UBS
| |
| 'AG, Ldndbn'Brinch, and Westar Energy,'Ind. (filed as'Exhibif 1.1 to'th F6tm 8-K' hl'ed'on'!NoVemi-ber 16, 2007) 3(a) - By-laws of Westar Energy,.Inc., as amended April 28, 2004 (filed as Ehit 3,(a) to tbeform 10'Q for the period I ended June 30, 2004 filed on August 4, 2004) 3(b) ;.'Restated Articles of Incorporation.of Westar Energy, Inc., as amended through May,25, 1988 (filed as Exhibit 4 I to the Form S-8 Registration Statement, SEC File No; 33-23022 filed on July 15, 1988)1... .
| |
| 3(c) - ,ertificate, of Amendment to Restated Articles of Incorporation ofWestar Energy, Inc (filed as. Exhibit 3 to the I
| |
| .Form 10-K405 for the period ended December 31, 1998filed on April 14, 1999) 3(d) - 'Certificate of Designations for..Preference Stock, 8.5% Series'(filed as Exhibit,3(d) to:the'Form 10-K for the I period ended Deceember 31, 1993.filed on .March 22, 1.994)
| |
| * 3(e) Certificate;of Correcti6n to'Restated Articles of Incorporation of.Westar Energy, Inc. (filed as Exhibit 3(b),to the I Form 10-K for the peripodended December 31; 1991.filed on March'30, 1992) 3(f) -- Certificate-of Designatiohs'forPreference Stocký 7.58%/ Series '(filed as Exhibit 3(e) to-the Form 10-K for the , I
| |
| -'.period endediDecember 31,;1993 filed on March'22, 199.4) . , .
| |
| 3(g) - Certificate of Amendment to Restated Articles of incorporation of Westar Energy, Inc. (filed as Exhibit 3(L) to I
| |
| * Form 10*K fr,'the period:ended December 31;'1994 filed on March 30 1995) the - '
| |
| 3(h)' " Cerificate 'fAneiinient to Restaf~d Articleý of Incorporation of:Westar Eneigy, Inc. (filed as Exhibit 3' fo the I Form 10-Q'for the period ended June 30,1994 filed, on Augusrt 1171994)' .'-
| |
| 3(i) -Certificýte'ofAmehdh-inet to Re'stated Articles of.Incorporation of Wetar Energy Inc (filedas Exhibit3(a) to the F6 10-0lQ'f6fr'the peiod ended June 3061'996filed-bnAugusf'14, 1996) .'
| |
| 3(j) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibits3'to the I Forimn10-*Q fof the period'ended March 31,1998 filed'on'Mayi12, 1998) ''i'''
| |
| 3(k) -- Form of Certificate of Designations for 7.5% Convertible Preference Stock (filed as Exhibit 99.4 to the Form I 8-K filed'on November 17, 2000) '. . .' . . .
| |
| 3(1) .- Certificate of Amendment to Restated Articles of Incorporation of Westar: Energy, Inc. (fled as Extibit 3(1) to I
| |
| 'the Form. 10-K for the period ended December 31, 2002 filed on April 1i1 2003) 3(m) Certificate of Amendment to Restated Articles of IncorporatiOn of Westar Energy, .Inc. (filed as Exhibit3(m)o I the Form 10-K for the period ended December 31, 2002 filed on April 11, 2003) '
| |
| 3(n) Certificate of Amendment to Restated-Articles of Incorporation of Westar Energy,.Iric,(filed as Exhibit 3(m) to 'I the Form S-3 Registration Statement NoI333-125828'filed on"June,15,2005), ,"
| |
| 4(a) -- Mortgage anid Deedof Trust. dated.July 1, 1939. between Westar Energy, Inc. arid Harris Trust and Savings Bank, I Trustee (filed as Exhibit 4(a) to Registration Statement No. 33-21739) 4(b) -. jFirst and Second'Supplemental Indentures dcated July.1, 1939 andApril 1,1949, respectively' filed as.:" I
| |
| :Exhibit 4(b). to Registration StatementNo': 33T21739)..' ; . ,. . . ,. - .
| |
| 4(c) Sixth Supplemental Indenture dated, October'4; 1951 (filed as.Exhibit 4(b)'to"Regstration Statement ' I No. 33-21739)
| |
| -75
| |
| | |
| ............ Westar Energy 1 2007 Annual Report 4(d) Fourteenth Supplemental Indenture dated May 1, 1976 (filed as Exhibit 4(b) to Registration Statement. ' .. I No. 33-21739) 4(e) TTwenty-Eighth Supplemental Indenture dated Juiy.1,1992;(fled, asExhibit 4(6).to the Form.10-K for the -I period ended December 31, 1992 filed on March 30,1993) -Z .
| |
| 4(f) Twenty-Ninth Supplemental Indenture dated August 20, 1992 (filed as Exhibit 4(p) to-theForm 10-K for the I period ended December 31, 1992 filed on March 30; 1993) 4(g) Thirtieth Supplemental Irde'Ature dated February., 1993 (filed'a. Exhibit4(q) to theFoirm 10-K for the period I ended December 31, 1992 filed on March 30; 1993) ', "
| |
| 4(h) 7, Thirty-First Supplemental Indenture dated April 15, 1993 (filed as Exhibit 4(r) to the Form S-3 Registration I Statement No. 33-50069 filed on August 24; 193) "
| |
| 4(i) Thirty-Second Supplemental Indenture daiediApril 15, 1994 (filed as*Exhibit 4(s)'to the Form 10wK forthe, I period ended December.31, 1994 filed on March 30, 1995) 4(j) Thirty-Fourth Supplemental Indenture dated June 28, 2000'(fled as Exhibit 4(v) 'i6 the Form 10-K for.the I period ended December 31, 2000 filed on April 2, 2001) 4(k) Thirty-Fifth Supplemental Indenture dated May 10, 2002 between Westar Energy, Inc:. andBN:Y Midwest Trust I Company, as Trustee (filed as Exhibit 4.1 to the Form 10-Q.fgr the period ended March 31, 2002.filedon~ay 15,.2002) -' be..een. ."
| |
| 4(1) Thirty-Sixth Supplemental Indenture dated as of June 1, 2004,-between Westar Energy, In'c. atnd'BNYý Midwest I-Trust Company (as'successor to Harris Trust and Savings Bank), t6its Mortgage and Deed of Trust dated., July 1, 1939 (filed as Exhibif'4.1 to-the F6ri- 8-K filed on January 18, 2005)' . '
| |
| 4(m) '7- Thirty-Seventh Supplemental Indenture, dated as of June 17, 2004, between WestarEnergyInc: and BNY I Midwest Trust Company (as successor to Harris Trust and Savings Bank), to ifS Mortngagie'an Deed of Trust dated July 1,1939 (filed as Exhibit'4.2 to the Form 8-K filed on January 18, 2005) ý%, ''
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| 4 (n) - 'Thirty-Eighth Supplemental Indentuie,'dated asobf January 18, 2005,',between WestaFEn*ergy, Inc. and BNY I Midwest Trust Company (agsuccessor'to Harris Trmst and SavingsBank), to itsMortgaige and Deed of Trust dated July 1, 4939 (filed as Exhibit 4'3 to theForm 8-K filed on Januaiy 18,2005) '
| |
| 4(o) Thirty-Ninth Supplemental Indenture dated June .30, 2005 betlveen Westar,Energy, Inc. and'BNY Midwest I Trust Company (as successor to Harris Trust and Savings Bank) to its Mortgage-and Deed of TrustldatedJuly 1, 1939 (filed as Exhibit 4.1 to the Forri 8-K filed on July 1, 2005) ..
| |
| 4(p) 'Forty-First SupplementalIndenture dated June 6,2002'between Kansas Gas and Electfnc'Company and BNY I Midwest Trust Company, as Trustee (filed as Exhibit 4:1'to'the Form'lf-.Q fotrthe'pehod ended'June 30,.2002 filed on August 14, 2002) ,..
| |
| 4(q) Forty-Second Supplemental Indenture dated March'12, 2004 between Kansas Gas and Electric Company I and BNY Midwest Trust Company, asTrstee (filedIas Exhibit,4(p) to the Form 10K fqr.th1.pe~riod ended ..
| |
| December 31, 2004 filed on March 16, 2005). ". '.' .. '-,- ..
| |
| 4(r) - F9rty.-Fourth SupplementalIndenturedated May 6,'2005,1ýetween kansas-Gas and'Electric ComPany and.BNY I Midwest Trust Company, as Trustee (filed as Exhibit4,to.the Form10-Q for the period nded March,.31, 2005 filed on May 10, 2005) ' . '. . ".: ' .
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| 4(s) Debt Securities Indenture dated August 1, 1998 (filed,as Exhibit 4.1 to the Form ,0.-.Q for .theperiod ended I June 30, 1998,filed on August.12, 1998) 4(t) - Securities Resolution No. 2 dated as of May 10, 2002 under Indenture dated as of August 1, 1998.between I Western Resources, Inc. and Deutsche Bank Trust Company Americas (filed as Exhibit 4.20to the Form 10-Q for the' penrod eided Maaich3, 2002 filedon Ma 15,2002) 2 " ' ' ' ' "
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| 4(u) Forty-Fifth Supplemental Indenture dated March 17, 2006 between Kansas Gas and Electric Company and, I BNY Midwest Trust Comnpi.any, as Trustee, tuthe Kan'sa'sGas and Electrc Company Mortgag and Deed, of Trust dated April 1, 1940 (filed as Exhibit 4.1 to' the Form 8-K filed`on March 21, 2006)' . r ,
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| 4(v) "' Forty-Sixth Supplement*. hndeth re datedJune 1, 2006 btwe'e n'K nsas Gas and ElectricCot6upny and ..
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| BNY Midwest Trust Companj, as Trustee, to the Kansas Gas and'Electric Comipany Mortgage andDeed *f Trust dated April' 1, 1940(filed as Exhibit 4 to the Form 10,Q foi the period ended June 30, 2006 filed on'7 August 9, 2006) , ::"- ' - '. ; . 1/2 ...
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| 4(w) Fortieth Supplemental Indenture dated May 15, 2007, between Westar. Energy'Inc. and The Bank of NewYork I Trust Company, N.A. (as successor to Harris Trust ýnd Savihgs Bank) to its'Mortgd8ge" indlDeed of Trust dated July 1,1939 (filed as Exhibit'4.16,to the Form 8-Kifedon Ma.16,2007)"' - ' :
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| 76
| |
| | |
| *Westar Energy I 2007 Annual: Report.........
| |
| 4(x) Forty-Eighth Supplemental Indenture, dated as of July 10, -2007,.byfand among Kansas Gas and,Electric, #
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| Company, The Bank of NewYork Trust Company, N.A. and Judith L. Bartolini' -
| |
| 4(y) - Bond Purchase Agreement, dated as.of August 14, 2007, between' Kansas Gas and Electric Company and I Nomura International PLC (fied as Exhibit 4.1 to the' Form 8-K filed on August 15, 2007) 4(z) - Forty-Ninflt Supplemental Indenture, dated as of October 12, 2007, by and among Kansas Gas and Electric I Company', The Bank of NewYork Trust Company, N.A. and Judith L. Bartolini (filed as Exhibit 4.1 to the Form 8.-K filed on October 19, 2007) ., .
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| 4(aa) -Form of First Mortgage Bornds, 6.10% Series Due 2047 (contained'in Exhibit 4(w) '''. I Instruments defining the rights, of holders of other long-term debt not required to be filed as Exhibits will be furnished to the Commission ffpon request. . ," .: .,
| |
| 10(a) Long-.Term Incentive and Share Award Plan (filed as Exhibit 10(a) to the Form 10-Q for the period ended I June 30, 1996 filed on August 14, 1996)*. .:' . .
| |
| 10(b) Form of Employment Agreements with Messrs. Grennan, Koupai, 'Terrill, Lake and Wittig and Ms. Sharpe I (filedas'Exhibit 10(b) to the Form 10-K for the period ended December 31, 2000 filed on April 2, 2001)*
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| 10(c) A Rail Transportation Agreement among Burlington Northern Railroad Company, the Union Pacific Railroad I Company and Westar Energy, Inc. (filed as Exhibit 10 to the Form 10-Q for the period ended June 30, 1994 filed on August 11, 1994)', .. . . .
| |
| 10(d) - Agreement between Westar Energy, Inc. and AMAX Coal West Inc. effective March 31, 1993 (filed as, I Exhibit 10(a) to the Form 10-K for the period ended D1ecember 31,.1993 filed on March 22,1994) 10(e) - Agreement between Westar Energy, Inc. and Williams Natural Gas Company dated October 1, 1993 (filed as I Exhibit 1(b)'to the Form 10-K for the period. ended 'December 31, 1993 filed on March 2ý,.1994) 10(f) :Short-term Incentive Plan (filed as Exhibit 10(j) to the Form 10-K forthe period ended December 31, 1993 I
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| -filed on March 22,.1994)*,
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| 10(g) Westar Energy, Inc. Non-Employee Director Deferred Compensation Plan, asa~mednded and restated,' dated as I of October 20,2004 (filed'as Exhibit 10.1 to.the Form 8-K filed on October 21, 2004)* , '-
| |
| 10(h) - Executive Salary Coitinuation Plan 6f Western Resources, Inc., as revised, effective September 22, 1995 I (filed as Exhibit,10(j) to. the Form 10-K for the.period ended December 31; 1995 filed on March 27, 1996)*
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| 10(i) - Letter Agreement between Westar Energy, Inc. and David C. Wittig, dated April 27, 1995 (filed as Exhibit 10(m) I to the Form 10-K for the period ended December 31, 1995 filed on March 27, 1996)*
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| 10(j) Form of Split Dollar 'Insurance Agreement (filed as Exhibit 10.3 to the Form 10-Q for the period ended June 30, ' I 1998 filed on August 12, 1998)*
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| 10(k) Amendment to Letter Agreement between'Westar Energy, Inc. and'D'avid C. Wittig, datedApril 27, 1995 ' I (filed as Exhibit 10 to the Form 10-Q/A for the period ended June 30, 1998:filed on August 24, 1998)*"
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| 10(1) Letter Agreement between Westar Energy, Inc. and Douglas T. Lake, dated August 17, 1998 (filed as' I Exhibit 10(n) to the Form 10-K405 for the period ended.December 31, 1999 filed on March 29, 2000),*
| |
| 10(m) - Form of Change of Control Agreement with officers of Wesfadr Ehergy, Inc. (filed as Exhibit 10(o) to'the I
| |
| . - -, I -
| |
| Form 10-K for the period,ended December 31,2000 filed onApril 2,'2001)*'* , '
| |
| 10(n) - Form of loan agreement with officers of Westar Energy, Inc. (filed as Exhibit 10(r) to the Form 10-K for the I period ended .December 31, 2001 filed on April 1, 2002)*
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| 10(o) - Amendment to Employment Agreement dated April 1, 2002'between Westar Energy, Inc. and David C. Wittig I (filed'as Exhibit 10.1 to the Form 10-Q for the period ended June 30, 2002 filed on August 14, 2002)*
| |
| 10(p) - Amendment to Empl6yment'Agreement dated April 1, 2002 between Westar Energy and Douglas T. Lae I (filed as Exhibit 10.2 to the Fon'i 10-Q for the period ended June'30, 2002 filed on August 14, 2002)*
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| 10(q) - Credit-Agreement dated as of June 6, 2002 among Westar Energy, Inc., the lenders from time to time party I there to, JPMorgan Chase Bank, as'Administrative Agent, Citibank, N.A., as Syndication Agent, and Bank of America, N.A.; as Documentation Agent (filed as Exhibit 10.3 to the Form 10-Q-for the period. ended June 30, 2002 filed on August 14, 2002) ' ' '
| |
| 10(r) - Employment Agreement dated September 23, 2002 between Westar Energy, Inc. and David C. Wittig (filed as I Exhibit 10.1 to,the Form 10-Q for the period ended. September 30, 2002 filed on November 15, 2002)*:..
| |
| 10(s) Employment Agreement dated September 23,.2002 between Westar Energy, Inc. and Douglas T. Lake (filed as I Exhibit 10.1 to the Form8-Kfiled on November 25,,2002)* ..
| |
| 77
| |
| | |
| .......... Westar Energy I 2007 Annual. Report 10(t) - Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and James S.Haines,' Jr..(filed as . .I Exhibit 10(a) to the Form 10-Q for the period ended September 30, 2003 filed on November.10, 2003)*
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| 10(u) - Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and William B.'Moore (filed as I Exhibit 10(b) to the Form 10-Q forthe period ended September 30, 2003 filed on November10,2003)*
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| 10(v) - Letter Agreement dated November 1., 2003 between Westar Energy, Inc. and Mark A. RuellW(filed as I Exhibit 10(c)lto the Form 10-Q for the periodended September 30, 2003 filed on November 10, 2003)*
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| 10(w) - Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and Douglas R. Sterbenz (filed as I Exhibit 10(d) to the Form 1.0-Q for the period, ended.September 30, 2003 filed on'November 10; 2003)*-
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| 10(x) - Letter.Agreement dated November. 1, 2003 between.Westar Energy, Inc. and Larry D. Trick (filed as I Exhibit 10(e) to the Form 10-Q for the period ended September 30, 2003 filed on November 10, 2003)*
| |
| 10(y) - Waiver and Amendment, dated as of November 6, 2003, to the Credit Agreement, .dated as of June 6, . I 2002, among Westar Energy, Inc., the Lenders from:time to time party thereto,, JPMorgah Chase Bank, as Administrative Agent-for the Lenders, Citibank, N.A., as Syndication Agent, and.Bank of America, N.A.,.
| |
| as Documentation Agent (filed as Exhibit 10(f) to the Form 10-Q for the period ended September 30, 2003 filed on Noyember 10, 2003) ' .
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| 10(z) - Credit Agreement dated as of March 12, 2004 among Westar Energy Inc., the several banks and other financial institutions or entities from time to time parties to the Agreement, JPMorgan Chase.Bank, ,as administrative agent, The Bank of NewYork, as syndication agent, and Citibank, N.A., Union Bank of California, N.A., and Wachovia Bank, National Association, as documentation agents (filed as Exhibit 10(a) 'to'the Form 10-Q for the period ended'March 31, 2004 filed'on May 10, 2004) 10(aa) fSupplements and modificatio'ns to Credit Agreemnent dated as of March 12, 2004 amolg Westar Energy, Inc.,
| |
| as Borrower, the Several Lenders Pý ty The'reto, JPMorgan Chase Bank, as Admini'strative Agelnt, The Bank of NewYork, as Syndication Agent, and Citibank, N.A., Union Bank of Calif6rnia; N.A.1 and Wachovia Bank, national Association, as Documentation Agents (filed as Exhibit 10(a) to the Forrin 10-Q for theperiod ended June 30,.2004 filed on August 4, 2004) * . .,. .
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| 10(ab) - Purchase Agreement dated as of December 23, 2003 between POI A:cquisition, L.L.C.,"Westar Industries, Inc. I and Westar Energy Inc. (filed as Exhibit 9,9.2 to the Form 8XK. filed on December 24, 2003) 10(ac) - Settlement Agreement dated November 12, 2004 by and among Westar Energy, Inc:, Protection One, Itic., I POI.Acquisition, L.L.C., and PoI Aqquisition I, Inc. (filed as Exhibit 10.1 to the Form, 8-K filed on November 15, 2004) .
| |
| 10(ad) - Restricted Share Unit Award Agreement between.Westar Energy, Inc. and James S.Haines, Jr. (filed as i Exhibit 10.1 to the Form 8-K filed on December 7, 2004)*
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| 10(ae) - Deferral Election Form of James S.Haines, Jr. (filed as Exhibit 10.2 to the Form 8-K filed on December 7, 2004)* I 10(af) - Resolutions of the Westar Energy, Ind;Board of Directors regarding Non-Employee Director Compensation, I approved on September 2, 2004 (filed as Exhibit 10.1 to the Form 8-K filed on December 17, 2004)*
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| 10(ag) - Restricted Share Unit Award Agreement between'Westar Energy, Inc. anrd William B.Moore (filed as I Exhibit 10.1 to the Form 8-K filed on December29, 2004)'ý,
| |
| 10(ah) - Deferral Election Form of William B.Moore (filed as Exhibit'10.2 to the Form 8-K filed on December 29, 2004)* I 10(ai) - Amended and Restated Credit Agreement dated as of May 6, 2005 among Westar Energy, Inc., the several I banks and other financial institutions or entities from time to time parties to the Agreement, JPMorgan Chase Bank, N.A., as administrative agent, The Bank of NewYork, as syndication agent, and Citibank, N.A., Union Bank of California, N.A., and Wachovia Bank, National Association, as documentation agents (filed as Exhibit 10. to the Fonim 10-Q for the period ended March 31, 2005 filed on May 10, 2005) 10(aj) - Amended and Restated Westar Energy Restricted Share Units Deferral Election Form for James .S.Haines, Jr. I (filed as Exhibit 10.1 to the Form 8-K filed on December 22, 2005)*'
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| 10(ak) - Form of Change in Control Agreement (filed as Exhibit 10.1 to.the Form 8-K filed on January 26, 2006)* J 10(al) - Form of Amendment to -the-Employment Letter Agreeirhents for.Mr..Ruelle and Mr. Sterbenz (filed as I Exhibit 10.2 to the Form 8-K filed on January 26, 2006)*
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| 10(am) -- 'Form of Amendment to~the Employment Letter Agreements for Mr. Irick'and.One Other Officer (filed as I Exhibit 10.3 to the Form .8-K filed on January 26; 2006)*..- :. t . ''
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| 10(an) - Second Amended and Restated Credit Agreement, dated'as of March 17,:2006, among Westar Energy, Inc., the I several banks and other financial institutions or entities from time to time parties to the-Agreement (filed as Exhibit 10.1 to the Form 8-K filed on March 21, 2006) 78
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| | |
| Westar Energy I 2007'Annual Report ............
| |
| 10(ao) - Amendment to the Employment Letter Agreement for Mr. James S.Haines, Jr. (filed as Exhibit 99.3 to the "; *.! I Form 8-K filed on August 22, 2006)*
| |
| 10(ap) - Confirmation of Forward Sale Transaction, dated November 15, 2007, between.UBS AG, London Branch and I Westar Energy, Inc. (filed as Exhibit 10.1 to the Form 8-K filed on November 16, 2007) 10(aq) - Third Amended and Restated Credit Agreement dated as of February 22, 2008, among Westar Energy, Inc., and I several banks and other finandial, institutions or entities from time to time parties to the Agreement (filed as Exhibit 10.1 to the Form 8-K filed on February-26, 2008) 12(a) - Computations of Ratio of Consolidated Earnings to Fixed Charges #
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| 12(b) - Computation of Ratio of Earnings to Fixed Charges for the Three Months Ended March 31, 2007 (filed as I Exhibit 12.1 to the Form 8-K filed on May 10,2007) 21 - Subsidiaries of the Registrant .. .
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| 23 - Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP ,#
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| 31(a) - Certification of Principal Executive, Officer pursuant to'Section 302"of the Sarbanes-Oxley Act of 2002. #
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| 31(b) - Certification of Principal Accounting Officer pursuanfto Section 302 of the Sarbanes-Oley Act 'f 2002 #
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| 32 :- . Certifications pursuant to Section906 of the Sarbanes-Oxley Act of 2002 (furnished and not to be considered, #
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| filed as part of the Form 10-K) 99(a) - Kansas Corporation Commission Order dated November 8, 2002 (filed as Exhibit 99.2 to the Form 10-Q for I
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| ,the period ended September 3.0,,2002 filed~on November 15,2002) , .
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| 99(b) - Kansas Corporation Commission Order dated, December 23, 2002 (filed as Exhibit 99.1 to the Form 8-K filed I on December 27, 2002) 99(c) .. - Debt'Reduction and Restructuring Plan filed with the Kansas Corp6ration Commission on February 6, 2003 I (filed as Exhibit 99.1 to the Form 8-K filed on February 6, 2003) 99(d) - Kansas Corporation Commission Order dated February 10, 2003 (fied as Exhibit 99.1 to the Form 8-K filed on I
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| - February 11, 2003) 99(e) - Kansas Corporation Commission Order dated March 11, 2003 (filed as Exhibit 99(f) to the Form 10-K for the I period ended December 31, 2002 filed on April 11, 2003) 99(f)o'.* 'Demand for Arbitration (filed as Exhibit 99.1 to the Form 8-K filed 6n June 13, 2003) ' ". I 99(g) - Stipulation and Agreement filed with the Kansas Corporation Commission on July 21, 2003"(filed as Exhibif I 99.1 to the Form 8-K filed on July 22, 2003) 99(h) - Summary of Rate Application dated May 2, 2005 (filed as Exhibit 99.1 to the Form.8-KA filed on.May 10, 2005) I 99(i) - Federal Energy Regulatory Commission Order On Proposed Mitigation Measures, Tariff Revisions, and'' ' I Compliance Filings issued September 6, 2006 (filed as Exhibit 99,.1 to the Form 8-K filed on September 12, 2006) 99(j) Westar Energy, Inc. Form of Restricted Share Units Award (filed as Exhibit 99.1 to the Form 8-K filed on I December 19, 2006)
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| WESTAR ENERGY, INC. -
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| SCHEDULE II-1 VALUATION AND QUALIFYING ACCOUNTS Balance at Charged to - Balance Beginning Costs and . at End Description of Period Expenses- Deductions1' . of Period (InThousands)
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| Year ended December 31, 2005 , ,, , . .
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| Allowances deducted from assets for doubtful accounts ........................................ $5,313 $3,959 , $(4,039).. . , $5,233 Year ended December 31, 2006 Allowances deducted from assets for doubtful accounts ................................... ... $5,233 $5,091'.,1 . $(4,067) . . $6,257 Year ended December 31, 2007 Allowances deducted from assets for doubtful accounts .. . $6,257 $3,273 $(3,809) $5,721 f"'Deductions are the result of write-offs of accounts receivable.
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| 79
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| ............. Westar Energy[1-2007 Annual Report SIGNATURE-; . ,..
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| Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act 6f 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly afuthoi-ized. ' "
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| WESTAR ENERGY, INC., ..,..
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| Date: Febriury 29, 2008 -By: /s/ Mark A. Ruelle Mark A. Ruelle, Executive Vice President and Chief Financial Officer SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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| Signature Title' Date
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| /s/WILLIAM B. MOORE , President,.Director and Chief Executive Officer February 29; 2008 (William B. Moore) (Principal Executive Officer)
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| /s/ MARK A. RUELLE ExecutiveVice President and Chief Financial Officer February 29, 2008 (Mark A. Ruelle) (Principal Financial and Accounting Officer).
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| /s/ CHARLES Q. CHANDLER IV Chairman of the Board February 29, 2008 (Charles Q. Chandler IV) "
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| Is/ MOLLIE H. CARTER Director February 29, 2008 (Mollie H. Carter)
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| /s/ R. A. EDWARDS III Director .. February 29, 2008 (R. A. Edwardsll). . .I
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| /s! JERRY B. FARLEY Director February 29, 2008 (Jerry B. Farley)
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| Is/ B. ANTHONY ISAAC Director February 29, 2008 (B. Anthony Isaac)
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| /s/ ARTHUR B. KRAUSE Director February 29, 2008 (Arthur B. Krause)
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| /s! SANDRA A. J. LAWRENCE. Director February 29, 2008 (Sandra A. J. Lawrence)
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| Is! MICHAEL F. MORRISSEY Director, February 29, 2008 (Michael F. Morrissey)
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| Is/ JOHN C. NETFELS, JR. Director February 29, 2008 (John C. Nettels, Jr.)
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| 80
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| Westar Energy 1 2007 Annual Report .............
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| Constructionon the circulating water line replacementon unit 3 at Jeffrey Energy Center.
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| We all share the responsibility of being good stewards of the environment.
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| At Westar Energy, that means doing what it takes to preserve resources and to protect our environment for future generations.
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| Westar plans to invest about $465 million in environmental projects at Jeffrey Energy Center over the next several years to dramatically decrease air emissions. Projects include rebuilding machinery that removes sulfur dioxide, adding new burners to reduce nitrous oxides and modifying equipment to better capture very small particulate matter. We will also invest to meet new regulations to reduce mercury emissions. We have similar emission control projects lined up at all of our coal plants.
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| PLANNED CAPITAL EXPANSION
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| .. Incremental
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| -$50 I. .. Growth Billion
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| -$2.S Billion Environmentalimprovements, represented by the first layer of investment, will reduce the emissions of our existing power plants.
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| 81
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| ............ Westar Energy 1 2007 Annual Report Our planned transmission expansion will also increase the availability of affordable Westar Energy power to Kansans, as well as improve regional reliability. Transmission systems can is expanding help ensure the power we have is distributed most efficiently within our state, improve its transmission reliability and facilitate the introduction of wind power into our system.
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| network with In January 2008 we began constructing the first section of a 345 kilovolt (kV) high-capacity transmission line extending from near Wichita to the Hutchinson area.
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| initiatives that The remaining section will take the line from Hutchinson to southeast of Salina. We will serve Kansas expect to complete construction of this line in late 2009.
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| well into future We have proposed a 345 kV high-capacity transmission line from near Wichita south to Oklahoma Gas and Electric's system to support current demand, while decades.
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| allowing for growth. We would build the line from south of Wichita to the border of Kansas and Oklahoma. If approved, this project is expected to be serving customers by summer 2011.
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| Reels of wire at Gordon Evans Energy Center that will be used for the new 345 kV line from Wichita to Hutchinson,and then to Salina.Construction is expected to be complete by late 2009.
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| PLANNED CAPITAL EXPANSION I Incremental ansmission network Growth
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| .$5.0 Billion vironmental controls
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| - $2.5 ýplacement CapEx Billion
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| )proximate rate base Investment in new transmissionlines, representedby the next layer of the graph,will increase the reliabilityof our system and the availabilityof affordable power throughout the state.
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| 82
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| I Westar Energy I 2007 Annual Report.........
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| Contractorspour the concrete foundationfor a steel polefor phase one of the 345 kV Wichita to Hutchinson to Salina line.
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| Phase one extendsfrom Wichita to Hutchinson. Phase two continues from Hutchinson to Salina.
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| Contractorsconstruct the 40foot long rebar cages that will serve as partof the foundationfor hundreds of steel poles.
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| 83
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| ............. Westar Energy I 2007 Annual Report Westar Energy generates electricity using diverse resources - nuclear, coal, natural gas, and, by the end of 2008, wind.
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| We operate about 6,200 megawatts (MW) of electric generation.
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| We estimate that over the next decade, we will need another 1,100 MW of generation to meet consumer needs. During this time, our nuclear and coal-fueled plants will continue to be important to our generation mix, but we will see natural gas and wind taking larger roles.
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| Our moderate size makes it important to balance innovation and risk. We have designed our investment plan to provide time for industry developments as technologies mature and regulations evolve. This flexible approach to planning allows us to make better decisions for our customers and shareholders. Our plan allows us to remain nimble and anticipate change.
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| Water ti Eraporit Overview of Emporia Energy Centerconstru PLANNED CAPITAL EXPANSION
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| ............................................. .............................................................................. o.......
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| Intermediateio kind eakinggeneration generation Incremental
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| -$5.0 ransmission network Growth Billion nvironmental controls Bo$2.5 eplacement CapEx pproximate rate base Generation resourcesaccountfor the remaininglayers of ourinvestment plan. Even with successful energy efficiency initiatives,new generationwill be needed.
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| 84
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| Westar Energy I 2007 Annual Report .............
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| Westar Energy is launching Kansas' largest wind energy program.
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| By the end of 2008, we will add nearly 300 MW of wind generation to our energy resources, making our program one of the largest utility-sponsored wind programs in the country.
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| Technological advances in recent years have made wind affordable and appealing.
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| Westar has worked with regulators to ensure recovery of these investments and has signed agreements with developers for three wind farms in different parts of the state. The agreements represent more than a half-billion dollar commitment to wind power in Kansas. We will bringabout 300 MW of wind generation into our generationmix by the end of 2008 with windfarms in Wichita, Barber and Cloud Counties.
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| : Along with energy efficiency and renewable
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| : energy, we will need to build additional
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| : plants to meet growing needs.
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| Growth in customers' use of electricity requires us to invest in additional new power plants. We will keep a close eye on market changes, but at this point we expect a highly efficient combined-cycle natural gas plant will be a more cost effective solution than a base load coal plant when it comes time to build more than a peaking plant.
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| The first phase of our Emporia Energy Center, which is a gas peaking plant, will be available to serve customers this spring and construction of the second phase is scheduled to be complete next spring. This natural gas plant paired with our wind investment will provide reliable electricity for our consumers.
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| Units at the new Emporia Energy Center.
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| LarryGraves, EmporiaEnergy Center plantmanager.
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| 85
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| ............. Westar Energy I 2007 Annual Report Constructive rate mechanisms will benefit shareholders and customers as we grow.
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| We prepared carefully for this time of growth, working with the Kansas Corporation Commission, our primary regulator, to develop forward-thinking approaches to setting utility rates and to ensure we have the financial capacity to meet growing demands and increasingly uncertain future conditions.
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| Our Environmental Cost Recovery Rider adjusts each year to reflect investments related to meeting the requirements of the Clean Air Act and other environmental regulations since the prior full review of our rates. Customers benefit because rate changes are more gradual and ultimately lower than they would be without this cost recovery rider.
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| Investors benefit from more timely investment recovery.
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| Our ability to adjust components of our rates monthly in response Dustin Spencer, substationapprentice, to changing fuel prices helps customers understand the cost of their Topeka Operations Center.
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| electric service, including the cost of meeting stricter environmental standards, which in turn helps them make better choices to meet their energy needs. In today's volatile fuel markets, it also ensures they are paying the correct price for fuel.
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| Under a recent state law, Kansas utilities are able to establish with regulators how new generation investment will be recovered in utility rates before a utility makes a substantial commitment to invest. With the rapid changes affecting our industry, this confirms the prudence of these investments and keeps our cost of capital reasonable.
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| Darnin Hackney, journeyman lineman, loads material at the Shawnee Service Centerbefore heading to the job site.
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| 86
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| Westar Energy I 2007 Annual Report ............
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| I Construction on the circulating water line replacementon unit 3 at Jeffrey Energy Center.
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| We are ready for change, but are still steadfast in our mission.
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| As needs, policies and regulations change, we expect to make adjustments to our investment plan, but our mission and sole business purpose remains the same: Westar Energy provides safe, reliable, high quality electric energy service at a reasonable cost to all customers.
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| Transmissionlines coming out of Emporia Energy Center.
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| Todd Richardson,apprenticelineman, communicates with crew members as an underground cable is installedfor a new residentialdevelopment in Olathe.
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| 87
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| I
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| ............. Westar Energy I 2007 Annual Report Shareholder Information & Assistance:
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| Westar Energy's Shareholder Services CONTACTING SHAREHOLDER SERVICES TRUSTEE FOR FIRST MORTGAGE BONDS department offers personalized service to the company's individual TELEPHONE PRINCIPAL TRUSTEE, PAYING AGENT shareholders. We are the transfer AND REGISTRAR Toll-free: (800) 527-2495 agent for Westar Energy common and The Bank of New York preferred stock. Shareholder Services In the Topeka area: (785) 575-6394 2 North LaSalle Street, Suite 1020 provides information and assistance Fax: (785) 575-1796 Chicago, IL60602-3802 to shareholders regarding: (800) 548-5075 ADDRESS
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| " Dividend payments Westar Energy, Inc.
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| - Historically paid on the first Shareholder Services business day of January. April, CORPORATE INFORMATION RO. Box 750320 July and October Topeka, KS 66675-0320 CORPORATE ADDRESS
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| " Direct deposit of dividends Westar Energy, Inc.
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| E-MAIL ADDRESS
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| " Transfer of shares 818 South Kansas Avenue shareholders@WestarEnergy.com Topeka, KS 66612-1203
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| " Lost stock certificate assistance (785) 575-6300 Please include a daytime telephone
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| " Direct Stock Purchase Plan assistance number in all correspondence. www.WestarEnergy.com
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| - Dividend reinvestment COMMON STOCK LISTING
| |
| - Purchase additional shares by CO-TRANSFER AGENT Ticker Symbol (NYSE): WR making optional cash payments by check or monthly electronic Daily Stock Table Listing:
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| Continental Stock Transfer WestarEngy withdrawal from your bank account
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| &Trust Company
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| - Deposit your stock certificates 17 Battery Place, 8th Floor into the plan for safekeeping New York, NY 10004 CHIEF EXECUTIVE OFFICER AND CHIEF
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| - Sell shares FINANCIAL OFFICER CERTIFICATIONS Please contact us in writing to request In 2007, our chief executive officer elimination of duplicate mailings CONTACTING INVESTOR RELATIONS submitted a certificate to the New York because of stock registered in more TELEPHONE (785) 575-8227 Stock Exchange (NYSE) affirming that than one way. Mailing of annual reports he is not aware of any violation by the can be eliminated by marking your ADDRESS company of the NYSE's corporate proxy card to consent to accessing Westar Energy, Inc. governance listing standards. Our chief reports electronically on the Internet. Investor Relations executive officer's and chief financial RO. Box 889 officer's certifications pursuant to Please visit our Web site Topeka, KS 66601-0889 Section 302 of the Sarbanes-Oxley Act at www.WestarEnergy.com.
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| of 2002 for the year ended December 31, Registered shareholders can easily E-MAIL ADDRESS 2007, were included as exhibits to Westar access their shareholder account ir@WestarEnergy.com Energy, Inc.'s Annual Report on Form information online by clicking on the Copies of our Annual Report on 10-K for the year ended December 31, Go to Shareholder Sign-in button.
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| Form 1O-K filed with the Securities 2007, that was filed with the Securities and Exchange Commission and other and Exchange Commission.
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| published reports can be obtained without charge by contacting Investor Relations at the above address, by accessing the company's home page on the Internet at www.WestarEnergy.
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| com or by accessing the Securities and Exchange Commission's Internet Web site at www.sec.gov.*
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| 88
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| Westar Energy I 2007 Annual Report ............
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| Directors:
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| B. ANTHONY ISAAC (54)
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| Directorsince 2003 President LodgeWorks, LP Wichita, Kansas Committees: Compensation, Finance ARTHUR B. KRAUSE (66)
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| Directorsince 2003 Executive Vice President and Chief Financial Officer (Retired)
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| Sprint Corporation Naples, Florida Committees: Audit, Finance SANDRA A.J. LAWRENCE (50)
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| Directorsince 2004 Executive Vice President and Chief Financial Officer Children's Mercy Hospital Kansas City, Missouri Committees: Compensation, Nominating Westar Energy Board of Directors,fromn left, is composed of John C. Nettels Jr., and CorporateGovernance Michael F. Morrissey, SandraA.J. Lawrence, CharlesQ. ChandlerIV, William B. Moore, WILLIAM B. MOORE (55)
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| Arthur B. Krause, Mollie Hale Carter,Jerry B. Farley, B. Anthony Isaac and R.A. Edwvards III.
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| Directorsince 2007 President and Chief Executive Officer CHARLES Q. CHANDLER IV (54) R.A. EDWARDS III(62)
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| Westar Energy, Inc.
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| Chairman of the Board Directorsince 2001 Topeka, Kansas Directorsince 1999 Director, President and Chairmansince 2002 Chief Executive Officer MICHAEL F.MORRISSEY (65)
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| Chairman of the Board, President First National Bank Directorsince 2003 and Chief Executive Officer of Hutchinson Managing Partner (Retired)
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| INTRUST Bank, NA Hutchinson, Kansas Ernst & Young LLP Wichita, Kansas Committees: Audit, Nominating Naples, Florida MOLLIE HALE CARTER (45) and Corporate Governance Committees: Audit, Compensation Directorsince 2003 JERRY B. FARLEY (61) JOHN C.NETTELS, JR. (51)
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| Chairman of the Board, President Directorsince 2004 Directorsince 2000 and Chief Executive Officer President Partner Sunflower Banks, Inc. Washburn University Stinson Morrison Hecker LLP Salina, Kansas Topeka, Kansas Overland Park, Kansas Committees: Compensation, Finance Committees: Audit, Nominating Committee: Finance and Corporate Governance Officers:
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| WILLIAM B. MOORE (55) JEFF BEASLEY (49) MICHAEL LENNEN (62) 27 years of service 30 years of service 1year of service President and Chief Executive Officer Vice President, Corporate Compliance Vice President, Regulatory Affairs and Internal Audit DOUGLAS R. STERBENZ (44) PEGGY S. LOYD (50) 10 years of service GREG A. GREENWOOD (42) 29 years of service Executive Vice President and 14 years of service Vice President, Customer Care Chief Operating Officer Vice President, Generation Construction ANTHONY D. SOMMA (44)
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| MARK A. RUELLE (46) KELLY B. HARRISON (49) 73 years of service 15 years of service 26 years of service Treasurer Executive Vice President and Vice President, Transmission Operations LEE WAGES (59)
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| Chief Financial Officer and Environmental Services 30 years of service JAMES J. LUDWIG (49) LARRY D. IRICK (51) Vice President, Controller 17 years of service 8 years of service CAROLINE A. WILLIAMS (51)
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| Executive Vice President, Vice President, General Counsel and 32 years of service Public Affairs and Consumer Services Corporate Secretary Vice President, BRUCE AKIN (43) KENNETH C.JOHNSON (54) Distribution Power Delivery 20 years of service 6 years of service Vice President, Operations Strategy Vice President, Generation and Support 89 Ages and years of service are as of December 31, 2007
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| 6' 2
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| C o000000000000000000000o0000000000000000000000000000000000000000000000000 mI.
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| II Ui somm,
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| %- M lffli
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| [Fit THE PO LEAD Great PhI )rt
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| GPE OPERATING REVENUES STOCK PERFORMANCE GRAPH (Dollars in Millions) (Dollars)
| |
| Comparison of Cusmulative Total Returns* Great Plains Energy, S&P 500 Index and EElIndex
| |
| $2500
| |
| $4,000...................................................
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| $3,000 . . . . . . . . ......... ............... .......n .....
| |
| ......... $3267
| |
| $250 0Great PlainnsEnergy Ie S&P500
| |
| * EEl Index
| |
| $215 $2.464 $2,605 $,7
| |
| $2,000 ý.......... ........ $150
| |
| $100 ---------........................ .........
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| 2002 2003 2004 2005 2006 2007
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| $1,000 -- --- 04 2006 . 2.
| |
| Fiscal YearEnded December 31 2003 2004 2005 2006 2007 "Tootareturna-ssues reinrestement of divdends. ams*nes$100ireestedon December31,2002, incompanycorneon stok. S&P500 Indexand EOIndex SELECTED FINANCIAL INFORMATION Year Ended December 31 2007 2006 2005 2004 2003 (Dollars in millions except per share amounts)
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| Great Plains Energy (a)
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| Operating revenues $3,267 $2,675 $2,605 $2,464 $2,148 Income from continuing operations (b) $ 159 $ 128 $ 164 $ 175 $ 189 Net income $ 159 $ 128 $ 162 $ 183 $ 144 Basic earnings per common share from continuing operations $ 1.86 $ 1.62 $ 2.18 $ 2.41 $ 2.71 Basic earnings per common share $ 1.86 $ 1.62 $ 2.15 $ 2.51 $ 2.06 Diluted earnings per common share from continuing operations $ 1.85 $ 1.61 $ 2.18 $ 2.41 $ 2.71 Diluted earnings per common share $ 1.85 $ 1.61 $ 2.15 $ 2.51 $ 2.06 Total assets at year-end $4,827 $4,336 $3,842 $3,796 $3,694 Total redeemable preferred stock, mandatorily redeemable preferred securities and long-term debt (including current maturities) $1,103 $1,142 $1,143 $1,296 $1,347 Cash dividends per common share $ 1.66 $ 1.66 $ 1.66 $ 1.66 $ 1.66 SEC ratio of earnings to fixed charges 3.08 3.20 3.60 3.54 4.22 Consolidated KCP&L a)
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| Operating revenues $1,293 $1,140 $1,131 $1,092 $1,057 Income from continuing operations (c) $ 157 $ 149 $ 144 $ 145 $ 125 Net income $ 157 $ 149 $ 144 $ 145 $ 116 Total assets at year-end $4,292 $3,859 $3,340 $3,335 $3,315 Total redeemable preferred stock, mandatorily redeemable preferred securities and long-term debt (including current maturities) $1,003 $ 977 $ 976 $1,126 $1,336 SEC ratio of earnings to fixed charges 3.53 4.11 3.87 3.37 3.68 r (a) Great Plains Energy's and KCP&L's consolidated financial statements include results for all subsidiaries in operation for the periods presented, (b) This amount is before discontinued operations of $(1.9) million, $7.3 million and $(44.8) million in 2005 through 2003, respectively.
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| (c) This amount is before discontinued operations of $(8.7) million in 2003.
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| I F'~v
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| /7
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| /I
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| / /
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| //
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| WE ARE GREAT PLAINS EIN GY'-
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| From growing our power generatin capabilities to becoming a growing leader in the ndustry, we are Great Plains Energy - delivering sustainable growth, service and reliability to our custo-$ers and communities.
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| Through collaboration and novative leadership, we are maintaining solid/financial performance and increasing the company's value.
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| GREAT PLAINS ENERGY 2007 ANNUAL REPORT I
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| LETTER TO SHAREHOLDERS Great Plains Energy (GPE) enters 2008 having completed one environmental retrofits which are already helping the metro of the most challenging and productive years in its 125-year area achieve its air-quality goals and have been placed into history. During 2007, we made great progress in the execu- service by the Missouri and Kansas regulatory bodies. Phase tion of our Comprehensive Energy Plan and acquisition of two of our La Cygne environmental investment isnow projected Aquila while remaining focused on operational performance. to be completed in the 2011-2012 time frame in advance of Although we dealt with several operational issues in the first expected Environmental Protection Agency regional compli-half of the year, we overcame the challenges and produced ance requirements.
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| second-half earnings that were a 22 percent increase over the Additional CEP investments, including environmental same period in 2006. retrofits at latan 1 and construction of the latan 2 high-The focus in 2007 was on the execution of our Compre- efficiency coal plant near Weston, Missouri, are well under hensive Energy Plan (CEP), which brings reliable, clean way. The industry is experiencing an increase in construction energy to our growing region. In addition to the CEP, we labor and material costs, and we arediligent in our efforts to achieved a collaborative agreement with the Sierra Club in control these costs while working closely with regulators on early 2007 which set a new standard for cooperation between our planning and management processes. We are also plan-utilities and environmental organizations. Great Plains ning an additional 400 MW of wind energy by 2012, subject Energy received national attention by winning the Edison to regulatory approvals.
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| Award, the industry's top honor, in recognition of our collab- Our commitment to energy efficiency delivered solid orative efforts with the CEP. Through it all, we maintained results last year as more customers partnered with us to help our dividend and served our customers with low rates and lower their carbon footprint and reduce energy demand. The award-winning service. ability to deliver on these commitments while benefiting our shareholders and the community is an important part of our REAPING THE BENEFITS mission, all made possible through the efforts and commit-Our Comprehensive Energy Plan was designed to meet the ment of our outstanding team of employees.
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| growing electric needs of our region. As the CEP comes to We recently submitted a revised proposal for our life, we are seeing the benefits of these sound investments. planned acquisition of Aquila. This transaction will provide Last year was the first full year for our Spearville Wind the opportunity to grow our service area and customer base Energy Facility, which powers the needs of approximately in a territory adjacent to our own. The resulting operational 33,000 homes in our area with clean, renewable power. savings and rate base growth will make us an even more In 2007, we completed the first phase of our La Cygne attractive utility investment.
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| STRATEGIC INTENT GREAT PLAINS ENERGY CELEBRATES 125 YEARS OF SERVICE...
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| Great Plains Energy's Strategic Intent is a comprehensive plan that will make us an industry TT rl M7 leader at supplying and deliv-ering electricity and innovative energy solutions to all kinds of customer - homeowners, businesses, municipalities and other utilities - for years 1881 Kawsmouth Electric 1885 Kawsmouth reincor- 1903 Kansas City Electric 1914 Kansas City Light and to come.
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| Company formed porates as Kansas City Co. unites with only street- Railway Company slips into Electric Co.; replaces gas car company to form receivership street lights with new Kansas City Light and electric lights Railway Company; begins construction of Grand Avenue Station 2 GREAT PLAINS ENERGY 2007 ANNUAL REPORT
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| EEl Outstanding Customer Service Award: For a medium-sized utility.
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| J.D. Power and Associates Tier 1 performance recognition:
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| Ranked No. 1 in communications; No. 2 in power quality and reliability, and billing and payment; and No. 3 in overall satisfaction.
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| 2007 ReliabilityOneTM National Reliability Excellence Award:
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| PA Consulting Grobp named KCP&L the most reliable electric utility nationwide.'
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| EEI Emergency Assistance Award: Cited KCP&L's outstanding efforts to assist fellow utilities in power restoration during 2007.
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| 2007 Mid-America Regional Council's Regional Leadership Award: Recognized KCP&L for its outstanding environmen-Bill Downey, President and Chief Operating Officer (left) and Mike Chesser, Chairman of the Board and Chief Executive Officer tal initiatives in metropolitan Kansas City.
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| SERVING CUSTOMERS WITH EXCELLENCE We are extreinely pleased to have been recognized for Great Plains Energy remains focused on delivery of Tier 1 superior customer'service and satisfaction because our cus-service. We received notable recognition for our performance tomers depend on their utility to provide low-cost electrical in 2007 that we believe demonstrates the strength and focus power with a high degree of reliability. Even with investments of our company: in new generation and resulting rate increases, our customers still enjoy rates more than 20 percent below the national average.
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| EEI Edison Award: For distinguished leader-ship, innovation and contribution to the PLANNING FOR THE FUTURE advancement of the electric industry through Great Plains Energy has become a company that is recog-our CEP collaboration. The award is given nized nationally for our leadership in the new frontiers of annually to the utility demonstrating outstanding power delivery. We've chaired national task forces looking at industry leadership. energy efficiency - which we view as the "first fuel" to allow 1916 Kansas City Light and 1922 Final reorganization and 1931 Company builds the 1952 With the addition of 1956 Company doubles its Power Company formed adoption of present name: Power & Light building at high-voltage tie to Union Elec- system capacity with four new Kansas City Power & Light 1330 Baltimore, Missouri's tric, Kansas City becomes the units at Hawthorn; develops a tallest building hub for future super-highways load center system to elimi-for electric power. Hawthorn nate low voltage substations plant goes online and handle much larger loads GREAT PLAINS ENERGY 2007 ANNUAL REPORT 3
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| us to meet growing demand while also lowering overall Execution of our CEP will provide long-term benefits emissions. We're among the first utilities to implement a to customers, shareholders and the region. This strategy broad-based portfolio of energy efficiency. We believe will result in maintaining competitive energy costs, a cleaner strongly that energy efficiency must succeed if we are to environment and energy-efficient solutions for customers.
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| meet the challenge of addressing increasing demand while We'll increase earnings the old-fashioned way, by staying managing environmental responsibilities. That's why we focused on our core businesses while we collaborate with our were a founding member of Edison Electric Institute's new stakeholders and provide top-tier customer service, low rates Institute for Electric Efficiency (LEE), which has already and award-winning service. As we continue to execute in the announced several new initiatives to advance the adoption future, we believe we can deliver a total return to sharehold-of energy efficiency. ers that includes a solid dividend. Thanks for your support of Through our agreement with the Sierra Club in 2007, Great Plains Energy. We look forward to having you with us we have already increased our own commitments for energy on this journey for many years to come.
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| efficiency to offset traditional generation and lower carbon emissions. The Sierra Club pledged to assist us in working Best regards, with legislators and regulators to design a new regulatory model that would allow us to receive returns for our energy efficiency investments similar to those we receive for tradi-tional power plants.
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| Achieving these and other ambitious goals, while plan- Mike Chesser ning for the future beyond the 2010 completion of our CEP, will be challenging. It will require new thinking on the part of our people and support from all of our stakeholders. It is a challenge we will answer.
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| Bill Downey OUR PROMISE TO SHAREHOLDERS AND CUSTOMERS Our focus for 2008 is clear. We will continue to execute on our CEP projects, including completion of environmental retrofits at Iatan I and continued construction of latan 2.We will finalize our strategic assessment of Strategic Energy and work to complete the acquisition and integration of Aquila.
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| 1958 Montrose Station goes 1980 latan 1 plant goes 1995 Wolf Creek Nuclear 2006 Spearville tO0-megawatt 2007 KCP&L announces online. Company opens the online Generating Station named the Wind Generation Facility goes intention to purchase Manchester Service Center No. 1 nuclear generating plant online, latan 2 construction Aquila Inc.; celebrates 125th and sells the 1330 Baltimore 1982 Company wins tEl in the United States begins. Company achieves anniversary; becomes signa-building award for long-range Tier 1 performance insafety ture sponsor of Kansas City generation plan and reliability Power & Light District 4 GREAT PLAINS ENERGY 2007 ANNUAL REPORT
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| FIVE REASONS TO INVEST MN GREAT PLAINS ENERGY 1 9&MI(99- kwI 1w1b@81gvI f t
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| : 1. OPERATIONAL EXCELLENCE "I'm veryproud to work for a company that is so dedicated to improving the ENVIRONMENT.We added a lot of value for future generations, including my grandkids."
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| BILL RADFORD La Cygne Plant Manager When GPE created its Strategic Intent, the focus was on in gross generation. Wolf Creek ranks in the top quartile building operational excellence, strengthening strategic rela- among all 104 U.S. plants in the Institute of Nuclear Power tionships and initiating its Comprehensive Energy Plan (CEP). .Operations overall performance index.
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| We have positioned the company to demonstrate leadership in supplying and delivering electricity and energy solutions that IATAN 1 AND 2 meet the needs of our customers and, in the process, deliver CONSTRUCTION CONTINUES solid long-term earnings growth and dividends for our Work continues on KCP&L's shareholders. In 2006, we made major investments in energy tatan Generating Station, generation and environmental upgrades. In 2007, we began which is simultaneously reaping the benefits of those investments as we also announced undergoing two major proj-an anticipated acquisition to expand our growth potential. ects: the Unit 1 environmental 2007 was a year of growth in our power generation. The equipment addition and the company set a new record for total system net generation due construction of Unit 2. We to virtually 100 percent availability at our Wolf Creek nuclear have completed 70 percent of the latan 2 engineering. This unit and a full year of generation at our Spearville wind facil- investment in clean-coal power generation will reduce the ity. Both La Cygne coal plants also set all-time highs for net combined sulfur dioxide emissions by 80 percent when it generation. Our CEP projects continued on time and on goes online in 2010. It is the largest non-transportation budget. Reliability has remained excellent with strong Tier 1 construction project in Missouri.
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| SAIDI metrics, which rate customer service outage duration, and two reliability awards. Rate cases included the costs of LA.CYGNE UNIT 1 ENVIRONMENTAL UPGRADES upgraded infrastructure investments and the La Cygne project. Installation of the La Cygne Generating Station's Unit 1 Selective Catalytic Reduction (SCR) system was completed NUCLEAR FACILITY IN in 2007. This upgrade became a key component of our CEP TOP U.S. QUARTILE after research conducted by the Mid-America Regional In 2007, Wolf Creek Generating Council showed that this investment could be the single Station ranked 11th worldwide largest contributor to reducing regional ground level ozone.
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| and eighth among all U.S. The upgrade was completed ahead of schedule and slightly nuclear power plants in capac- under budget. The new SCR reduced the unit's nitrogen ity factor, and 16th worldwide oxide emissions by approximately 87 percent.
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| and fourth among U.S. plants GREAT PLAINS ENERGY 2007 ANNUAL REPORT 7
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| : 1. OPERATIONAL EXCELLENCE PA Consulting Group honored KCP&L for its LEADERSHIP, innovation and achievement inthe area of electric RELIABILITY NATIONAL RELIABILITY EXCELLENCE AWARD PA Consulting Group OUTSTANDING SERVICE RELIABILITY AND SAFETY In October, we received the SAFETY RECORD: OSHA RECORDABLES Injuries& Illnesses - TotalRecordable 2007 National Reliability Case Rate per 100Employees*
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| Excellence Award for AllIndustryA.erage(4.4) .--.......... 1aI "leadership, innovation and achievement in the area of electric reliability," given by PA Consulting Group, a global management, systems
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| .IIIIIIII and technology consulting firm. All utilities operating electric delivery networks in c, o North America are eligible for the award, which is based 1.Bu primarily on system reliability statistics that measure the *..Bureau of LaborStatistics, 2006 date - Injuris and Illne*sses **DuPont 20]06data frequency and duration of customer outages. The award recognized KCP&L's superior regional performance and orga- We at Great Plains Energy were deeply saddened by the untimely nizational and cultural focus on reliability. It also highlighted loss of Ron Jones and Tom McCool in the incident at our the company's outage data-collection and reporting systems. Iatan Generating Station last spring. Their families remain in KCP&L also received the regional ReliabilityOneTM award our thoughts, and we honor their contributions and service.
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| for electric reliability in the Plains Region.
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| 8 GREAT PLAINS ENERGY 2007 ANNUAL REPORT
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| : 1. OPERATIONAL EXCELLENCE "Distribution Automation has become a very important part of an overall program that integrates CUSTOM ER satisfaction, system efficiency, asset management and demand response."
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| CARL GOECKELER Lead Distribution Automation Engineer COLLABORATION TO manage their businesses. Chartwell's Best Practicesfor IMPROVE LINE MAINTENANCE Utilities & Energy Companies, a well-respected industry AND LOWER COSTS publication, noted that this initiative "marks yet another Working on equipment while step toward closer partnerships between the utility (KCP&L) it is energized has become an and its customers."
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| important breakthrough in transmission reliability, and BETTER DISTRIBUTION AUTOMATION KCP&L is now using this. KCP&L's Distribution Automation (DA) system monitors technique. As our system our distribution system and facilitates supervisory control of load continues to increase, we can work on energized lines devices. In 2007, we were recognized for our work to develop without removing them from service. communication solutions using two-way cellular radio sys-tems and Web-based applications.
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| "Duringpeak times when the lines are heavily loaded and an outage would significantly impact our customers, we can work 20 PERCENT REDUCTION IN FOSSIL FUEL USE on energized lines without removing them from service-for In his 2007 State of the Union address, the President's goal both maintenance and emergency work on the transmission was to reduce our nation's gasoline usage by 20 percent by system. It is now a significantpart of our toolbox." 2017. KCP&L met that goal in July 2007 and surpassed it by PAUL BEAULIEU year-end. The KCP&L fleet now includes Manager, Transmission Construction & Maintenance ,* ",,380 112 ethanol flex-fuel biodiesel vehicles, vehicles and ENHANCED OUTAGE COMMUNICATION three first-of-their-kind In 2007, we implemented a new system that immediately E85 Hybrid Escapes.
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| notifies Tier 1 commercial and industrial customers of pertinent information during outages, to help them better GREAT PLAINS ENERGY 2007 ANNUAL REPORT 9
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| : 1. OPERATIONAL EXCELL*fý It 1"
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| KCP&L was recognized as having the best overall CUSTOMER service for a medium-sized utility, NATIONAL ACCOUNTS OUTSTANDING CUSTOMER SERVICE AWARD Edison Electric Institute RECOGNIZED CUSTOMER SERVICE KCP&L also won the Edison Electric Institute's 2007 National In 2007, we reachedK"Fier 1 Accounts Outstanding Customer Service Award for the year's i status in the J.D. Power best overall customer service in the medium-sized utility Residential affd Cdonriiercial category. Electric companies are grouped according to the Customer Satisfaction Stud-number of commercial customers they serve, and KCP&L ies, which benchmarked our was selected by more than 100 multi-site businesses. performance against other For the second time in less than a year, KCP&L also investor-owned utilities shar-received one of eight EEI Emergency Assistance Awards for ing similar geography and outstanding efforts to restore electric service or assist other size. J.D. Power and Associates utilities in restoring service following major storms or other is a respected global marketing information services firm natural events during 2007. KCP&L was recognized for that conducts independent, unbiased industry surveys of sending employees and equipment to outage events in Iowa, customer satisfaction, product quality and buyer behavior. J.D.
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| Illinois, Missouri and Oklahoma. Power recognized KCP&L for our prompt power restoration, energy efficiency efforts, bill payment options and knowl-edgeable and helpful customer care.
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| 10 GREAT PLAINS ENERGY 2007 ANNUAL REPORT
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| : 2. RECOGNIZED INDUSTRY LEADERSHIP The Mid-America Regional Council honored Kansas City Power & Light for its leadership through ENVIRONMENTAL initiatives.
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| REGIONAL LEADERSHIP AWARD Mid-America Regional Council ENVIRONMENTAL AND REGIONAL RECOGNITION Taking care of the air is part of our environmental responsibil- CONTINUED ity, and it's one we take very seriously. Emerging technologies COLLABORATION to reduce greenhouse gas emissions may not be available or We continue to collaborate practical during the next decade. In the interim, wind power with stakeholders as we and energy efficiency are the most viable options, along with plan our 2010-2015 energy strategies to reduce existing plant emission levels. strategies. In this effort, This year, in recognition of our environmental commit- KCP&L initiated a series ment, KCP&L received the Mid-America Regional Council of 2007 Energy Efficiency (MARC) Regional Leadership Award. MARC is an associa- Forums to build awareness tion of city and county governments and the metropolitan and support in the Kansas City area. Experts from around the planning organization for the bi-state Kansas City region. country were invited to express their views on the topic and The award recognized KCP&L's environmental initiatives, interact with regional, civic and business leaders. We also which included making environmental infrastructure helped fund the community air-quality efforts of the Kansas upgrades ahead of mandates and collaborating with City Climate Protection Committee, of which KCP&L Presi-community leaders on environmental issues. dent and CEO Bill Downey is a member, and the Kansas City KCP&L also received the 2007 David Garcia Award for Area Mayors Sustainability & Climate Protection Conference.
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| Environmental Excellence from Bridging The Gap in Together, we will build a viable plan to meet the region's partnership with MARC. growing energy demand.
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| GREAT PLAINS ENERGY 2007 ANNUAL REPORT 13
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| Fl U
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| : 3. BROAD COMMUNITY SUPPORT "Holding ourselves accountable to living this collaboration isthe key to moving forwardinthe years ahead. It's at the VERY CORE of what we do:'
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| BILL DOWNEY President and Chief Operating Officer, Great Plains Energy Inc.;
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| President and Chief Executive Officer, Kansas City Power & Light DOWNTOWN K.C. REDEVELOPMENT COMMITMENT "KCP&L is having a global effect on electric grid security."
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| KCP&L wants to be a catalyst for positive change and a STEPHEN DIEBOLD partner in greater Kansas City's economic development. Manager, Real-time Systems and Consortium Chair In 2007, we became the signature sponsor of the new "Kansas City Power & Light District" an $850 million eight- EMPOWERING THE FUTURE block downtown commercial and residential redevelopment. KCP&L employee volun-KCP&L will underwrite displays to educate visitors on energy teerism has increased 120 efficiency and will also fund district events and concerts. percent since 2005 and by In 2007, we also held public forums for Troost Avenue more than 45 percent since (Kansas City, Missouri) residents and business owners to we launched our community enhance service reliability in the heart of Kansas City. strategy a year ago to refocus our resources, engage and "Our company is absolutely committed to Kansas City's expand our top leadership downtown. The Power & Light Districtand the Sprint within the community and leverage our employee volun-Center are the anchorsfor downtown revitalization,so our teerism. In 2007, employees participated in more than 7,000 leadership and support are partof the commitment." hours of company-sponsored community events, focused MIKE DEGGENDORF in the areas of at-risk youth; environmental; economic and Vice President, Public Affairs workforce development.
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| A CONSORTIUM TO PROTECT THE GRID "KCP&L employees participatein events and relationships Cyber security is a primary focus and strength of the that absolutely changeKansas City and dramaticallyimpact state-of-the-art ABB Energy Management System (EMS) the lives of kids and teenagers."
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| used by KCP&L. ABB is a global leader that enables utility DANA L. CAMPBELL and industry customers to improve their performance while Development Director, YMCAof Greater Kansas City lowering their environmental impact. This year, KCP&L joined a consortium of ABB customers to fund advanced research and testing into securing supervisory control and data acquisition (SCADA) systems.
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| GREAT PLAINS ENERGY 2007 ANNUAL REPORT 15
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| WH INES mmN mP 4 . STRONG GRWT PROSPECTS* Sm*
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| In a 200 arice BarI a respected naioa fiania pubicaion reiee Grea Plin Enrg' statg of buldn soi ivstes to mee the ned of is grwn reio whil fotein a ses of colaoato an pateshi wit al of it stkhles Th artcl red "Th kin ofsrtg iths purue wil be for anySeesrutltosccentecoigyas reial power whil manann top tie pefrac stnad. Growt a-0
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| : 5. ATRCTV DIVIDEN I . 5 6 E S6 SThe of a Seurt diidn is impotan to mayGetPan 0
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| SHAR YOU ElINION OP~I*I Please fill out and drop this card in the mail to us.
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| Pleasecircle the number that most closely correlates to your opinion on a scale of ) to 5:
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| 1 Strongly disagree 2 Disagree 3 Neither agree nor disagree 4 Agree 5 Strongly agree The annual report gives a clear sense of where Great Plains Great Plains Energy is involved in the communities it serves.
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| Energy is headed and how it intends to get there. 1 2 3 4 5 1 2 3 4 5 Great Plains Energy is an industry leader.
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| Great Plains Energy is focused on operating more efficiently. 1 2 3 4 5 1 2 3 4 5 Based on this report and current data, I will increase my The quality of the company's management is excellent, investment in Great Plains Energy.
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| 1 2 3 4 5 1 2 3 4 5 I like Great Plains Energy's environmental commitment. Comments:
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| 1 2 3 4 5
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| NO POSTAGE NECESSARY 111111 IF MAILED IN THE UNITED STATES
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| [ BUSINESS REPLY MAIL FIRST-CLASS MAIL PERMIT NO. 221 KANSAS CITY MO POSTAGE WILL BE PAID BY ADDRESSEE CORPORATE COMMUNICATIONS KANSAS CITY POWER & LIGHT COMPANY PO BOX 418679 KANSAS CITY MO 64179-0030
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| GREAT PLAINS ENERGY INCORPORATED 1201 WALNUT STREET KANSAS CITY, MISSOURI 64106 March 26, 2008
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| ==Dear Shareholder:==
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| We are pleased to invite you to the Annual Meeting of Shareholders of Great Plains Energy Incorporated.
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| The meeting will be held at 10:00 a.m. (Central Daylight Time) on Tuesday, May 6, 2008, at the Nelson-Atkins Museum of Art, 4525 Oak Street, Kansas City, Missouri 64111. The Nelson-Atkins Museum of Art is accessible to all shareholders. Shareholders with special assistance needs should contact the Corporate Secretary, Great Plains Energy Incorporated, 1201 Walnut Street, Kansas City, Missouri 64106, no, later than Friday, April 25, 2008.
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| At this meeting, you will be asked to:
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| : 1. Elect ten directors; and
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| : 2. Ratify the appointment of independent auditors for 2008.
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| The attached Notice of Annual Meeting and Proxy Statement describe~the business to be transacted at the meeting. Your vote is important. Please review these materials and vote your shares.
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| We hope you and your guest will be able to attend the meeting. Registration and refreshments will be available starting at 9:00 a.m.
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| Sincerely, Michael J. Chesser Chairman of the Board Important Notice Regarding the Availability of Proxy Materials for the Shareholder Meeting to Be Held on May 6, 2008.
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| This proxy statement and our 2007 Annual Report are available at www.proxyvote.com.
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| (IPEfiT PLflIfl Ifl NY I Nelson-Atkins Museum of Art 4525 Oak Street Kansas City, Missouri Complimentary parking is available in the underground parking garage, located off Oak Street.
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| Construction at the Nelson-Atkins Museum of Art is now complete, and shareholders should access the facility through the glass doors of the Bloch building via the underground parking garage. Registration is located to the right and up the ramp.
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| ii
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| CONTENTS Page Proxy Statement 1 About the Meeting 1 About Proxies 5 About Householding 6 Election of Directors (Item I on Proxy Card) 7 Ratification of Appointment of Independent Auditors (Item 2 on Proxy Card) 9 Audit Committee Report 9 Corporate Governance 11 Director Independence 13 Board Policies Regarding Communications 15 Security Ownership of Certain Beneficial Owners, Directors and Officers 15 Director Compensation 16 Compensation Discussion and Analysis 17 Compensation Committee Report 31 Executive Compensation 31 Summary Compensation Table 32 Grants of Plan-Based Awards 33 Narrative Analysis of Summary Compensation Table and Plan-Based Awards Table 35 Outstanding Equity Awards at Fiscal Year-End 38 Option Exercises and Stock Vested 39 Pension Benefits 40 Nonqualified Deferred Compensation 41 Potential Payments upon Termination or Change-in-Control 41 Other Business 46 iii
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| GREAT PLAINS ENERGY INCORPORATED 1201 Walnut Street Kansas City, Missouri 64106 NOTICE OF ANNUAL MEETING OF SHAREHOLDERS Date: Tuesday, May 6,' 2008 Time: 10:00 a.m. (Central Daylight Time)
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| Place: The Nelson-Atkins Museum of Art 4525 Oak Street Kansas City, Missouri 64111 PROXY STATEMENT This proxy statement and accompanying proxy card are being mailed, beginning March 26, 2008,ý to owners of our common stock for the solicitation of proxies by our Board of Directors ("Board") for the 2008 Annual Meeting of -Shareholders ("Annual Meeting"). The Board encourages you to read this document carefully and take this opportunity to vote on the matters to be decided at the Annual Meeting.
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| In this proxy' statement, we refer to Great Plains Energy Incorporated as "we," "us, "..Company," or "Great Plains Energy," unless the context clearly indicates otherwise.
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| ABOUT THE MEETING Why did you provide me this proxy statement?
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| We provided you this p~roxy statement because you are a holder of our common stock and our Board of Directors is soliciting your proxy to vote at the Annual Meeting. As permitted by rules recently adopted by the Securities and Exchange Commission ("SEC"), we have elected to provide access to this proxy statement and our 2007 annual report to our beneficial shareholders electronically via the internet. If you received a Notice by mail, you will not receive a printed copy of the proxy materials in the mail. Instead, the Notice instructs you how to access and review all of the important information contained in, the proxy statement and 2007 annual report. The Notice also instructs you how to submit your vote over the internet. If you received a Notice by mail and would like to receive a printed copy of our proxy materials, you should follow the instructions for requesting such materials included in the Notice. In the future, we 1
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| may elect to expand electronic delivery and provide all shareholders a Notice of Electronic Availability of Proxy Materials in lieu of incurring the expense of printing and delivering hard copies of the materials to everyone.
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| For information on how to receive electronic delivery of annual shareholder reports, proxy statements and proxy cards, please see "Can I elect electronic delivery of annual shareholder reports, proxy statements and proxy cards?" below.
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| What will be voted on?
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| At the annual meeting, you will be voting on:
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| " The election of ten directors to our Board; and
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| * The ratification of the appointment of Deloitte & Touche LLP ("Deloitte & Touche") to be our independent registered public accounting firm in 2008.
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| How do you recommend that I vote on these matters?
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| The Board of Directors recommends that you vote FOR each of the people nominated to be directors, and FOR the ratification of the appointment of Deloitte & Touche.
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| Who is entitled to vote on these matters?
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| You are entitled to vote if you owned our common stock as of the close of business on February 27, 2008. On that day, approximately 86,284,103 shares of our common stock were outstanding and eligible to be voted. Shares of stock held by the Company in its treasury account are not considered to be outstanding, and will not be voted or considered present at the Annual Meeting.
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| Is cumulative voting allowed?.
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| Cumulative voting is allowed with respect to the election of our directors. This means that you have a total vote equal to the number of shares you own, multiplied by the ten directors to be elected. Your votes for directors may be divided equally among all of the director nominees, or you may vote for one or more of the nominees in equal or unequal amounts. You may also withhold your votes for one or more of the nominees. If you withhold your votes, these withheld votes will be distributed equally among the remaining director nominees.
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| How many votes are needed to elect directors?
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| The ten director nominees receiving the highest number of FOR votes will be elected. This is called "plurality voting." Withholding authority to vote for some or all of the director nominees, or not returning your proxy card, will have no effect on the election of directors.
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| How many votes are needed to ratify the appointmentof Deloitte & Touche?
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| Ratification requires the affirmative vote of the majority of shares voting at the Annual Meeting.
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| Absentee and broker non-votes will have the effect of negative votes. Shareholder ratification of the appointment is not required, but your views are important to the Audit Committee and the Board. If shareholders do not ratify the appointment, our Audit Committee will reconsider the appointment.
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| 2
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| How can I submit a proposal to be included in next year's proxy statement?
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| Shareholders wishing to have a proposal included in the proxy statement for the Annual Meeting in 2009 must submit a written proposal to the Corporate Secretary by November 19, 2008. SEC rules set certain standards for shareholder proposals to be included in a proxy statement, including that each shareholder may submit no more than one proposal for a shareholder meeting.
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| To be eligible to bring a proposal for inclusion in the proxy statement, you:
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| * must have continuously held at least $2,000 in market value or 1% of our common stock for at least one (1) year as of the date the proposal is submitted to us; and
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| " intend to continue ownership of the shares through the date of the Annual Meeting.
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| To be in proper written form, your proposal must include:
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| * a brief description (no more than 500 words in length) *ofthe business to be brought before the shareholder meeting and the reasons for conducting the business at the shareholder meeting;
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| * your name and record address;
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| * the class or series and number of shares of our stock that you own beneficially or of record, including proof of ownership and length of ownership by written statement from the record holder of the securities or a copy of the proof of ownership filed with the SEC, and a written statement of your intent to continue ownership of the shares through the date of the Annual Shareholders Meeting;
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| " a description of all arrangements or understandings between you and any other person or persons (including their names) in connection with your proposal, and any material interest of yours in such proposal; and
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| * your representation that you intend to appear in person or by a qualified representative at the Annual Meeting to bring such business before the meeting.
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| Can I bring up matters at the Annual Meeting or other shareholder meeting, other than through the proxy statement?
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| If you intend to bring up a matter at a shareholder meeting, other than by submitting a proposal for inclusion in our proxy statement for that meeting, our By-laws require you to give us notice at least 60 days, but no more than 90 days, prior to the date of the shareholder meeting. If we give shareholders less than 70 days notice of a shareholder meeting date, the shareholder's notice must be received by the Corporate Secretary no later than the close of business on the tenth (1loth ) day following the earlier of the date of the mailing of the notice of the meeting or the date on which public disclosure of the meeting date was made.
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| May I ask questions at the Annual Meeting?
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| Yes. We expect that all of our directors, senior management, and representatives of Deloitte & Touche will be present at the Annual Meeting. We will answer your questions of general interest at the end of the Annual Meeting. We may impose certain procedural requirements, such as limiting repetitive or follow-up questions, so that more shareholders will have an opportunity to ask questions.
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| 3
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| How can I propose someone to be a nomineefor election to the Board?
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| The Governance Committee of the Board will consider candidates for director suggested by shareholders, using the process described in the section below titled "Director Nominating Process."
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| Our By-laws require shareholders wishing to make a director nomination to give notice not less than 60 days, nor more than 90 days prior to the date of the shareholder meeting. If we give shareholders less than 70 days notice of a shareholder meeting date, your notice must be received by the Corporate Secretary no later than the close of business on the tenth (1 0 th) day following the earlier of the date of mailing of the notice of the meeting or the date on which public disclosure of the meeting date was made.
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| For your director nominee election to. be in proper written form, your notice to the Corporate Secretary must include your:
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| * name and shareholder record; and
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| " class or series of our stock and number of shares you own beneficially or of record; and your nominee's:
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| * name, age, business address and residence address;
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| * principal occupation or employment;*
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| * class or series of our stock and number of shares owned beneficially or of record; and
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| * written consent to serve as a director, if elected.
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| The notice must also provide:
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| * a description of all arrangements or understandings between you and the nominee;
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| * a representation that you intend to appear in person or by a qualified representative at the shareholder meeting to nominate the nominee; and
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| * any other information relating to you and your nominee that is required to be reported in a proxy statement or other filings asrequired by SEC rules.
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| No person shall be eligible for election as a director unless nominated according to procedures in Great Plains Energy's By-laws as described above. You may request'a copy of the By-laws by contacting the Corporate Secretary, Great Plains Energy Incorporated, 1201 Walnut Street, Kansas City, Missouri 64106.
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| Who is allowed to attend the Annual Meeting?
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| If you own our shares, you and a guest are welcome to attend our Annual Meeting. You will need to register when you arrive at the meeting. We may also verify your name against our shareholder list. If you own shares in a brokerage account in the name of your broker or bank ("street name"), you should bring your most recent brokerage account statement or other evidence of your share ownership. If we cannot verify that you own our shares, it is possible that you may not be admitted to the meeting.
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| If your shares are registered in the name of a broker' or nominee, you and a guest are also welcome to attend the Annual Meeting. If you would like to vote in person, you should contact your broker or nominee to obtain a broker's proxy card and bring it, together with proper identification and your account statement or other evidence of your share ownership, with you to the Annual Meeting. If your shares are held in a street name, you must contact your broker or nominee to revoke your proxy.
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| 4
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| ABOUT PROXIES How can I vote at the Annual Meeting?
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| You can vote your shares either by casting a ballot during the Annual Meeting, or by proxy.
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| Are you soliciting proxiesfor theAnnual Meeting?
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| Yes, our Board is soliciting proxies. We will pay the costs of this solicitation. In addition to the use of the mails, proxies may be solicited in person, by telephone, facsimile or other electronic means by our directors, officers, and employees without additional compensation.
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| Morrow & Co., Inc., 445 Park Avenue, New York, New York 10022, has been retained by us to assist in the solicitation, by phone, of votes for the fee of $6,500, plus reimbursement of out-of-pocket expenses.
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| We will also reimburse brokers, nominees, and fiduciaries for their costs in sending proxy materials to holders of our shares.
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| How do I vote by proxy before the Annual Meeting?
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| If you are a registered shareholder, we have furnished to you the proxy materials, including the proxy card. You may also view the proxy materials electronically at the www.proxyvote.com website.
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| Registered shareholders may vote their shares by mail, telephone or internet. To vote by mail, simply mark, sign and date the proxy card and return it in the postage-paid envelope provided. To vote by telephone or internet, 24 hours a day, 7 days a week, refer to your proxy card for voting instructions.
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| If your shares are registered in the name of your broker or other nominee, you should vote your shares using the method directed by that broker or other nominee. A large number of banks and brokerage firms are participating in the Broadridge Financial Solutions, Inc. online program. This program provides eligible street name shareholders the opportunity to vote via the internet or by telephone. Voting forms will provide instructions for shareholders whose banks or brokerage firms are participating in Broadridge's program.
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| Properly executed proxies received by the Corporate Secretary before the close of voting at the Annual Meeting will be voted according to the directions provided. If a proxy is returned without shareholder directions, the shares will be voted as recommended by the Board.
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| What shares are includedon the proxy card?.
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| The proxy card represents all .the shares registered to you, including all shares held in your Great Plains Energy Dividend Reinvestment and Direct Stock Purchase Plan ("DRIP") account and Employee Savings Plus Plan as of the close of business on February 27, 2008.
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| Can I change my mind after I submit a proxy?
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| You may revoke your proxy at any time before the close of voting by:
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| * written notice to the Corporate Secretary; 5
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| * submission of a proxy bearing a later date; or
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| * casting a ballot at the Annual Meeting.
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| I have Company shares registeredin my name, and also have shares in a brokerage account. How do I vote these shares?
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| Any shares that you own in street name are not included in the total number of shares that are listed on your proxy card. Your bank or broker will send you directions on how to vote those shares.
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| Will my sharesheld in street name be voted if I don 't provide a proxy?
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| These shares might be voted even if you do not provide voting instructions to the broker. The current New York Stock Exchange ("NYSE") rules allow brokers to vote shares on certain "routine" matters for which their customers do not provide voting instructions. The election of our directors and the ratification of the appointment of Deloitte & Touche are considered "routine" matters, assuming that no contest arises on these matters.
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| Is my vote confidential?
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| We have a policy of voting confidentiality. Your vote will not be disclosed to the Board or our management, except as may be required by law and in other limited circumstances.
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| ABOUT HOUSEHOLDING Are you "householding"foryour shareholderswith the same address?
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| Yes. Shareholders that share the same last name and household mailing address with multiple accounts will receive a single copy of shareholder documents (annual report, proxy statement, prospectus or other information statement) unless we are instructed otherwise. Each registered shareholder will continue to receive a separate proxy card. Any shareholder who would like to receive separate shareholder documents may call or write us at the address below, and we will promptly deliver them. If you received multiple copies of the shareholder documents and would like to receive combined mailings in the future, please call or write us at the address below. Shareholders who hold their shares in street name should contact your bank or broker regarding combined mailings.
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| Great Plains Energy Incorporated Shareholder Relations 1201 Walnut Street Kansas City, Missouri 64106 1-800-245-5275 Can I elect electronicdelivery of annualshareholderreports,proxy statements andproxy cards?
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| Yes. You can elect to receive future annual shareholder reports, proxy statements and proxy cards electronically via e-mail or the internet. To sign up for electronic delivery, please either select the box that corresponds with the "Materials Election" section of the proxy card before mailing in your proxy card, or follow the instructions on the proxy card to vote using the internet and, when prompted, indicate that you agree to receive or access shareholder communications electronically in future years.
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| 6
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| ELECTION OF DIRECTORS Item 1 on Proxy Card The ten nominees presented have been recommended to the independent directors of the Board by the Governance Committee to serve as directors until the next Annual Meeting of Shareholders and until their successors are elected and qualified. Mr. William K. Hall, one of our current directors, announced on March 18, 2008, that he would not stand for re-election. No director nominee for Mr. Hall's position is being proposed at this meeting. All of the directors elected in 2007, with the exception of Mr. Hall, are listed below as nominees. Each nominee has consented to stand for election, and the Board does not anticipate any nominee will be unavailable to serve. In the event that one or more of the director nominees should become unavailable to serve at the time of the Annual Meeting, shares represented by proxy may be voted for the election of a nominee to be designated by the Board. Proxies cannot be voted for more than ten persons.
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| Nominees for Directors The following persons are nominees for election to our Board:
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| David L. Bodde Luis A. Jimenez Michael J. Chesser James A. Mitchell William H. Downey William C. Nelson Mark A. Ernst Linda H. Talbott Randall C. Ferguson, Jr. Robert H. West The Board of Directors recommends a vote FOR each of the ten listed nominees.
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| Director and Director Nominee Information David L. Bodde Director since 1994 Dr. Bodde, 65, is the Senior Fellow and Professor, Arthur M. Spiro Institute for Entrepreneurial Leadership at Clemson University (since 2004). He previously held the Charles N. Kimball Chair in Technology and Innovation (1996-2004) at the University of Missouri-Kansas City. He also serves on the board of The Commerce Funds. Dr. Bodde served as a member of the Executive, Audit and Governance Committees during 2007.
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| Michael J. Chesser Director since 2003 Mr. Chesser, 59, is Chairman of the Board and Chief Executive Officer - Great Plains Energy and Chairman of the Board - Kansas City Power & Light ("KCP&L") (since October 2003). Previously he served as Chief Executive Officer of United Water (2002-2003); and President and Chief Executive Officer of GPU Energy (2000-2002). Mr. Chesser served as a member of the Executive Committee in 2007.
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| William ff. Downey Director since 2003 Mr. Downey, 63, is President and Chief Operating Officer - Great Plains Energy and President and Chief Executive Officer - KCP&L (since October 2003). Mr. Downey joined the Company in 2000 as Executive Vice President - Kansas City Power & Light Company and President - KCP&L Delivery. Mr. Downey also serves on the boards of Grubb & Ellis Realty Advisors, Inc. and Enterprise Financial Services Corp.
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| 7
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| Mark A. Ernst Director since 2000 Mr. Ernst, 49, is President of Bellevue Capital, LLC, a private investment firm. He was formerly Chairman of the Board, President, and Chief Executive Officer of H&R Block, Inc., a global provider of tax preparation, investment, and accounting services (2001-2007). Mr. Ernst served on the Executive, Audit, and Compensation and Development Committees during 2007.
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| Randall C. Ferguson, Jr. Director since 2002 Mr. Ferguson, 56, was the Senior Partner for Business Development for Tshibanda & Associates, LLC (2005-2007), a consulting and project management services firm committed to assisting clients to improve operations and achieve long-lasting, measurable results. Previously he served as Senior Vice President Business Growth & Member Connections with the Greater Kansas City Chamber of Commerce (2003-2005) and is the retired Senior Location Executive (1998-2003) for the IBM Kansas City Region. Mr.
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| Ferguson served on the Audit and Governance Committees during 2007.
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| William K. Hall Director since 2000 Dr. Hall, 64, is Chairman (since 2000) of Procyon Technologies, Inc., a holding company with investments in the aerospace and defense industries. He also served as Chief Executive Officer (2000-2003) of the company. Dr. Hall also serves on the boards of Actuant Corporation, A. M. Castle & Co., Stericycle, Inc.,
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| and W. W. Grainger, Inc. Dr. Hall served on the Audit and Governance Committees during 2007.
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| Luis A. Jimenez Director since 2001 Mr. Jimenez, 63, is Senior Vice President and Chief Industry Policy Officer (since 2007) of Pitney Bowes Inc., a global provider of integrated mail and document management solutions. Previously, he was Senior Vice President and Chief Strategy Officer (2001-2007). Mr. Jimenez served on the Governance and Compensation and Development Committees during 2007.
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| James A. Mitchell Director since 2002 Mr. Mitchell, 66, is the Executive Fellow-Leadership of the Center for Ethical Business Cultures (since 1999), a not-for-profit organization assisting business leaders in creating ethical and profitable cultures and is a Director for Capella Education Company. Mr. Mitchell served on the Compensation and Development and Governance Committees during 2007.
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| William C. Nelson, Director since 2000 Mr. Nelson, 70, is Chairman (since 2001) of George K. Baum Asset. Management, a provider of investment management services to individuals, foundations, and institutions. He also serves on the board of DST Systems. Mr. Nelson served on the Executive, Audit, and Compensation and Development Committees during 2007.
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| Linda H. Talbott Director since 1983 Dr. Talbott, 67, is President and CEO of Talbott & Associates (since 1975), consultants in strategic planning, philanthropic management and development to foundations, corporations, and nonprofit organizations. She is also Chairman of the Center for Philanthropic Leadership. Dr. Talbott served as the Advising Director for Corporate Social Responsibility and on the Governance and Compensation and Development Committees during 2007.
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| Robert H. West Director since 1980 Mr. West, 69, retired in July 1999 as Chairman of the Board of Butler Manufacturing Company, a supplier of non-residential building systems, specialty components and construction services. He also serves on the boards of Burlington Northern Santa Fe Corporation and Commerce Bancshares, Inc. Mr. West served as 8
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| the Lead Independent Director of the Board and as a member of the Audit, Executive, and Compensation and Development Committees during 2007.
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| Director Nominating Process The Governance Committee identifies and recommends to the independent directors of the Board the nominees for the election of directors at the shareholder meeting. At its discretion, the Governance Committee may pay a fee to third party consultants and experts to help identify and evaluate potential new nominees for director.
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| In accordance with the Corporate Governance Guidelines, the Governance Committee takes into account a number of factors when considering director candidates. Director nominees are selected based on-their practical wisdom, mature judgment and diversity of backgrounds and business experience. Nominees should possess the highest levels of personal and professional ethics, integrity, and values and be*
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| committed to representing the interests of shareholders. The Governance Committee may also consider in its assessment the Board's diversity in its broadest sense, reflecting geography, age, gender, and ethnicity, as well as other appropriate factors.
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| RATIFICATION OF APPOINTMENT OF INDEPENDENT AUDITORS Item 2 on Proxy Card Deloitte & Touche has acted as our independent registered public accounting firm since 2002, and has been appointed by the Audit Committee to audit and certify our financial statements for 2008, subject to ratification by the shareholders of the Company.
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| Representatives from Deloitte & Touche are expected to be present at the Annual Meeting, with the opportunity to make statements if they wish to do so, and are expected to be available to respond to appropriate questions.
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| The affirmative vote of the holders of a majority of the shares of our common stock present and entitled to vote at the meeting is required for ratification of this appointment. If the appointment of Deloitte &
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| Touche is not ratified, the selection of the independent registered public accounting firm will be reconsidered by the Audit Committee.
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| The Board of Directors recommends a vote FOR ratification.
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| -AUDIT COMMITTEE REPORT The Audit Committee comprises six independent directors. In connection with its function to oversee and monitor the financial reporting process of Great Plains Energy, the Audit Committee's activities in 2007 included the following:
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| * reviewed and discussed the audited financial statements and the reporton internal control over financial reporting with management and the independent auditors;
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| * discussed with Deloitte & Touche, the Company's independent auditors for the year ended
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| *December 31, 2007, the matters required to be discussed by SEC regulations and by Statement on Auditing Standards No. 61, as amended, as adopted in Rule 3200T of the Public Company Accounting Oversight Board (the "PCAOB");
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| * received the written disclosures and the letter from Deloitte & Touche required by Independence Standards Board Standard No. 1 (Independence Standards Board Standard No. 1, 9.
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| Independence Discussions with Audit Committees), as adopted by Rule 3600T of the PCAOB, and discussed with Deloitte & Touche its independence from management and the Company and its subsidiaries; and 0 considered whether the non-audit services in the categories below were compatible with maintaining Deloitte & Touche's independence.
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| Based on the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in the Company's annual report on Form 10-K for the fiscal year ended December 31, 2007 for filing with the SEC.
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| Fees paid to Deloitte & Touche The following table sets forth the aggregate fees billed by Deloitte & Touche for audit services rendered in connection with the consolidated financial statements and reports for 2007 and 2006,-and for other services rendered during 2007 and 2006 on behalf of the Company and its subsidiaries, as well as all out-of-pocket costs incurred in connection with these services:
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| Fee Category 2007 2006 Audit Fees $2,294,695 $1,905,708
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| ~Audit-Relawt 1-ces o1.ý Io, o,,6 Tax Fees 43__,349 31,137 AllTOther $e2,4,44 ( (5) $2, 5004 Total Fees: $2,442,757 $2,004,980 Audit Fees: Consist of fees billed for professional services rendered for the audits of the annual consolidated financial statements of the Company and its subsidiaries and reviews of the interim condensed consolidated financial statements included in quarterly reports. Audit fees also include:
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| services provided by Deloitte & Touche in connection with statutory and regulatory filings or .
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| engagements; audit of and reports on the effectiveness of internal control over financial reporting and on management's assessment of the effectiveness of internal control over financial reporting and other attest services, except.those not required by statute or regulation; services related to filings with the SEC, including comfort letters, consents and assistance with and review of documents filed with the SEC; and accounting research in support of the audit.
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| Audit-Related Fees: Consist of fees billed to the Company for benefit plan audits and for assurance and related services that are reasonably related to the performance of the audit or review of consolidated financial statements of the Company and its subsidiaries, and are not reported under "Audit Fees." These services include consultation concerning financial accounting and reporting standards and, in 2007, the proposed acquisition of Aquila, Inc.
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| Tax Fees: Consist of fees billed to the Company for benefit plan tax services and for tax compliance and related support of tax returns and other tax services, including assistance with tax audits, and tax research and planning.
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| All Other Fees: Consist of fees for all other services other than those reported above. Those services in 2007 and 2006 included accounting research tool subscriptions.
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| 10
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| Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firms The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accounting firms to the Company and its subsidiaries. These services may include audit services, audit-related services, tax services and other services. The Audit Committee has adopted for the Company and its subsidiaries policies and procedures for the pre-approval of services provided by the independent auditor. Under these policies and procedures, the Audit Committee may pre-approve certain types of services, up to aggregate fee levels established by the Audit Committee. Any proposed service within a pre-approved type of service that would cause the applicable fee level to be exceeded cannot be provided unless the Audit Committee either amends the applicable fee level or specifically approves the proposed service. The Audit Committee, as well, may specifically approve other audit and permissible non-audit services on a case-by-case basis. Pre-approval is generally provided for up to one year, unless the Audit Committee specifically provides for a different period. The Audit Committee receives quarterly reports regarding the pre-approved services performed by the independent registered public accounting firms. The Chairman of the Audit Committee may between meetings pre-approve audit and non-audit services provided by the independent registered public accounting firms, and report such pre-approval at the next Audit Committee meeting.
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| Audit Committee Mark A. Ernst, Chair David L. Bodde Randall C. Ferguson, Jr.
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| William K. Hall William C. Nelson Robert H. West CORPORATE GOVERNANCE Our business, property and affairs are managed under the direction of our Board, in accordance with Missouri General and Business Corporation Law and our Articles of Incorporation and By-laws.
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| Although directors are not involved in the day-to-day operating details, they are kept informed of our business through written reports and documents regularly provided to them. In addition, directors receive operating, financial and other reports by the Chairman and other officers at Board and committee meetings.
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| Board Attendance at Annual Meeting. The directors are expected to attend the Annual Meetings. In 2007, all directors were present at the Annual Meeting.
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| Meetings of the Board. The Board held thirteen meetings in 2007. Each of our directors attended at least 80% of the aggregate number of meetings of the Board and committees to which he or she was assigned.
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| The independent members of the Board annually elect a Lead Independent Director. Mr. West was the Lead Independent Director in 2007, and continues in that role in 2008. Mr. West, as Lead Independent Director, presides over regularly scheduled executive sessions of the non-management members of the Board, among other duties set out in our corporate governance guidelines.
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| Committees of the Board. The Board's four standing committees are described below. Directors' committee memberships are included in their biographical information beginning on page 7.
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| 11
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| Executive Committee - exercises the full power and authority of the Board to the extent permitted by Missouri law. The Committee generally meets when action is necessary between scheduled Board meetings. The Committee's members are Messrs. Chesser (Chairman), Ernst, Nelson, and West, and Dr. Bodde.
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| The Committee did not meet in 2007.
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| Audit Committee - oversees the auditing, accounting and financial reporting of Great Plains Energy including:
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| * monitoring the integrity of the Company's financial reporting process and systems of internal controls regarding finance, accounting, legal and regulatory compliance;
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| * having direct responsibility for the appointment, compensation, retention, termination, terms of engagement, evaluation and oversight of the work of the Company's independent auditors;
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| * reviewing and discussing significant audit services department findings and recommendations and management's responses; and
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| * providing an avenue of communication among the independent auditors, management, internal auditing department and the Board.
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| The Committee's members are Messrs. Ernst (Chairman), Ferguson, Nelson, and West, and Drs.
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| Bodde and Hall. All members of the Audit Committee are "independent," as defined for audit committee members by the NYSE listing standards. The Board identified Messrs. Ernst, Nelson, and West, and Dr. Hall as independent "audit committee financial experts" as that term is defined by the SEC pursuant to Section 407 of the Sarbanes-Oxley Act of 2002.
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| The Committee held six meetings in 2007.
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| Compensation andDevelopment Committee - reviews and assists the Board in overseeing compensation and development matters including:
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| * aligning the interests of directors and executives with the interests of shareholders;
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| " motivating performance to achieve the Company's business objectives;
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| * developing existing and emerging executive talent within the Company;
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| * administering Great Plains Energy's incentive plans for senior officers; and
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| * recommending compensation to be paid to Board members.
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| The Committee's members are Messrs. Nelson (Chairman), Ernst, Jimenez, Mitchell and West, and Dr. Talbott. The Committee held five meetings in 2007.
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| The processes and procedures for considering and determining executive compensation, including the Committee's authority and role in the process, its delegation of authority to others, and the roles of our executive officers and third-party executive compensation consultants in making the decisions or recommendations, are described in the "Compensation Discussion and Analysis" section below.
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| Governance Committee - reviews and assists the Board with all corporate governance matters including:
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| 12
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| * identifying and recommending nominees qualified to become board members; 0 monitoring the effectiveness of the Company and its subsidiaries in meeting overall objectives and goals of the organization;
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| * developing, recommending and monitoring a set of appropriate corporate governance principles applicable to Great Plains Energy and its subsidiaries; and
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| * monitoring the effectiveness of the Company's social responsibility program.
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| The Committee's members are Drs. Bodde (Chairman), Hall, and Talbott, and Messrs. Jimenez and Mitchell. The Committee held five meetings in 2007.
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| Corporate Governance Guidelines, Committee Charters and Code of Ethical Business Conduct.
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| The Board has adopted written corporate governance guidelines, charters for the Audit, Compensation and Development, and Governance Committees, and a Code of Ethical Business Conduct. These documents are available on the Company's website at www.greatplainsenergy.com. These documents are also available in print to any shareholder upon request. Requests should be directed to Corporate Secretary, Great Plains Energy Incorporated, 1201 Walnut Street, Kansas City, Missouri 64106.
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| DIRECTOR INDEPENDENCE Our stock is listed on the NYSE, and our board uses the NYSE director and board committee independence definitions in determining whether our directors and committee members are independent. In addition, there are SEC independence requirements for the members of our Audit Committee.
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| The NYSE director independence definitions provide that directors cannot be independent if they do not meet certain objective standards, or if the Board determines that the director has a material relationship with the Company. The Board has determined that the following current directors (who are also nominees for directors at our Annual Meeting) are "independent" under the NYSE definitions:
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| David L. Bodde William K. Hall William C. Nelson-Mark A. Ernst " Luis A. Jimenez Linda H. Talbott Randall C. Ferguson, Jr. James A. Mitchell *Robert H*West Only these independent directors are members of our Audit, Compensation and Development, and Governance Committees. All members of our Audit Committee also meet the additional NYSE and SEC independence requirements. Messrs. Chesser and Downey are not "independent" under the NYSE definitions, because they are also officers of the Company.
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| The Board considered all relationships between the Company, on the one hand, and the directors and their immediate families, on the other hand, as required by the NYSE definition. The following relationships were considered by the Board, and determined not to impair the independence of the directors:
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| Name Relationships David L. Bodde Consultant to a Company supplier; trustee of a mutual fund family associated with a bank providing banking services to Company.
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| Mark A. Ernst Director of charitable, civic, and educational organizations to which the' Company contributes, pays dues or fees, or has officers serving as directors; related to an employee of a company that is'a supplier to the Company and a Strategic Energy electric customer; 13
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| Name Relationships Randall C. Ferguson, Jr. Director of charitable, civic and educational organizations to which the Company contributes, pays dues or fees, or has officers serving as directors; related to an employee of a supplier to the Company; related to two employees of companies providing financial services to the Company.
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| William K. Hall Advisor to an educational organization to which the Company contributes; director of a supplier to the Company.
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| Luis A. Jimenez Officer of a supplier to the Company.
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| William C. Nelson Director of charitable, civic and educational organizations to which the Company contributes, pays dues or fees, or has officers serving as directors; director of a supplier to the Company.
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| Linda H. Talbott Advisor to charitable or civic organizations to which the Company contributes, pays dues or fees.
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| Robert H. West Director of suppliers to the Company; director of a bank providing banking services to the Company; director of an educational organization to which the Company contributes.
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| In addition to those matters, the Board considered the fact that our regulated electric utility subsidiary provides retail electric service to the directors, their immediate family members, and employers who are in our regulated utility's service territory.
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| Related Party Transactions Our written Code of Ethical Business Conduct applies to our directors, officers and employees. It deals with conflicts of interest, among other things. The Code prohibits any conduct or activities that are inconsistent with the Company's best interests, or that disrupt or impair the Company's relationship with any person or entity which the Company has, or proposes to enter into, a business or contractual relationship. The Code also requires directors and officers to report their conflict of interest concerns to the Audit Committee.
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| Waivers of the Code's requirements for officers and directors can be given only by our Board or a Board Committee. No waivers have been granted.
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| The Governance Committee adopted written policies and procedures regarding evaluation and approval of transactions between the Company and related parties that are required to be disclosed under Section 404(a) of Regulation S-K. As used in the policies, a "related party" includes directors and officers of the Company, immediate family members of the directors and officers, any person who holds more than 5%
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| of our voting stock, any entity that is owned or controlled by someone listed above, and any entity in which someone listed above is a director, officer, employee or a substantial shareholder. A "transaction" is defined as any transaction with the Company, including, but not limited to sales or purchases of property or services, leases of property, loans, guaranties, financial arrangements or relationships.
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| Proposed transactions that may be required to be disclosed pursuant to Item 404(a) of Regulation S-K are required to be forwarded to legal counsel and, if counsel determines that the matter constitutes a probable conflict of interest or a disclosable related party transaction, the matter will be referred to the Governance Committee for review and approval before the transaction is entered into.
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| 14
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| In addition to these policies and procedures, our directors and officers are required each year to respond to a detailed questionnaire. The questionnaire requires each director and officer to identify every non-Company organization of any type of which they or their immediate family are a director, partner, member, trustee, officer, employee, representative, consultant or significant shareholder. The questionnaire also requires disclosure of any transaction, relationship or arrangement with the Company. The information obtained from the questionnaires is then evaluated and compared against Company records to determine the nature and amount of any transactions or relationships. The results are provided to the Governance Committee and Board for their use in determining director independence and related party disclosure obligations. There were no transactions in 2007 required to be disclosed pursuant to Item 404(a) of Regulation S-K.
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| Compensation Committee Interlocks and Insider Participation None of the members of our Compensation and Development Committee is or was an officer or employee of Great Plains Energy or its subsidiaries. None of our executive officers served as a director or was a member of the compensation committee (or equivalent body) of any entity where a member of our Board or Compensation and Development Committee was also an executive officer.
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| BOARD POLICIES REGARDING COMMUNICATIONS The Company has a process for communicating with the Board. Communications from interested parties to the non-management members of the Board can be directed to:
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| Dr. David L. Bodde Chairman, Governance Committee Great Plains Energy Incorporated 1201 Walnut Street Kansas City, MO 64106 Attn: Barbara B. Curry, Corporate Secretary Communications are forwarded to the Governance Committee to be handled on behalf of the Board.
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| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS,,
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| DIRECTORS AND OFFICERS The following table shows beneficial ownership of Company common stock by the directors, the named executive officers ("NEOs"), and all executive officers of the Company as of March 1, 2008. The total of all shares owned by directors and executive officers represents less than 1% of our outstanding shares.
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| Our management has no knowledge of any person (as defined by the SEC) who owns beneficially more than 5% of our common stock.
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| 15
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| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, DIRECTORS AND OFFICERS Vested Stock Options and Share Shares Held Options that Equivalents to Beneficially in Company Vest Within Total Shares be Settled in Total Share Name Owned Shares Plans (1) 60 Days Held Stock (2) Interest (a) )(b) (#) (c) (#) (d) (#)(e) (#) (f) (#)-(g)
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| Named Executive Officers Michael J. Chesser 32,185 104,077 -_ 7 136,262 - 136,262 TerrfyBassham - 41,813 1 * - 41,813, 41,813)
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| S&hahidtlalikIr 0,24_3ý 2f4,2 ~7 3) ~ K24,4273 John R. Marshall. 6,703 56,005 62,708 - 62,708 Non-Management Directors David L. Bodde 13,853 13,853 (3) 1,767 15,620
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| %IarkA. Erns~t 1 24 ______ ~l313? -,F, Randall C. Ferguson, Jr. 6,278 - - 6,278 1,767 8,045 WViliamn K. Ialb, jfIgoj I 9 ~ 9;1 1~7,1r90 119 Luis A. Jimenez 10,238 10,238 _ 10,238 Jatrin& . Mitclhell 0,4 ~45~,_______ _____ 0.745 William C. Nelson 9,699 -)- 9,699699 9,699 (4)
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| Robert H. West 10,143 - - 10,143 (s) 1,767 ___11,910 All Great Plains Energy Directors and Executive Officers as a Group (17 persons) 533,013 (1) The shares listed include restricted shares and shares held in the 401(k) plan.
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| (2) The shares listed are director deferred share units through our Long-Term Incentive Plan which will be settled in stock on a I-for- I basis upon the first January 31 st following the last day of service on the Board.
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| (3) The nominee disclaims beneficial ownership of 1,000 shares reported and held by nominee's mother.
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| (4) The nominee disclaims beneficial ownership of 62 shares reported and held by nominee's wife:
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| (5) The nominee disclaims beneficial ownership of 1,000 shares reported and held by nominee's wife.
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| Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers and persons who own more than 10% of our common stock to file reports of holdings and transactions in our common stock with the SEC. Based upon our records, we believe that all required reports for 2007 have been timely filed.
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| DIRECTOR COMPENSATION We compensate our non-employee directors as summarized below. Messers. Chesser and Downey are officers of the Company, and do not receive compensation for their service on the Board. We paid non-employee directors an annual retainer of $85,000 in 2007 ($50,000 of which was used to acquire shares of common stock through our DRIP). Our Lead Independent Director received an additional annual retainer of
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| $20,000, and the chairs of the Board's Audit, Compensation and Development, and Governance Committees received an additional annual retainer of $10,000, $5,000 and $5,000, respectively. Attendance fees of $1,000 for each Board meeting and $1,000 for each committee and other meeting attended were also paid in 2007. Directors may defer the receipt of all or part of the cash retainers and meeting fees. Starting in 16
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| 2008, directors will receive the equity portion of the annual retainer through our Long-Term Incentive Plan
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| ("LTIP"). Under the LTIP, directors may elect to receive the stock currently, or may elect to defer receipt of all or part of the stock .
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| We offer life and medical insurancecoverage for the current non-employee directors and their families.
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| We do not expect to offer this coverage to new non-employee directors. The aggregate premium paid by us for this coverage in 2007 was $33,146., We pay or reimburse directors for travel, lodging and related expenses they incur in attending Board and committee meetings, including the expenses incurred by directors' spouses in accompanying the directors to one Board meeting in 2007. We also match on a two-for-one basis up to $5,000 per year (which would result in up to a $10,000 Company match) of charitable donations made by a-director to 501 (c)(3) organizations that meet our strategic giving priorities and are located in KCP&L's generation and service communities.
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| The following table outlines all compensation paid to our non-employee directors in 2007. We have omitted the columns titled "Stock awards," "Option awards,". and "Non-equity incentive plan compensation," because our non-employee directors did not receive any in 2007.
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| DIRECTOR COMPENSATION Change in Pension Value and Nonqualified Fees Earned or -Deferred Compensation All other Paid in Cash (1) Earnings (2) Compensation (3) Total Name ($) ($) ($) ($)
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| (a) (b)(0 (g) (h)
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| Dr. Bodde "113,000 26,963 - 1-39,963 Mr. Feruson, Jr. 108,000 22,696 130,696 Mr. Jimenez 106,000 1600- 106,160 tMr. Mitchell 16~08000 - K \ 08,000 Mr. Nelson 112,000 10,371 122,371 1 r. F~iafbtt ~ 1i07,000 33J4V 1ý jF 119 51 2 128,703 Mr. West. 131,000 21,184 18,854 171,038 (1) The amounts shown include retainers of $85,000, attendance fees of $1,000 for each Board and Committee meeting attended, and additional retainers for Mr. West ($20,000), as lead director, Dr. Bodde ($5,000), and Messrs. Ernst
| |
| ($10,000) and Nelson ($5,000) as committee chairs.
| |
| (2) The amounts shown represent the above-market earnings during 2007 on nonqualified deferred compensation.
| |
| (3) The amounts shown consist of matched charitable contributions, spouse travel expenses to one Board meeting, and premiums for life insurance and health insurance. As permitted by SECrules, we excluded from the table perquisites and personal benefits for any director where the total value was less than $10,000.
| |
| COMPENSATION DISCUSSION AND ANALYSIS This section provides information and a comprehensive analysis of the compensation awarded to, earned by, or paid to the following NEOs:
| |
| * Michael J. Chesser, Chairman of the Board and ChiefExecutive Officer of GreatPlains Energy and Chairman of the Board of Kansas City Power & Light Company (KCP&L);
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| 17
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| * William H. Downey, Presidentand Chief OperatingOfficer of Great PlainsEnergy and Presidentand ChiefExecutive Officer ofKCP&L;
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| " Terry Bassham, Executive Vice President- Finance and Strategic Development and Chief FinancialOfficer of Great PlainsEnergy and ChiefFinancialOfficer of KCP&L;
| |
| " Shahid Malik, Executive Vice Presidentof Great PlainsEnergy and Presidentand Chief Executive Officer of Strategic Energy, and
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| " John R. Marshall, Senior Vice President- Delivery, KCP&L.
| |
| Great Plains Energy is currently organized around two corebusinesses: KCP&L, a regulated provider of electricity in the Midwest, and Strategic Energy, L.L.C., a competitive electricity supplier. A small services organization provides common support functions across both businesses. Given the significant differences in the scope and nature of responsibilities, as well as differences in market levels of compensation, there are generally significant differences in compensation among the NEOs.
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| Governance of the Company's-Compensation Program The Committee is made up of six non-employee directors, each of whom is independent under the applicable standards of the NYSE. They are:
| |
| " William C. Nelson (Chairman) 0 James A. Mitchell
| |
| * Mark A. Ernst
| |
| * Linda H. Talbott
| |
| * Luis A. Jimenez
| |
| * Robert H. West The Committee sets the executive compensation structure and administers the policies and plans that govern compensation for the NEOs and other executive officers. The Committee's charter has been approved by our Board and decisions by the Committee are reviewed with, and approved by, the. full Board. A copy of the charter can be found on the Company's website at www.greatplainsenergy.com.
| |
| Role of Executive Officers Each year, Mr. Chesser submits to the Committee a performance evaluation and compensation recommendation for each of the NEOs, other than himself. The performance evaluation is based on factors such as achievement of individual, departmental, and Company results, as well as an assessment of leadership accomplishments. The Committee reviews these recommendations and makes final recommendations for Board approval. Annual performance metrics and goals are also developed through a process in which management, including the CEO, develops preliminary recommendations that the Committee considers in the development of final recommendations for Board approval.
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| While Mr. Chesser routinely attends meetings of the Committee, he is not a member and does not vote on Committee matters. Only members of the Committee may call Committee meetings. In addition, there are certain portions of Committee meetings when he is not present, such as when the Committee is in closed executive session or discusses his performance or individual compensation. Mr. Chesser's compensation levels and performance goals are recommended by the Committee for approval by the Board. The Senior Vice President - Corporate Services and Corporate Secretary and the external executive compensation consultant were consulted in this process in 2007, as described in the next section.
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| As established by the Committee, Messrs. Chesser and Downey may grant awards of restricted stock under the Company's LTIP to non-executive employees. Actions taken by those individuals are reported back to the Board and Committee.
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| 18
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| | |
| Role of Compensation Consultant The Committee retains Mercer as its third-party compensation consultant. Mercer was selected by the Committee several years ago following presentations from other consulting firms and based on their overall capabilities in the area of executive compensation. Mr. Michael Halloran is the Company's lead consultant who works with the Committee. Mr. Halloran is a Worldwide Partner at Mercer and has more than 25 years of experience in executive compensation.
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| On a periodic basis, Mercer provides the Committee with a comprehensive review of the Company's executive compensation programs, including plan design, all executive benefit programs, and a review of pay positioning versus performance to evaluate the magnitude of pay versus performance. On an annual basis, Mercer performs a competitive review and analysis of base salary and variable components of pay, relative to survey market data and the Company's identified peer group. The consultant recommends to the Committee the peer group which might be used; the structure of plans; the market data which should be used as the basis of comparison for base salaries and incentive targets; and conducts comparisons and analyses of base and variable components. Mercer provides detailed information on base salaries, annual incentives, long-term incentives, and other specific aspects of executive compensation for each NEO, as well as Mercer' s overall findings and recommendations. Comparisons of executive compensation are made to energy industry data, general industry data, and-peer proxy data, as appropriate. The compensation consultant neither determines, nor recommends, the amount of an executive's compensation since it is not in a position to evaluate individual executive performance.
| |
| While Mercer is engaged by, and takes direction from the Committee, the Senior Vice President -
| |
| Corporate Services and Corporate Secretary (non-NEO) works directly with Mercer's consultants to provide information, coordination, and support. The Committee also pre-approves all other work unrelated to executive compensation proposed to be provided by Mercer, if the fees would be expected to exceed $10,000.
| |
| Mr. Chesser did not meet with the compensation consultant respecting 2006, 2007, or 2008 compensation, except at Committee meetings where the consultant was also present.
| |
| Role of Peer Group The proxy peer group, as recommended by Mercer and approved by the Committee, consists of 13 organizations of similar character, industry, revenue size, and market capitalization, as compared to the Company. The peer group companies relied upon to assist in formulating the executive compensation for 2007 include:
| |
| Allete Inc. Equitable Resources Inc. TECO Energy Inc.
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| Alliant Energy Corp. Pinnacle West Capital Corp. Unisource Energy Corp.
| |
| Ameren Corp. PNM Resources Inc. Vectren Corp.
| |
| Avista Corp. Scana Corp. Wisconsin Energy Corp.
| |
| Black Hills Corp.
| |
| When other surveys are relied on, Mercer conducts, where possible, regression analyses to adjust the compensation data for differences in the companies' revenues, allowing the Company to compare compensation levels to similarly-sized companies. Other surveys used by Mercer to assist in formulating its recommendations to the Company include the Mercer Benchmark Database; Watson Wyatt Report on Top Management Compensation; Towers Perrin U.S. Energy Services Executive Database; and the Mercer Energy Compensation Survey.
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| 19
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| | |
| Objectives of the Company's Compensation Program The three main objectives of the Company's Executive Compensation Program are:
| |
| : 1. To Attract and Retain Highly Qualifiedand ExperiencedExecutives Shareholders and customers are best served when the Company is able to attract and retain talent. All of the current NEOs have been hired from outside the Company in the last eight years, and each brought considerable industry and business expertise to the Company. While the Company's goal is to provide base salaries at the median of comparable companies and variable compensation at higher levels based on performance, on occasion, the Company pays above-market base salaries in order to attract and retain specific talent.
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| : 2. To Motivate Executives to Achieve Strong Short-Term and Long-Term Financialand Operational.
| |
| Results The Committee believes that pay and performance should be linked with. objectives for which employees can have a clear line of sight, and this is principally accomplished through variable compensation opportunities. While the Committee has not elected to adopt policies for allocating between long-term and currently-paid-out compensation, or between cash and non-cash compensation, it does believe in putting more pay at risk as employees move to higher levels of responsibility with more direct influence over the Company's performance. Variable compensation targets for the NEOs represent between 57% to 71% of total direct compensation, constituting a significant component of pay at risk. The Committee uses a balanced scorecard approach in setting the NEOs' annual incentive plan goals, which includes financial, operational, and individual components, along with key operational and/or financial measures for the long-term plan, which place a much greater emphasis on increasing long-term shareholder value.
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| : 3. To Ensure the Alignment of ManagementInterests with Those of Shareholders The Committee believes that a substantial portion of total compensation for its NEOs should be delivered in the form of equity-based incentives. In 2007, for Messrs. Chesser, Downey, Bassham, and Marshall, 75% of long-term incentive grants (excluding the special grants of restricted stock discussed later) were in the form of performance shares which, if earned after three years based on total return to shareholders, would be paid out in Company stock.. To mitigate potential volatility in payouts and provide a retention device, the remaining 25% of the. long-term grant was in the form of time-based restricted shares. For Mr.
| |
| Malik, 50% of his long-term grant was in the form of performance shares which, if earned after three years based on various financial and operational metrics, would be paid out in company stock, and, 50%
| |
| eligible to be paid in cash. In addition, the Committee has also implemented share ownership guidelines for executives, to further align their compensation with shareholder interests. The guidelines include the value of Company shares executives are expected to acquire and hold, and reflect a level of five times base salary for Mr. Chesser; four times base salary for Mr. Downey; and three times base salary for Messrs. Bassham, Marshall, and Malik. In addition, in 2007 the Committee and Board also implemented "hold 'til" requirements, which require the executive to refrain from disposing of shares received under the Company's LTIP, except to satisfy obligations for payment of taxes relating to those shares, until the share ownership guidelines are met and maintained.
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| 20
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| | |
| Analysis of Executive Compensation The elements.of compensation are:
| |
| : 1. Cash compensation in the form of base salaries, annual incentives, discretionary bonuses, and the cash portion of Strategic Energy's long-term incentives;
| |
| : 2. Equity compensation under the Company's LTIP;
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| : 3. Perquisites and generally available employee benefits;
| |
| : 4. Deferred compensation;
| |
| : 5. Post-termination compensation;.
| |
| : 6. Pension plan and supplemental pension .plan; and
| |
| : 7. Employee savings plan (40 1-(k)).
| |
| : 1. Cash Compensation Cash compensation to our NEOs includes (i) a market-competitive and performance-driven base salary, (ii) annual short-term incentive plans, and (iii)for Mr. Malik, a long-term incentive cash component which, if earned, is paid in cash. The Committee has not chosen to target a specific percentage of total compensation for NEOs to be delivered in cash or cash opportunities as it believes this will vary based on the NEO's position and individual performance and circumstance. However, it does believe that, in.
| |
| general, the level of cash opportunity should decrease in proportion to equity compensation as individuals move to higher levels of responsibility.
| |
| Base Salary Base salaries are reviewed at the February Committee meeting, approved by the Board, and, if adjusted, made retroactive to the first of the year. The Committee considers performance evaluations and base salary recommendations submitted by Mr. Chesser for the NEOs, other than himself. Mr. Chesser's performance evaluation is conducted and salary recommendation is prepared by the Committee. Salary recommendations are not determined by formula, but instead take into consideration job responsibilities, level of experience, individual performance, internal comparisons, comparisons of the salaries of executives in similar positions at similar companies obtained from market surveys, and other competitive data and input provided by Mercer. Individual performance evaluations are subjective. The factors considered in the evaluations include, among others, the following: personal leadership; engagement of employees; disciplined performance management; accountability for results; community involvement; and major accomplishments during the performance period. For 2007, the base salary of each NEOwas benchmarked against two to four comparable positions reported in peer group proxies, utility surveys, and general industry surveys. Our general goal is to set base salaries to approximate the median salaries of individuals in comparable positions in companies of similar size within the relevant industry or function. Differences in base salaries between the NEOs are primarily due to differences in job responsibilities and base compensation market levels. The responsibilities of Mr. Chesser, as CEO, span all aspects of the Company, and his base salary reflects this responsibility. In contrast, the responsibilities of the other NEOs are narrower in scope.
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| Messrs. Bassham, Chesser, Downey, Malik, and Marshall received base salary increases effective January 1, 2007, of approximately 8.3%, 11.5%, 4.4%, 4.8% and 3.1%, respectively. Larger percentage increases were given when the salaries were significantly less than market medians and the NEOs demonstrated a high level of performance.
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| 21
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| | |
| Annual Incentives The Company's annual incentive plans are based upon Company-wide and business unit financial and operational metrics, as well as individual performance. Metric levels are established, so that the target level reflects the business plan and has a 50% probability of achievement. The threshold and maximum levels are established to have approximately 80% and 20% probabilities of achievement, respectively.
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| The Committee reviews management's recommendations of goals and metrics, makes any revisions, and recommends the final goals and metrics to the Board for its approval. In establishing final goals, the Committee assures that:
| |
| * Incentives are aligned with the strategic goals set by the Board;
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| * Goals are sufficiently ambitious so as to provide a meaningful incentive; and
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| " Bonus payments, assuming target levels are met, will be consistent with the overall compensation program established by the Committee.
| |
| The Committee developed, with input from Mercer, a structure for the annual incentive plans for all executives, including NEOs, which provides a financial objective of core earnings weighted at 40% and relating to the earnings for the executive's primary business or as determined by the Committee; 40%
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| reflecting key Great Plains Energy, KCP&L, and/or Strategic Energy business objectives; and 20% as a discretionary individual performance component. The 20% individual component includes, but is not limited to, a subjective review of the individual's personal leadership; engagement of employees; disciplined performance management; accountability for results; and community involvement. Target incentives for each NEO were established as a percentage of base pay, using survey data provided by Mercer for comparable positions and markets, as well as comparisons for internal equity. For 2007, annual incentive plan targets as a percentage of base salaries for Messrs. Bassham, Chesser, Downey, Malik, and Marshall were 50%, 100%, 70%, 60% and 50%, respectively.
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| The basic structure of the annual incentive plans provides for 100% payout for target performance for each goal; 50% is payable at the threshold level of goal performance; and 200% is payable at the maximum level of goal performance. Goal performance is set between the threshold and target levels, and between target and maximum levels. Performance results for any goal which is less than threshold will result in a zero payment for that goal. In addition, in order for any incentive award to be paid, the core earnings objective must be met at least at the threshold level of achievement.
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| After considering the performance criteria and results, the Committee approves, and occasionally uses its discretion in determining, the final amount of the individual award. Discretion is exercised primarily regarding the 20% individual performance component.
| |
| There were no payouts under the 2007 annual incentive plans because the threshold core earnings level was not achieved. The following tables summarize the 2007 annual incentive plan, year-end results, and payout levels for Great Plains Energy, KCP&L, and Strategic Energy.
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| 22
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| | |
| GREAT PLAINS ENERGY 2007 ANNUAL INCENTIVE PROGRAM 200% Actual Payout Payout Payout Performance Payout
| |
| .Measure Weighting Level Level Level Result Percentage AAL'P1 '01 AA J 1. Powers Uustomer Satisfaction Index -
| |
| f%7QA2A* A52'-AGGI~ Ah1-- F00 A
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| 1iv W n unuer management - Strategic Fnerov 21.l6 Total 100% 0%
| |
| KANSAS CITY POWER & LIGHT COMPANY 2007 ANNUAL INCENTIVE PROGRAM 50% 100% 200% Actual Payout Payout Payout Perform-ance Payout Measure Weighting Level Level Level Result Percentage Core earnings per share 40% $1.70 $1.80 $1.90 $1.67 11) 0%
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| % equivalent availability
| |
| - coal and nuclear 10% 85.6% 87.2% 88.0% 83.64% 0%
| |
| J D Powers Customer Satisfaction Index -
| |
| residential 5% 678-684 685-699 Above 699 694 0% '
| |
| l~~tan~~Pyom ssc Ponllective wpr),k projrL 14%1)~o~ 0 Individual performance 20% 1 Discretionary 0%
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| Total 100% 0%
| |
| (1) KCP&L's core earnings for this period reflected the allocation to Great Plains Energy of $0.05 per share of labor-related costs associated with the proposed Aquila transaction that would otherwise have been reflected in KCP&L's core earnings.
| |
| As the core earnings targets were established without this allocation, the Committee exercised its discretion to reduce core earnings per.share performance by this amount.
| |
| 23
| |
| | |
| STRATEGIC ENERGY 2007 ANNUAL INCENTIVE PROGRAM 50% 100% 200% Actual Payout Payout Payout Performance Payout Measure Weighting Level Level Level Result Percentage Core earnings 40% $34 million $39 million $48 million $13 milliont1 ) 0%
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| 01 inatmetd 2935,
| |
| _10g& million $)0 mnillhibn ~ $_8_______ol
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| $120iifl~n million Project 2-3-0 Process improvement 10% - - - Completed 0%
| |
| Individual performance 20% Discretionary 0%
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| Total 100% .0%
| |
| (1) This measure reflects core earnings at Strategic Energy, and differs from core earnings that Great Plains Energy discloses for the Strategic Energy reportable segment, which includes allocated holding company-related costs.
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| Core earnings and core earnings per share are financial measures that differ from earnings and earnings per share calculated in accordance with generally accepted accounting principles (GAAP). Core earnings in 2007 excluded mark-to-market impacts of an interest rate hedge and energy contracts, skill set realignment costs, costs and tax benefits associated with the proposed acquisition of Aquila, and certain costs associated with the review of strategic and structural alternatives for Strategic Energy.
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| Funds from operations as a percentage of average total debt is also a non-GAAP financial measure. It is calculated by adding non-cash expenses to net income and dividing the resulting amount by the sum of short-term debt (including current maturities), long-term debt and off-balance sheet debt.
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| The Committee has not established the 2008 annual incentive plans, given the proposed acquisition of Aquila and the review of strategic and structural alternatives for Strategic Energy.
| |
| Cash Portionof Strategic Energy's Long-Term Incentives Strategic Energy's long-term incentives are designed principally to reward sustained value creation through the achievement of long-term financial and operational performance goals. Strategic Energy's long-term incentives have been largely cash-based, because the Committee and Board believe companies with which Strategic Energy competes for executive talent are more likely to offer cash-based long-term incentives, than equity-based long-term incentives. As a result, Mr. Malik is the only NEO that receives cash-based long-term incentives.
| |
| However, based upon the Company's overall compensation philosophy, an equity component is utilized in Strategic Energy's long-term incentives. Mr. Malik's 2005-2007 and 2006-2008 long-term grants consist of 25% time-based restricted stock, with the remaining cash-based component based 80% on Strategic Energy performance goals and 20% on Great Plains Energy performance goals. Components based on Strategic -Energy's performance included payout opportunities ranging from 0% to 300%. The structure of Strategic Energy's Long-Term Plan changed for grants in 2007, so that the target award includes 50% performance shares and 50% cash, with total payouts ranging from 0% to 275% of target, plus earned dividends, if any. The change results in the equity portion of this plan more directly reflective of Strategic Energy's performance. Mr. Malik's long-term target is 150% of base pay. The Committee has chosen to provide significant long-term award opportunities to Strategic Energy executives to motivate the highest levels of performance within its highly competitive, unregulated 24
| |
| | |
| environment. Strategic Energy's executives do not have a defined benefit pension plan, as do other Great Plains Energy and KCP&L executives. Based on the terms of Mr. Malik's 2005-2007 long-term grants, and the actual performance for that period, Mr. Malik received a cash award of $495,000.
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| Metric levels are established for Strategic Energy's long-term incentive plans, so that the target level reflects the business plan and has a 50% probability of achievement. The threshold and maximum levels are established to have approximately 80% and 20% probabilities of achievement, respectively. The following tables summarize the 2005-2007, 2006-2008, and 2007-2009 Long-Term Incentive Plans, as well as the results and payout levels for the 2005-2007 Plan.
| |
| STRATEGIC ENERGY 2005-2007 LONG-TERM INCENTIVE PLAN uumull ction in GkA F I 1^1 Is0%
| |
| (1) This measure reflects pre-tax net income excluding mark-to-market impacts of energy contracts (core earnings) at Strategic Energy, and differs from core earnings that Great Plains Energy discloses for the Strategic Energy reportable segment which includes allocated holding company-related costs.
| |
| (2) Cash amount of target for all-cash participants.
| |
| STRATEGIC ENERGY 2006-2008 LONG-TERM INCENTIVE PLAN Payout Measure Weighting Metrics Percentages Cumulative pre-tax net income 25% Confidential 0-300%
| |
| i ......... 11 , 2 5co ide tl O(/
| |
| Cumulative Sales, General and Administrative expense per MWh serviced during the three year period 25% Confidential 0-300%
| |
| ýýUli mde~r anagemernt . ~ I~;~2V3/4 Coiifide~ntial o-30___9__
| |
| STRATEGIC ENERGY 2007-2009 LONG-TERM INCENTIVE PLAN Payout Measure Weighting Metrics Percentages 25% Confidential 0-300%
| |
| _____________________________________ 5 ~~'onfidenti* Qr;0Q 35th percentile 50%
| |
| Total shareholder return for the three year period compared to the 25% 50th percentile 100%
| |
| EEI Index of electric utilities. 6 5 th percentile 150%
| |
| ,___ 81't percentile 200% -
| |
| %I\[u d rina a e et* 25 Co fi en ia T.........................
| |
| 25
| |
| | |
| Strategic Energy's Plans contain quantitative performance-related factors. The metrics for these factors in the 2006-2008 and 2007-2009 Plans are confidential commercial or financial information, and their disclosure would result in competitive harm to the Company. Strategic Energy provides competitive retail electricity supply services in certain states that offer retail choice. By definition, Strategic Energy operates only in competitive retail markets, where it faces substantial competition from the incumbent electric utilities as well as other competitive suppliers. Strategic Energy does not own any generation, and thus must compete in the wholesale market to obtain all of the electricity required for its customers' current and forecasted needs. This is in sharp contrast to Great Plains Energy's other major subsidiary, Kansas City Power & Light Company, which is a rate-regulated public utility with substantial installed generation capacity and no retail competition.
| |
| The Committee has not established the 2008-2010 Strategic Energy Long-Term Incentive Plan, given the review of strategic and structural alternatives for Strategic Energy.
| |
| : 2. Equity Compensation As previously explained, the Committee believes that a substantial portion of compensation for NEOs should be in the form of equity, in order to best align executive compensation with shareholder interests.
| |
| The Committee does not believe any of the NEOs have accumulated equity amounts, or previously been given the opportunity for significant amounts of equity ownership, that warrant consideration in granting equity awards.
| |
| The Great Plains Energy LTIP was last approved by shareholders in May 2007 and allows for grants by the Committee of stock options, restricted stock, performance shares, and other stock-based awards. The Committee discontinued making any new stock option grants in late 2003, because it believed motivating executives based solely on stock price appreciation was not entirely consistent with the best interests of its shareholder base. Since that time, the Committee has used a mix of time-based restricted shares and performance shares that vest solely on the basis of the attainment of performance goals. While the Committee believes that performance shares should generally account for the majority of annual long-term grants, this could change in any year, as it did in 2007 with respect to the special grant of restricted stock, based on the needs of the Company and the characteristics of its executive team.
| |
| While directors, officers and employees of the Company are eligible for equity awards under the LTIP, none of them have any right to be granted awards. The Committee, in its discretion, may approve an equity award or awards for officers and employees, including NEOs. When the Committee approved awards in 2007 for officers, it set the awards with a cash value determined by multiplying the officers' base salary by a target percentage chosen by the Committee, which was the same method used in 2006 as the Committee believed that the target percentage used last year provided an effective long-term incentive for the officers. The target percentage is based on both internal comparisons and survey data provided by Mercer, which provides long-term incentive information on comparable positions at comparable companies, and/or markets in which the Company competes for talent. Generally, the Committee has established targets at the 5 0 th percentile. In 2007, long-term incentive target percentages for Messrs. Bassham, Chesser, Downey, Malik, and Marshall were 85%, 150%, 115%, 150% and 85%,
| |
| respectively, excluding special restricted stock grants discussed below. These target percentages are consistent with the Company's incentive compensation practices in 2006, and resulted in the following long-term incentive grants of restricted stock and performance shares in 2007, excluding special restricted stock grants:
| |
| 26
| |
| | |
| Name Restricted Stock- Performance Shares (at target)
| |
| Mr. Chesser 8,507 25,520
| |
| ~Mr. DOWaCie 4,12Q 8 12,684 Mr. Bassham 2,161 0,483
| |
| ~Mr. alik~ N32 - 10, 15 Mr. Marshall 2,227 6,682 Performance share grants are for multiple-year performance periods beginning with January 1 of the grant year. Restricted stock is typically, but not always, granted at the February Board meeting, effective on the meeting date. However, when restricted shares are granted by the Committee in conjunction with the employment of a new executive or for other reasons, the effective dates are the date of hire, the date of Committee or Board action, or a date following the Committee/Board meeting. We do not have any program, plan, or practice of timing grants in coordination with the release of material non-public information. Effective in May of 2007, the Fair Market Value calculation for issuance of equity grants is based on the closing market price for the Company's common stock, as reported on the NYSE for the applicable date.
| |
| For Great Plains Energy and KCP&L NEOs, performance shares can pay out at the end of the performance period from 0% to 200%, based on performance. For the 2006-2008 and 2007-2009 performance periods, the sole performance metric is total shareholder return ("TSR") compared to the Edison Electric Institute ("EEI") index of electric companies. The EEI index is a recognized, publicly-available index which the company uses as prepared by EEl, and with no additions or deletions. The Committee believes TSR is a strong indicator of shareholder value and is influenced both by successful execution by executives, as well as market perceptions of the strength and future prospects of the Company. Great Plains Energy's TSR percentile ranking in the EEl index determines the percentage payout our executives will receive, as follows:
| |
| Percentile Rank Percentage Payout 81st and above 200%
| |
| 50th to 6 4th 100%
| |
| 34t and below 0%
| |
| There will not be any payment of performance shares for a negative return over the performance period.
| |
| Awards are paid out in shares of Great Plains Energy common stock, unless otherwise determined by the Board. Dividends which accrue on the performance shares will be paid in cash at the end of the performance period, based on the number of performance shares earned, if any.
| |
| In October of 2007, Messrs. Chesser and Downey received restricted stock payouts for the remaining one-third of the restricted shares granted at the time of Mr. Chesser's employment and Mr. Downey's promotion to ChiefOperating Officer, both of which occurred in October of 2003. Mr. Malik received a restricted stock payout for the remaining one-third of the restricted shares granted at the time of his employment in November of 2004.
| |
| The following tables summarize the 2005-2007 Long-Term Incentive Plans for Great Plains Energy and KCP&L, including year-end results and payout levels. Only Messrs. Downey and Marshall received payouts for the 2005-2007 performance share grants of 5,507 and 4,482 shares, respectively. Mr.
| |
| Downey's and Mr. Marshall's performance share grants were weighted on the results of both the Great 27
| |
| | |
| Plains Energy and KCP&L plans, and the number of shares awarded was reduced, pursuant to the performance share grants, to reflect the reduction in share price between the time of the performance share grants and the end of the performance share period.
| |
| 2005-2007 GPE LONG-TERM INCENTIVE PLAN RESULTS Percentage of Scorecard Goal Total Goal Three-Year Target Three-Year Results Percentage Payout Three-Year Total Shareholder Return 50% 5 0th Percentile 13 th Percentile 0.00%:
| |
| Return on Invested Capital (ROIC) 25% 24.8% 23.0% 0.00%
| |
| Total Payout (up to 200% of target amount) 0.00%
| |
| 2005-2007 KCP&L LONG-TERM INCENTIVE PLAN RESULTS Percentage of Three-Year Three-Year Percentage Scorecard Goal Total Goal Target Results Payout Core Earnings 25% $447 million $428.4 million (1) 0.00%
| |
| Regulatory/Build on On Schedule/
| |
| Schedule and Budget 25% Budget 140% 35.00%
| |
| DisToibItdal P 1\t(Goal Total Payout (up to 200% of target amount) 85.00%.
| |
| (1) KCP&L's core earnings for this period reflected the allocation to Great Plains Energy of $0.05 per share of labor-related costs associated with the proposed Aquila transaction that would otherwise have been reflected in KCP&L's core earnings.
| |
| As the core earnings targets were established without this allocation, the Committee exercised its discretion to reduce core earnings per share performance by this amount.
| |
| Special Restricted Stock Grants in 2007 In February 2007, the Board made a special one-time grant of restricted stock to a number of officers (including all NEOs, exceptMr.Malik), both to recognize performance over the last year and to ensure their continued focus and commitment to the Company's core business; projects and the proposed acquisition and subsequent operational integration of Aquila, Inc. with the Company. The grants to the NEOs were: Mr. Chesser, 80,000 shares; Mr. Downey, 45,000 shares; Mr. Bassham, 25,000 shares; and Mr. Marshall, 25,000 shares.
| |
| : 3. Perquisites NEOs are eligible to receive various perquisites provided by or paid for by the Company. These perquisites are generally consistent with those offered to executives at comparable organizations with which we compete for executive talent, and are important for retention and recruitment. The NEOs are also eligible for employment benefits that are generally available to all employees, such as vacation, medical and life insurance.
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| 28
| |
| | |
| As shown in the Summary Compensation Table on page 32, all NEOs are eligible for participation in comprehensive financial planning services provided by a national financial counseling firm; a car allowance; memberships in social clubs and, in limited situations, country clubs; use of certain equipment for personal use, such as home computer equipment; and access to sporting events and other entertainment which may be used for personal use on a limited basis. On occasion, the Company may also provide for spousal travel and accommodations when accompanying the executive on out-of-town trips. As required by current tax laws, the executive is assessed imputed income taxes on the subsidized or reimbursed amounts.
| |
| : 4. DeJerredCompensation Plan The Company's Deferred Compensation Plan (DCP) allows selected employees, including NEOs, to defer the receipt of up to 50% of base salary and 100% of awards under the Annual Incentive Plan. An earnings rate is applied to the deferral amounts, which is annually determined by the Committee and based on the Company's weighted average cost of capital. The current rate is 9%. In addition, the Plan provides for a matching contributtion in an amount equal to 50% of the first 6% of base salary deferred, or 100% of the first 6% of base salary, bonus and incentive pay deferred, depending on the retirement option selected by the individual, and reduced by the matching contribution made for the year to the Participant's Employee Savings Plus Plan (40 1(k)). The DCP is a nonqualified and unfunded plan, and is shown in external market comparisons to be a common element of an executive rewards strategy.
| |
| : 5. Post-Termination Compensation The Company has entered into severance agreements and other compensation and benefit agreements with its executive officers, including NEOs, to help in securing their continued employment and dedication, particularly in situations such as a change in control when an executive may have concerns about his or her own continued employment. The Company believes these agreements and benefits are important recruitment and retention devices, as virtually all of the companies with which we compete for executive talent have similar agreements in place for their senior executives.
| |
| Employmeht Arrangements Messrs. Chesser, Malik, and Marshall, all hired from outside the Company within the last five years, are the'only NEOs with ongoing employment arrangements. The Committee has historically wished to minimize the use of employment agreements to the extent possible.
| |
| As discussed on pages 35 and 45, under the terms of an employment arrangement, Mr. Chesser is entitled.
| |
| to receive three times annual salary and bonus if he is terminated without cause prior to reaching age 63.
| |
| After age 63, any benefit for termination without cause would be one times annual salary and bonus until age 65. Similarly, under the terms of his employment arrangement, Mr. Marshall is entitled to receive two times annual salary and bonus in the event he is terminated other than for cause. Mr. Malik is the only NEO who has a full written employment agreement with Strategic Energy and Great Plains Energy.
| |
| It provides for three times annual salary and bonus in the event he is terminated without cause or terminates for good reason.
| |
| Change-in-ControlSeverance Agreements The Company has change-in-control agreements, updated in 2006, with all its executive officers, including the NEOs, to ensure their continued service, dedication, and objectivity in the event of a transaction that would change the control of the Company. These agreements provide for payments and 29
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| | |
| other benefits if the officer's employment terminates for a qualifying event or circumstance, such as being terminated without "Cause" or leaving employment for "Good Reason" as these terms are. defined in the agreements. All the agreements require a double trigger so that both a change in control and a termination (actual or constructive) of the executive's employment must occur, with very limited exceptions. Generally, the Committee and Board determined the eligibility for potential payments upon change-in-control, based on comparable practices in the market. It is not uncommon for the chief executive officer and chief operating officer to be covered under a "three times" change-in-control agreement, nor is it uncommon for other senior level officers to be covered under a "two times" change-in-control agreement. Messrs. Chesser, Downey, and Malik are eligible for three times base and incentive in the event of a change-in-control and Messrs. Bassham and Marshall are eligible for two times. We believe the terms and protection afforded is in line with current market practice.
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| Additional information, including a quantification of benefits that would have been received by NEOs had termination occurred on December 31, 2007, is found under the heading "Potential Payments upon Termination or Change-in-Control" beginning on page 41.
| |
| : 6. Pension Plan and Supplemental Pension Plan The Company's Pension Plan is a funded, tax-qualified, noncontributory defined benefit plan that covers employees of Great Plains Energy and KCP&L, including the NEOs of those companies. Mr. Malik is the only NEO not covered by a pension plan. Benefits under the Plan are based on the employee's years of service and the average annual base salary over a specified period.
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| The Company also has a Supplemental Executive Retirement Plan ("SERP") that applies to executives of Great Plains Energy and KCP&L. This unfunded plan essentially provides the difference between the amount that would have been payable under the Pension Plan in the absence of Internal Revenue Service tax code limitations and the amount actually payable under the Plan. It also adds a slightly higher accrual rate on years of service.
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| Based on provisions in their employment arrangements as previously described, both Mr. Chesser and Mr. Marshall receive credit for two years of service for every one year of service earned under the Pension Plan, payable under the SERP.
| |
| In 2007, management employees of Great Plains Energy and KCP&L were given a one-time election to remain in their existing Pension Plan and 401 (k) Plan ("Old Retirement Plan"), or choose a new retirement program that includes a slightly reduced benefit accrual formula under the PensionPlan paired with an enhanced benefit under the 401 (k) Plan ("New Retirement Plan"). Elections were effective January 1, 2008. Messrs. Bassham and Marshall elected to participate in the New Retirement Plan.
| |
| : 7. Employee Savings Plan (401(k))
| |
| The Great Plains Energy Employee Savings Plus Plan and the Strategic Energy, L.L.C. 401 (k) Plan are offered to all employees as a tax-qualified retirement savings plan.
| |
| * Employees in the Old Retirement Plan can contribute up to 40% of base pay. After one year of employment, the Company matches 50% of the first 6% of pay that is contributed. Employees are fully vested in the entire match and associated earnings after 6 years.
| |
| 30
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| | |
| Employees in the New Retirement Plan can contribute up to 75% of base pay, bonus, incentive, and overtime pay. The Company matches 100% of the first 6% of total pay that is contributed.
| |
| All contributions vest immediately.
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| " The Company match is made with Great Plains Energy stock, although a participant may diversify or transfer out of Company stock at any time and reinvest his or her plan account in different investments.
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| * Contributions are limited by the tax code.
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| Tax and Accounting Implications With respect to Section 162(m) of the Internal Revenue Code, the Committee believes that while it is the Company's goal to be as tax efficient as possible, the Company's shareholders are best served by not restricting the Committee's and the Company's discretion and flexibility in developing compensation programs. The unrealized tax benefit by the Company in 2007, as a result of lost deductions, was
| |
| $323,477.
| |
| COMPENSATION COMMITTEE REPORT The Compensation and Development Committee of the Board reviewed and discussed with management the Compensation Discussion and Analysis ("CD&A") contained in this proxy statement and, based on such reviews and discussions,. recommended to the Board that the CD&A be included in the Company's proxy statement.
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| Compensation and Development Committee William C. Nelson, Chair Mark A. Ernst Luis A. Jimenez James A. Mitchell Linda H. Talbott Robert H. West EXECUTIVE COMPENSATION Executive Compensation is more fully explained in the CD&A section of this proxy statement, starting on page 17. The following table shows the total salary and other compensation awarded to and earned by our Chief Executive Officer, Chief Financial Officer and our three other most highly compensated executive officers for services rendered in all capacities to Great Plains Energy and its subsidiaries. We have omitted from the table the column titled "Bonus," because compensation earned under our annual incentive plans is reported in the "Non-Equity Incentive Plan Compensation" column.
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| 31
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| | |
| ==SUMMARY==
| |
| COMPENSATION TABLE Change in Pension Value.
| |
| and Non-Equity Nonqualified Incentive Plan Deferred All Other Stock Opiion Compensation Compensation Compensation Name and Principal Salary Awards () Awards () (2) Earnings (3) (4) Total Position Year ($) ($) ($) (S) ($) ($) ($)
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| (a) (b) I (c) (e) (f) (g) (h) (i) 0,) 1 Exete 2007 725,000 1,553,694 692,253
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| - 236,452 3,207,399 Chairmef and Chief Executive Officer - 2006 650,000 1,094,691 936,650 281,177 105,499 3,068,017 Great Plains Energy Mr. Baessham tInd Chid Mr. Bassham Executive Vice 2007 325,000 513,852 44,656 119,241 1,002,749 President - Finance &
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| Strategic Development
| |
| & Chief Financial Officer- Great Plains 2 300,000 183,297 223,650 27,750 49,382 784,079 Enemy (2Ij6, 420J (111 55~
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| ISW 100 I J~j( ol1)
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| Mr. Marshall Senior Vice President - 2007 335,000 679,096 - 235,825 137,738 1,387.659 Delivery - Kansas City I__II__II_
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| Power & Light 2006 325,000 294,024 203,450 125,637 76,306 1,024,417 Company I I I I I , II_ I (1) The amounts shown in these columns are the compensation expense as recognized for financial statement reporting purposes with respect to the fiscal year in accordance with the Financial Accounting Standards Board Statement of Financial Accounting Standard No. 123 (revised 2004), "Share-Based Payment" ("FAS 123R") for restricted stock, performance shares and options granted under our LTIP. See note 9 to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2007, for a discussion of the relevant assumptions used in calculating these amounts. The amounts shown are exclusive of the estimate of forfeitures related to service-based vesting conditions, as required by SEC rules. For further information on these awards, please see the Grants of Plan-Based Awards and Outstanding Equity Awards at Fiscal Year-End tables later in this proxy statement.
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| (2) The amounts shown in this column constitute payments made under our annual incentive plans. The amount shown for Mr.
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| Malik also includes $592,744 and $495,000 paid in cash in 2006 and 2007, respectively,,under long-term incentive plans.
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| (3) The amounts shown in this column include the aggregate of the increase in actuarial values of each of the 6fficer's benefits under our pension plan and SERP and above-market earnings on compensation that is deferred on a non-tax qualified basis.
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| Following is the quantification ofthese amounts attributable to each NEO:
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| Above-Market Earnings on Name Change in Pension Value ($) Change in SERP Value ($) Deferred Compensation ($)
| |
| Mr. Chesser 349,943 310,969 31,341 Mr. Bassham 28,923 12,11-43,619 Mr. MalThik "I \ N/A .~7,2,217 Mr. Marshall 123,276 88,716 23,833 (4) These amounts include the value of perquisites and personal benefits that are not generally available to all employees. These perquisites and personal benefits are of the following types: (A) employer match of contributions to our 401(k) plans (which are contributed to the maximum extent permitted by law to the 401(k), with (B) any excess contributed to the officers' accounts in our non-qualified deferred compensation plan); (C) flexible benefits and other health and welfare plan benefits; 32
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| | |
| (D) car allowances; (E) club memberships; (F) executive financial planning services; (G) parking; (H) spouse travel; (I) personal use of company tickets; and (J) matched charitable donations as attributed in greater detail below:
| |
| Name (A) ($) (B) ($) (C) ($) (D) ($) (E) ($) (F) ($) (G) ($) (H) ( (1) ) (J)
| |
| Mr. Chesser 6,750 15,001 21,583 7,200 4,620 11,000 480 4,366 - -
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| Mr. Bassham 6,750 3,000 19,841 7,200 1,740 12,667 480 254 288 Mr. Marshall 6,750 5,025 15,936 7,200 1,740 12,250 480 The amounts also include dividends paid on restricted stock awards that are not factored into the grant date fair value required to be reported in the Grants of Plan-Based Awards Table. Dividends paid on restricted stock awards are reinvested in our common stock through our DRIP, and carry the same restrictionsas the' underlying awards. In 2007, the following amounts of dividends were paid on restricted stock awards to our NEOs:
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| Name Restricted Stock Dividends ($)
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| Mr. Chesser 165,452
| |
| ~Mr. DowiieK' 2,3 Kt' Mr. Bassham. 67,021 Mr. Marshall 88,357 GRANTS OF PLAN-BASED AWARDS The following table provides additional information with respect to awards under both the non-equity and equity incentive plans. We have omitted from the table the columns titled "All other option awards:
| |
| number of securities underlying options" and "Exercise or base price of option awards," because no options were granted in 2007.
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| 33
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| | |
| GRANTS OF PLAN-BASED AWARDS Estimated Future Payouts Under Estimated Future Payouts Under Equity All Other Non-Equity Incentive Plan Awards Incentive Plan Awards Stock Awards: Grant Date Fair Number of Value of Stock Shares of and Option Name Grant Date Threshold Target Maximum Threshold Target Maximum Stock or Units Awards (S) (7)
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| (a) (b) ($) (c) ($) (d) ($) (e) (#) (f) (#) (g) (#) (h) (#) (i) (1)
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| February 6, 2007 () 362,500 725,000 1,450,000 Mr. Chesser February 6, 2007 (2) 12,760 25,520 51,040 815,619 (6)
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| February 6, 2007 (3) 8,507 271,884 February 6, 2007 (4) 80,000 2,556,800 Febli (),'007 164,50O 329,000 ,58'000
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| ~M.
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| ~wey 1/22'ebru 1 6 2007 a268 45,38ý 0 1I6 1/2Febru~~4 6 O7 ý,2~ 135,127 Febr(iia t), _'07 () 45,(090 l438,2N) 1, February 6, 2007 (1) 81,250 162,500 325,000 Mr. Bassham February 6, 2007 (2) 3,242 6,483 12,966 207,197 (6)
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| February 6, 2007 (3) 2,161 69,066 February 6, 2007 (4) 25,000 799,000
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| ~ebrta F 6iOO2007 1~3_'O(j0 'o24,000 I -- p
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| ~Mr~Malik <~Febii>.tr o, 220070j February 6, 2007 O) 83,750 167,500 335,000 Mr. Marshall February 6, 2007 (2) 3,341 6,682 13,364 213,557 (
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| February 6, 2007 (3) 2,227 71,175 February 6, 2007 (4) 25,000 799,000 (1) Reflects potential payments under our 2007 annual incentive plans. The actual amounts earned in 2007 are reported as Non-Equity Incentive Plan Compensation in the Summary Compensation Table.
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| (2) Consists of performance share awards under our LTIP for the period 2007-2009. Performance shares are payable in our stock at the end of the performance period, depending on our total shareholder return for the period compared against the EEl index of electric utilities. The number of shares awarded can range from 0% to 200%
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| of the target amount, as adjusted for the change in fair market value between the time of grant and the end of the award period. Dividends will be paid in cash at the end of the period on the number of shares earned.
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| (3) Consists of time-based restricted stock awards under our LTIP that vest on February 6, 2010.
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| (4) Consists of time-based restricted stock awards under our LTIP. Half of these awards vest on February 6, 2009, and the remaining half vest on February 6, 2010.
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| (5) Consists of awards under the Great Plains Energy and Strategic Energy LTIPs for the period 2007-2009 applicable to Mr. Malik. A portion of the awards is in the form of performance shares payable in our stock at the end of the performance period, depending on the four criteria of cumulative pre-tax net income, return on invested capital, total shareholder return, and MWhs under management by December 31, 2009. The number of shares awarded can range from 0% to 200% of the target amount, as adjusted for the change in fair market value between the time of grant and the end of the award period. Dividends will be paid in cash at the end of the period on the number of shares earned. The remainder of the award is in the form of cash. Cash awards can range from 0% to 300% of the target amount, depending on the accomplishment against the following objectives at the end of the performance period: cumulative pre-tax net income; return on average book equity; cumulative sales; general and administrative expenses (excluding net interest expense) per MWh; and MWhs under management.
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| (6) Calculated at target.
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| (7) Grant date fair value on February 6, 2007 was $31.96 calculated in accordance with FAS 123R.
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| | |
| NARRATIVE ANALYSIS OF
| |
| | |
| ==SUMMARY==
| |
| COMPENSATION TABLE AND PLAN-BASED AWARDS TABLE Employment Arrangements Mr. Malik has a written employment agreement with the Company, and Messrs. Chesser and Marshall have ongoing employment arrangements with the Company. Mr. Malik's employment agreement was for a three-year period ending November 10, 2007; however, the term has been automatically extended for a one-year period, and will continue to be automatically extended for one-year periods unless either we or Mr. Malik give 60 days notice prior to the expiration of the then-current term.
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| The agreement provides for additional compensation if Mr. Malik's' employment is terminated without "Cause" by the Company, or if Mr. Malik terminates his employment for "Good Reason." This additional compensation is three times Mr. Malik's annual base salary, the current year's annual incentive (prorated through the termination date), and three times the average annual incentive compensation paid during the three most recent fiscal years (or such shorter period as Mr. Malik shall have been employed).
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| The agreement further provides for additional compensation if Mr. Malik is terminated upon disability or following his death. If Mr. Malik's employment is terminated by him or the Company as a result of his disability, .he would receive his current salary for three months following termination or the period until disability benefits commence under any insurance provided by the Company, and his incentive compensation, if any, prorated through the end of the month when the disability occurred. If Mr.
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| Malik's employment was terminated because of his death, his beneficiary or estate would receive his current salary, through then end of the month in which his death occurred and his incentive compensation, if any, prorated through the end of the month when his death occurred.
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| Mr. Malik's employment agreement defines "Cause" as a:
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| * material breach of duties and responsibilities that is willful and deliberate and is not remedied within a reasonable period after notice; or
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| * commission of a felony involving moral turpitude.
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| "Good Reason" is defined in the employment agreement as:
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| * assignment of duties that are inconsistent with those held on November 10, 2004;
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| " a change in reporting responsibilities, titles or offices;
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| * any removal or involuntary termination otherwise than as expressly permitted by the agreement;
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| " any failure to re-elect Mr. Malik to any position;
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| * a reduction of more than 15% in annual base salary; or
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| * any requirement that Mr. Malik be based anywhere other than at his current location.
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| We have also agreed to certain compensation arrangements with Messrs. Chesser and Marshall at the time of their employment. For Mr. Chesser, if he is terminated without cause prior to age 63, he will be paid a severance amount equal to three times his annual salary and bonus; if terminated without cause between the age of 63 and 65, he will be paid a severance amount equal to the aggregate of his annual salary and bonus.
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| In addition, Mr. Chesser is credited with two years of service for every one year of service earned under our pension plan, with such amount payable under our SERP.
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| 35
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| | |
| If Mr. Marshall is terminated without cause, he will be paid a severance amount equal to the target payment under the annual incentive plan plus two times his annual base salary. Mr. Marshall is also credited with two years of service for every one year of service earned under our pension plan, with such amount payable under our SERP. Please see "Payments under Other Compensation Arrangements," beginning on page 45, for additional information, including definitions of key terms, regarding these employment arrangements.
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| Our NEOs have also entered into Change in Control Severance Agreements. Please see "Potential, Payments Upon Termination or Change-in-Control," beginning on page 41 for a description of these agreements.
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| Base salaries for our NEOs are set by our Board, upon the recommendations of our Compensation and Development Committee. For 2007, the base salaries were: Mr. Chesser, $725,000; Mr. Downey, $470,000; Mr. Bassham, $325,000; Mr. Malik, $440,000; and Mr. Marshall, $335,000. Our NEOs also participate in our health, welfare and benefit plans, our annual and long-term incentive plans, our pension and SERP plans (except for Mr. Malik), our non-qualified deferred compensation plan and receive certain other perquisites and personal benefits, such as car allowances, club memberships, executive financial planning services, parking, spouse travel, personal use of company tickets, and matched charitable donations.
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| Awards Restricted Stock During 2007, our Board made two awards of restricted stock to each of the NEOs, except Mr. Malik. One award of restricted stock is consistent with the Company's equity incentive compensation practices in 2006, and will vest on February 6, 2010. These awards were: Mr. Chesser, 8,507 shares; Mr.. Downey, 4,228 shares; Mr. Bassham, 2,161 shares; and Mr. Marshall, 2,227 shares. The second, special, award of restricted stock was made to recognize performance in 2006 and to ensure the NEOs' continued focus and commitment to the Company's core business, projects and the proposed acquisition and subsequent' operational integration of Aquila, Inc. with the Company. Half of the special award of restricted stock will vest on February 6, 2009, and the remaining half will vest on February 6, 2010. Restricted stock awards include the right to vote. Dividends paid on the restricted stock are reinvested in stock through our DRIP, and carry the same restrictions as the underlying awards, The special awards were: Mr.
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| Chesser, 80,000 shares; Mr. Downey, 45,000 shares; Mr. Bassham, 25,000 shares; and Mr. Marshall, 25,000 shares.
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| PerformanceShares The Board also granted performance shares for the period 2007-2009 to the NEOs. Performance shares are payable in our stock at the end of the performance period, depending on the achievement of specified measures. For our NEOs except Mr. Malik, the performance share measure is our total shareholder return for the period compared against the EEI index of electric utilities. For Mr. Malik, the measures are the same as for the Strategic Energy 2007-2009 long-term incentive plan discussed in our CD&A (cumulative pre-tax net income, return on invested capital, total shareholder return, and MWhs under management by December 31, 2009). The number of shares awarded can range from 0% to 200% of the target amount, as adjusted for the change in fair market value of our shares between the time of grant and the end of the award period. Dividends will be paid in cash at the end of the period on the number of shares earned. The following table describes the potential payout percentages for the total shareholder return measure:
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| 36
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| | |
| Total Shareholder Return Percentile Rank Percentage Payout 81 st and Above 200%
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| o I 5 0 th to 64th 100%
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| 34 "hand Below' 0 Performance shares were awarded to our NEOs (except Mr. Malik) for the performance period of 2005-2007. As discussed in our CD&A, threshold performance was not achieved for the performance shares granted to Messrs. Chesser and Bassham, and 85% performance was achieved for the performance shares granted to Messrs. Downey and Marshall, who thus received 5,507 and 4,482 shares, respectively, of our stock.
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| Cash-BasedLong-Term Incentives Mr. Malik's long-term incentives that were earned and granted in 2007 under long-term incentive plans comprised time-based restricted stock (described above) and cash based on performance. The performance is based on Strategic Energy's long-term goals, as discussed in our CD&A.
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| Annual Incentives Under the annual incentive plans for 2007, our NEOs were eligible to receive up to 200% of a target amount set as a percentage of their respective base salaries, as follows: Mr. Chesser, 100%; Mr. Downey, 70%; Mr. Bassham, 50%; Mr. Malik, 60%; and Mr. Marshall, 50%. There were no payouts under the 2007 annual incentive program because the threshold core earnings level was not achieved. The tables on pages 23 and 24 summarize the 2007 annual incentive plan, year-end results,. and payout levels for Great Plains Energy, KCP&L, and Strategic Energy.
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| Based upon performance in 2007, no annual incentives were paid.
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| Salaryand Bonus in Proportionto Total Compensation As we discuss in our CD&A, one objective of our compensation program is to align management interests with those of our shareholders. The Compensation and Development Committee believes that a substantial portion of total compensation for its officers should be delivered in the form of equity-based incentives. In 2007, 75.% of the long-term incentive grants to Messrs. Chesser, Downey, Bassham, and Marshall were in the form of performance shares which, if earned after three years based on total return to shareholders, will be paid in Company stock. To mitigate potential volatility in payouts and provide a retention device, the remaining 25% of the long-term grant was in time-based restricted shares. For Mr.
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| Malik, 50% of his long-term grant was in time-based performance shares, with the remaining portion of
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| *his long-term grant eligible to be paid in cash..
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| In 2007, we determined cash and equity incentive grants (excluding the special grants of restricted stock discussed in the CD&A) using the following proportions of base salary:
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| 37
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| | |
| Annual Cash Long-term Cash Long-term Equity Name Incentive at Target Incentive at Target Incentive at Target Mr. Chesser 100% 150%
| |
| IvMr.Dqoyw7%
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| f.2. .Aý?
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| Mr. Bassham 50% _85%
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| Mr. Marshall 50% 85%
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| The following table provides information regarding the outstanding equity awards held by each' of the NEOs as of December 31, 2007. We have omitted from the table the columns titled "Number of securities underlying unexercised options, unexercisable" and "Equity incentive plan awards:Number of securities underlying unexercised unearned options," because there are no unexercisable options.
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| OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END Option Awards Stock Awards I Equity Incentive Plan Market . Equity Awards:
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| Number of Number of Value of Incentive Plan Market or Securities Shares of Shares of Awards: Payout Value Underlying Stock That Stock That Number of of Unearned Unexercised Option Option Have Not Have Not Shares That Shares That Option (#) Exercise Expiration Vested Vested Have Not Have Not
| |
| ($) (2)
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| Name Exercisable Price ($) Date (#) (1) Vested (#) (3) Vested ($) (2)
| |
| (a) (b) (e) (f) (i)
| |
| (1) Includes reinvested dividends on restricted stock that carry the same restrictions.
| |
| (2) The value of the shares is calculated by multiplying the number of shares by the closing market price ($29.32) as of December 31, 2007.
| |
| (3) The payment of performance shares is contingent upon achievement of specific performance goals over a stated period of time as approved by the Compensation and Development Committee of the Company's Board of Directors. The number of performance shares ultimately paid can vary from the number of shares initially granted, depending on Company performance, based on internal and external measures, over stated performance periods:
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| (4) Mr. Chesser received a restricted stock grant on February 7, 2006 for 8,643 shares that vest February 7, 2009. He also received a performance share grant on February 7, 2006 for 25,930 shares, at target, for the three-year period ending December 31, 2008. He received a restricted stock grant on February 6, 2007 for 80,000 shares, of which 40,000 shares vest on February 6, 2009 and 40,000 shares vest on February 6, 2010. He received a restricted stock grant on February 6, 2007 for 8,507 shares that vest on February 6, 2010. He received a performance share grant on February 6, 2007 for 25,520 shares, at target, for a three-year period ending December 31, 2009.
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| (5) Mr. Downey received a restricted stock grant on February 7, 2006 for 4,587 shares that vest February 7, 2009. He also received a performance share grant of 13,763 shares, at target, for the three-year period ending December 31, 2008. He received a restricted stock grant on February 6, 2007 for 45,000 shares, of which 22,500 shares vest on February 6, 2009 and 22,500 shares vest on February 6, 2010. He also received a restricted stock grant on February 6, 2007 for 4,228 shares, which vest on February 6, 2010. He received a performance share grant on February 6, 2007 for 12,684 shares, at target, for a three-year period ending December 31, 2009.
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| (6) Mr. Bassham received a restricted stock grant on March 28, 2005 for 9,083 shares that vest on March 28, 2008. He received a restricted stock grant on February 7, 2006 for 2,260 shares that vest February 7, 2009. He also received a performance share grant on February 7, 2006 for 6,781 shares, at target, for the three-year period ending December 31, 2008. He received 38
| |
| | |
| a restricted stock grant on February 6, 2007 for 25,000 shares, of which 12,500 shares vest on February 6, 2009 and 12,500 shares vest on February 6, 2010. He also received a restricted stock grant on February 6, 2007 for 2,161 shares that vest on February 6, 2010. He also received a performance share grant on February 6, 2007 for 6,483 shares, at target, for the three-year period ending December 31, 2009.
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| (7) Mr. Malik received a restricted stock grant on February 1, 2005 for 4,956 shares that vested February 1, 2008. He received a restricted stock grant on February 7, 2006 for 5,585 shares that vest February 7, 2009. He also received a performance share grant on February 7, 2007 for 10,325 shares, at target, for the three-year period ending December31, 2009.
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| (8) Mr. Marshall received a restricted stock grant on May 25, 2005 for 20,275 shares that vest on May 25, 2008. He received a restricted stock grant on February 7, 2006 for 2,449 shares that vest February 7, 2009. He also received a performance share grant of 7,347 shares for the three-year period ending December 31, 2008. He.received a restricted stock grant on February 6, 2007 for 25,000 shares, of which 12,500 shares vest on February 6, 2009 and 12,500 shares vest on February 6, 2010. He also received a restricted stock grant on February 6, 2007 for 2,227 shares that vest on February 6, 2010. He also received a performance share grant on February 6, 2007 for 6,682 shares, at target, for the three-year period ending December 31, 2009.
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| OPTION EXERCISES AND STOCK VESTED We have omitted the "Option award" columns from the following table, because none of our NEOs exercised options in 2007.
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| Number of Shares Acquired Value Realized Name on Vesting (#) on Vesting ($)
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| (a) (d) (e)
| |
| Mr. Chesser (1)15,079 436,386 Mr. Bassham Mr. Marshall 14) 4,482 127,827 (1) Restricted stock of 12,135 shares, plus 2,944 DRIP shares vested on October 1, 2007. The value realized on vesting is the closing price of $28.94 on October 1, 2007, multiplied by the number of shares vested.
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| (2) Restricted stock of 8,826 shares, plus 2,141 DRIP shares vested on October 1, 2007. The value realized on vesting is the closing price of $28.94 on October 1, 2007, multiplied by the number of shares vested. Mr. Downey earned 5,507 shares pursuant to a performance share grant for the period of 2005-2007, which were issued in February 2008. The value realized on vesting is the closing price of $28.52 on February 5, 2008, multiplied by the number of shares awarded.
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| (3) Mr. Malik had a restricted stock grant of 4,956 shares, plus 577 DRIP shares, vest on February 1, 2007. The value realized on vesting is the closing price of $31.51 on February 1, 2007, multiplied by the number of shares vested. Mr. Malik had a restricted stock grant of 4,445 shares, plus 799 DRIP shares, vest on November 10, 2007. The value realized on vesting is the closing price of $30.14 on November 10, 2007, multiplied by the number of shares vested.
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| (4) Mr. Marshall earned 4,482 shares pursuant toa performance share grant for the period of 2005-2007, which were issued in February 2008. The value realized on vesting is the closing price of $28.52 on February 5, 2008, multiplied by the number of shares awarded.
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| The following discussion of the pension benefits for the NEOs reflects the terms of the Company's Management Pension Plan (the "Pension Plan") and SERP, and the present value of accumulated benefits, as of December 31, 2007. As discussed in the CD&A, management employees were given a one-time election to either remain in these existing plans or choose a new retirement program effective January 1, 2008. We have omitted the column titled "Payments during the last fiscal year," because no payments were made in 2007.
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| 39
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| | |
| PENSION BENEFITS Numberaf Years Present Value of Name Plan Name Credited Service (#) Accumulated Benefit($
| |
| (a) (b) (c) (d)
| |
| Mr. Chesser ( Management Pension Plan 4.5 151,705 Supplemental Executive Retirement Plan 9 971,165 Mr. Bassharn Management Pension Plan 2.5 41,663 Suplemental Executive Retirement Planl 2.5 2,7 Sýupplemna Exctv Reiemn Pli 271 Management Pension Plan 2.5 81,382 Mr. Marshall (1 Supplemental Executive Retirement Plan 5 209,435 (1) Messrs. Chesser and Marshall are credited with two years of service for every one year of service earned under our pension plan, with such amount payable under our SERP. Without this augmentation, Messrs. Chesser and Marshall would have accrued
| |
| $409,703 and $64,026, respectively, under the SERP.
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| (2) Mr. Malik does not participate in either the Management Pension Plan or SERP.
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| Our NEOs, excluding Mr. Malik, participate in the Pension Plan and the SERP. The Pension Plan is a funded, tax-qualified, noncontributory defined benefit pension plan. Benefits under the Pension Plan are based on the employee's years of service and the average annual base salary. over a specified period.
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| Employees who retire after they reach 65, or whose age and years of service. add up to 85, are entitled to a total monthly annuity for the rest of their life (a "single life" annuity) equal to 50% of their average base monthly salary for the period of 36 consecutive months in which their earnings were highest. The annuity will be proportionately reduced if years of credited service are less than 30 or if age and years of service do not add up to 85. Employees may elect other annuity options, such as joint and, survivor annuities or annuities with payments guaranteed for a period of time. The present value of each annuity option is the same; however, the monthly amounts payable under these options are less than the amount payable under the single life annuity option. Employees also may elect to receive their retirement benefits in a lump sum equal to .the actuarial equivalent of a single life pension under the Pension Plan.
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| Of our NEOs, only Mr. Downey is eligible for early retirement benefits under the Pension Plan. His early retirement benefits would be a monthly annuity equal to 10.9% of his average base month salary during the period of 48 consecutive months in which his earnings were highest. The compensation covered by the Pension Plan excludes any bonuses or other compensation. The amount of annual earnings that may be considered in calculating benefits under the Pension Plan is limited by law. For 2007, the annual limitation is $220,000.
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| The SERP is unfunded and provides out of general assets an amount substantially equal to the difference between the amount that would have been payable under the Pension Plan in the absence of tax laws limiting pension benefits and earnings that may be considered in calculating pension benefits, and the amount actually payable under the Plan. It also adds an additional 1/3% of highest average annual base salary for each year of credited service when the executive was eligible for supplemental benefits, up to 30 years. As mentioned, Messrs. Chesser and Marshall are credited with two years of service for every one year of service earnedunder our Pension Plan, with such amount payable under the SERP.
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| In the table above, the present value of the current accrued benefits with respect to each listed officer is based on the following assumptions: retirement at the earlier of age 62 or when the sum of age and years 40
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| | |
| of service equal 85; full vesting of accumulated benefits; a discount rate of 5.9%; and use of the Pension Plan's mortality and lump sum tables.
| |
| As discussed in the CD&A, employees (including NEOs) were given a choice in 2007 to either continue accruing benefits in the Pension Plan as described above, or accrue slightly less benefits starting in 2008, with an enhanced benefit under our 401 (k) plan. Messrs. Bassham and Marshall have made the latter election. Starting in 2008, their accrual rate under the Pension Pian will be 1.25% per year, compared to 1.67% in prior years.
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| We have omitted from the following table the column titled "Aggregate withdrawals/distributions,"
| |
| because there were no withdrawals or distributions in 2007 to our NEOs.
| |
| NONQUALIFIED DEFERRED COMPENSATION Executive Registrant Contribution in Last Contributions in Last Aggregate Earnings Aggregate Balance at FY ( FY (2) in Last FY (3) Last FYE Name ($) ($) ($) ($)
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| (a) (b) (c) (d) (f)
| |
| Mr. Chesser 108,750 15,001 86,525 1,136,871 Mr. Bassharn 12,000 3,000 9,991 . 6,816 Mr. Marshall 167,500 5,025 65,796 .885,859 (1) Amounts in this column are included in the "Salary" column in the Summary Compensation Table.
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| (2) Amounts in this column are included in column (B) of the first table located in footnote (4) of the Summary Compensation Table.
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| (3) Only the above-market earnings are reported in the Summary Compensation Table. The above-market earnings were:
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| *Chesser, $31,341; Downey, $44,011; Bassham, $3,619; Malik, $21,111; and Marshall, $23,833.
| |
| Our deferred compensation plan is a nonqualified and unfunded plan. It allows selected employees, including our NEOs, to defer the receipt of up to 50% of base salary and 100% of awards under annual incentive plans. The plan provides for a matching contribution in an amount equal to 50% of the, first 6%
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| of the base salary deferred by participants, reduced by the amount of the matching contribution-made for the year to the participant's account under our Employee Savings Plus Plan, as described in our CD&A.
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| An earnings rate is applied to the deferral amounts. This rate is determined annually by the Compensation and Development Committee and is generally based on the Company's weighted average cost of capital. The rate was set at 9.0% for 2007. Interest is compounded monthly on deferred amounts.
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| Participants may elect prior to rendering services for which the compensation relates when deferred amounts are paid to them: either at a specified date, or upon separation from service. For our NEOs who elect payment on separation of service, amounts are paid the first business day of the seventh calendar month following their separation from service.
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| POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE-IN-CONTROL Our NEOs are eligible to receive lump sum payments in connection with any termination of their employment. The Company believes that severance protections, particularly in the context of a change in control transaction, can play a valuable role in attracting and retaining key executive officers.
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| Accordingly, we provide such protections for our NEOs. The Compensation Committee evaluates the 41
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| | |
| level of severance benefits to provide a NEO on a case-by-case basis, and in general, considers these severance protections an important part of an executive's overall compensation and consistent with competitive practices. Payments made will vary, depending on the circumstances of termination, as we discuss below.
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| Payments under Change in ControlSeverance Agreements We have Change in Control Severance Agreements ("Change in Control Agreements") with our NEOs, specifying the benefits payable in the event their employment is terminated within two years of a "Change in Control" or within a "protected period." Generally, a "Change in Control" occurs if:
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| " Any person (as defined by SEC regulations) becomes the beneficial owner of at least 35% of our outstanding voting securities;
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| * A change occurs in the majority of our Board; or
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| * A merger, consolidation, reorganization or similar transaction is consummated (unless our shareholders continue to hold at least 60% of the voting power of the surviving entity), or a liquidation, dissolution or a sale of substantially all of our assets occurs or is approved by our shareholders.
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| A "protected period" starts when:
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| * We enter into an agreement that, if consummated, would result in a Change in Control;
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| * We, or another person, publicly announces an intention to take or to consider taking actions which, if consummated, would constitute a Change in Control;
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| " Any person (as defined by SEC regulations) becomes the beneficial owner of 10% or more of our outstanding voting securities; or
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| " Our Board, or our shareholders, adopt a resolution approving any of the foregoing matters or, approving a Change in Control.
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| Mr. Malik's Change in Control Agreement also defines "Change in Control" to include the occurrence of these events at Strategic Energy.
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| The protected period ends when the Change in Control transaction is consummated, abandoned or terminated.
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| The Company also believes that the occurrence, or potential occurrence, of a change in control transaction will create uncertainty regarding the continued employment of our executive officers. This uncertainty results from the fact that many change in control transactions result in significant organizational changes, particularly at the senior executive level. We believe these change of control arrangements effectively create incentives for our executive team to build stockholder value and to obtain the highest value possible should we be acquired in the future, despite the risk of losing employment and potentially not having the opportunity to otherwise vest in equity awards which are a significant component of each executive's compensation. These agreements are designed to encourage our NEOs to remain employed with the Company during an important time when their prospects for continued employment following the transaction could be uncertain. Because we believe that a termination by the executive for good reason may be conceptually the same as a termination by the Company without cause, and because we believe that in the context of a change in control, potential acquirors would otherwise have an incentive to constructively terminate the executive's employment to avoid paying severance, we believe it is appropriate to provide severance benefits in these circumstances.
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| 42
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| Our change of control arrangements are "double trigger," meaning that acceleration of vesting is not awarded upon a change of control, unless the NEO's employment is terminated involuntarily (other than for cause) within 2 years of a Change in Control or protected period. We believe this structure strikes a balance between the incentives and the executive hiring and retention effects described above, without providing these benefits to executives who continue to enjoy employment with an acquiring company in the event of a change of control transaction. We also believe this structure is more attractive to potential acquiring companies, who may place significant value on retaining members of our executive team and who may perceive this goal to be undermined if executives receive significant acceleration payments in connection with such a transaction and are no longer required to continue employment to earn the remainder of their equity awards.
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| The benefits under the Change in Control Agreements depend on the circumstances of termination.
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| Generally, benefits are greater if the employee is not terminated for "Cause," or if the employee terminates employment for "Good Reason." "Cause" includes:
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| * A material misappropriation of any funds, confidential information or property;
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| * The conviction of, or the entering of, a guilty plea or plea of no contest with respect to a felony (or equivalent);
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| * Willful damage, willful misrepresentation, willful dishonesty, or other willful conduct that can reasonably be expected to have a material adverse effect on the Company; or
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| " Gross negligence or willful misconduct in performance of the employee's duties (after written notice and a reasonable period to remedy the occurrence).
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| An employee has "Good Reason" to terminate employment if:
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| * There is any material and adverse reduction or diminution in position, authority, duties or responsibilities below the level provided at any time during the 90-day period before the "protected period";
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| " There is any reduction in annual base salary after the start of the "protected period";
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| * There is any reduction in benefits below the level provided at any time during the 90-day period prior to the "protected period"; or
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| * The employee is required to be based at any office or location that is more than 70 miles from where the employee was based immediately before the start of the "protected period."
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| Our Change in Control Agreements also have covenants prohibiting the disclosure of confidential information and preventing the employee from participating or engaging in any business that, during the employee's employment, is in direct competition with the business of the Company within the United States (without prior written consent which, in the case of termination, will not be unreasonably withheld).
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| Change in Control with Termination of Employment The following table sets forth our payment obligations under the Change in Control Agreements under the circumstances specified upon a termination of employment. The table is based on the assumptions that the termination took place on December 31, 2007, that all vacation was taken during the year, and the NEO was paid for all salary earned through the date of termination. The table does not reflect amounts that would be payable to the NEOs for benefits or awards that already vested.
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| 43
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| | |
| Mr.
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| Chesser Mr.
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| Bassham \11 a*laik Mr.
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| Marshall Benefit ($)
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| ($) (s)$
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| Two Times or Three Times Salary l 2,175,000 650,000 1,32P,000 670,000 Two Times or Three Times Bonus (2) 1,859,143 409,418 958,928' .529,897 Annualized Pro Rata Bonus (3) 619,714 204,709 **33 643* 264,949 SERP/Pension Plan (4) 1,629,334 364,549 K,*- *2j: 535,971 Health and Welfare (5) 29,716 28,848 '0,264 18,428 Performance Incentives (6) 1,508,514 388,900 t ( _-)N) 411,330 Performance Share Dividends (7) 128,451 33,275 17*t40* 35,484 Acceleration of Performance Share Pay- !iq:!
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| * 674 Out (8)
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| Restricted Stock (9) 738,927 231,842 .. 1 259,686 Restricted Stock and Option Dividends (10) 44,937 14,835 .. 1, i 19,290 Unvested 401 (k) Employer Match 8,345 Unvested Deferred Plan Employer Match 17,378 2,616 , 14,745 Tax Gross-Up (II) 4,029,906 1,015,022 4166 1,035 1,258,936 Total 12,789,365 3,344,014 5,439*,52 4,019,390 (1) Messrs. Chesser, Downey, and Malik receive three times their highest annual base salary immediately preceding the fiscal year in which the Change in Control occurs. Messrs. Bassham and Marshall receive two times their highest annual base salary immediately preceding the fiscal year in which the Change in Control occurs.
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| (2) Messrs. Chesser, Downey, and Malik receive three times their highest average annualized annual incentive compensation awards during the five fiscal years (or, if less, the years they were employed by the company) immediately preceding the fiscal year in which the Change in Control occurs. Messrs. Bassham and Marshall receive two times their highest average annualized annual incentive compensation awards.
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| (3) The annualized pro rata bonus amount is at least equal to the average annualized incentive awards paid to the NEO during the last five fiscal years of the Company (or the number of years the NEO worked for the Company) immediately before the fiscal year in which the Change-in-Control occurs, pro rated for the number of days employed in that year.
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| (4) Mr. Chesser is credited with two years for every one year of credited service under the Pension Plan, plus six additional years of credited service. Mr. Downey is credited for three additional years of service. Mr. Marshall is credited for two years for every one year of credited service under the Pension Plan, plus four additional years of credit service. Mr. Bassham is credited for two additional years of service. Mr. Malik does not participate in the Pension Plan or SERP.
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| (5) The amounts include medical, accident, disability, and life insurance and are estimated based on our current COBRA premiums for medical coverage and indicative premiums for private insurance coverage for the individuals.
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| (6) In the event of a Change in Control (which is generally consistent with the definition of a Change in Control in the Change in Control Agreements, except that the beneficial ownership threshold percentage is lower), our LTIP provides that all performance share grants (unless awarded less than six months prior to the change in control) are deemed to have been fully earned. As discussed in the CD&A, above, a portion of Mr. Malik's performance incentives are paid in cash.
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| (7) Performance Share Dividends are the cash dividends paid on the Performance Shares.
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| (8) Acceleration of Performance Share Pay-Out is the value of receiving the pay-out on December 31, 2007, instead of February, 2008, the usual time of payout.
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| (9) In the event of a Change in Control (which is generally consistent with the definition of a Change in Control in the Change in Control Agreements, except that the beneficial ownership threshold percentage is lower), our LTIP provides that all restrictions on restricted stock grants are removed.
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| (10) In the event of a Change in Control (which is generally consistent with the definition of a Change in Control in the Change in Control Agreements, except that the beneficial ownership threshold percentage is lower), our LTIP provides that: all outstanding stock options outstanding are fully exercisable and all limited stock appreciation rights are automatically exercised; and all restrictions on restricted stock grants are removed.
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| (11) The Change in Control Agreements generally provide for an additional payment to cover excise taxes imposed by Section 4999 of the Internal Revenue Code ("Section 280G gross-up payments"). We have calculated these payments based on the estimated payments discussed above, as well as the acceleration of equity awards that are discussed below. In calculating these payments, we did not make any reductions for the value of reasonable compensation for pre-Change in Control period and post-Change in Control period service, such as the value attributed to non-compete provisions. In the event that payments are due under Change in Control Agreements, we would perform evaluations to determine the reductions attributable to these services.
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| 44
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| Change in Control without Termination of Employment Upon a Change in Control, all restrictions on outstanding unvested restricted stock and unvested restricted stock options granted prior to the May 2007 amendments to our LTIP held by our NEOs would vest. As well, all outstanding performance share grants would be deemed to have been fully earned. All of the outstanding restricted stock, stock options and performance shares were granted prior to the amendments. These grants would become payable, and it is expected that Mr. Malik's long-term cash incentives would become payable, even if the NEO continues employment throughout the protected period. The following table sets forth the amounts payable to our NEOs assuming a Change in Control, without termination of the NEO's employment.
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| Mr. Chesser I k Mr. Bassham I Ilahk Mr. Marshall
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| $3,879,555 1.()()4 $1,401,441 S 1 I441 $1,784,061 Retirement, Resignation,Death or Disability Upon retirement or resignation, the NEO would receive all accrued and unpaid salary and benefits, including the retirement benefits discussed above. In the event of death or disability, the NEO (or his beneficiary) would receive group life insurance proceeds or group disability policy proceeds, as applicable. In addition, these events would have the following effects on outstanding LTIP awards: (i) if employment is terminated by either the Company or the NEO, all restricted stock and performance share awards would be forfeited; (ii) if the NEO retires, becomes disabled or dies, restricted stock and performance share awards would be prorated for service during the applicable periods; (iii) if the NEO retires, outstanding options expire three months from the retirement date; (iv) if the NEO resigns or is discharged, outstanding options terminate; and (v) if the NEO becomes disabled or dies, outstanding options terminate twelve months after disability or death. Mr. Malik's employment agreement also provides for additional compensation, should his employment terminate as a result of his death or disability. Please see "Payments under Other Compensation Arrangements," below, and "Narrative Analysis of Summary Compensation Table and Plan-Based Awards Table" on page 35 for additional information regarding his employment agreement.
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| OutstandingStock Options Mr. Downey holds stock options that are currently exercisable. He has limited stock appreciation rights on 45,249 option shares, which entitle him to receive cash in an amount equal to the difference between the fair market value of the shares underlying the stock appreciation rights exercised on the date of exercise, over the aggregate base or exercise price. Assuming Mr., Downey's limited stock appreciation rights were exercised on December 31, 2007, he would have received $167,446, less applicable withholding taxes.
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| Payments under Other CompensationArrangements Three of our NEOS have compensation arrangements in addition to those discussed above, as follows:
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| Mr. Chesser. Mr. Chesser's employment arrangement with the Company provides that if he is terminated without cause, he will receive three times annual salary and bonus (if terminated prior to age 63), or one-time salary and bonus (if terminated between age 63 and before age 65). If Mr. Chesser were terminated without cause as of December 31, 2007 (and assuming that the Change in Control Agreement was not applicable), he would have received $4,350,000 under this arrangement.
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| 45
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| | |
| Mr. Marshall. Mr. Marshall's employment arrangement with the Company provides that if he is terminated without cause, he will receive a severance amount equal to the target payment under the annual incentive plan plus two times his annual base salary. If Mr. Marshall were terminated without cause as of December 31, 2007 (and assuming that the Change in Control Agreement was not applicable), he would have received $837,500 under this arrangement.
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| Mr. Malik. Mr. Malik is the only NEO with an employment agreement. The agreement provides for additional compensation if Mr. Malik's employment is terminated without "Cause" by the Company, or if Mr. Malik terminates his employment for "Good Reason." This additional compensation is three times Mr. Malik's annual base salary, the current year's annual incentive (prorated through the termination date), and three times the average annual incentive compensation paid during the three most recent fiscal years (or such shorter period as Mr. Malik shall have been employed). Mr. Malik's agreement also provides for additional compensation, should his employment terminate as a result of his death or disability. Please see "Narrative Analysis of Summary Compensation Table and Plan-Based Awards Table" on page 35 for additional information regarding his employment agreement.
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| If Mr. Malik would have been terminated without Cause, or terminated employment for Good Reason as of December 31, 2007 (and assuming that the Change in Control Agreement was not applicable), he would have received $3,061,847 under his employment agreement. If Mr. Malik's employment terminated on December 31, 2007 due to disability that occurred on December 31, 2007, his additional compensation would have been $507,222, assuming disability payments commenced in the first three months. If his employment terminated on December 31, 2007 due to his death on the same day, his beneficiary or estate would have received $495,000.
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| OTHER BUSINESS Great Plains Energy is not aware of any other matters that will be presented for shareholder action at the Annual Meeting. If other matters are properly introduced, the persons named in the accompanying proxy will vote the shares they represent according to their judgment.
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| By Order of the Board of Directors
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| $F43 `7 Barbara B. Curry Senior Vice President-Corporate Services and Corporate Secretary Kansas City, Missouri March 26, 2008 46
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| | |
| UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K
| |
| [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2007 or
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| [ TRANSITION REPORT PURSUANT SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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| - For the transition period from - to Exact name of registrant as specified in charter, Commission state of incorporation, address of principal I.R.S. Employer File Number executive offices and telephone number Identification Number 001-32206 GREAT PLAINS ENERGY INCORPORATED 43-1916803 (A Missouri Corporation) 1201 Walnut Street Kansas City, Missouri 64106 (816) 556-2200 www.qreatplainsenerqy.com 000-51873 KANSAS CITY POWER & LIGHT COMPANY 44-0308720 (A Missouri Corporation) 1201 Walnut Street Kansas City, Missouri 64106 (816) 556-2200 www.kcpl.com Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is registered on the New York Stock Exchange:
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| Registrant Title of each class Great Plains Energy Incorporated Cumulative Preferred Stock par value $100 per share 3.80%
| |
| Cumulative Preferred Stock par value $100 per share 4.50%
| |
| Cumulative Preferred Stock par value $100 per share 4.35%
| |
| Common Stock without par value Securities registered pursuant to Section 12(g) of the Act: Kansas City Power & Light Company Common Stock without par value.
| |
| | |
| Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
| |
| Great Plains Energy Incorporated Yes X No _ Kansas City Power & Light Company Yes _ No X Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| |
| Great Plains Energy Incorporated Yes _ No X Kansas City Power & Light Company Yes _ No X Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
| |
| Great Plains Energy Incorporated Yes _ No X Kansas City Power & Light Company Yes X No _
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| Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to the Form 10-K.
| |
| Great Plains Energy Incorporated X Kansas City Power & Light Company X Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
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| Great Plains Energy Incorporated Large accelerated filer X Accelerated filer _ Non-accelerated filer Kansas City Power & Light Company Large accelerated filer _ Accelerated filer - Non-accelerated filer X Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
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| Great Plains Energy Incorporated Yes _ No X Kansas City Power & Light Company Yes _ No X The aggregate market value of the voting and non-voting common equity held by non-affiliates of Great Plains Energy Incorporated (based on the closing price of its common stock on the New York Stock Exchange on June 30, 2007) was approximately $2,506,432,307 All of the common equity of Kansas City Power & Light Company is held by Great Plains Energy Incorporated, an affiliate of Kansas City Power & Light Company.
| |
| On February 21, 2008, Great Plains Energy Incorporated had 86,280,058 shares of common stock outstanding.
| |
| On February 21, 2008, Kansas City Power & Light Company had one share of common stock outstanding and held by Great Plains Energy Incorporated.
| |
| Kansas City Power & Light Company meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
| |
| Documents Incorporated by Reference Portions of the 2008 annual meeting proxy statement of Great Plains Energy Incorporated to be filed with the Securities and Exchange Commission are incorporated by reference in Part Illof this report.
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| (This page intentionally left blank.)
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| TABLE OF CONTENTS Page Number Cautionary Statements Regarding Forward-Looking Information 3 Glossary of Terms 4 PART I Item 1 Business 6 Item 1A Risk Factors 14 Item 1B Unresolved Staff Comments 25 Item 2 Properties 25 Item 3 Legal Proceedings 26 Item 4 Submission of Matters to a Vote of Security Holders 26 PART II Item 5 Market for Registrant's Common Equity, Related Stockholder Matters 27 and Issuer Purchases of Equity Securities Item 6 Selected Financial Data 29 Item 7 Management's Discussion and Analysis of Financial Condition 30 and Results of Operation Item 7A Quantitative and Qualitative Disclosures About Market Risk 56 Item 8 Consolidated Financial Statements and Supplementary Data Great Plains Energy Consolidated Statements of Income 59 Consolidated Balance Sheets 60 Consolidated Statements of Cash Flows 62 Consolidated Statements of Common Stock Equity 63 Consolidated Statements of Comprehensive Income 64 Kansas City Power & Light Company Consolidated Statements of Income 65 Consolidated Balance Sheets 66 Consolidated Statements of Cash Flows 68 Consolidated Statements of Common Stock Equity 69 Consolidated Statements of Comprehensive Income 70 Great Plains Energy Kansas City Power & Light Company Notes to Consolidated Financial Statements 71 Item 9 Changes in and Disagreements With Accountants on Accounting 132 and Financial Disclosure Item 9A Controls and Procedures 132 Item 9A (T) Controls and Procedures 134 Item 9B Other Information 136 PART III Item 10 Directors, Executive Officers and Corporate Governance 137 Item 11 Executive Compensation 138 Item 12 Security Ownership of Certain Beneficial Owners and Management 138 and Related Stockholder Matters Item 13 Certain Relationships and Related Transactions, and Director Independence 138 Item 14 Principal Accounting Fees and Services 138 PART IV Item 15 Exhibits, Financial Statement Schedules 140 2
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| | |
| This combined annual report on Form 10-K is being filed by Great Plains Energy Incorporated (Great Plains Energy) and Kansas City Power & Light Company (KCP&L). KCP&L is a wholly owned subsidiary of Great Plains Energy and represents a significant portion of its assets, liabilities, revenues, expenses and operations. Thus, all information contained in this report relates to, and is filed by, Great Plains Energy. Information that is specifically identified in this report as relating solely to Great Plains Energy, such as its financial statements and all information relating to Great Plains Energy's other operations, businesses and subsidiaries, including Strategic Energy, L.L.C. (Strategic Energy),, does not relate to, and is not filed by, KCP&L. KCP&L makes no representation as to that information.
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| Neither Great Plains Energy nor Strategic Energy has any obligation in respect of KCP&L's debt securities and holders of such securities should not consider Great Plains Energy's or Strategic Energy's financial resources or results of operations in making a decision with respect to KCP&L's debt securities. Similarly, KCP&L has no obligation in-respect of securities of Great Plains Energy and of Strategic Energy.
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| CAUTIONARY STATEMENTS REGARDING CERTAIN FORWARD-LOOKING INFORMATION Statements made in this report that are not based on historical facts are forward-looking, may involve risks and uncertainties, and are intended to be as of the date when made. Forward-looking statements include, but are not limited to, statements regarding projected delivered volumes and margins, the outcome of regulatory proceedings, cost estimates of the Comprehensive Energy Plan and other matters affecting future operations. In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, the registrants are providing a number of important factors that could cause actual results to differ materially from the provided forward-looking information. These important factors include: future economic conditions in the regional, national and international markets, including but not limited to regional-and national wholesale electricity markets; market perception of the energy industry, Great Plains Energy and KCP&L; changes in business strategy, operations or development plans; effects of current or proposed state and federal legislative and regulatory actions or developments, including, but not limited to, deregulation, re-regulation and restructuring of the electric utility industry; decisions of regulators regarding rates KCP&L can charge for electricity; adverse changes in applicable laws, regulations, rules, principles or practices governing tax, accounting and environmental matters including, but not limited to, air and water quality; financial market conditions and performance including, but not limited to, changes in interest rates and credit spreads and in availability and cost of capital and the effects on pension plan assets and costs; credit ratings; inflation rates; effectiveness of risk management policies and, procedures and the ability of counterparties to satisfy their contractual commitments; impact of terrorist acts; increased competition including, but not limited to, retail choice in the electric utility industry and the entry of new competitors; ability to carry out marketing and sales plans; weather conditions including weather-related damage; cost, availability, quality and deliverability of fuel; ability to achieve generation planning goals and the occurrence and duration of planned and unplanned generation outages; delays in the.anticipated in-service dates and cost increases of additional generating capacity and environmental projects; nuclear operations; ability to enter new markets successfully and capitalize on growth opportunities in non-regulated businesses and the effects of competition; workforce risks including retirement compensation and benefits costs; performance of projects undertaken by non-regulated businesses and the success of efforts to invest in and develop new opportunities; the ability to successfully complete merger, acquisition or divestiture plans (including the acquisition of Aquila, Inc. (Aquila), and Aquila's sale of assets to Black Hills Corporation); the outcome of Great Plains Energy's review of.strategic and structural alternatives for its subsidiary Strategic Energy, L.L.C.; and other risks-and uncertainties.
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| This list of factors is not all-inclusive because it is not possible to predict all factors. Item 1A. Risk Factors included in this report should be carefully read for further understanding of potential risks for each of Great Plains Energy and KCP&L. Other sections of this report and other periodic reports filed by each of Great Plains Energy and KCP&L with the Securities and Exchange Commission (SEC) should also be read for more information regarding risk factors. Great Plains Energy and. KCP&L 3
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| undertake no obligation to publicly update, or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
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| GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.
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| Abbreviation or Acronym Definition Aquila Aquila, Inc.
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| ARO Asset Retirement Obligation BART Best available retrofit technology Black Hills Black Hills Corporation CAIR Clean Air Interstate Rule CAMR Clean Air Mercury Rule Clean Air Act Clean Air Act Amendments of 1990 C0 2 Carbon Dioxide Collaboration Agreement Agreement among KCP&L;- the Sierra Club and the Concerned Citizens of Platte County Company Great Plains Energy Incorporated and its subsidiaries Consolidated KCP&L KCP&L and its wholly owned subsidiaries DOE Department of Energy EBITDA Earnings before interest, income taxes, depreciation and amortization ECA Energy Cost Adjustment EEl Edison Electric Institute EIRR .Environmental Improvement Revenue Refunding EPA Environmental Protection Agency EPS Earnings per common share" ERISA Employee Retirement Income Security Act of 1974 FASB Financial Accounting, Standards Board FELINE PRIDESsM Flexible Equity Linked Preferred Increased Dividend Equity Securities, a service mark of Merrill Lynch& Co., Inc.
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| FERC The Federal Energy Regulatory'Commission -
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| FGIC Financial Guaranty Insurance Company FIN Financial Accounting Standards Board Interpretation FSP Financial Accounting Standards.Board Staff Position FSS Forward Starting Swaps GAAP Generally Accepted Accounting Principles Great Plains Energy Great Plains Energy Incorporated and its subsidiaries, Holdings DTI Holdings, Inc.
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| HSS Home Service Solutions Inc., a wholly owned subsidiary of KCP&L IEC Innovative Energy Consultants Inc., a wholly owned subsidiary of Great Plains Energy ISO Independent System Operator. -
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| KCC The State Corporation Commission of the State of Kansas KCP&L Kansas City Power & Light Company, a wholly owned subsidiary of Great Plains Energy 4
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| Abbreviation or Acronym Definition KDHE Kansas Department of Health and Environment KLT Gas KLT Gas Inc., a wholly owned subsidiary of KLT Inc.
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| KLT Inc. KLT Inc., a wholly owned subsidiary of Great Plains Energy KLT Investments KLT Investments Inc., a wholly owned subsidiary of KLT Inc KLT Telecom KLT Telecom Inc, a wholly owned subsidiary of KLT Inc.
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| KW Kilowatt kWh Kilowatt hour MAC Material Adverse Change Market Street Market Street Funding LLC MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations MDNR Missouri Department of Natural Resources MISO Midwest Independent Transmission System Operator, Inc.
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| MPSC Public Service Commission of the State of Missouri MW Megawatt '
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| MWh Megawatt hour NEIL Nuclear Electric Insurance Limited NO, Nitrogen Oxide NPNS Normal Purchases and Normal Sales NRC Nuclear Regulatory Commission OCl Other Comprehensive Income PJM PJM Interconnection, LLC PRB Powder River Basin PURPA Public Utility Regulatory Policy Act Receivables Company Kansas City Power & Light Receivables Company, a wholly owned subsidiary of KCP&L RTO Regional Transmission Organization SEC Securities and Exchange Commission SECA Seams Elimination Charge Adjustment Services Great Plains Energy Services Incorporated SFAS Statement of Financial Accounting Standards SIP State Implementation Plan S02 Sulfur Dioxide SPP Southwest Power Pool, Inc.
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| STB Surface Transportation Board Strategic Energy Strategic Energy, L.L.C., a subsidiary of KLT Energy Services Strategic Receivables Strategic Receivables, LLC, a wholly owned subsidiary of Strategic Energy, L.L.C.
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| T - Lock Treasury Lock Union Pacific Union Pacific Railroad Company WCNOC Wolf Creek Nuclear Operating Corporation Wolf Creek Wolf Creek Generating Station Worry Free Worry Free Service, Inc., a wholly owned subsidiary of HSS 5
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| PART I ITEM 1. BUSINESS General Great Plains Energy Incorporated and Kansas City Power & Light Company are separate registrants filing this combined annual report. The terms "Great Plains Energy," "Company," "KCP&L" and "consolidated KCP&L" are used throughout this report. "Great Plains Energy" and the "Company" refer to Great Plains Energy Incorporated and its consolidated subsidiaries, unless otherwise indicated.
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| "KCP&L" refers to Kansas City Power & Light Company, and "consolidated KCP&L" refers to KCP&L and its consolidated subsidiaries.
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| Information in other Items of this report as to which reference is made in this Item 1. is hereby incorporated by reference in this Item 1. The use of terms such as "see" or "refer to" shall be deemed to incorporate into this Item 1. the information to which such reference is made.
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| GREAT PLAINS ENERGY Great Plains Energy, a Missouri corporation incorporated in 2001 and headquartered in Kansas City, Missouri, is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy has four direct subsidiaries with operations or active subsidiaries:
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| * KCP&L is described below.
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| * KLT Inc. is an intermediate holding company that primarily holds indirect interests in Strategic Energy, L.L.C. (Strategic Energy), which provides competitive retail electricity supply services in several electricity markets offering retail choice, and holds investments in affordable housing limited partnerships. KLT Inc. also wholly owns KLT Gas Inc. (KLT Gas) and KLT Telecom Inc.,
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| which have no active operations.
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| * Innovative Energy Consultants Inc. (IEC) is an intermediate holding company that holds an indirect interest in Strategic Energy. IEC does not own or operate any assets other than its indirect interest in Strategic Energy. When combined with KLT Inc.'s indirect interest in Strategic Energy, the Company indirectly owns 100% of Strategic Energy.
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| * Great Plains Energy Services Incorporated (Services) provides services at cost to Great Plains Energy and its subsidiaries, including consolidated KCP&L.
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| Anticipated Acquisition of Aquila On February 6, 2007, Great Plains Energy entered into an agreement to acquire Aquila. Immediately prior to Great Plains Energy's acquisition of Aquila, Black Hills Corporation will acquire Aquila's electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. Each of the two transactions is conditioned on the completion of the other transaction and is expected to close in the first half of 2008. Following closing, Great Plains Energy will own Aquila and its Missouri-based utilities consisting of the Missouri Public Service and St. Joseph Light & Power divisions, as well as Aquila's merchant service operations, which primarily consists of the 340MW Crossroads power generating facility and residual natural gas contracts. The transaction is still subject to regulatory approvals from the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC); the closing of the asset sale to Black Hills Corporation (Black Hills) (which is still subject to regulatory approvals from KCC); as well as other customary conditions. See Note 2 to the consolidated financial statements for additional information.
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| 6
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| CONSOLIDATED KCP&L KCP&L, a Missouri corporation incorporated in 1922, is an integrated, regulated electric utility, which provides electricity to customers primarily in the states of Missouri and Kansas. At the end of 2007, KCP&L had two wholly owned subsidiaries, Kansas City Power & Light Receivables Company (Receivables Company) and Home Service Solutions Inc. (HSS). HSS has no active operations and effective January 2, 2008, its ownership was transferred to KLT Inc.
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| Business Segments of Great Plains Energy and KCP&L Consolidated KCP&L's sole reportable business segment is KCP&L. Great Plains Energy, through its direct and indirect subsidiaries, has two reportable business segments: KCP&L and Strategic Energy.
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| For information regarding the revenues, income and assets attributable to Great Plains Energy's reportable business segments, see Note 17 to the consolidated financial statements. Comparative financial information and discussion regarding Great Plains Energy's and KCP&L's reportable business segments can be found in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A).
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| KCP&L KCP&L, headquartered in Kansas City, Missouri, is an integrated, regulated electric utility that engages in the generation, transmission, distribution and sale of electricity. KCP&L serves approximately 506,000 customers located in all or portions of 24 counties in western Missouri and eastern Kansas.
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| Customers include approximately 446,100 residences, 57,600 commercial firms, and 2,300 industrials, municipalities and other electric utilities. KCP&L's retail revenues averaged approximately 81% of its total operating revenues over the last three years. Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the remainder of utility revenues. KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter.
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| KCP&L's total electric revenues averaged approximately 42% of Great Plains Energy's revenues over the last three years. KCP&L's net income accounted for approximately 98%, 117% and 88% of Great Plains Energy's income from continuing operations in 2007, 2006 and 2005, respectively.
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| Regulation KCP&L is regulated by the MPSC and KCC with respect to retail rates, certain accounting matters, standards of service and, in certain cases, the issuance of securities, certification of facilities and service territories. KCP&L is classified as a public utility under the Federal Power Act and accordingly, is subject to regulation by the Federal Energy Regulatory Commission (FERC). By virtue of its 47%
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| ownership interest in Wolf Creek Generating Station (Wolf Creek), KCP&L is subject to regulation by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.
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| Missouri and Kansas jurisdictional retail revenues averaged 57% and 43%, respectively, of KCP&L's total retail revenue over the last three years. See Item 7. MD&A, Critical Accounting Policies section and Note 6 to the consolidated financial statements for additional information concerning regulatory matters.
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| Missouriand Kansas Rate Case Filings In November 2007, KCP&L received an order from KCC regarding its rate case filed in March 2007. In December 2007, KCP&L received an order from the MPSC regarding its rate case filed in February 2007. For information on these rate cases, see Note 6 to the consolidated financial statements.
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| KCP&L anticipates filing rate cases with the MPSC and KCC in 2008 seeking recovery of the latan No.
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| 1 environmental retrofits and overall increased costs of service.
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| 7
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| Competition Missouri and Kansas continue on the fully integrated utility model and no legislation authorizing retail choice has been introduced in Missouri or Kansas for several years. As a result, KCP&L does not compete with others to supply and deliver electricity in its franchised service territory, although other sources of energy can provide alternatives to KCP&L's customers. If Missouri or Kansas were to pass and implement legislation authorizing or mandating retail choice, KCP&L may no longer be able to apply regulated utility accounting principles to deregulated portions of its operations and may be required to write off certain regulatory assets and liabilities.
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| KCP&L competes in the wholesale market to sell power in circumstances when the power it generates is not required for customers in its service territory. In this regard, KCP&L competes with owners of other generating stations and other power suppliers, principally utilities in its region, on the basis of availability and price. KCP&L's wholesale revenues averaged approximately 17% of its total revenues over the last three years.
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| Power Supply KCP&L has over 4,000 MWs of generating capacity. KCP&L's maximum system net hourly summer peak load of 3,721 MW occurred on July 19, 2006. The maximum winter peak load of 2,563 MW occurred on December 7, 2005. During 2007, the summer peak load was 3,638 MW and the winter peak load was 2,446 MW. The projected peak summer demand for 2008 is 3,612 MW. KCP&L expects to meet its projected capacity requirements for the years 2008 and 2009 with its generation assets, short-term capacity purchases and demand-side management and efficiency programs. As part of its Comprehensive Energy Plan, KCP&L expects to have latan No. 2, a coal-fired plant, in service in 2010, which will add approximately 465 MW (KCP&L's share) to its generating capacity.
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| KCP&L is a member of the Southwest Power Pool, Inc. (SPP). SPP is a Regional Transmission Organization (RTO) mandated by FERC to ensure reliable supply of power, adequate transmission infrastructure and competitive wholesale prices of electricity. As a member of the SPP, KCP&L is required to maintain a capacity margin of at least 12% of its projected peak summer demand. This net positive supply of capacity and energy is maintained through its generation assets and capacity, power purchase agreements and peak demand reduction programs. The capacity margin is designed to ensure the reliability of electric energy in the SPP region in the event of operational failure of power generating units utilized by the members of the SPP.
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| 8
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| Fuel The principal fuel sources for KCP&L's electric generation are coal and nuclear fuel. KCP&L expects, with normal weather, to satisfy approximately 96% of its 2008 generation requirements from these sources with the remainder provided by wind, natural gas and oil. The actual 2007 and estimated 2008 fuel mix and delivered cost in cents per net kWh generated are in the following table.
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| Fuel cost in cents per Fuel Mix (a) net kWh generated Estimated Actual Estimated Actual Fuel 2008 2007 2008 2007 Coal 75 % 72 % 1.39 1.23 Nuclear (b) 21 24 0.47 0.45 Natural gas and oil 2 3 7.57 7.30 Wind 2 1 - -
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| Total Generation 100 % 100 % 1.28 1.19 (a)Fuel mix based on percent of total MWhs generated.
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| (b) 2008 reflects the next scheduled refueling outage.
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| Prior to January 1, 2008, less than 1% of KCP&L's rates contained an automatic fuel adjustment clause. New Kansas retail rates effective January 1, 2008, contain an Energy Cost Adjustment (ECA) tariff. See Note 6 to the consolidated financial statements. KCP&L's Missouri retail rates do not contain a similar provision. To the extent the price of coal, coal transportation, nuclear fuel, nuclear fuel processing, natural gas or purchased power increases significantly, or if KCP&L's lower fuel cost units do not meet anticipated availability levels, KCP&L's net income may be adversely affected until the increased cost could be reflected in Missouri retail rates. Missouri retail rates reflect a set level of non-firm wholesale electric sales margin. KCP&L will not recover any shortfall in non-firm wholesale electric sales margin, but any amount above the level reflected in Missouri retail rates will be returned to retail customers in a future rate case.
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| Coal During 2008, KCP&L's generating units, including jointly owned units, are projected to burn approximately 13.2 million tons of coal. KCP&L has, entered into coal-purchase contracts with various suppliers in Wyoming's Powder River Basin (PRB), the nation's principal supply region of low-sulfur coal, and with local suppliers. The coal to be provided under these contracts will satisfy almost all of the projected coal requirements for 2008 and approximately 45% and 30% for 2009 and 2010, respectively. The remainder of KCP&L's coal requirements will be fulfilled through additional contracts or spot market purchases. KCP&L has entered into its coal contracts over time at higher average prices affecting coal costs for 2008 and beyond.
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| KCP&L has also entered into rail transportation contracts with various railroads to transport coal from the PRB to its generating units. The transportation services to be provided under these contracts will satisfy virtually all of the projected requirements for 2008, approximately 80% for 2009 and approximately 75% for 2010. Coal transportation costs are expected to increase in 2008 and beyond.
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| See Note 15 to the consolidated financial statements regarding a rate complaint case against Union Pacific Railroad Company.
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| 9
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| NuclearFuel KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek, its only nuclear generating unit. Wolf Creek purchases uranium and has it processed for use as fuel in its reactor. This process involves conversion of uranium concentrates to uranium hexafluoride, enrichment of uranium hexafluoride and fabrication of nuclear fuel assemblies. The owners of Wolf Creek have on hand or under contract all of the uranium and conversion services needed to operate Wolf Creek through March 2011 and approximately 86% after that date through September 2018. The owners also have under contract 100% of the uranium enrichment and fabrication required to operate Wolf Creek through March 2025.
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| Management expects its cost of nuclear fuel to remain relatively stable through 2009 because of contracts in place. From 2009 through 2018, management anticipates the cost of nuclear fuel to increase significantly due to higher contracted prices and market conditions. Even with this anticipated increase, management expects nuclear fuel cost per MWh generated to remain less than the cost of other fuel sources.
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| See Note 5 to the consolidated financial statements for additional information regarding nuclear plant.
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| Natural Gas At December 31, 2007, KCP&L had hedged approximately 35% and 4% of its 2008 and 2009, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales.
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| PurchasedPower KCP&L purchases power to meet its customers' needs when it does not have sufficient available generation or when the cost of purchased power is less than KCP&L's cost of generation or to satisfy firm power commitments. Management believes KCP&L will be able to obtain enough power to meet its future demands due to the coordination of planning and operations in the SPP region; however, price and availability of power purchases may be impacted during periods of high demand. KCP&L's purchased power, as a percent of MWh requirements, averaged approximately 7%, 2% and 4% for 2007, 2006 and 2005, respectively.
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| Environmental Matters See Note 13 to the consolidated financial statements for information regarding environmental matters.
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| STRATEGIC ENERGY Great Plains Energy indirectly owns 100% of Strategic Energy. Strategic Energy provides competitive retail electricity supply services by entering into power supply contracts to supply electricity to its end-use customers. Of the states that offer retail choice, Strategic Energy operates in California, Connecticut, Illinois, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. In addition to competitive retail electricity supply services, Strategic Energy also provides strategic planning, consulting and billing and scheduling services in the natural gas and electricity markets.
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| Strategic Energy provides services to approximately 109,000 commercial, institutional and small manufacturing accounts (for approximately 25,700 customers) including numerous Fortune 500 companies, smaller companies and governmental entities. Strategic Energy offers an array of products designed to meet the various requirements of a diverse customer base including fixed price, index-based and month-to-month renewal products. Strategic Energy's projected MWh deliveries for 2008 are in the range of 21 million to 25 million MWhs. Based solely on expected usage under current signed contracts, Strategic Energy has forecasted future MWh commitments (backlog) at December 31, 2007, of 18.5 million MWh, 9.0 million MWh and 5.6 million MWh for the years 2008 through 2010, respectively, and 3.5 million MWh over the years 2011 through 2012.
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| 10
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| Strategic Energy's revenues averaged approximately 58% of Great Plains Energy's revenues over the last three years. Strategic Energy's net income (loss) accounted for approximately 24%, (8)% and 17%
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| of Great Plains Energy's income from continuing operations in 2007, 2006, and 2005, respectively.
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| Strategic Energy's growth objective is to continue to expand in retail choice states and to increase its share of the market opportunity. Strategic Energy's continued success is dependent on a number of industry and operational factors including, but not limited to, the ability to contract for wholesale MWhs to meet its customers' needs at prices that are competitive with the host utility territory rates and with current and/or future competitors, the ability to provide value-added customer services and the ability to attract and retain employees experienced in providing service in retail choice states.
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| Conduct Strategic Alternative Review of Strategic Energy Great Plains Energy has retained Merrill Lynch & Co. as financial advisor to assist in a review of strategic and structural alternatives for its Strategic Energy subsidiary. The alternatives may include, among others, continuation of Strategic Energy's current subsidiary status and business plans, joint ventures with strategic partners, acquisitions of similar businesses, or sales of part or all of Strategic Energy. There is no assurance regarding which of the foregoing alternatives, if any, will be selected, or the terms of any possible joint venture, acquisition or sale.
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| Power Supply Strategic Energy does not own generation, transmission or distribution facilities. Strategic Energy purchases electricity from power suppliers based on forecasted peak demand for its retail-customers.
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| Management believes it has adequate access to energy in the markets it serves.
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| Regulation Strategic Energy, as a participant in the wholesale electricity and transmission markets, is subject to FERC jurisdiction. Additionally, Strategic Energy is subject to regulation by state regulatory agencies in states where Strategic Energy is licensed to sell power. Each state has a public utility commission and rules related to retail choice. Each state's rules are distinct and may conflict. These rules do not restrict the amount Strategic Energy can charge for its services, but can have an impact on Strategic Energy's ability to compete in any jurisdiction.
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| Transmission In many markets, RTOs/Independent System Operators (ISOs) manage the power flows, maintain reliability and administer transmission access for the electric transmission grid in a defined region.
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| RTOs/ISOs coordinate and monitor communications among the generator, distributor and retail electricity provider. Additionally, RTOs/ISOs manage the real-time electricity supply and demand, and direct the energy flow. Through these activities, RTOs/ISOs maintain a reliable energy supply within their region.
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| As a competitive retail electricity supplier, Strategic Energy must register with each RTO/ISO in order to operate in the markets covered by their grids. Strategic Energy primarily engages with PJM Interconnection, LLC (PJM), New England RTO (formerly ISO-New England), California ISO, New York ISO, Electric Reliability Council of Texas (ERCOT) and the Midwest Independent Transmission System Operator, Inc. (MISO).
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| In some cases, RTOs/ISOs provide Strategic Energy with all or a combination of the data for billing, settlement, application of electricity rates and information regarding the imbalance of electricity supply.
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| In addition, they provide balancing energy services and ancillary services to Strategic Energy in the fulfillment of providing services to retail end users. Strategic Energy must go through a settlement process with each RTO/ISO in which the RTO/ISO compares scheduled power with actual meter usage during a given time period and adjusts the original costs charged to Strategic Energy through a revised settlement. All participants in the RTOs/ISOs have exposure to other market participants. In the event 11
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| of default by a market participant within the RTOs/ISOs, the uncollectible balance is generally allocated to the remaining participants in proportion to their load share.
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| RTOs/ISOs may continue to modify the market structure and mechanisms in an attempt to improve market efficiency. In addition,. existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to Strategic Energy's activities. These actions could have an effect on Strategic Energy's results of operations. Strategic Energy participates extensively, together with other market participants, in relevant RTO/ISO governance and regulatory issues.
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| Revenue Sufficiency Guarantee RSG charges are collected by MISO in order to compensate generators that are standing by to supply electricity when called upon by MISO. See Note 6 to the consolidated financial statements for further information regarding RSG.
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| Competition The principal elements of competition are price, service and product differentiation. Strategic Energy operates in several retail choice electricity markets. Strategic Energy has several competitors that operate in most or all of the same states in which it provides services to customers. Strategic Energy also faces competition in certain markets from regional suppliers and deregulated utility affiliates formed by holding companies affiliated with regulated utilities to provide retail load in their home market territories. Strategic Energy's competitors vary in size from small companies to large corporations, some of which have significantly greater financial, marketing, and procurement resources than Strategic Energy. Additionally, Strategic Energy, as well as its other competitors, must compete with the host utility in order to convince customers to switch from the host utility. There is a regulatory lag in several RTOs/ISOs that slows the adjustment of host public utility rates in response to changes in wholesale prices, which may negatively affect Strategic Energy's ability to compete in a rising wholesale price environment.
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| GREAT PLAINS ENERGY AND CONSOLIDATED KCP&L EMPLOYEES At December 31, 2007, Great Plains Energy had 2,504 employees. Consolidated KCP&L had 2,166 employees, including 1,346 represented by three local unions of the International Brotherhood of Electrical Workers (IBEW), KCP&L has labor agreements with Local 1613, representing clerical employees (expires March 31, 2008), with Local 1464, representing transmission and distribution workers (expires January 31, 2009), and with Local 412, representing power plant workers (expires February 28, 2010).
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| 12
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| Executive Officers All of the individuals in the following table have been officers or employees in a responsible position with the Company for the past five years except as noted in the footnotes. The term of office of each officer commences with his or her appointment by the Board of Directors and ends at such time as the Board of Directors may determine. There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.
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| Year First Assumed an Officer Name Age Current Position(s) Position Michael J. Chesser (a) 59 Chairman of the Board and Chief Executive Officer - 2003 Great Plains Energy and Chairman of the Board -
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| KCP&L William H. Downey (b) 63 President and Chief Operating Officer.- Great Plains 2000 Energy and President and Chief Executive Officer -
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| KCP&L Terry Bassham (c) 47 Executive Vice President - Finance and Strategic 2005 Development and Chief Financial Officer - Great Plains Energy and Chief Financial Officer - KCP&L Barbara B. Curry (d) 53 Senior Vice President - Corporate Services and 2005 Corporate Secretary - Great Plains Energy and Corporate Secretary - KCP&L Michael L. Deggendorf (e) 46 Vice President - Public Affairs - Great Plains Energy 2005 Stephen T. Easley ) 52 Senior Vice President - Supply - KCP&L 2000 Shahid Malik (g) 47 Executive Vice President - Great Plains Energy 2004 President and Chief Executive Officer - Strategic Energy John R. Marshall (h) 58 Senior Vice President - Delivery - KCP&L 2005 Lori A. Wright 45 Controller - Great Plains Energy and Controller - 2002 KCP&L (a) Mr. Chesser was previously Chief Executive Officer of United Water (2002-2003).
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| (b) Mr. Downey was previously Executive Vice President of Great Plains Energy (2001-2003).
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| (c) Mr. Bassham was previously Executive Vice President, Chief Financial and Administrative Officer (2001-2005) of El Paso Electric Company.
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| (d) Ms. Curry was previously Senior Vice President, Retail Operations (2003-2004) and Executive Vice President, Global Human Resources (2001-2003) of TXU Corporation.
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| (e) Mr. Deggendorf was previously Senior Director, Energy Solutions of KCP&L (2002-2005).
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| ) Mr. Easley was previously Vice President, Generation Services (2002-2005).
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| (g) Mr. Malik was previously a partner of Sirius Solutions LLP, a consulting company, (2002-2004) and was appointed as President and Chief Executive Officer of Strategic Energy effective November 10, 2004 and Executive Vice President of Great Plains Energy effective January 1, 2006.
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| (h) Mr. Marshall was previously President of Coastal Partners, Inc., a strategy consulting company (2001-2005),
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| and Senior Vice President, Customer Service of Tennessee Valley Authority (2002-2004).
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| 13
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| Available Information Great Plains Energy's website is www.-qreatplainsenercqy.com and KCP&L's website is www.kcpl.com.
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| Information contained on the companies' websites is not incorporated herein. Both companies make available, free of charge, on or through their websites, their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act as soon as reasonably practicable after the companies electronically file such material with, or furnish it to, the SEC. In addition, the companies make available on or through their websites all other reports, notifications and certifications filed electronically with the SEC.
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| The public may read and copy any materials that the companies file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC, 20549. For information on the operation of the Public Reference Room, please call the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site at http://www.sec.,ov that contains reports, proxy statements and other information regarding the companies.
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| ITEM 1A. RISK FACTORS Actual results in future periods for Great Plains Energy and consolidated KCP&L could differ materially from historical results and the forward-looking statements contained in this report. Factors that might cause or contribute to such differences include, but are not limited to, those discussed below. The companies' business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the companies' control. Additional risks and uncertainties not presently known or that the companies' management currently believes to be immaterial may also adversely affect the companies. The risk factors described below, as well as the other information included in this Annual Report and in the other documents filed with the SEC, should be carefully considered before making an investment in the Company's securities. Risk factors of consolidated KCP&L are also risk factors for Great Plains Energy.
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| The Company is subject to complex utility and environmental regulation that could adversely affect its operations.
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| The Company is subject to, or affected by, extensive federal and state utility regulation, as described below. The Company must also comply with environmental legislation and associated regulations. In the Company's business planning and management of operations, it must address the effects of existing and proposed regulation on its businesses and changes in the regulatory framework, including initiatives by federal and state legislatures, regional transmission organizations, utility regulators and taxing authorities. Failure to obtain adequate rates or regulatory approvals, in a timely manner, adoption of new regulations by federal or state agencies, or changes to current regulations and interpretations of such regulations may materially affect the Company's business and its results of operations, financial position and cash flows.
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| The outcome of KCP&L's retail rate proceedings could have a materialimpact on its business and is largely outside its control.
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| The rates that KCP&L is allowed to charge its customers are the single most important item influencing its results of operations, financial position and liquidity. These rates are subject to the determination, in large part, of governmental entities outside of KCP&L's control, including the MPSC, KCC and FERC.
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| KCP&L also is exposed to cost-recovery shortfalls due to the inherent lag in the rate-setting process, especially during periods of significant cost inflation. A reduction or rejection by the MPSC or KCC of rate increase requests reflecting the costs of projects under the Comprehensive Energy Plan or Collaboration Agreement, which are discussed below, or other costs and expenses, could lead to lowered credit ratings, reduced access to capital markets, increased financing costs, lower flexibility due to constrained financial resources and collateral security requirements.
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| 14
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| As a part of the Missouri and Kansas stipulations approved by the MPSC and KCC in 2005, KCP&L began implementation of its Comprehensive Energy Plan. Under the Comprehensive Energy Plan, KCP&L agreed to undertake certain projects, including building and owning a portion of latan No. 2, installing a new wind-powered generating facility, installing environmental upgrades to certain existing plants, infrastructure improvements and demand management, distributed generation, and customer efficiency and affordability programs. In March 2007, KCP&L entered into a Collaboration Agreement with the Sierra Club and Concerned Citizens of Platte County that provides for increases in KCP&L's wind generation capacity and energy efficiency initiatives, reductions in certain emission permit levels at its latan and LaCygne generating stations, and projects to offset certain carbon dioxide emissions.
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| Most, but not all, of these commitments are conditioned on regulatory approval. A reduction or rejection by the MPSC or KCC of rate increase requests reflecting the costs of projects under the Comprehensive Energy Plan or Collaboration Agreement would adversely affect KCP&L's results of operations, financial position, and cash flows, and the effect could be material.
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| The MPSC order approving an approximate $51 million increase in annual revenues effective January 1, 2007, was appealed in February 2007 to the Circuit Court of Cole'County, Missouri, by the Office of Public Counsel, Praxair, Inc., and Trigen-Kansas City Energy Corporation, seeking to set aside or remand the order to the MPSC. The court affirmed the MPSC's decision in December 2007 and this decision has been appealed by Trigen-Kansas City Energy Corporation. Although subject to the appeal, the MPSC order remains in effect pending the court's decision.
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| The KCP&L rate increase authorized by the MPSC of $35 million, effective January 1, 2008, may be appealed to the Missouri courts. Parties have until March 3, 2008, to appeal. If there is an appeal, it is possible that the MPSC order could be vacated and the proceedings remanded to the MPSC.
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| Management cannot predict or provide any assurances regarding the outcome of these proceedings.
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| In response to competitive, economic, political, legislative and regulatory pressures, KCP&L may be subject to rate moratoriums, rate refunds, limits on rate increases or rate reductions, including phase-in plans designed to spread the impact of rate increases over an extended period of time for the benefit of customers. Any or all of these could have a significant adverse effect on KCP&L's results of operations, financial position and cash flows.
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| Regulatory requirementsregardingKCP&L's utility operationsmay increase KCP&L's costs and may expose KCP&L to compliance penalties.
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| The MPSC and KCC have the authority to implement utility operational standards and requirements, such as vegetation management standards, facilities inspection requirements, and quality of service standards. The costs of new or modified operational standards and requirements could have an adverse effect on KCP&L's results of operations, financial position and cash flows, and could expose KCP&L to penalties if it does not meet these standards and requirements.
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| The ability of StrategicEnergy to compete in states offering retail choice may be materially affected by state regulationsand host public utility rates.
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| Strategic Energy is a participant in the wholesale electricity and transmission markets, and is subject to FERC regulation with respect to wholesale electricity sales and transmission matters. Additionally, Strategic Energy is subject to regulation by state regulatory agencies in states where it has retail customers. Each state has a public utility commission and rules related to retail choice. Each state's rules are distinct and may conflict. These rules do not restrict the amount Strategic Energy can charge for its services, but can have an impact on Strategic Energy's ability to compete in any jurisdiction.
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| Additionally, the timing and amount of changes in host public utility rates can materially affect Strategic Energy's results of operations, financial position and cash flows.
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| 15
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| Financial market disruptions and declines in the credit ratings of Great Plains Energy or KCP&L may increase financing costs or limit access to the credit markets, which may ,adversely affect liquidity and results.
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| KCP&L's capital requirements are expected to be substantial over the next several years as it implements its Comprehensive Energy Plan. The amount of credit support required for Strategic Energy operations varies with a number of factors, including the amount and price of power purchased for its customers. The amount of collateral or other credit support required under Strategic Energy and KCP&L power supply agreements is also dependent on credit ratings. If the proposed acquisition of Aquila occurs, the future capital requirements of Aquila will further increase the Company's overall capital requirements. The Company relies on access to both short-term money markets and long-term capital markets as significant sources of liquidity for capital requirements not satisfied 'by cash flows from operations. The Company also relies on the financial markets for credit support, such as letters of credit, to support Strategic Energy and KCP&L operations.
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| Great Plains Energy, KCP&L and certain of their securities are rated by Moody's Investors Service and Standard & Poor's. A decrease in these credit ratings would have an adverse impact on the Company's access to capital, its cost of funds, the amount of collateral required under power supply agreements and Great Plains Energy's ability to provide credit support for its subsidiaries. While management anticipates that Great Plains Energy, KCP&L and Aquila will be rated investment grade if the proposed acquisition of Aquila closes, Great Plains Energy and KCP&L credit ratings were negatively affected by the announcement of the proposed acquisition, and may be further negatively affected.
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| The recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased credit spreads, reduced access to the capital markets and actual or potential downgrades of municipal bond insurers and the bonds insured by those insurers, among other adverse matters. The interest rates on $257.0 million aggregate principal amount of KCP&L's EIRR bonds are periodically reset through auction processes. These auction rate bonds are supported by municipal bond insurance policies issued by either XL Capital Assurance, Inc. or Financial Guaranty Insurance Company. Both firms and the supported KCP&L auction rate bonds were downgraded by at least two rating agencies in January and February 2008. Concerns related to municipal bond insurers' credit have adversely affected the ordinary course of operation of auctions for these types of bonds. The interest rates set in recent auctions of KCP&L's auction rate bonds have been adversely affected by these concerns, and the adverse effects are expected to continue until the bonds are changed to another interest rate mode.
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| The Company's management believes that it will maintain sufficient access to the financial markets at a reasonable cost based upon current credit ratings and market conditions. However, changes in financial or other market conditions or credit ratings could adversely affect the Company's ability to access financial markets, increase borrowing costs, increase collateral or other credit support requirements, or impact the rate treatment provided to KCP&L, and therefore materially affect its results of operations, financial position and cash flows.
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| Great Plains Energy is subject to business and regulatory uncertainties as a result of the potential acquisition of Aquila, which could adversely affect its business.
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| On February 6, 2007, Great Plains Energy entered into definitive agreements under which it would acquire all the outstanding shares of Aquila. Immediately prior to this acquisition, Black Hills would acquire from Aquila its electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. These transactions are complex, remain subject to outstanding regulatory approvals and other conditions, and there is no assurance as to whether or when the transactions will be consummated.
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| While various regulatory approvals have been obtained, the approvals of the MPSC and KCC have not yet been obtained. The timing of, and the conditions imposed by, regulatory approvals may delay or 16
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| give rise to the ability to terminate the transactions. In the event of termination, Great Plains Energy would be required to write-off its deferredtransaction costs, which could be material. The conditions imposed by regulatory approvals could increase the costs, or decrease the benefits, anticipated by Great Plains Energy from the transaction.
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| Uncertainty about the effect of the merger on employees and customers may have an adverse effect on the Company. Although the Company has taken steps to reduce any adverse effects, these uncertainties could impair the Company's ability to attract, retain and motivate key personnel until the merger closes and for a period of time afterwards, and could cause customers, suppliers and others to seek to change existing business relationships.
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| The anticipated costs and benefits of the Aquila transaction may not be realized, which could adversely affect the Company's business and results of operations.
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| Great Plains Energy entered into the Aquila proposed transaction with the expectation that the acquisition would result in various benefits to it and KCP&L including, among other things, synergies, cost savings and operating efficiencies. Although Great Plains Energy expects to achieve the anticipated benefits of the acquisition, achieving them cannot be assured. The Company expects to incur significant costs relating to the acquisition of Aquila and its operational integration with KCP&L.
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| These costs may be significantly greater than the Company's estimates. Although the Company has requested to recover a portion of these costs through utility rates, there is no assurance regarding the recovery of these costs or other regulatory treatment of benefits or costs in rate cases occurring after the closing of the transaction.
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| The Company expects to achieve various benefits, including synergies, cost savings and operating efficiencies in connection with the proposed acquisition. Approximately half of the total estimated cost savings and synergies, over the first five years following the transaction are expected to come from reductions in Aquila's corporate overhead and other costs currently not being recovered through ,
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| Aquila's Missouri utility rates, and are not expected to be recovered through utility rates following the merger. If the Company is not able to eliminate these non-Missouri utility costs as anticipated, its results from operations will be negatively impacted.
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| Integration of Aquila and KCP&L utility operations following the transaction will pose significant challenges due to the size and complexity of each organization. The Company has dedicated substantial efforts and resources since the proposed transaction was announced to plan for an efficient and successful integration of utility operations. The Company believes that it will have the necessary employees to successfully operate the integrated utility operations after the transaction closes.
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| However, there is no assurance that the utility operations integration will be completed successfully or in a timely manner.
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| Most of the Aquila employees remaining after the sale to Black Hills are expected to become employees of KCP&L. KCP&L employees will operate and manage both KCP&L properties and Aquila's properties, and KCP&L will charge Aquila for the cost of these services. These expected arrangements may pose risks to KCP&L, including possible claims arising from actions of KCP&L employees in operating Aquila's properties and providing other services to Aquila. KCP&L's claims for reimbursement for services provided to Aquila will be unsecured and rank equally with other unsecured obligations of Aquila. KCP&L's ability to be reimbursed for the costs incurred for. the benefit of Aquila depends on the financial ability of Aquila to make such payments.
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| Additionally, Aquila's utility operations are subject to regulation by numerous government entities, including the MPSC and FERC. As such, a successful acquisition of Aquila Will subject Great Plains Energy to additional regulatory risk.
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| 17
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| The announced review of alternatives for Strategic Energy may cause business uncertainties, which could adversely affect the Company's results of operation.
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| Strategic Energy contributed 60% of the Company's consolidated revenues and 24% of the Company's consolidated net income in 2007. In November 2007, the Company announced that it was undertaking a review of strategic and structural alternatives for Strategic Energy. The alternatives may include, among others, continuation of Strategic Energy's current subsidiary status and business plans, joint ventures with strategic partners, acquisitions of similar businesses, or sales of part or all of Strategic Energy.
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| Uncertainty about the outcome of this review on Strategic Energy employees, suppliers and customers may have an adverse effect on the Company. Although the Company has taken steps to reduce any adverse effects, including employee retention agreements, these uncertainties could impair the Company's ability to attract, retain and motivate key personnel until the outcome of the review and for a period of time after, and could cause customers, suppliers and others to seek to terminate or change existing business relationships.
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| The Company is subject to current and potential environmental laws and the incurrence of environmental liabilities, any or all of which may adversely affect the Company's business and financial results.
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| The Company is subject to regulation by federal, state and local authorities with regard to air quality and other environmental matters, primarily through KCP&L's operations. The generation, transmission and distribution of electricity produces and requires disposal of certain hazardous products, which are subject to these laws and regulations. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. Failure to comply with these laws and regulations could have a material adverse effect on Great Plains Energy's and consolidated KCP&L's results of operations, financial position and cash flows.
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| KCP&L currently projects a range of capital expenditures of $1.0 billion to $1.6 billion (KCP&L's share of jointly owned units) over an approximate ten year period to comply with environmental requirements regarding SO 2 , NOx, mercury and particulate emissions that will take effect during that period. The actual cost and the timing of such expenditures may be materially different than these estimates due to the risks described in this risk factor and in the risk factor regarding construction risks.
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| There is also a risk of new environmental laws and regulations, and judicial interpretations of environmental laws and regulations, affecting KCP&L's operations. In particular, various stakeholders, including legislators, regulators, shareholders and non-governmental organizations, as well as utilities and other companies in many business sectors, are considering ways to address climate change.
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| These include regulation of carbon dioxide and other greenhouse gas emissions and efforts to encourage or mandate the use of renewable resources, energy efficiency and demand response management. Federal and/or state legislation or regulation to reduce greenhouse gas emissions may be enacted in the near future. The Kansas Department of Health and Environment has indicated that it intends to engage industries and stakeholders to establish goals for reducing CO 2 emissions and strategies to achieve those goals. KCP&L's current generation capacity is primarily coal-fired, and is estimated to produce about one ton of CO 2 per MWh, or approximately 17 million tons per year. Efforts to reduce greenhouse gas emissions may cause the Company to incur material costs to reduce the greenhouse gas emissions from its operations (through additional environmental control equipment, retiring and replacing existing generation, or selecting more costly generation alternatives), procure emission allowance credits, or incur taxes, fees or other governmental impositions on account of such emissions. Another area of law that is in a state of flux is the rules governing emissions of mercury.
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| Rules issued by the Environmental Protection Agency (EPA) were overturned in February 2008, and it is unclear what standards will be imposed in the future, or when we may have to comply with any new 18
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| standards. KCP&L's proposed capital expenditures reflect estimated costs to comply with the overturned rule, and compliance with any new standards is likely to result in the incurrence of increased costs, although at this point there is insufficient information to estimate those costs. Other new environmental laws and regulations affecting KCP&L's operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to KCP&L or its facilities, any of which may adversely affect the Company's business and substantially increase its environmental expenditures in the future.
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| New facilities, or modifications of existing facilities, may require new environmental permits or amendments to existing permits. Delays in the environmental permitting process, denials of permit applications, conditions imposed in permits and the associated uncertainty may materially affect the cost and timing of the environmental retrofit projects included in the Comprehensive Energy Plan, among other projects, and thus materially affect KCP&L's results of operations, financial position and cash flows.
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| Under current law, KCP&L is also generally responsible for any on-site liabilities associated with the environmental condition of its facilities, including those that it has previously owned or operated, regardless of whether the liabilities arose before, during or after the time it owned or operated the facilities. KCP&L may not be able to recover all of its costs for environmental expenditures through rates in the future. The incurrence of material environmental costs or liabilities, without related rate recovery, could have a material adverse effect on KCP&L's results of operations, financial position and cash flows. See Note 13 to the consolidated financial statements for additional information regarding environmental matters.
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| The Federal Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to reduce emissions when making a major modification or a change in operation of an existing facility if either is expected to cause a significant net increase in regulated emissions. The Sierra Club and Concerned Citizens of Platte County have claimed that modifications were made to latan No. 1 in violation of Clean Air Act regulations. Although KCP&L has entered into a Collaboration Agreement with those parties that provides, among other things, for the release of such claims, the Collaboration Agreement does not bind any other entity. KCP&L is aware of subpoenas issued by a Federal grand jury to certain third parties seeking documents relating to capital projects at latan No. 1.
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| KCP&L has not received a subpoena, and has not been informed of the scope of the grand jury inquiry.
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| The ultimate outcome of these grand jury activities cannot presently be determined, nor can the costs and other liabilities that could potentially result from a negative outcome presently be reasonably estimated. Failure to recover such costs through rates could have a material adverse effect on Great Plains Energy's and consolidated KCP&L's results of operations, financial position and cash flows.
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| The inability of Great Plains Energy's subsidiaries to provide sufficient dividends to allow Great Plains Energy to pay dividends to its shareholders and meet its financial obligations would have an adverse effect.
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| Great Plains Energy is a holding.company with no significant operations of its own. The primary source of funds for payment of dividends to its shareholders and its financial obligations is dividends paid to it by its subsidiaries, particularly KCP&L. KCP&L has committed to its state regulatory commissions to maintain a 35% equity to total capitalization ratio, and has similar covenants in its revolving credit facility. Strategic Energy also has financial covenants in its financing arrangements. The ability of Great Plains Energy's subsidiaries to pay dividends or make other distributions, and accordingly Great Plains Energy's ability to pay dividends on its common stock and meet its financial obligations, principally depends on the actual and projected earnings and cash flow, capital requirements and general financial position of its subsidiaries, as well as on regulatory factors, financial covenants, general business conditions and other matters.
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| 19
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| Changes in customer demand, due to sustained downturns or sluggishness in the economy and weather conditions may adversely affect KCP&L's and Strategic Energy's business and financial results.
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| The results of operations of KCP&L and Strategic Energy can be materially affected by changes in weather and customer demand. KCP&L and Strategic Energy estimate customer demand based on historical trends, to procure fuel and purchased power. Sustained downturns or sluggishness in the economy generally affects the markets in which KCP&L and Strategic Energy operate. Declines in economic conditions may reduce overall electricity sales and/or increase bad debt expense, which could materially affect KCP&L's and Strategic Energy's results of operations and cash flows.
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| Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. In addition, severe weather, including but not limited to extreme heat or cold, tornados, snow, rain, floods and ice storms can be destructive causing outages and property damage that can potentially result in additional expenses and lower revenues. KCP&L's latan and Hawthorn stations use water from the Missouri River for cooling purposes. Low water and flow levels, which have been experienced in recent years, can increase KCP&L's maintenance costs at these stations and, if these levels were to get low enough, could cause KCP&L to modify plant operations and/or install additional equipment.
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| The use of derivative contracts in the normal course of business could result in financial losses that could negatively impact Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.
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| Great Plains Energy, KCP&L and Strategic Energy use derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial risks. Financial losses could be recognized as a result of volatility in the market values of these contracts, if a counterparty fails to perform, or if the underlying transactions which the derivative instruments are intended to hedge fail to materialize. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
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| Changes in commodity prices could have an adverse effect on the Company's business and financial condition.
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| KCP&L and Strategic Energy engage in the wholesale and retail marketing of electricity and are exposed to risks associated with the price of electricity. Strategic Energy routinely enters into contracts to purchase and sell electricity in the normal course of business. KCP&L generates, purchases and sells electricity in the retail and wholesale markets. To the extent that exposure to the price of electricity is not hedged, the Company could experience losses associated with the changing market price for electricity.
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| Increases in fuel and transportationprices could have an adverse impact on KCP&L's costs.
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| New Kansas retail rates effective January 1, 2008, contain an ECA tariff. KCP&L's Missouri retail rates do not contain a similar provision. Missouri retail rates reflect a set level of non-firm wholesale electric sales margin. KCP&L will not recover any shortfall in non-firm wholesale electric sales margin, but any amount above the level reflected in Missouri retail rates will be returned to retail customers in a future rate case. This exposes KCP&L to risk from changes in the market prices of coal, natural gas, nuclear fuel and purchased power. Changes in KCP&L's fuel mix due to electricity demand, plant availability, transportation issues, fuel prices, fuel availability and other factors can also adversely affect KCP&L's fuel and purchased power costs.
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| 20
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| KCP&L does not hedge its entire exposure from fuel and transportation price volatility. Forward prices for coal have increased, principally due to international demand, and management expects prices will continue to increase. Management also expects its cost of nuclear fuel to increase significantly from 2009 through 2018. Consequently, its results of operations and financial position may be materially impacted by changes in these prices until increased costs are recovered in Missouri retail rates.
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| Wholesale electricityprices affect costs and revenues, creatingearnings volatility.
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| KCP&L's level of wholesale sales depends on the wholesale market price, transmission availability and the availability of KCP&L's generation for wholesale sales, among other factors. A substantial portion of KCP&L's wholesale sales are made in the spot market, and thus KCP&L has immediate exposure to wholesale price changes. KCP&L is also exposed to price risk because at times it purchases power to meet its customers' needs. The cost of these purchases may be affected by the timing of customer demand and/or unavailability of KCP&L's lower-priced generating units. Wholesale power prices can be volatile and generally increase in times of high regional demand and high natural gas prices. While an allocated portion of wholesale purchases and sales are reflected in KCP&L's Kansas ECA, KCP&L's Missouri rates are set on an estimated amount of wholesale sales and purchases. KCP&L will not recover any shortfall in non-firm wholesale electric sales margin, but any amount above the level reflected in Missouri retail rates will be returned to retail customers in a future rate case. Declines in wholesale market price or availability of generation or transmission constraints in the wholesale markets could reduce KCP&L's wholesale sales and adversely affect KCP&L's results of operations and financial position.
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| Strategic Energy operates in competitive retail electricity markets, competing against the host utilities and other retail suppliers. Wholesale electricity costs, which account for a significant portion of its operating expenses, can materially affect Strategic Energy's ability to attract and retain retail electricity customers. There is also a regulatory lag that slows the adjustment of host public utility rates in response to changes in wholesale prices. This lag can negatively affect Strategic Energy's ability to compete in a rising wholesale price environment. Strategic Energy manages wholesale electricity risk by establishing risk limits and entering into contracts to offset some of its positions to balance energy supply and demand; however, Strategic Energy does not exactly match hedges to its aggregate exposure. This imbalance position leaves Strategic Energy subject to the effects of electricity price volatility. Consequently, its results of operations and financial position may be materially impacted by changes in the wholesale price of electricity.
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| Operations risks may adversely affect the Company's business and financial results.
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| The operation of KCP&L's electric generation, transmission and distribution systems involves many risks, including breakdown or failure of equipment or processes; operating limitations that may be imposed by equipment conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling; and catastrophic events such as fires, explosions, severe weather or other similar occurrences. With the exception of Hawthorn No. 5, which was substantially rebuilt in 2001, all of KCP&L's coal-fired generating units and its nuclear generating unit were constructed prior to 1986. The age of these generating units increases the risk of unplanned outages and higher maintenance expense. KCP&L has implemented training, preventive maintenance and other programs, but there is no assurance that these programs will prevent or minimize future breakdowns or failures of KCP&L's facilities.
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| KCP&L currently has general liability and property insurance in place to cover its facilities in amounts that management considers appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of KCP&L's facilities may not be sufficient to restore the loss or damage.
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| 21
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| These and other operating events may reduce KCP&L's revenues, increase its costs, or both, and may materially affect KCP&L's results of operations, financial position and cash flows.
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| The cost and schedule of KCP&L's construction projects may materially change.
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| KCP&L's Comprehensive Energy Plan includes the construction of an estimated 850 MW coal-fired generating plant and environmental retrofits at two existing coal-fired units. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability or increased cost of qualified craft labor, the scope and timing of projects may change, and other events beyond KCP&L's control may occur that may materially affect the schedule, budget and performance of these projects.
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| The construction projects contemplated in the Comprehensive Energy Plan rely upon the supply of a significant percentage of materials from overseas sources. This global procurement subjects the delivery of procured material to issues beyond what would be expected if such material were supplied from sources within the United States. These risks include, but are not limited to, delays in clearing customs, ocean transportation, currency exchange rates and potential civil unrest in sourcing countries, among others.
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| The demand for environmental projects, similar to those in the Comprehensive Energy Plan, has increased substantially with many utilities in the United States starting similar projects to address changing environmental regulations. This demand has constrained labor and material resources for such projects, and there is a risk that such constraints may increase.
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| These and other risks could materially increase the estimated costs of these construction projects, delay the in-service dates of these projects, adversely affect the performance of the projects, and/or require KCP&L to purchase additional electricity to supply its retail customers until the projects are completed. KCP&L is not permitted to start recovering the costs of these projects until they are completed and put into service. Thus, these risks may materially affect KCP&L's results of operations, financial position and cash flows.
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| The anticipated acquisition of Aquila will increase Great Plains Energy's ownership of latan Nos. 1 and
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| : 2. Aquila owns 18% of both latan generating units. Great Plains Energy's post-acquisition ownership percentages of the latan generating units would be 88% of latan No. 1 and 72.71% of latan No. 2, which would expose the Company to greater risks associated with the ongoing latan construction projects.
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| Failure of one or more generation plant co-owners to pay their share of construction, operations and maintenance costs could increase KCP&L's costs and capital requirements.
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| KCP&L owns 47% of Wolf Creek, 50% of LaCygne Station, 70% of latan No. 1 and 55% of latan No. 2.
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| The remaining portions of these facilities are owned by other utilities that are contractually obligated to pay their proportionate share of capital and other costs and, in the case of latan No. 2, construction costs.
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| While the ownership agreements provide that a defaulting co-owner's share of the electricity generated can be sold by the non-defaulting co-owners, there is no assurance that the revenues received will recover the increased costs borne by the non-defaulting co-owners. The latan No. 2 co-owners have provided financial assurances related to their respective construction cost obligations, but there is a risk that such assurances may not be sufficient in the event of a co-owner default. During the construction period, the latan No. 2 agreements provide for re-allocations of part or all of a defaulting co-owner's share of the facility to the non-defaulting owners, which would increase the capital requirements, operations and maintenance costs of the non-defaulting owners. Occurrence of these or other events could materially increase KCP&L's costs and capital requirements.
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| 22
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| An aging workforce and increasing demand for skilled craft labor poses operational and planning challenges to KCP&L.
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| Through 2011, approximately 22% of KCP&L's current employees will be eligible to retire with full pension benefits. This is a general industry issue, which has increased the demand for and cost of skilled craft labor for both companies and contractors. KCP&L uses contractors for a substantial portion of its construction and maintenance work. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect KCP&L's ability to manage and operate its business.
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| Substantially all of KCP&L's employees participate in defined benefit and post-retirement plans. If KCP&L employees retire when they become eligible for retirement through 2011, or if KCP&L's plans experience adverse market returns on investments, or if interest rates materially fall, KCP&L's contributions to the plans could rise substantially over historical levels. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on KCP&L's results of operations, financial position and cash flows.
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| The Pension Protection Act of 2006 alters the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions and changes the timing of required contributions to underfunded plans. The funding rules, which became effective in 2008, could -
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| significantly affect the Company's funding requirements. In addition, the Financial Accounting Standards Board (FASB) has a project to reconsider the accounting for pensions and other post-retirement benefits. This project may result in accelerated expense.
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| KCP&L is exposed to risks associated with the ownership and operation of a nuclear generating unit, which could result in an adverse effect on the Company's and KCP&L's business and financial results.
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| KCP&L owns 47% (545 MW) of Wolf Creek. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including Wolf Creek. In the event of non-compliance, the NRC has the authority to impose fines, shut down the facilities, or both, depending Upon its assessment of the severity of the situation, until compliance is achieved. Any revised safety requirements promulgated by the NRC could result in substantial capital expenditures at Wolf Creek.
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| Wolf Creek has the lowest fuel cost per MWh of any of KCP&L's generating units. Although not expected, an extended outage of Wolf Creek, whether resulting from NRC action, an incident at the plant or otherwise, could have a substantial adverse effect on KCP&L's results of operations and financial position in the event KCP&L incurs higher replacement power and other costs that are not recovered through rates. If a long-term outage occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base.
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| Ownership and operation of a nuclear generating unit exposes KCP&L to risks regarding decommissioning costs at the end of the unit's life. KCP&L contributes annually to a tax-qualified trust fund to be used to decommission Wolf Creek. The funding level assumes a projected level of return on trust assets. If the actual return on trust assets is below the anticipated level, KCP&L could be responsible for the balance of funds required; however, should this happen, management believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the unit.
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| 23
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| KCP&L is also exposed to other risks associated with the ownership and operation of a nuclear generating unit, including, but not limited to, potential liability associated with the potential harmful effects on the environment and human health resulting from the operation of a nuclear generating unit and the storage, handling and disposal of radioactive materials, and to potential retrospective assessments and losses in excess of insurance coverage.
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| KCP&L's participation in the SPP could increase costs, reduce revenues, and reduce KCP&L's control over its transmission assets.
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| Functional control of the KCP&L transmission systems was transferred to the SPP during the third quarter of 2006. KCP&L may be required to incur expenses or expand its transmission systems, which it would seek recovery for through rate increases, according to decisions made by the SPP rather than according to its internal planning process.
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| The sale of power in the SPP Energy Imbalance Service (EIS) Market may result in unanticipated transmission congestion and other settlement charges. There is also uncertainty regarding the impact of ongoing RTO developments at FERC. KCP&L is unable to predict the impact these issues could have on its results of operations and financial position.
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| Strategic Energy operates in competitive retail electricity markets, which could impact financial results.
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| Strategic Energy has several competitors that operate in most or all of the same states in which it serves customers. It also faces competition in certain markets from regional suppliers and deregulated utility affiliates formed by holding companies affiliated with regulated utilities to provide retail load in their home market territories. Strategic Energy's competitors vary in size from small companies to large corporations, some of which have significantly greater financial, marketing and procurement resources than Strategic Energy. Additionally, Strategic Energy must compete with the host utility in order to convince customers to switch from the host utility to Strategic Energy as their electric service provider.
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| Strategic Energy's results of operations and financial position are impacted by the success Strategic Energy has in attracting and retaining customers in these markets.
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| Strategic Energy supplier and customer credit risk may adversely affect financial results.
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| Strategic Energy has credit risk exposure in the form of the loss that it could incur if a counterparty failed to perform under its contractual obligations. Strategic Energy has two types of counterparty risk -
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| supplier risk and customer risk. Strategic Energy enters into forward contracts with multiple suppliers.
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| In the event of supplier non-delivery or default, Strategic Energy's results of operations may be affected to the extent the cost of replacement power exceeded the combination of the contracted price with the supplier and the amount of collateral held by Strategic Energy to mitigate its credit risk with the supplier.
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| Strategic Energy's results of operations may also be affected, in a given period, if it were required to make a payment upon termination of a supplier contract to the extent the contracted price with the supplier exceeded the market value of the contract at the time of termination. Strategic Energy has also experienced an increase in customer bad debt expense, primarily related to its small business customer segment. Strategic Energy has taken steps to address this exposure, but there can be no assurance that bad debt expense will be reduced. Failure of suppliers or customers to perform their obligations may adversely affect results of operations.
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| The outcome of legal proceedings cannot be predicted. An adverse finding could have a material adverse effect on Great Plains Energy's and KCP&L's financial condition.
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| Great Plains Energy and KCP&L are party to various material litigation and regulatory matters arising out of their business operations. The ultimate outcome of these matters cannot presently be determined, nor, in many cases, can the liability that could potentially result from a negative outcome in each case presently be reasonably estimated. The liability that Great Plains Energy and KCP&L may ultimately incur with respect to any of these cases in the event of a negative outcome may be in excess 24
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| of amounts currently reserved and insured against with respect to such matters and, as a result, these matters may have a material adverse effect on the consolidated financial position of Great Plains Energy, KCP&L or both. See Notes 2, 6, 13 and 15 to the consolidated financial statements for further information regarding legal proceedings.
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| ITEMIlB. UNRESOLVED STAFF COMMENTS None.
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| ITEM 2. PROPERTIES KCP&L Generation Resources Year Estimated 2008 Primary Unit Completed MW Capacity Fuel Base Load* Wolf Creek 1985 545 (a) Nuclear latan No. 1 1980 456 (a)(b) Coal LaCygne No. 2 1977 341 (a) Coal LaCygne No. 1 1973 368 (a) Coal Hawthorn No. 5 (6) 1969 563- Coal Montrose No. 3 1964 176 Coal Montrose No. 2 1960 164 Coal Montrose No. 1 1958 170 Coal Peak Load West Gardner Nos. 1, 2, 3 and 4 (d) 2003 308 Natural Gas Osawatomie (d) 2003 76 Natural Gas Hawthorn No. 9 (e) 2000 130 Natural Gas Hawthorn No. 8 (d) 2000 76 Natural Gas Hawthorn No. 7 (d) 2000 75 Natural Gas Hawthorn No. 6 (d) 1997 136 Natural Gas Northeast Nos. 17 and 18 (e) 1977 117 Oil Northeast Nos. 15 and 16 (e) 1975 116 Oil Northeast Nos. 13 and 14 (e) 1976 114 Oil Northeast Nos. 11 and 12 (e) 1972 100 Oil Northeast Black Start Unit 1985 2 Oil Wind Spearville Wind Energy Facility (f) 2006 15" Wind Total 4,048 (a) KCP&L's share ofajointlyowned unit.
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| (b) The latan No. 2 air permit limits KCP&L's accredited capacityof latan No. 1 to 456 MWs from 46.9 MWs until the air quality control equipment included in the Comprehensive Energy Plan is operational, which is expected in the fourth quarter of 2008.
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| (c) The Hawthorn Generating Station returned to commercial operation in 2001 with a new boiler, air quality control equipment and an uprated turbine following a 1999 explosion.
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| (d) Combustion turbines.
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| (e) Heat Recovery Steam Generator portion of combined cycle.
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| ( The 100.5 MW Spearville Wind Energy Facility's accredited capacity is 15 MW pursuant to-SPP reliability standards.
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| 25
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| KCP&L owns the Hawthorn Station (Jackson County, Missouri), Montrose Station (Henry County, Missouri), Northeast Station (Jackson County, Missouri), West Gardner Station (Johnson County, Kansas), Osawatomie Station (Miami County, Kansas) and Spearville Wind Energy Facility (Ford County, Kansas). KCP&L also owns 50% of the 736 MW LaCygne No. I and 682 MW LaCygne No. 2 (Linn County, Kansas), 70% of the 651 MW latan No. 1 (Platte County, Missouri) and 47% of the 1,160 MW Wolf Creek Unit (Coffey County, Kansas). See Note 6 to the consolidated financial statements for information regarding KCP&L's Comprehensive Energy Plan and the construction of new generation capacity.
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| KCP&L Transmission and Distribution Resources KCP&L's electric transmission system interconnects with systems of other utilities for reliability and to permit wholesale transactions with other electricity suppliers. KCP&L owns over 1,700 miles of transmission lines, approximately 9,000 miles of overhead distribution lines and over 3,900 miles of underground distribution lines in Missouri and Kansas. KCP&L has all the franchises necessary to sell electricity within its retail service territory. KCP&L's transmission and distribution systems are continuously monitored for adequacy to meet customer needs. Management believes the current systems are adequate to serve its customers.
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| KCP&L General KCP&L's principal plants and properties, insofar as they constitute real estate, are owned in fee simple except for the Spearville Wind Energy Facility, which is on land held under easements. Certain other facilities are located on premises held under leases, permits or easements. KCP&L electric transmission and distribution systems are for the most part located over or under highways, streets, other public places or property owned by others for which permits, grants, easements or licenses (deemed satisfactory but without examination of underlying land titles) have been obtained.
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| Substantially all of the fixed property and franchises of KCP&L, which consist principally of electric generating stations, electric transmission and distribution lines and systems, and buildings (subject to exceptions, reservations and releases), are subject to a General Mortgage Indenture and Deed of Trust dated as of December 1, 1986. General mortgage bonds totaling $158.8 million were outstanding at December 31, 2007.
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| ITEM 3. LEGAL PROCEEDINGS Other Proceedings The companies are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Notes 2, 6, 13 and 15 to the consolidated financial statements. Such descriptions are incorporated herein by reference.
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| ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Great Plains Energy Great Plains Energy held a special meeting of its common stock shareholders on October 10, 2007, to vote on the proposal to approve the issuance of shares of Great Plains Energy Incorporated common stock as contemplated by the Agreement and Plan of Merger, dated as of February 6, 2007, by and among Aquila, Great Plains Energy, Gregory Acquisition Corp. and Black Hills. The proposal was approved by the following vote:
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| Votes For Votes A-qainst Abstentions 55,362,672 1,574,331 571,219 26
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| Also at the meeting, shareholders voted on the proposal to approve the authority of the proxy holders to vote in favor of a motion to adjourn the meeting for the purpose of soliciting additional proxies. The proposal was approved by the following vote:
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| Votes For Votes Against Abstentions 53,081,961 3,641,183 785,077 KCP&L During the fourth quarter of 2007, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise for KCP&L.
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| PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES GREAT PLAINS ENERGY Great Plains Energy common stock is listed on the New York Stock Exchange under the symbol GXP.
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| At February 21, 2008, Great Plains Energy's common stock was held by 12,523 shareholders of record.
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| Information relating to market prices and cash dividends on Great Plains Energy's common stock is set forth in the following table.
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| Common Stock Price Range Common Stock 2007 2006 Dividends Declared Quarter High Low High Low 2008 2007 2006 First $ 32.67 $ 30.42 $ 29.32 $ 27.89 $ 0.415 (a) $ 0.415 $ 0.415 Second 33.18 28.82 28.99 27.33 0.415 0.415 Third 29.94 26.99 31.43 27.70 0.415 0.415 Fourth 30.45 28.32 32.80 31.13 0.415 0.415 (a)Declared February 5, 2008.
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| Regulatory Restrictions Under stipulations with the MPSC and KCC, Great Plains Energy has committed to maintain consolidated common equity of not less than 30% of total capitalization.
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| Dividend Restrictions Great Plains Energy's Articles of Incorporation contain certain restrictions on the payment of dividends on Great Plains Energy's common stock in the event common equity falls to 25% of total capitalization.
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| If preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect members to the Board of Directors.
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| 27
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| Equity Compensation Plan The Company's Long-Term Incentive Plan is an equity compensation plan approved by its shareholders. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of the Company and KCP&L. The following table provides information, as of December 31,.2007, regarding the number of common shares to be issued upon exercise of outstanding options, warrants and rights, their weighted average exercise price, and the number of shares of common stock remaining available for future issuance under the Long-Term Incentive Plan. The table excludes shares issued or issuable under Great Plains Energy's defined contribution savings plans.
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| Number of securities remaining available for future issuance Number of securities to Weighted-average under equity be issued upon exercise exercise price of compensation plans of outstanding options, outstanding options, (excluding securities warrants and rights warrants and rights reflected in column (a))
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| Plan Category (a) (b) (c)
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| Equity compensation plans approved by security holders 419,161 (1) $ 25.52 (2) 3,439,157 Equity compensation plans not approved by security holders -
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| Total 419,161 $ 25.52 3,439,157 (1) Includes 309,689 performance shares at target performance levels and options for 109,472 shares of Great Plains Energy common stock outstandingat December 31, 2007.
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| (2) The 309,689 performance shares have no exercise price and therefore are not reflected in the weighted average exercise price.
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| Purchases of Equity Securities The following table provides information regarding purchases by the Company of its equity securities during the fourth quarter of 2007.
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| Issuer Purchases of Equity Securities Maximum Number Total Number of (or Approximate Shares (or Units) Dollar Value) of Total Purchased as Shares (or Units)
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| Number of Average Part of Publicly that May Yet Be Shares Price Paid Announced Purchased Under (or Units) per Share Plans or the Plans or Month Purchased (or Unit) Programs Programs October 1 - 31 11,316 (1) $28.94 N/A November 1 - 30 2,148 (1) 30.14 N/A December 1 - 31 - - N/A Total 13,464 $29.13 N/A (1) Represents shares of common stock surrendered to the Company by certain officers to paytaxes related to the vesting of restricted com mon stock.
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| 28
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| KCP&L KCP&L is a wholly owned subsidiary of Great Plains Energy, which holds the one share of issued and outstanding KCP&L common stock.
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| Regulatory Restrictions Under the Federal Power Act, KCP&L can pay dividends only out of retained or current earnings.
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| Under stipulations with the MPSC and KCC, KCP&L has committed to maintain consolidated common equity of not less than 35% of total capitalization.
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| Equity Compensation Plan KCP&L does not have an equity compensation plan; however, KCP&L officers participate in Great Plains Energy's Long-Term Incentive Plan.
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| ITEM 6. SELECTED FINANCIAL DATA Year Ended December 31 2007 2006 2005 2004 2003 Great Plains Energy (a) (dollars in millions except per share amounts)
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| Operating revenues $ 3,267 $ 2,675 $ 2,605 $ .2,464 $ 2,148 Income from continuing operations (b) $ 159 $ 128 $ 164 $ 175 $ 189 Net income $ 159 $ 128 $ 162 $ 183 $ 144 Basic earnings percommon share from continuing operations $ 1.86 $ 1.62 $ 2.18 $ 2.41 $ 2.71 Basic earnings per common share $ 1.86 $ 1.62 $ 2.15 $ 2.51 $ 2.06 Diluted earnings per common share from continuing operations $ 1.85 $ 1.61 $ 2.18 $ 2.41 $ 2.71 Diluted earnings per common share $ 1.85 $ 1.61 $ 2.15 $ 2.51 $ 2.06 Total assets at year end $ 4,827 $ 4,336 $ 3,842 $ 3,796 $ 3,694 Total redeemable preferred stock, mandatorily redeemable preferred securities and long-term debt (including current maturities) $ 1,103 $ 1,142 $ 1,143 $ 1,296 $ 1,347 Cash dividends per common share $ 1.66 $ 1.66 $ 1.66 $ 1.66 $ 1.66 SEC ratio of earnings to fixed charges 3.08 3.20 3.60 3.54 4.22 Consolidated KCP&L (a)
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| Operating revenues $ 1,293 $ 1,140 $ 1,131 $ 1,092 $ 1,057 Income from continuing operations (c) $ 157 $ 149 $ 144 $ 145 $ 125 Net income $ 157 $ 149 $ 144 $ 145 $ 116 Total assets at year end $ 4,292 $ 3,859 $ 3,340 $ 3,335 $ 3,315 Total redeemable preferred stock, mandatorily redeemable preferred securities and long-term debt (including current. maturities) $ 1,003 $ 977 $ 976 $ 1,126 $ 1,336 SEC ratio of earnings to fixed charges 3.53 4.11 3.87 3.37 3.68 (a) Great Plains Energy's and KCP&L's consolidated financial statements include results for all subsidiaries in operation for the periods presented. .
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| (b) This amount is before discontinued operations of $(1.9) million, $7.3 million and $(44.8) million in 2005 through 2003, respectively.
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| (c) This amount is before discontinued operations of $(8.7) million in 2003.
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| 29
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| ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The MD&A that follows is a combined presentation for Great Plains Energy and consolidated KCP&L, both registrants under this filing. The discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of the registrants during the periods presented.
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| EXECUTIVE
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| ==SUMMARY==
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| Description of Business Great Plains Energy is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy's direct subsidiaries with operations or active subsidiaries are KCP&L, KLT Inc., IEC and Services. As a diversified energy company, Great Plains Energy's reportable business segments include KCP&L and Strategic Energy.
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| KCP&L KCP&L is an integrated, regulated electric utility that engages in the generation, transmission, distribution and sale of electricity. KCP&L has over 4,000 MWs of generating capacity and has transmission and distribution facilities that provide electricity to approximately 506,000 customers in the states of Missouri and Kansas. KCP&L has continued to experience modest load growth. Load growth consists of higher usage per customer and the addition of new customers. Retail electricity rates are below the national average.
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| KCP&L's nuclear unit, Wolf Creek, accounts for approximately 20% of its base load capacity. In 2006, WCNOC submitted an application for a new operating license for Wolf Creek with the NRC, which would extend Wolf Creek's operating period to 2045. The NRC may take up to two years to rule on the application. Wolf Creek's most recent refueling outage was in October 2006 and lasted 35 days. The next refueling outage is scheduled to begin in March 2008.
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| Strategic Energy Great Plains Energy indirectly owns 100% of Strategic Energy. Strategic Energy does not own generation, transmission or distribution facilities. Strategic Energy provides competitive retail electricity supply services by entering into power supply contracts to supply electricity to its end-use customers.
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| Of the states that offer retail choice, Strategic Energy operates in California, Connecticut, Illinois, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. Strategic Energy also provides strategic planning, consulting and billing and scheduling services in the natural gas and electricity markets.
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| Strategic Energy provides services to approximately 109,000 commercial, institutional and small manufacturing accounts (for approximately 25,700 customers) including numerous Fortune 500 companies, smaller companies and governmental entities. Strategic Energy offers an array of products designed to meet the various requirements of a diverse customer base including fixed price, index-based and month-to-month renewal products. Strategic Energy's volume-based customer retention rate, excluding month-to-month customers on market-based rates for 2007 was 59%. The corresponding volume-based customer retention rates including month-to-month customers on market-based rates was 68%. Strategic Energy deliberately reduced sales in certain markets and customer.
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| segments during the year and, consequently, experienced lower retention rates than previous years.
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| 30
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| Management has focused sales and marketing efforts on states that currently provide a more competitive pricing environment in relation to host utility default rates. As a result, total forecasted future MWh commitments (backlog) grew to 36.6 million MWh at December 31, 2007, compared to 32.8 million MWh at December 31, 2006. Based solely on expected MWh usage under current signed contracts, Strategic Energy has backlog of 18"5 million MWh, 9.0 million MWh and 5.6 million MWh for the years 2008 through 2010, respectively, and 3.5 million MWh over the years 2011 through 2012.
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| Strategic Energy's projected MWh deliveries for 2008 are in the range of 21 million to 25 million MWhs.
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| Strategic Energy expects to deliver additional MWhs above amounts currently in backlog through new and renewed term contracts and MWh deliveries to month-to-month customers.
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| Strategic Energy currently expects the average retail gross margin per MWh delivered (retail revenues less retail purchased power divided by retail MWhs delivered) in 2008 to average $3.50 to $4.50. This range excludes unrealized changes in fair value of non-hedging energy contracts and from hedge ineffectiveness because management does not predict the future impact of these unrealized changes.
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| Actual retail gross margin per MWh may differ from these estimates.
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| Earnings Overview Great Plains Energy's 2007 earnings of $157.6 million, or $1.85 per diluted share, were up from 2006 earnings of $126.0 million, or $1.61 per diluted share. Earnings in 2007 were favorably impacted by weather, increased wholesale revenues, new retail rates, and increased customer usage at KCP&L, as well as higher delivered volumes and an increase in changes in fair value related to non-hedging energy contracts and from hedge ineffectiveness at Strategic Energy. These favorable impacts more than offset the impact of plant outages during the first and second quarters at KCP&L, higher consolidated operating expense and interest expense, and higher power prices, a first quarter resettlement charge, customer attrition in the small customer segment, and higher bad debt expense at Strategic Energy.
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| STRATEGIC FOCUS Close Aquila transaction In February 2007, Great Plains Energy entered into an agreement to acquire all outstanding shares of Aquila for $1.80 in cash plus 0.0856 of a share of Great Plains Energy common stock for each share of Aquila common stock. Immediately prior to Great Plains Energy's acquisition of Aquila, Black Hills will acquire Aquila's electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa plus associated liabilities for a total of $940 million in cash, subject to closing adjustments. Each of the two transactions is conditioned on the completion of the other transaction and is expected to close in the first half of 2008. Activity related to the Aquila transactions included the following:
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| " In 2007, Great Plains Energy, KCP&L and Aquila filed joint applications with the MPSC and KCC for approval of the acquisition of Aquila by Great Plains Energy. Evidentiary hearings in Missouri began in December 2007, but recessed to allow Great Plains Energy, KCP&L and Aquila time to develop a modified proposal that addresses many of the concerns of various parties represented in the proceeding. In February 2008, a revised proposal was submitted and hearings were requested to reconvene in late April 2008. Also in February 2008, a settlement was reached with the parties in the KCC proceedings and submitted to KCC. Decisions in both cases are currently anticipated in the first half of 2008.
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| * In 2007, Aquila and Black Hills filed applications with the Colorado Public Utilities Commission (CPUC), KCC, the Nebraska Public Service Commission (NPSC) and the Iowa Utilities Board (IUB) seeking approval of the sale of assets to Black Hills. The CPUC, IUB and NPSC have approved the sale of assets and a settlement has been submitted in the KCC proceedings.
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| 31
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| * In 2007, Great Plains Energy, KCP&L, Aquila and Black Hills filed a joint application with FERC for approval of the transactions, which was granted.
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| * In July 2007, Great Plains Energy, Aquila and Black Hills submitted their respective Hart-Scott-Rodino pre-merger notifications and received early termination of the waiting period on August 27, 2007.
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| " In October 2007, Great Plains Energy received approval from its shareholders to issue common stock in connection with the anticipated acquisition of Aquila and Aquila's shareholders approved the acquisition of Aquila by Great Plains Energy.
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| * Great Plains Energy is focused on closing the transaction and on achieving operational integration (people, processes and systems) throughout 2008 to maximize synergies.
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| See Note 2 to the consolidated financial ,statements for additional information.
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| KCP&L's Comprehensive Energy Plan KCP&L continues to execute on its Comprehensive Energy Plan. The first phase of environmental upgrades at LaCygne No. 1, installation of selective catalytic reduction equipment, was completed and placed into service during the second quarter of 2007. Environmental upgrades at latan No. 1 are underway and completion is currently scheduled for late 2008. An outage at latan No. 1 is planned to complete and place in service these environmental upgrades during the fourth quarter of 2008.
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| Construction of latan No. 2 is on-going and currently scheduled for completion in 2010. The erection of the stack liner continues, underground utilities and foundations are proceeding on schedule, boiler.
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| foundations have been released to the boiler erection contractor, steel erection has commenced and the turbine generator pedestal is complete.
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| The construction environment entering 2008 for the latan No. 1 and latan No. 2 projects is challenging, particularly the tight market conditions for skilled labor and the lengthening lead times for deliveries of materials. KCP&L is conducting a thorough assessment of the impact of the current environment on the projects' cost and schedule. The results of the assessment are expected to be available in the second quarter of 2008.
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| In March 2007, KCP&L, the Sierra Club and the Concerned Citizens of Platte County entered into a Collaboration Agreement that resolved disputes among the parties and KCP&L agreed to pursue a set of initiatives including energy efficiency, additional wind generation, lower emission permit levels at its latan and LaCygne generating stations and other initiatives designed to offset carbon dioxide emissions. Under the Collaboration Agreement, KCP&L will, among other things, pursue increasing its wind generation capacity by 100 MW by year-end 2010 and another 300 MW by year-end 2012, subject to regulatory approval. In April 2007, KCP&L issued a request for proposals to develop 100 MW of wind generation in Missouri and/or Kansas. This request was an outgrowth of commitments under the Comprehensive Energy Plan. As with any large investment of this type, part of the planning and evaluation involves financing considerations. Difficulties impacting the credit markets are ongoing and consequently, KCP&L's management believes the prudent business decision is not to move forward with wind construction in 2008. This decision will not, however, impact KCP&L's commitment to pursue additional wind generation.
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| KCP&L is focusing on development of the next phase of its Comprehensive Energy Plan, which includes developing a long range resource plan and filing an integrated resource plan in Missouri in the third quarter of 2008, continuing to engage community groups and regulators to develop energy efficiency and demand response as a resource alternative and continuing development of environmental and renewable generation alternatives.
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| 32
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| Conduct Strategic Alternative Review of Strategic Energy Great Plains Energy has retained Merrill Lynch & Co. as financial advisor to assist in a review of strategic and structural alternatives for its Strategic Energy subsidiary. The alternatives may include, among others, continuation of Strategic Energy's current subsidiary status and business plans, joint ventures with strategic partners, acquisitions of similar businesses, or sales of part or all of Strategic Energy. There is no assurance regarding which of the foregoing alternatives, if any, will be selected, or the terms of any possible joint venture, acquisition or sale.
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| KCP&L REGULATORY PROCEEDINGS In December 2007, KCP&L received a rate order from the MPSC authorizing an annual rate increase of
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| $35 million. In November 2007, KCP&L received a rate order from KCC authorizing an annual rate increase of $28 million. The KCC order also includes an ECA. The ECA tariff will reflect the projected annual amount of fuel, purchased power, emission allowances, transmission costs and asset-based off-system wholesale sales margin, subject to quarterly re-forecasts. Any difference between the ECA revenue collected and the actual ECA amounts for a given year (which may be positive or negative) will be recovered from or refunded to Kansas retail customers over twelve months beginning April 1 of the succeeding year. KCP&L's Missouri retail rates do not contain a similar provision. In addition, any non-firm wholesale electric sales margin above the level reflected in Missouri retail rates will be recorded as a regulatory liability and returned to retail customers in a future rate case. The ordered rates were implemented January 1, 2008. See Note 6 to the consolidated financial statements for additional information.
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| RELATED PARTY TRANSACTIONS See Note 12 to the consolidated financial statements for information regarding related party transactions.
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| CRITICAL ACCOUNTING POLICIES The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures. Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or different estimates that could have been used could have a material impact on the results of operations and financial position.
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| Management has identified the following accounting policies as critical to the understanding of Great Plains Energy's and consolidated KCP&L's results of operations and financial position. Management has discussed the development and selection of these critical accounting policies with the Audit Committee of the Board of Directors.
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| Pensions Great Plains Energy and consolidated KCP&L incur significant costs in providing non-contributory defined pension benefits. The costs are measured using actuarial valuations that are dependent upon numerous factors derived from actual plan experience and assumptions of future plan experience.
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| Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plan, earnings on plan assets and plan amendments. In addition, pension costs are also affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.
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| These actuarial assumptions are updated annually at the beginning of the plan year. In selecting an assumed discount rate, the prevailing market rate of fixed income debt instruments with maturities 33
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| matching the expected timing of the benefit obligation was considered. The assumed rate of return on plan assets was developed based on the weighted average of long-term returns forecast for the expected portfolio mix of investments held by the plan. These assumptions are based on management's best estimates and judgment; however, material changes may occur if these assumptions differ from actual events. See Note 8 to the consolidated financial statements for information regarding the assumptions used to determine benefit obligations and net costs.
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| The following table reflects the sensitivities associated with a 0.5% increase or a 0.5% decrease in key actuarial assumptions. Each sensitivity reflects the impact based on a change in that assumption only.
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| Impact on Impact on Projected 2007 Change in Benefit Pension Actuarial assumption Assumption Obligation Expense (millions)
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| Discount rate 0.5% increase $ (32.6) $ (2.8)
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| Rate of return on plan assets 0.5% increase - (2.0)
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| Discount rate 0.5% decrease 33.2 2.8 Rate of return on plan assets 0.5% decrease - 2.0 Pension expense for KCP&L is recorded in accordance with rate orders from the MPSC and KCC. The orders allow the difference between pension costs under Statement of Financial Accounting Standards (SFAS) No. 87, "Employers' Accounting for Pensions" and SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits" and pension costs for ratemaking to be recorded as a regulatory asset or liability with future ratemaking recovery or refunds, as appropriate. KCP&L recorded 2007 pension expense of $35 million after allocations to the other joint owners of generating facilities and capitalized amounts in accordance with the 2006 MPSC and KCC rate orders. Expected 2008 pension expense will approximate $38 million after allocations to the other joint owners of generating facilities and capitalized amounts consistent with the 2007 MPSC and KCC rate orders. See Note 8 to the consolidated financial statements for additional information.
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| Market conditions and interest rates significantly affect the future assets and liabilities of the plan. It is difficult to predict future pension costs, changes in pension liability and cash funding requirements due to volatile market conditions.
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| Regulatory Matters As a regulated utility, KCP&L is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, KCP&L has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not otherwise be recorded under GAAP. Regulatory assets represent incurred costs that are probable of recovery from future revenues. Regulatory liabilities represent: amounts imposed by rate actions of KCP&L's regulators that may require refunds to customers; amounts provided in current rates that are intended to recover costs that are expected to be incurred in the future for which KCP&L remains accountable; or a gain or other reduction of allowable costs to be given to customers over future periods. Future recovery of regulatory assets is not assured, but is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Future reductions in revenue or refunds for regulatory liabilities generally are not mandated, pending future rate proceedings or actions by the regulators.
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| Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC on KCP&L's rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to KCP&L; and changes in laws and 34
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| regulations. If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations. KCP&L's continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by restructuring and deregulation in the electric industry. In the event that SFAS No. 71 no longer applied to a deregulated portion of KCP&L's operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment on utility plant assets as determined pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets." See Note 6 to the consolidated financial statements for more information.
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| Energy and Energy-Related Contract Accounting Strategic Energy generally purchases power under forward physical delivery contracts to supply electricity to its retail energy customers under full requirement sales contracts. The full requirements sales contracts and the forward physical delivery contracts meet the accounting definition of a derivative; however, Strategic Energy applies the normal purchases and normal sales (NPNS) exception accounting treatment on full requirement sales contracts. Derivative contracts designated as NPNS are accounted for by accrual accounting, which requires the effects of the derivative to be recorded when the underlying contract settles.
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| Strategic Energy designates forward physical delivery contracts that do not meet the requirements for the NPNS exception as cash flow hedges. Under cash flow hedge accounting, the fair value of the contract is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in Other Comprehensive Income (OCI) and subsequently reclassified to purchased power expense in Great Plains Energy's consolidated statement of income as the power is delivered and/or the contract settles. Accounting for derivatives as cash flow hedges or as NPNS transactions may affect the timing and nature of accounting recognition, but does not change the underlying economic results.
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| The fair value of forward purchase derivative contracts that do not meet the requirements for the NPNS exception or cash flow hedge accounting are recorded as current or long-term derivative assets or liabilities. Changes in the fair value of these contracts could result in operating income volatility as changes in the associated derivative assets and liabilities are recorded in purchased power expense in Great Plains Energy's consolidated statements of income.
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| Strategic Energy's derivative assets and liabilities consist of a combination of energy and energy-related contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices. The market prices used to determine fair value reflect management's best estimate considering time, volatility and historical trends. Future market prices may vary from those used in recording energy assets and liabilities at fair value and such variations could be significant.
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| Market prices for energy and energy-related commodities vary based upon a number of factors.
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| Changes in market prices will affect the recorded fair value of energy contracts. Changes in the fair value of energy contracts will affect operating income in the period of the change for contracts under fair value accounting and OCI in the period of change for contracts under cash flow hedge accounting, while changes in forward market prices related to contracts under accrual accounting will affect operating income in future periods to the extent those prices are realized. Management cannot predict whether, or to what extent, the factors affecting market prices may change, but those changes could be material and could be either favorable or unfavorable.
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| 35
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| | |
| GREAT PLAINS ENERGY RESULTS OF OPERATIONS The following table summarizes Great Plains Energy's comparative results of operations.
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| 2007 2006 2005 (millions)
| |
| Operating revenues $ 3,267.1 $ 2,675.3 $ 2,604.9 Fuel (245.5) (229.5) (208.4)
| |
| Purchased power (1,931.7) (1,516.7) (1,429.7)
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| Other operating expenses (595.2) (524.4) (527.2)
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| Skill set realignment 8.9 (9.4)
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| Depreciation and amortization (183.8) (160.5) (153.1)
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| Gain (loss) on property 0.6 (3.5)
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| Operating income 319.8 235.4 283.0 Non-operating income and expenses 6.7 13.2 2.7 Interest charges (93.8) (71.2) (73.8)
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| Income taxes (71.5) (47.9) (39.5)
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| Minority interest in subsidiaries (7.8)
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| Loss from equity investments (2.0) (1.9) (0.4)
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| Income from continuing operations 159.2 127.6 164.2 Discontinued operations (1.9)
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| Net income 159.2 127.6 162.3 11 AN Preferred divAdends (1 A\ (1.6)
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| Earnings available for common shareholders $ 157.6 $ 126.0 $ 160.7 2007 compared to 2006 Great Plains Energy's 2007 earnings available for common shareholders increased to $157.6 million, or
| |
| $1.85 per diluted share, from $126.0 million, or $1.61 per diluted share in 2006. A higher number of common shares, primarily due to the issuance of 5.2 million shares to the holders of FELINE PRIDESsM in February 2007 and 5.2 million shares in May 2006, diluted 2007 earnings per share by $0.17.
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| Consolidated KCP&L's net income increased $7.4 million in 2007 compared to 2006 due to increased retail and wholesale revenues, which more than offset the impact of planned and unplanned outages during the first half of the year that lead to increased fuel, purchased power and operating expenses.
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| Additionally, in 2006 KCP&L recorded $9.3 million of skill set realignment costs and in 2007 received authorization from the MPSC and KCC to defer and amortize $8.9 million of these costs.
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| Strategic Energy had net income of $38.4 million in 2007 compared to a net loss of $9.9 million in 2006 due to the impact of a $64.7 million after-tax increase in changes in fair value related to non-hedging energy contracts and from hedge ineffectiveness. Partially offsetting this increase to net income was increased purchased power associated with a resettlement attributable to under-reported deliveries and the disposition of previously-acquired power at lower than contracted prices caused by early terminations in the small business segment and the absence of supplier contract settlements. Strategic Energy also experienced increased bad debt expense in the small business segment and recognized penalty expense related to the purchased power adjustment for under-reported deliveries.
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| Great Plains Energy's other non-regulated activities recognized an additional $24.1 million loss in 2007 compared to 2006, which was primarily attributable to a decline in available tax credits from affordable housing investments and overall higher expenses at the holding company, including $11.7 million of transition costs related to the anticipated acquisition of Aquila, and a $10.3 million after-tax loss for the fair value of Forward Starting Swaps (FSS) entered into by Great Plains Energy during 2007.
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| 36
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| | |
| 2006 compared to 2005 Great Plains Energy's 2006 earnings available for common shareholders decreased to $126.0 million, or $1.61 per diluted share, from $160.7 million, or $2.15 per share, in 2005. A higher average number of common shares, primarily due to the issuance of 5.2 million shares in May 2006, diluted 2006 earnings per share by $0.08.
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| Consolidated KCP&L's net income increased $5.6 million in 2006 compared to 2005 due to increased retail revenues and decreased purchase power expense. These increases to net income were partially offset by costs related to skill set realignments, increased fuel expense and higher income taxes due to higher pre-tax income in 2006 and a decrease in 2005 income taxes reflecting a reduction in KCP&L's deferred tax balances as a result of a reduction in KCP&L's composite tax rate.
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| Strategic Energy had a net loss of $9.9 million in 2006 compared to net income of $28.2 million in 2005.
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| The net loss was primarily the result of the after-tax impact of $33.4 million of changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Additionally, retail MWhs delivered decreased 15% in 2006 compared to 2005, but the impact to net income was partially offset by higher average retail gross margins per MWh without the impact of unrealized fair value gains and losses.
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| CONSOLIDATED KCP&L RESULTS OF OPERATIONS The following discussion of consolidated KCP&L results of operations includes KCP&L, an integrated, regulated electric utility and HSS, an unregulated subsidiary of KCP&L. In the discussion that follows, references to KCP&L reflect only the operations of the utility.
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| KCP&L's residential customers' usage is significantly affected by weather. Bulk power sales, the major component of wholesale sales, vary with system requirements, generating unit and purchased power availability, fuel costs and requirements of other electric systems. Prior to January 1, 2008, less than 1% of KCP&L's rates contained an automatic fuel adjustment clause. New Kansas retail rates effective January 1, 2008, contain an ECA tariff. Any difference between the ECA revenue collected and the actual ECA amounts for a given year (which may be positive or negative) will be recorded as an increase to or reduction of retail revenues and deferred as a regulatory asset or liability to be recovered from or refunded to Kansas retail customers over twelve months beginning April 1 of the succeeding year. See Note 6 to the consolidated financial statements. KCP&L's Missouri retail rates do not contain a similar provision. Missouri retail rates reflect a set level of non-firm wholesale electric sales margin. KCP&L will not recover any shortfall in non-firm wholesale electric sales margin, but any amount above the level reflected in Missouri retail rates will be returned to retail customers in a future rate case.
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| Generation fuel mix can substantially change the fuel cost per MWh generated. Nuclear fuel cost per MWh generated is substantially less than the cost of coal per MWh generated, which is significantly lower than the cost of natural gas and oil per MWh generated. The cost per MWh for purchased power is generally significantly higher than the cost per MWh of coal and nuclear generation. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply and purchased power, and the requirements of other electric systems to provide reliable power economically.
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| 37
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| | |
| The following table summarizes consolidated KCP&L's comparative results of operations.
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| 2007 2006 2005 (millions)
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| Operating revenues $ 1,292.7 $ 1,140.4 $ 1,130.9.
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| Fuel (245.5) (229.5) (208.4)
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| Purchased power (101.0) (26.4) (61.3)
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| Skill set realignment 8.9 (9.3)
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| Other operating expenses (500.6) (452.1) (460.5)
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| Depreciation and amortization (175.6) (152.7) (146.6)
| |
| Gain (loss) on property 0.6 (4.6)
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| Operating income 278.9 271.0 249.5 Non-operating income and expenses 4.3 9.6 11.8 Interest charges (67.2) (61.0) (61.8)
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| Income taxes (59.3) (70.3) (48.0)
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| Minority interest in subsidiaries (7.8)
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| Net income $ 156.7 $ 149.3 $ 143.7 Consolidated KCP&L Sales Revenues and MWh Sales 2007 Change 2006 Change 2005 Retail revenues (millions)
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| Residential $ 433.8 13 $ 384.3 1 $ 380.0 Commercial 492.1 11 442.6 2 434.6 Industrial 106.8 7 99.8 (1) 100.9 Other retail revenues 9.9 12 8.8 3 8.6 Pro\ision for rate refund (1.1) NA - NA -
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| Total retail 1,041.5 11 935.5 1 924.1 Wholesale revenues 234.0 23 190.4 (1) 192.4 Other revenues 17.2 19 14.5 1 14.3 KCP&L electric revenues 1,292.7 13 1,140.4 1 1,130.8 Subsidiary revenues - - - NM 0.1 Consolidated KCP&L revenues $1,292.7 13 $1,140.4 $1,130.9 2007 Change 2006 Change 2005 Retail MWh sales (thousands)
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| Residential 5,597 3 5,413 1 5,383 Commercial 7,737 5 7,403 2 7,292 Industrial 2,161 1 . 2,148 (1) 2,165 Other retail MWh sales 92 8 86 4 82 Total retail 15,587 4 15,050 1 14,922 Wholesale MWh sales 5,635 21 4,676 1 4,608 KCP&L electric MWh sales 21,222 8 19,726 1 19,530 Retail revenues increased $106.0 million in 2007 compared to 2006 primarily due to new retail rates effective January 1, 2007, growth in the number of customers and higher usage per customer. In addition, favorable weather in 2007, with a 22% increase in heating degree days partially offset by a 5%
| |
| decrease in cooling degree days, contributed to the increase in retail revenue.
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| 38
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| | |
| Retail revenues increased $11.4 million in 2006 compared to 2005 primarily due to growth in the number of customers and higher usage per customer slightly offset by the impact of weather with favorable summer weather being more than offset by mild winter weather.
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| The following table provides cooling degree days (CDD) and heating degree days (HDD) for the last three years at the Kansas City International Airport. CDD and HDD are used to reflect the demand for energy to cool or heat homes and buildings.
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| 2007 Change 2006 Change 2005 CDD 1,637 (5) 1,724 6 1,626 HDD 4,925 22 4,052 (15) 4,780 Wholesale revenues increased $43.6 million in 2007 compared to 2006 due to a 21% increase in wholesale MWh sales resulting from increased generation due to greater plant availability in the second half of the year. Wholesale revenues decreased $2.0 million in 2006 compared to 2005 due to an 11%
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| decrease in the average market price per MWh to $42.52 partially offset by a 1% increase in wholesale MWh sales. The decrease in average market price per MWh was primarily due to lower gas prices in 2006 compared to 2005, as well as the effects on 2005 average prices from coal conservation in the region. Additionally, wholesale revenues for 2006 include $2.5 million in litigation recoveries for the loss of use of Hawthorn No. 5 from a 1999 boiler explosion.
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| Consolidated KCP&L Fuel and Purchased Power Net MWhs Generated % %
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| by Fuel Type 2007. Change 2006 Change 2005 (thousands)
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| Coal 14,894 (1) 15,056 - 14,994 Nuclear 4,873 11 4,395 6 4,146 Natural gas and oil 544 (4) 564 19 473 Wind 305 NM 106 N/A _
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| Total Generation 20,616 2 20,121 3 19,613 KCP&L's coal base load equivalent availability factor for 2007 decreased to 80% from 83% in 2006, primarily due to plant outages in the first half of 2007, and was 82% in 2005.
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| Fuel expense increased $16.0 million in 2007 compared to 2006 primarily due to higher coal and coal transportation costs and a 2% increase in MWhs generated, excluding wind generation, which has no fuel cost. This increase was partially offset by changes in the fuel mix with more nuclear and less coal and natural gas in the fuel mix.
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| Fuel expense increased $21.1 million in 2006 compared to 2005 due to a 2% increase in MWhs generated, excluding wind generation, increased coal and coal transportation costs and more natural gas generation in the fuel mix, which has higher costs compared to other fuel types. These increases were partially offset by lower natural gas prices. Fuel expense in 2006 was reduced by $3.7 million in Hawthorn No. 5 litigation recoveries.
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| Certain of KCP&L's current coal transportation contracts include higher tariff rates being charged by Union Pacific. KCP&L has filed a rate case complaint against Union Pacific with the Surface 39
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| Transportation Board (STB) and until the case is finalized, KCP&L is paying the tariff rates subject to refund. See Note 15 to the consolidated financial statements for more information.
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| Purchased power expense increased $74.6 million in 2007 compared to 2006 primarily due to a240%
| |
| increase in MWh purchases to support increased retail load, the impact of planned and unplanned outages in the first half of 2007 and increased purchases for resale to satisfy firm wholesale MWh sales commitments when it was more economical to purchase power rather than delivering MWhs generated at KCP&L's plants. This increase was slightly offset by a 10% decrease in the average price per MWh.
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| Purchased power expense decreased $34.9 million in 2006 compared to 2005 due to a 40% reduction in MWhs purchased due to uneconomical purchased power prices and increased net MWhs generated and a $5.1 million decrease in capacity payments in 2006 due to the expiration of two large contracts in the second quarter of 2005. KCP&L entered into new capacity contracts in June 2006. Purchased power expense in 2006 was reduced by $10.8 million in Hawthorn No. 5 litigation recoveries.
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| Consolidated KCP&L Other Operating Expenses (includingoperatingexpenses - KCP&L, maintenance,general taxes and other),
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| Consolidated KCP&L's other operating expenses increased $48.5 million in 2007 compared to 2006 primarily due to the following:
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| " increased pension expenses of $18.4 million due to the increased level of pension costs in KCP&L's rates effective January 1, 2007,
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| " increased plant operations and maintenance expenses of $9.7 million primarily due to planned and unplanned outages in the first half of 2007 and the addition of the Spearville Wind Energy Facility in the third quarter of 2006,
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| * increased transmission expenses of $7.7 million primarily due to increased transmission usage charges as a result of the increased wholesale MWh sales and higher SPP fees,
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| * increased gross receipts tax expense of $3.6 million due to the increase in revenues,
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| " increased labor expense of $2.8 million primarily due to filling open positions,
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| * increased equity compensation expense of $1.9 million and
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| " increased property taxes of $1.6 million primarily due to increases in mill levies..
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| Partially offsetting the year to date increase in other operating expenses was decreased incentive compensation expense of $5.7 million.
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| Consolidated KCP&L's other operating expenses decreased $8.4 million in 2006 compared to 2005 primarily due to the following:
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| * decreased severance and incentive compensation expense of $6.3 million, 0 deferring $6.2 million of expenses in accordance with the MPSC and KCC orders and
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| * decreased restoration expenses of $5.1 million due to expenses that were incurred for a January 2005 ice storm and a June 2005 wind storm.
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| Partially offsetting the decrease in other operating expenses was:
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| * increased maintenance expenses of $2.6 million for facilities, software and communication equipment and
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| " increased property taxes of $2.7 million primarily due to increases in assessed property valuations and mill levies.
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| 40
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| | |
| Consolidated KCP&L Skill Set Realignment In 2005 and early 2006, management undertook a process to assess, improve and reposition the skill sets of employees for implementation of the Comprehensive Energy Plan. KCP&L recorded $9.3 million in 2006 related to this workforce realignment process reflecting severance, benefits and related payroll taxes provided by KCP&L to employees. In 2007, KCP&L received authorization from the MPSC and KCC to establish an $8.9 million regulatory asset for these costs and amortize them over five years for the Missouri jurisdictional portion and ten years for the Kansas jurisdictional portion effective with new rates on January 1, 2008.
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| Consolidated KCP&L Depreciation and Amortization Consolidated KCP&L's depreciation and amortization costs increased $22.9 million in 2007 compared to 2006 primarily due to additional amortization pursuant to 2006 rate case orders of $11.9 million and a
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| $4.5 million increase due to wind generation assets placed in service in the third quarter of 2006.
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| Consolidated KCP&L Interest Charges Consolidated KCP&L's interest charges increased $6.2 million in 2007 compared to 2006 due to an increase in short-term borrowings to support expenditures related to the Comprehensive Energy Plan.
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| Consolidated KCP&L Income Taxes Consolidated KCP&L's income taxes decreased $11.0 million in 2007 compared to 2006 primarily due to $4.1 million of wind credits and a $7.3 million increase in the allocation of tax benefits from holding company losses pursuant to Great Plains Energy's intercompany tax allocation agreement.
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| Consolidated KCP&L's income taxes increased $22.3 million in 2006 compared to 2005 due to an increase in pre-tax income in 2006 and a decrease in 2005 of $11.7 million due to the impact of a lower composite tax rate on KCP&L's deferred tax balances resulting from the favorable impact of sustained audit positions.
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| STRATEGIC ENERGY RESULTS OF OPERATIONS The following table summarizes Strategic Energy's comparative results of operations.
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| 2007 2006 2005 (millions)
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| Operating revenues $ 1,974.4 $ 1,534.9 $ 1,474.0 Purchased power (1,830.7) (1,490.3) (1,368.4)
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| Other operating expenses (72.5) (61..5) (53.4)
| |
| Depreciation and amortization (8.2) (7.8) (6.4)
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| Loss on property " (0.1)
| |
| Operating income (loss) 63.0 (24.7) 45.7 Non-operating income and expenses 4.1 4.2 2.5 Interest charges (2.9) (2.1) (3.4) -
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| Income taxes (25.8) 12.7 (16.6)
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| Net income (loss) $ 38.4 $ (9.9) $ 28.2 Retail MWhs delivered increased 22% to 20.3 million in 2007 compared to 16.6 million MWhs delivered in 2006. The 2006 retail MWhs delivered decreased 15% compared to 2005 due to the effect of market conditions in midwestern states and competition in other markets where Strategic Energy serves.
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| customers. Management has focused sales and marketing efforts on states that currently provide a more competitive pricing environment in relation to host utility default rates resulting in increased MWh deliveries in 2007.
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| 41
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| | |
| Strategic Energy had net income of $38.4 million in 2007 compared to a net loss of $9.9 million in 2006 due to the impact of a $64.7 million after-tax increase in changes in fair value related to non-hedging energy contracts and from hedge ineffectiveness. Partially offsetting this increase to net income was increased purchased power associated with a resettlement attributable to under-reported deliveries and the disposition of previously-acquired power at lower than contracted prices caused by early terminations in the small business segment and the absence of supplier contract settlements. Strategic Energy also experienced increased bad debt expense in the small business segment and recognized penalty expense related to the purchased power adjustment for under-reported deliveries.
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| Strategic Energy's 2006 net loss was primarily the result of the after-tax impact of $33.4 million in changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Additionally, Strategic Energy's 2006 other operating expenses increased compared to 2005 primarily due to increased incentive compensation and bad debt expense.
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| Average Retail Gross Margin per MWh Without Fair Value Impacts As detailed in the table below, the average retail gross margin per MWh without the impact of unrealized fair value gains and losses decreased to $4.39 in 2007 compared to $5.93 in 2006. This decrease is attributable to the disposition of previously-acquired power at lower than contracted prices caused by early terminations in the small business segment, increased purchased power expense associated with a resettlement attributable to under-reported deliveries and the absence of settlements of supplier contracts. Partially offsetting these decreases was an increase in net SECA recoveries.
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| Average retail gross margin per MWh without the impact of unrealized fair value gains and losses increased to $5.93 in 2006 compared to $5.07 in 2005. The increase was primarily due to the net impact of SECA recoveries and charges as compared to 2005. The net SECA impact increased average retail gross margin per MWh by $0.06 in 2006 and decreased average retail gross margin per MWh by $0.42 in 2005. Additional impacts to the average retail gross margin per MWh included increases primarily due to the management of retail portfolio load requirements, favorable product mix and settlements of supplier contracts. The increases were partially offset by higher customer acquisition costs in 2006.
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| 2007 2006 2005 Average retail gross margin per MWh $ 6.99 $ 2.52 $ 5.19 Change in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness 2.60 (3.41) 0.12 Average retail gross margin per MWh without fair value impacts $ 4.39 $ 5.93 $ 5.07 Average retail gross margin per MWh without fair value impacts is a non-GAAP financial measure that differs from GAAP because it excludes the impact of unrealized fair value gains or losses. Fair value impacts result from changes in fair value of non-hedging energy contracts and from hedge ineffectiveness associated with MWhs under contract but not yet delivered. By not reflecting the impact of unrealized fair value gains or losses, this non-GAAP financial measure does not reflect the volatility recognized in the Company's consolidated statements of income as a result of the unrealized fair value gains or losses in the periods presented related to energy under contract for future delivery to customers. The fair value of energy under contract but not yet delivered fluctuates from the time the contract is entered into until the energy is delivered to customers. However, the ultimate value realized by Strategic Energy under the customer sales contracts is determined when the electricity supply contract settles at the originally contracted price at the'time of delivery to customers. Management and the Board of Directors use this non-GAAP financial measure as a measurement of Strategic Energy's 42
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| | |
| realized retail gross margin per delivered MWh, which are settled at contracted prices upon delivery.
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| Because certain of Strategic Energy's derivative supply contracts do not meet the requirements for cash flow hedge designation and certain other derivative supply contracts designated as cash flow hedges have a level of ineffectiveness, Strategic Energy recognizes uhrealized gains or losses during the term of these derivative supply contracts prior to delivery while the associated customer sales contracts are not subject to fair value accounting treatment and therefore do not result in unrecognized gains or losses being recorded during the term prior to delivery. By removing these non-cash timing differences that occur during the term of the contracts prior to delivery and impact only one side of the overall buy-sell transaction, management believes this non-GAAP financial measure provides investors with a measure of average retail gross margin per MWh that more accurately reflects Strategic Energy's realized margin on delivered MWhs.
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| Strategic Energy Purchased Power Purchased power is the cost component of Strategic Energy's average retail gross margin. The cost of supplying electric service to retail customers can vary widely by geographic market. This variability can be affected by many factors, including, but not limited to, geographic differences in the cost per MWh of purchased power, renewable energy requirements and capacity charges due to regional purchased power availability, requirements of other electricity providers and differences in transmission charges.
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| Strategic Energy purchases electricity from power suppliers based on forecasted peak demand for its retail customers. Actual customer demand does not always equate to the volume purchased based on forecasted peak demand. Consequently, Strategic Energy makes short-term power purchases in the wholesale market when necessary to meet actual customer requirements. Strategic Energy also sells any excess retail electricity supply over-actual customer requirements back into the wholesale market.
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| These sales occur on many contracts, are usually short-term power sales (day ahead) and typically settle within the reporting period. Excess retail electricity supply sales also include long-term and short-term forward physical sales to wholesale counterparties, which are accounted for on a mark-to-market basis. Strategic Energy typically executes these transactions to manage basis and credit risks. The proceeds from excess retail supply sales are recorded as a reduction of purchased power, as they do not represent the quantity of electricity consumed by Strategic Energy's customers. The amount of excess retail supply sales that reduced purchased power was $76.4 million, $80.0 million and $158.5 million in 2007, 2006 and 2005, respectively. Additionally, in certain markets, Strategic Energy is required to sell to and purchase power from a RTO/lSO rather than directly transact with suppliers and end use customers. The sale and purchase activity related to these certain RTO/lSO markets is reflected on a net basis in Strategic Energy's purchased power.
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| Strategic Energy utilizes derivative instruments, including forward physical delivery contracts, in the procurement of electricity. Purchased power is also impacted by the net change in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness. Net changes in fair value reduced purchased power expenses by $52.8 million in 2007, increased expenses by $56.7 million in 2006 and reduced expenses by $2.5 million in 2005. These changes are a result of volatility in the forward market prices for power. Also in 2006, Strategic Energy prospectively began designating more derivative instruments as cash flow hedges that historically were accounted for by the NPNS election.
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| See Note 22 to the consolidated financial statements for more information.
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| Strategic Energy Other Operating Expenses (including selling, general and administrative -
| |
| non-regulated and general taxes)
| |
| Strategic Energy's other operating expenses increased $11.0 million in 2007 compared to 2006 due to a $10.0 million increase in bad debt expense primarily attributable to the small business segment, which has a higher default rate than Strategic Energy's larger customers, combined with penalty expense related to the purchased power adjustment for under-reported deliveries partially offset by lower employee-related expenses. Strategic Energy's other operating expenses increased $8.1 million in 2006 compared to 2005 primarily due to a $4.5 million increase for incentive compensation and a 43
| |
| | |
| $4.3 million increase in bad debt expense due to the charge off of smaller customers, which have a higher default rate than Strategic Energy's larger customers.
| |
| During 2006, Strategic Energy significantly expanded its small customer business with approximately 25% of new sales in 2006 to small customers. In 2007, Strategic Energy implemented a stronger credit screening policy and shorter permissible contract lengths in the small business segment and as a result, only 3% of new sales in 2007 were attributable to small customers.
| |
| Strategic Energy Income Taxes Strategic Energy had tax expense of $25.8 million in 2007 compared to a tax benefit of $12.7 million in 2006 due to pre-tax income in 2007 compared to a pre-tax loss in 2006. The deferred tax expense related to the net changes in fair value related to non-hedging energy contracts and from hedge ineffectiveness was $21.5 million in 2007 compared to a tax benefit of $23.3 million for the same period in 2006.
| |
| Strategic Energy had a tax benefit of $12.7 million in 2006 compared to tax expense of $16.6 million in 2005 due to a pre-tax loss in 2006 compared to pre-tax income in 2005. The change was driven by a
| |
| $23.3 million deferred tax benefit in 2006 related to the net changes in fair value related to non-hedging energy contracts and from cash flow hedge ineffectiveness.
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| GREAT PLAINS ENERGY AND CONSOLIDATED KCP&L SIGNIFICANT BALANCE SHEET CHANGES (December 31, 2007 compared to December 31, 2006)
| |
| * Great Plains Energy's and consolidated KCP&L's receivables increased $88.0 million and $62.1 million, respectively. KCP&L's receivables increased $22.4 million due to additional receivables from joint owners of Comprehensive Energy Plan projects, $10.0 million mostly attributable to new retail rates effective January 1, 2007, $11.0 million due to an increase in wholesale sales and a $10.5 million increase in intercompany receivables from Great Plains Energy. Strategic Energy's receivables increased $36.3 million primarily due to increased MWh deliveries at higher prices partially offset by a higher allowance for doubtful accounts primarily due to aging of the small business customer segment.
| |
| " Great Plains Energy's and consolidated KCP&L's fuel inventories increased $8.1 million primarily due to increased coal inventory due to plant outages as well as increased coal and coal transportation costs.
| |
| * Great Plains Energy's deferred income taxes - current assets decreased $19.8 million primarily due to temporary differences resulting from changes in the fair value of Strategic Energy's energy-related derivative instruments of $24.1 million.
| |
| * Great Plains Energy's net liability for derivative instruments, including current and deferred assets and liabilities, decreased $113.0 million. The fair value of Strategic Energy's energy-related derivative instruments increased $154.2 million, which decreased the net liability. This decrease to the net liability was partially offset by a $16.4 million increase in the net liability for the fair value of an FSS entered into in 2007 by Great Plains Energy and an increase at consolidated KCP&L. Consolidated KCP&L's net liability for derivative instruments, including current assets and current liabilities, increased $24.8 million primarily related to the fair value of a Treasury Lock (T-Lock) entered into in 2007.
| |
| * Great Plains Energy's and consolidated KCP&L's construction work in progress increased
| |
| $315.7 million primarily due to a $305.5 million increase related to KCP&L's Comprehensive Energy Plan, including $227.4 million related to the construction of latan No. 2 and $78.1 million for environmental upgrades.
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| 44
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| * Great Plains Energy's other deferred charges and other assets increased $21.3 million primarily due to deferred costs associated with Great Plains Energy's anticipated acquisition of Aquila.
| |
| * Great Plains Energy's notes payable increased $42.0 million due to borrowings on its short-term credit facility used to settle a forward sale agreement for $12.3 million with the remainder due to the timing of cash payments.
| |
| * Great Plains Energy's and consolidated KCP&L's commercial paper increased $209.4 million primarily to support expenditures related to the Comprehensive Energy Plan.
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| " Great Plains Energy's and consolidated KCP&L's current maturities of long-term debt decreased $389.4 million and $225.5 million, respectively, due to Great Plains Energy's settlement of the FELINE PRIDES Senior Notes by issuing $163.6 million of common stock and KCP&L's repayment of $225.0 million of 6.00% Senior Notes at maturity.
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| * Great Plains Energy's and consolidated KCP&L's accounts payable increased $83.8 million and
| |
| $61.6 million, respectively, primarily due to a $67.1 million increase in payables related to the Comprehensive Energy Plan.
| |
| * Great Plains Energy's and consolidated KCP&L's regulatory liabilities increased $29.4 million primarily due to KCP&L's regulatory treatment of SO 2 emission allowance sales totaling $24.0.
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| million in 2007.
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| " Great Plains Energy's and consolidated KCP&L's other - deferred credits and other liabilities increased $28.3 million and $20.5 million, respectively, primarily due to the adoption of Financial Accounting Standards Board Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes."
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| " Consolidated KCP&L's common stock increased $94.0 million due to an equity contribution from Great Plains Energy.
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| * Great Plains Energy's accumulated other comprehensive loss decreased $44.6 million primarily due to changes in the fair value of Strategic Energy's energy related derivative instruments due to volatility in the forward market prices for power partially offset by activity at consolidated KCP&L. Consolidated KCP&L's accumulated other comprehensive income at December 31, 2006, decreased $14.2 million resulting in accumulated other comprehensive loss at December 31, 2007, due to the fair value of a T-Lock entered -into during 2007.
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| * Great Plains Energy's long-term debt increased $495.4 million due to Great Plains Energy's issuance of $100.0 million of 6.875% Senior Notes and an increase at consolidated KCP&L.
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| Consolidated KCP&L's long-term debt increased $396.2 million reflecting the issuance of
| |
| $250.0 million of 5.85% Senior Notes and the issuance of $146.5 million of EIRR Bonds Series 2007A and 2007B. The proceeds from the issuance of $146.5 million EIRR Bonds Series 2007A and 2007B were used for the repayment of $146.5 million of Series 1998A, B and D EIRR bonds in 2007 that were classified as current maturities at December 31,2006.
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| CAPITAL REQUIREMENTS AND LIQUIDITY Great Plains Energy operates through its subsidiaries and has no material assets other than the stock of its subsidiaries. Great Plains Energy's ability to make payments on its debt securities and its ability to pay dividends is dependent on its receipt of dividends or other distributions from its subsidiaries and proceeds from the issuance of its securities.
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| Great Plains Energy's capital requirements are principally comprised of KCP&L's utility construction and other capital expenditures, debt maturities and credit support provided to Strategic Energy. These items as well as additional cash and capital requirements for the companies are discussed below.
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| 45
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| | |
| Great Plains Energy's liquid resources at December 31, 2007, consisted of $67.1 million of cash and cash equivalents on hand, including $3.2 million at consolidated KCP&L, and $623.8 million of unused bank lines of credit. The unused lines consisted of $222.3 million from KCP&L's revolving credit facility,
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| $142.1 million from Strategic Energy's revolving credit facility and receivables facility and $259.4 million from Great Plains Energy's revolving credit facility. See Note 18 to the consolidated financial statements for more information on these agreements.
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| KCP&L currently expects to fund its Comprehensive Energy Plan from a combination of internal and external sources including, but not limited to, contributions from rate increases, capital contributions to KCP&L from Great Plains Energy's security issuances and new short and long-term debt financing.
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| KCP&L's capital requirements are expected to be substantial over the next several years as it funds the Comprehensive Energy Plan.
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| KCP&L expects to meet day-to-day cash flow requirements including interest payments, construction requirements (excluding its Comprehensive Energy Plan), dividends to Great Plains Energy and pension benefit plan funding requirements, discussed below, with internally generated funds. KCP&L may not be able to meet these requirements with internally generated funds because of the effect of inflation on operating expenses, the level of MWh sales, regulatory actions, compliance with environmental regulations and the availability of generating units. The funds Great Plains Energy and consolidated KCP&L need to retire maturing debt will be provided from operations, the issuance of long and short-term debt and/or the issuance of equity or equity-linked instruments. In addition, the Company may issue debt, equity and/or equity-linked instruments to finance growth or take advantage of new opportunities.
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| Strategic Energy expects to meet day-to-day cash flow requirements including interest payments, credit support fees and capital expenditures with internally generated funds. Strategic Energy may not be able to meet these requirements with internally generated funds because of the effect of inflation on operating expenses, the level of MWh sales, seasonal working capital requirements, commodity-price volatility and the effects of counterparty non-performance.
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| In February 2007, Great Plains Energy entered into an agreement to acquire Aquila. If the proposed acquisition of Aquila occurs, the future capital requirements of Aquila will further increase Great Plains Energy's capital requirements. See Note 2 to the consolidated financial statements for additional information.
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| Cash Flows from Operating Activities Great Plains Energy and consolidated KCP&L generated positive cash flows from operating activities for the periods presented. The increase in cash flows from operating activities for Great Plains Energy in 2007 compared to 2006 reflects an increase in consolidated KCP&L's cash flows from operating activities partially offset by a $15.5 million increase in deferred merger costs at Great Plains Energy and a lower retail margin per MWh without the impact of unrealized fair value gains and losses at Strategic Energy. Consolidated KCP&L's increase in cash flows from operating activities in 2007 compared to 2006 reflects KCP&L's higher retail and wholesale revenues more than offsetting higher operating expenses combined with $24.0 million in proceeds from sales of SO 2 emission allowances in 2007.
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| Other changes in working capital detailed in Note 3 to the consolidated financial statements also impacted operating cash flows.
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| 46
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| The changes in cash flows from operating activities for Great Plains Energy and consolidated KCP&L in 2006 compared to 2005 reflect KCP&L's sales of S02 emission allowances during 2005 resulting in proceeds of $61.0 million and KCP&L's $12.0 million cash settlement of T-Locks in 2005. The timing of the Wolf Creek outage affects the deferred refueling outage costs, deferred income taxes and amortization of nuclear fuel. Other changes in working capital detailed in Note 3 to the consolidated financial statements also impacted operating cash flows. The individual components of working capital vary with normal business cycles and operations.
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| Cash Flows from Investing Activities Great Plains Energy's and consolidated KCP&L's cash used for investing activities varies with the timing of utility capital expenditures and purchases of investments and nonutility property. Investing activities are offset by the proceeds from the sale of properties and insurance recoveries.
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| Great Plains Energy's and consolidated KCP&L's utility capital expenditures increased $35.6 million in 2007 compared to 2006 due to KCP&L's cash utility expenditures, including $27.0 million related to KCP&L's Comprehensive Energy Plan.
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| Great Plains Energy's and consolidated KCP&L's utility capital expenditures increased $148.6 million and $143.8 million, respectively, in 2006 compared to 2005 due to KCP&L's cash utility capital expenditures, including $234.3 million related to KCP&L's Comprehensive Energy Plan, $10.2 million to upgrade a transmission line, $13.8 million to purchase automated meter reading equipment and $23.4 million to purchase rail cars partially offset by 2005 investing activities including $154.0 million to purchase combustion turbines and $25.3 million related to wind generation and environmental upgrades, Additionally in 2006, KCP&L received $15.8 million of litigation recoveries related to Hawthorn No. 5, compared to $10.0 million of insurance recoveries received in 2005.
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| Cash Flows from Financing Activities Great Plains Energy's cash flows from financing activities in 2007 reflect consolidated KCP&L's repayment and issuance of Senior Notes; Great Plains Energy's issuance, at a discount, of $100.0 million of 6.875% Senior Notes that mature in 2017, an increase in short-term borrowings and the $12.3 million settlement of an equity forward contractat Great Plains Energy. Consolidated KCP&L's cash flows from financing activities in 2007 reflect KCP&L's repayment of its $225.0 million of 6.00% Senior Notes at maturity, issuance, at a discount, of $250.0 million of 5.85% Senior Notes that mature in 2017, and an increase in short-term borrowings. Consolidated KCP&L's short-term borrowings have increased primarily to support expenditures related to the Comprehensive Energy Plan.
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| Great Plains Energy's cash flows from financing activities in 2006 reflect Great Plains Energy's proceeds of $144.3 million from the issuance of 5.2 million shares of common stock at $27.50 per share in May 2006. Fees related to this issuance were $5.2 million. Great Plains Energy used the proceeds to make a $134.6 million equity contribution to KCP&L. Great Plains Energy and consolidated KCP&L's net cash from financing activities in 2006 compared to 2005 increased due to an increase in KCP&L's short-term borrowings primarily to support expenditures related to the Comprehensive Energy Plan.
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| Consolidated KCP&L's net cash from financing activities also increased due to a $23.7 million decrease in dividends paid to Great Plains Energy.
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| Great Plains Energy's and consolidated KCP&L's cash flows from financing activities in 2005 reflect KCP&L's issuance of $250.0 million of 6.05% unsecured senior notes, $35.9 million of secured EIRR bonds Series 2005 and $50.0 million of unsecured EIRR bonds Series 2005. The proceeds from these issuances were used to repay $250.0 million of 7.125% unsecured senior notes, $35.9 million of secured 1994 Series EIRR bonds and $50.0 million of Series C EIRR bonds.
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| 47
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| Financing Authorization Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%; respectively, of total capitalization. KCP&L's long-term financing activities are subject to the authorization of the MPSC. In 2005, the MPSC authorized KCP&L to issue up to $635.0 million of long-term debt and to enter into interest rate hedging instruments in connection with such debt through December 31, 2009. KCP&L utilized $500.0 million of this amount with the issuance of its 6.05% unsecured senior notes maturing in 2035 and its 5.85% unsecured senior notes maturing in 2017, leaving $135.0 million of authorization remaining. In February 2008, KCP&L received authorization from the MPSC to increase the $635.0 million authorization to $1:4 billion through December 31, 2009.
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| In December 2007, FERC authorized KCP&L to have outstanding at any time up to a total of $800.0 million in short-term debt instruments through December 2009. The authorization is subject to four restrictions: (i) proceeds of debt backed by utility assets must be used for utility purposes; (ii) if any utility assets that secure authorized debt are divested or spun off, the debt must follow the assets and also be divested or spun off; (iii) if any proceeds of the authorized debt are used for non-utility purposes, the debt must follow the non-utility assets (specifically, if the non-utility assets are divested or spun off, then a proportionate share of the debt must follow the divested or spun off non-utility assets);
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| and (iv) if utility assets financed by the authorized short-term debt are divested or spun off to another entity, a proportionate share of the debt must also be divested or spun off.
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| Significant Financing Activities Great PlainsEnergy Great Plains Energy has an effective shelf registration statement for the sale of unspecified amounts of securities that was filed and became effective. in May 2006. During 2007, Great Plains Energy issued
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| $100.0 million of 6.875% unsecured Senior Notes. Great Plains Energy used the proceeds to make a
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| $94.0 million equity contribution to KCP&L.
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| In February 2007, Great Plains Energy exercised its rights to redeem its $163.6 million FELINE PRIDES senior notes in full satisfaction of each holder's obligation to purchase the Company's common stock under the purchase contracts and issued 5.2 million shares of common stock to the holders of the FELINE PRIDES purchase contracts.
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| In 2006, Great Plains Energy also entered into a forward sale agreement with Merrill Lynch Financial Markets, Inc. (forward purchaser) for 1.8 million shares of Great Plains Energy common stock. In April 2007, Great Plains Energy elected to terminate the forward sale agreement and settle it in cash. Based on the difference between Great Plains Energy's average stock price of $32.60 over the period used to determine the settlement and the then-applicable forward price of $25.58, Great Plains Energy paid
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| $12.3 million to Merrill Lynch Financial Markets, Inc.
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| In 2007, Great Plains Energy entered into three FSS, with a total notional amount of $250.0 million, to hedge against interest rate fluctuations on future issuances of long-term debt. The long-term debt issuance is contingent on the consummation of the acquisition of Aquila. The FSS was designed to effectively remove most of the interest rate and to the extent that swap spreads correlate with credit spreads, some degree of credit spread uncertainty with respect to the debt to be issued, thereby enabling Great Plains Energy to-predict with greater assurance its future interest costs on that debt.
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| KCP&L KCP&L has an effective shelf registration statement providing for the sale of up to $900.0 million of investment grade notes and general mortgage bonds that became effective in January 2008. This is intended to preserve KCP&L's flexibility to access the debt capital markets.
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| 48
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| In 2007, KCP&L's $146.5 million of unsecured EIRR Bonds Series 2007A and 2007B were issued. The bonds mature on September 1, 2035, and will bear interest as determined through 35-day auction periods. The EIRR Bonds Series 2007A and 2007B are covered bya municipal bond insurance policy issued by Financial Guaranty Insurance Company (FGIC). The insurance agreement between KCP&L and FGIC provides for reimbursement by KCP&L for any amounts that FGIC pays under the municipal bond insurance policy. The insurance policy is in effect for the term of the bonds. The policy also restricts the amount of secured debt KCP&L may issue. In the event KCP&L issues debt secured by liens not permitted by the agreement, KCP&L is required to issue and deliver to FGIC first mortgage bonds or similar securities equal in principal amount to the principal amount of the EIRR Bonds Series 2007A and 2007B then outstanding. The proceeds from the issuance of $146.5 million EIRR Bonds Series 2007A and 2007B were used for the repayment of $146.5 million of Series 1998 A, B and D EIRR bonds.
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| In 2007, KCP&L issued $250.0 million of 5.85% unsecured Senior Notes. The proceeds from this issuance were used to repay a short-term intercompany loan from Great Plains Energy. KCP&L used the proceeds from the intercompany loan to repay its $225.0 million unsecured 6.00% Senior Notes at maturity. -
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| In 2007, Great Plains Energy entered into three T-Locks with a notional amount of $350.0 million, to hedge against interest rate fluctuations on the U.S. Treasury rate component on future issuances of long-term debt. Following a change in financing plans, Great Plains Energy assigned the T-Locks to KCP&L. The T-Locks will settle simultaneously with the issuance of future long-term fixed rate debt issued by KCP&L. The T-Locks remove the uncertainty with respect to the U.S. Treasury rate component of the debt to be issued, thereby enabling KCP&L to predict with greater assurance its future interest costs-on that debt.
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| Debt Agreements See Note 18 to the consolidated financial statements for discussion of Great Plains Energy's, KCP&L's and Strategic Energy's revolving credit facilities.
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| Projected Utility Capital Expenditures KCP&L's cash utility capital expenditures, excluding allowance for funds used to finance construction, were $511.5 million, $475.9 million and $332.1 million in 2007, 2006 and 2005, respectively. Utility capital expenditures projected for the next three years, excluding allowance for funds used during construction, are detailed in the following table.
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| 2008 2009 2010 (millions)
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| Generating facilities $ 553.0 $ 385.7 $ 676.6 Nuclear fuel 16.0 17.5 32.0 Distribution and transmission facilities 125.7 112.4 112.3 General facilities 30.0 48.2 39.6 Total. $ 724.7 $ 563.8 $ 860.5 This utility capital expenditure plan is subject to continual review and change and includes utility capital expenditures related to KCP&L's Comprehensive Energy Plan for environmental investments and new capacity. See Note 6 to the consolidated' financial statements for additional discussion of Comprehensive Energy Plan expenditures. If the proposed acquisition of Aquila is completed, Great Plains Energy expects to increase its utility capital expenditures. See Note 2 to the consolidated financial statements for additional information.
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| 49
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| Pensions The Company maintains defined benefit plans for substantially all employees of KCP&L, Services and WCNOC and incurs significant costs in providing the plans, with the majority incurred by KCP&L.
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| Funding of the plans equals or exceeds the minimum requirements of the Employee Retirement Income Security Act of 1974 (ERISA).
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| The Company contributed $32.7 million to the plans in 2007 to meet ERISA funding requirements. In 2006, the Company contributed $19.8 million to the plans, which included $14.0 million of funding above the minimum ERISA funding requirements. The 2007 and 2006 contributions were paid by KCP&L.
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| The Company expects to contribute $29.3 million to the plans in 2008 to satisfy the funding requirements of ERISA and the 2007 MPSC and KCC rate orders, all of which will be paid by KCP&L.
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| Management believes KCP&L has adequate access to capital resources through cash flows from operations or through existing lines of credit to support the funding requirements.
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| Effective January 1, 2008, the Company amended the retirement programs for management employees (other than WCNOC employees) to allow current employees the option to remain in the existing program or to choose a new retirement program which. will provide, among other things, an enhanced benefit under the employee savings plan (401(k)) and a lower benefit accrual rate under the defined pension benefit plan. Employees hired after September 1, 2007, will be placed in the new retirement program.
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| Credit Ratings At December 31, 2007, the major credit rating agencies rated Great Plains Energy's and KCP&L's securities as detailed in the following table.
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| Moody's Standard Investors Service & Poor's Great Plains Energy Outlook Stable Credit Watch Negative Corporate Credit Rating BBB Preferred Stock Bal BB+
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| Senior Unsecured Debt Baa2 BBB-KCP&L Outlook Stable Credit Watch Negative Senior Secured Debt A2 BBB Senior Unsecured Debt A3 BBB Commercial Paper P-2 A-3 The ratings presented reflect the current views of these rating agencies and are subject to change.
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| Great Plains Energy and KCP&L view maintenance of strong credit ratings as extremely important and to that end an active and ongoing dialogue is maintained with the agencies with respect to results of operations, financial position, and future prospects. A decrease in these credit ratings would have an adverse impact on Great Plains Energy's and KCP&L's access to capital, its cost of funds, the amount of collateral required under power supply agreements and Great Plains Energy's ability to provide credit support for its subsidiaries.
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| 50
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| On February 28, 2008, Moody's Investors Service (Moody's) announced that the outlook for both Great Plains Energy and KCP&L would be changed from "Stable" to "Negative". The Negative outlook captures Moody's concern that Great Plains Energy's credit metrics and financial flexibility may be weakened more than anticipated following its acquisition of Aquila based on the current regulatory proposal before the MPSC. Moody's also cited recent disclosure by Great Plains Energy of potential cost pressures on KCP&L's latan No. 1 and latan No. 2 projects, as well as recent weakness in certain key credit metrics at KCP&L as contributing to the changed outlook. See Notes 2 and 6 to the consolidated financial statements for additional information.
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| None of Great Plains Energy's and KCP&L's outstanding debt, except for the notes associated with affordable housing investments, requires the acceleration of interest and/or principal payments in the event of a ratings downgrade, unless the downgrade occurs in the context of a merger, consolidation or sale. The anticipated acquisition of Aquila will not be a merger, consolidation or sale that would trigger acceleration of interest and/or principal payments. In the event of a downgrade, Great Plains Energy and KCP&L and/or their subsidiaries would be subject to increased interest costs on their credit facilities. The interest rate on Great Plains Energy's $100.0 million of 6.875% Senior Notes due 2017, will increase if the notes are not rated investment grade. Additionally, in KCP&L's bond insurance policies on its secured 1992 series EIRR bonds totaling $31.0 million, its Series 1993A and 1993B EIRR bonds totaling $79.5 million, its secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, and its EIRR Bonds Series 2007A and 2007B totaling $146.5 million, KCP&L has agreed to limits on its ability to issue additional mortgage bonds based on the mortgage bond's credit ratings. See Note 19 to the consolidated financial statements. The interest rates on $257.0 million of these EIRR bonds are periodically reset through auction processes. The bond insurance policies were issued by either XL Capital Assurance, Inc., (XLCA) or FGIC. Both firms and the supported KCP&L auction rate bonds were downgraded by at least two rating agencies in January and February 2008. Concerns related to municipal bond insurers' credit have adversely affected the ordinary course of operation of auctions for these types of bonds. The interest rates set in recent auctions of KCP&L's auction rate bonds have been adversely affected by these concerns, and the adverse effects are expected to continue until the bonds are changed to another interest rate mode.
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| Management is pursuing alternatives to mitigate exposure from these downgrades.
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| Strategic Energy Supplier Concentration and Credit Strategic Energy enters into forward physical contracts with multiple suppliers. At December 31, 2007, Strategic Energy's five largest suppliers under forward supply contracts represented 72% of the total future dollar committed purchases. Strategic Energy's five largest suppliers, or their guarantors, are rated investment grade. In the event of supplier non-delivery or default, Strategic Energy's results of operations could be affected to the extent the cost of replacement power exceeded the combination of the contracted price with the supplier and the amount of collateral held by Strategic Energy to mitigate its credit risk with the supplier. In addition to the collateral, if any, that the supplier provides, Strategic Energy's risk may be further mitigated by the obligation of the supplier to make a default payment equal to the shortfall and to pay liquidated damages in the event of a failure to deliver power. There is no assurance that the supplier in such an instance would make the default payment and/or pay liquidated damages. Strategic Energy's results of operations and financial position could also be affected, in a given period, if it were required to make a payment upon termination of a supplier contract to the extent the contracted price with the supplier exceeded the market value of the contract at the time of termination.
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| 51
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| | |
| The following tables provide information on Strategic Energy's credit exposure to suppliers, net of collateral, at December 31, 2007.
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| Number Of Net Exposure Of Counterparties Counterparties Exposure Greater Than Greater Than Before Credit Credit Net 10% Of Net 10% of Net Rating Collateral Collateral Exposure Exposure Exposure External rating (millions) (millions)
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| Investment Grade $ 30.0 $ - $ 30.0 5 $ 27.1 Non-lnvestment Grade 7.2 6.7 0.5 -
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| Internal rating Investment Grade 0.3 - 0.3 -
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| Non-Investment Grade - - - -
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| Total $ 37.5 $ 6.7 $ 30.8 5 $ 27.1 Maturity Of Credit Risk Exposure Before Credit Collateral Less Than Tota I Rating 2 Years 2 - 5 Years Exposure External rating (millions)
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| Investment Grade $ 1.6 $ 28.4 $ 30.0 Non-Investment Grade 4.4 2.8 7.2 Internal rating Investment Grade 0.3 0.3 Non-Investment Grade -
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| Total $ 6.3 $ 31.2 $ 37.5 External ratings are determined by using publicly available credit ratings of the counterparty. If a counterparty has provided a guarantee by a higher rated entity, the determination has been based on the rating of its guarantor. Internal ratings are determined by, among other things, an analysis of the counterparty's financial statements and consideration of publicly available credit ratings of the counterparty's parent. Investment grade counterparties are those with a minimum senior unsecured debt rating of BBB- from Standard & Poor's or Baa3 from Moody's. Investors Service. Exposure before credit collateral has been calculated considering all netting agreements in place, netting accounts payable and receivable exposure with net mark-to-market exposure. Exposure before credit collateral, after consideration of all netting agreements, is impacted significantly by the power supply volume under contract with a given counterparty and the relationship between current market prices and contracted power. supply prices. Credit collateral includes the amount of cash deposits and letters of credit received from counterparties. Net exposure has only been calculated for those counterparties to which Strategic Energy is exposed and excludes counterparties exposed to Strategic Energy.
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| At December 31, 2007, Strategic Energy had exposure before collateral to non-investment grade counterparties totaling $7.2 million. In addition, Strategic Energy held collateral totaling $6.7 million limiting its exposure to these non-investment grade counterparties to $0.5 million.
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| Where available, Strategic Energy contracts with national and regional counterparties that have direct supplies and assets in the region of demand. Strategic Energy also manages its counterparty portfolio through disciplined margining, collateral requirements and contract-based netting of credit exposures against payable balances.
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| 52
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| Supplemental Capital Requirements and Liquidity Information The information in the following tables is provided to summarize cash obligations and commercial commitments.
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| Great PlainsEnergy ContractualObligations Payment due by period 2008 2009 2010 2011 2012 After 2012 Total Long-term debt (millions)
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| Principal $ 0.3 $ - $ - $150.0 $ 12.4 $ 942.9 $1,105.6 Interest 62.2 62.2 62.2 61.0 52.0 713.2 1,012.8 Lease obligations 18.8 15.3 9.1 8.2 8.0 75.1 134.5 Pension plans 29.3 (a) (a) (a) (a) (a) 29.3 Purchase obligations Fuel 120.0. 68.1 65.4 12.2 15.3 187.3 468.3 Purchased capacity 9.0 8.6 6.3 4.7 4.7 10.8 44.1 Purchased power 738.9 382.9 261.4 146.8 34.5 - 1,564.5 Comprehensive Energy Plan. 705.4 286.7 53.1 - - - 1,045.2 Other 101.3 19.5 27.8 10.2 11.3 22.4 192.5 Total contractual obligations $1,785.2 $843.3 $485.3 $393.1 $138.2 $1,951.7 $5,596.8 (a)Contributions expected beyond 2008 but not yet determined.
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| ConsolidatedKCP&L ContractualObligations Payment due by period 2008 2009 2010 2011 2012 After 2012 Total Long-term debt (millions)
| |
| Principal $ - $ - $ - $150.0 $ 12.4 $ 842.9 $1,005.3 Interest 55.3 55.3 55.3 54.1 45.1 680.9 946.0 Lease obligations .17.4 14.1 8.7 7.8 7.7 74.7 130.4 Pension plans 29.3 (a) (a) (a) (a) (a) 29.3 Purchase obligations Fuel 120.0 68.1 65.4 12.2 15.3 187.3 468.3 Purchased capacity 9.0 8.6 6.3 4.7 4.7 10.8 44.1 Comprehensive Energy Plan 705.4 286.7 53.1 - - - 1,045.2 Other 101.3 19.5 27.8 10.2 11.3 22.4 192.5 Total contractual obligations $1,037.7 $452.3 $216.6 $239.0 $ 96.5 $1,819.0 $3,861.1 (a) Contributions expected beyond 2008 but not yet determined.
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| Long-term debt includes current maturities. Great Plains Energy's long-term debt principal excludes
| |
| $2.4 million of discounts on senior notes. KCP&L's long-term debt principal excludes $1.9 million of discounts on senior notes. Variable rate interest obligations are based on rates as of December 31, 2007. See Note 19 to the consolidated financial statements for additional information.
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| Lease commitments end in 2028 and include capital and operating lease obligations; capital lease obligations are $0.2 million per year for the years 2008 through 2012 and total $3.7 million after 2012.
| |
| Lease obligations also include railcars to serve jointly-owned generating units where KCP&L is the managing partner. KCP&L will be reimbursed by the other owners for approximately $2.0 million per year ($19.3 million total) of the amounts included in the tables above.
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| The Company expects to contribute $29.3 million to the pension plans in 2008 to satisfy the funding requirements of ERISA and the 2007 MPSC and KCC rate orders, all of which will be paid by KCP&L.
| |
| Additional contributions to the plans are expected beyond 2008 in amounts sufficient to meet ERISA funding requirements; however, these amounts have not yet been determined.
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| 53
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| Fuel represents KCP&L's 47% share of Wolf Creek nuclear fuel commitments, KCP&L's share of coal purchase commitments based on estimated prices to supply coal for generating plants and KCP&L's-share of rail transportation commitments for moving coal to KCP&L's generating units.
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| KCP&L purchases capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total $11.2 million per year for 2008 through 2011, $6.9 million in 2012 and $1.6 million in 2013.
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| Purchased power represents Strategic Energy's agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Strategic Energy has firm energy sales contracts for 2008 not included above totaling $16.8 million.
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| Comprehensive Energy Plan represents KCP&L's contractual commitments for projects included in its Comprehensive Energy Plan, including jointly owned units. KCP&L expects to be reimbursed by other owners for their respective share of latan No. 2 and environmental retrofit costs included in the Comprehensive Energy Plan contractual commitments. Other purchase obligations represent individual commitments entered into in the ordinary course of business..
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| Strategic Energy has entered into financial swaps in certain markets to limit the unfavorable effect that future price increases will have on future electricity purchases. These financial swaps settle during the same period as power flows to the retail customer and could result in a cash obligation or a cash receipt. Due to the uncertainty of the future cash flows,' these financial swaps have been omitted from the table above.
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| Great Plains Energy and consolidated KCP&L adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes," an interpretation of SFAS No. 109, "Accounting for Income Taxes" on January 1, 2007. At December 31, 2007, the total liability for unrecognized tax benefits for Great Plains Energy and consolidated KCP&L was $21.9 million and $19.6 million, respectively. Great Plains Energy and consolidated KCP&L are unable to determine reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. An estimate of the amount of unrecognized tax benefits that may be recognized in the next twelve months was $8 million to $10 million for Great Plains Energy and $7 million to $9 million for KCP&L at December 31, 2007.
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| Great Plains Energy and consolidated KCP&L have long-term liabilities recorded on their consolidated balance sheets at December 31, 2007, that do not have a definitive cash payout date and are not included in the tables above.
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| 54
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| | |
| Off-Balance Sheet Arrangements In the normal course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees, stand-by letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended business purposes.
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| The information in the following table is provided to summarize these agreements.
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| Amount of commitment expiration per period 2008 2009 2010 2011 2012 After 2012 Total (millions)
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| Great Plains Energy Guarantees $267.5 $ 1.0 $13.4 $ - $ - $ - $ 281.9 Consolidated KCP&L Guarantees 1.0 1.0 0.9 - - - 2.9 KCP&L is contingently liable for guaranteed energy savings under an agreement with a customer, guaranteeing an aggregate value of approximately $2.9 million over the next three years. A subcontractor would indemnify KCP&L for any payments made by KCP&L under this guarantee. Great Plains Energy has provided $279.0 million of credit support for certain Strategic Energy power purchases and regulatory requirements. At December 31, 2007, credit support related to Strategic Energy is as follows:
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| " Great Plains Energy direct guarantees to counterparties totaling $167.4 million, which expire in 2008,
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| " Great Plains Energy indemnifications to surety bond issuers totaling $0.5 million, which expire in 2008,
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| * Great Plains Energy guarantee of Strategic Energy's revolving credit facility totaling $12.5 million, which expires in 2010 and
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| " Great Plains Energy letters of credit totaling $98.6 million, which expire in 2008.
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| The table above does not include guarantees related to bond insurance policies that KCP&L has as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million, its Series 1993A and 1993B EIRR bonds totaling $79.5 million, its EIRR Bond Series 2005 totaling $85.9 million and its EIRR Bonds Series 2007A and 2007B totaling $146.5 million. The insurance agreement between KCP&L and the issuer of the bond insurance policies provides for reimbursement by KCP&L for any amounts the insurer pays under the bond insurance policies.
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| New Accounting Standards See Note 24 to the consolidated financial statements for information regarding new accounting standards.
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| 55
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| ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK In the normal course of business, Great Plains Energy and consolidated KCP&L face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operations and credit risks and are not represented in the following analysis. See Item 1A. Risk Factors and Item. 7 MD&A for further discussion of risk factors.
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| Great Plains Energy and consolidated KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects the volatility of the markets may have on its operating results. During the normal course of business, under the direction and control of internal risk management committees, Great Plains Energy's and KCP&L's hedging strategies are reviewed to determine the hedging approach deemed appropriate based upon the circumstances of each situation. Though management believes its risk management practices to be effective, it is not possible to identify and eliminate all risk. Great Plains Energy and KCP&L could experience losses, which could. have a material adverse effect on its results of operations or financial position, due to many factors, including unexpectedly large or rapid movements or disruptions in the energy markets, from regulatory-driven market rule changes and/or bankruptcy or non-performance of customers or counterparties, and/or failure of underlying transactions that have been hedged to materialize.
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| Derivative instruments are.frequently utilized to execute risk management and hedging strategies.
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| Derivative instruments, such as futures, forward contracts, swaps or options, derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives and instruments listed and traded on an exchange. Great Plains Energy and KCP&L maintain commodity-price risk management strategies that use derivative instruments to minimize significant, unanticipated net income fluctuations caused by commodity price volatility.
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| Interest Rate Risk Great Plains Energy and consolidated KCP&L manage interest expense and short and long-term liquidity through a combination of fixed and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may also be used to achieve the desired combination. Using outstanding balances and annualized interest rates as of December 31, 2007, a hypothetical 10% increase in the interest rates associated with long-term variable rate debt would result in an increase of $1.4 million in interest expense for 2008. Additionally, interest rates impact the fair value of long-term debt. KCP&L had
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| $365.8 million of commercial paper outstanding at December 31, 2007. The principal amount, which will vary during the year, of the commercial paper will drive KCP&L's commercial paper interest expense. Assuming that $365.8 million of commercial paper was outstanding for all of 2008, a hypothetical 10% increase in commercial paper rates would result in an increase of $2.2 million in interest expense for 2008. A change in interest rates would impact the Company to the extent it redeemed any of its outstanding long-term debt. Great Plains Energy's and consolidated KCP&L's book values of long-term debt approximated fair values at December 31, 2007.
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| Commodity Risk KCP&L and Strategic Energy engage in the wholesale and retail marketing of electricity and are exposed to risk associated with the price of electricity.
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| KCP&L's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity and long, intermediate and short-term capacity or power purchase agreements.
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| The agreements contain penalties for non-performance to limit KCP&L's energy price risk on the contracted energy. KCP&L also enters into additional power purchase agreements with the objective of obtaining the most economical energy to meet its physical delivery obligations to customers. KCP&L is 56
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| required to maintain a capacity margin of at least 12% of its peak summer demand. This net positive supply of capacity and energy is maintained through its generation assets and capacity and power purchase agreements to protect it from the potential operational failure of one of its power generating units. KCP&L continually evaluates the need for additional risk mitigation measures in order to minimize its financial exposure to, among other things, spikes in wholesale power prices during periods of high demand.
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| KCP&L's sales include the sales of electricity to its retail customers and bulk power sales of electricity in the wholesale market. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply, the availability and cost of purchased power and the requirements of other electric systems; therefore, the impact of the hypothetical amounts that follow could be significantly reduced depending on the system requirements and market prices at the time of the increases. A hypothetical 10% increase in the market price of power could result in a $4.0 million decrease in operating income for 2008 related to purchased power. In 2008, approximately 75% of KCP&L's net MWhs generated are expected to be coal-fired. KCP&L currently has almost all of its coal requirements for 2008 under contract. A hypothetical 10% increase in the market price of coal could result in less than a $1.0 million increase in fuel expense for 2008. KCP&L has also implemented price risk mitigation measures to reduce its exposure to high natural gas prices. A hypothetical 10% increase in natural gas and oil market prices could result in an increase of $0.4 million in fuel expense for 2008.
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| At December 31, 2007, KCP&L had hedged approximately 35% and 4% of its 2008 and 2009, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales. At December 31, 2006, KCP&L had hedged approximately 30% and 9% of its 2007 and 2008, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales.
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| Strategic Energy maintains a commodity-price risk management strategy that uses derivative instruments including forward physical energy purchases, to minimize significant, unanticipated net income fluctuations caused by commodity-price volatility. In certain markets where Strategic Energy operates, entering into forward fixed price contracts is cost prohibitive. Financial derivative instruments, including swaps, are used to limit the unfavorable effect that price increases will have on electricity purchases, effectively fixing the future purchase price of electricity for the applicable forecasted usage and protecting Strategic Energy from significant price volatility. A hypothetical 10% increase in the market price of purchased power could result in a $13.0 million increase in purchased power expense for 2008.
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| Strategic Energy has historically utilized certain derivative instruments to protect against significant price volatility for purchased power that have qualified for the NPNS exception, in accordance with SFAS No. 133, as amended. However, as certain markets continue to develop, some derivative instruments may no longer qualify for the NPNS exception. As such, Strategic Energy is designating these derivative instruments as cash flow hedges, where appropriate, which could result in future increased volatility in derivative assets and liabilities, OCI and net income above levels historically experienced. Derivative instruments that were designated as NPNS are accounted for by accrual accounting, which requires the effects of the derivative to be recorded when the derivative contract settles. Accordingly, the increase in derivatives accounted for as cash flow hedges, and the corresponding decrease in derivatives accounted for as NPNS transactions, may affect the timing and nature of accounting recognition, but does not change the underlying economics of the transactions.
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| Investment Risk KCP&L maintains trust funds, as required by the NRC, to fund its share of decommissioning the Wolf Creek nuclear power plant. As of December 31, 2007, these funds were invested primarily in domestic equity securities and fixed income securities and are reflected at fair value on KCP&L's balance sheets.
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| The mix of securities is designed to provide returns to be used to fund decommissioning and to 57
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| compensate for inflationary increases in decommissioning costs; however, the equity securities in the trusts are exposed to price fluctuations in equity markets and the value of fixed rate fixed income securities are exposed to changes in interest rates. A hypothetical increase in interest rates resulting in a hypothetical 10% decrease in the value of the fixed income securities would have resulted in a $5.6 million reduction in the value of the decommissioning trust funds at December 31, 2007. A hypothetical 10% decrease in equity prices would have resulted in a $5.2 million reduction in the fair value of the equity securities at December 31, 2007. KCP&L's exposure to investment risk associated with the decommissioning trust funds is in large part mitigated due to the fact that KCP&L is currently allowed to recover its decommissioning costs in its rates.
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| KLT Investments has affordable housing notes that require the greater of 15% of the outstanding note balances or the next annual installment to be held as cash, cash equivalents or marketable securities.
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| A hypothetical 10% decrease in market prices of the securities held as collateral would have an insignificant impact on pre-tax net income for 2008.
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| 58
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| ITEM 8. CONSOLIDATED FINANCIALS STATEMENTS GREAT PLAINS ENERGY Consolidated Statements of Income Year Ended December 31 2007 2006 2005 Operating Revenues (millions, except per shares amounts)
| |
| Electric revenues - KCP&L $ 1,292.7 $ 1,140.4 $ 1,130.8 Electric revenues - Strategic Energy 1,972.8 1,532.1 1,471.5 Other revenues 1.6 2.8 2.6 Total 3,267.1 2,675.3 2,604.9 Operating Expenses Fuel 245.5 229.5 208.4 Purchased power - KCP&L 101.0 26.4 61.3 Purchased power - Strategic Energy 1,830.7 1,490.3 1,368.4 Skill set realignment (deferral) cost (Note 8) (8.9) 9.4 Operating expenses - KCP&L 295.8 260.3 263.4 Selling, general and administrative - non-regulated 91.7 67.7 62.0 Maintenance 91.7 83.8 90.0 Depreciation and amortization 183.8 160.5 153.1 General taxes 115.8 112.6 109.4 (Gain) loss on property (0.6) 3.5 Other 0.2 2.4 Total 2,947.3 2,439.9 2,321.9 Operating income 319.8 235.4 283.0 Non-operating income 12.4 19.9 19.5 Non-operating expenses (5.7) (6.7) (16.8)
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| Interest charges (93.8) (71.2) (73.8)
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| Income from continuing operations before income taxes, minority interest in subsidiaries and loss from equity investments 232.7 177.4 211.9 Income taxes (71.5) (47.9) (39.5)
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| Minority interest in subsidiaries (7.8)
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| Loss from equity investments, net of income taxes (2.0) (1.9) (0.4)
| |
| Income from continuing operations 159.2 127.6 164.2 Discontinued operations, net of income taxes (Note 11) (1.9)
| |
| Net income 159.2 127.6 162.3 Preferred stock dividend requirements 1.6 1.6 1.6 Earnings available for common shareholders $ 157.6 $ 126.0 $ 160.7 Average number of basic common shares outstanding 84.9 78.0 74.6 Average number of diluted common shares outstanding 85.2 78.2 74.7 Basic earnings (loss) per common share Continuing operations $ 1.86 $ 1.62 $ 2.18 Discontinued operations - - (0.03)
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| Basic earnings per common share $ 1.86 $ 1.62 $ 2.15 Diluted earnings (loss) per common share Continuing operations $ 1.85 $ 1.61 $ 2.18 Discontinued operations - - (0.03)
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| Diluted earnings per common share $ 1.85 $ 1.61 $ 2.15 Cash dividends per common share $ 1.66 $ 1.66 $ 1.66 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 59
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| GREAT PLAINS ENERGY Consolidated Balance Sheets December 31 2007 2006 ASSETS (millions, except share amounts)
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| Current Assets Cash and cash equivalents $ 67.1 $ 61.8 Restricted cash 0.7 Receivables, net 427.4 339.4 Fuel inventories, at average cost 35.9 27.8 Materials and supplies, at average cost 64.0 59.8 Deferred refueling outage costs 6.5 13.9 Refundable income taxes 10.7 9.8 Deferred income taxes 19.8 39.6 Derivative instruments 7.6 6.9 Other 15.2 11.8 Total 654.9 570.8 Nonutility Property and Investments Affordable housing limited partnerships 17.3 23.1 Nuclear decommissioning trust fund 110.5 104.1 Other 14.3 15.6 Total 142.1 142.8 Utility Plant, at Original Cost Electric 5,450.6 5,268.5 Less-accumulated depreciation 2,596.9 2,456.2 Net utility plant in service 2,853.7 2,812.3 Construction work in progress 530.2 214.5 Nuclear fuel, net of amortization of $120.2 and $103.4 60.6 39.4 Total 3,444.5 3,066.2 Deferred Charges and Other Assets Regulatory assets 400.1 434.4 Goodwill 88.1 88.1 Derivative instruments 45.8 3.5 Other 51.2 29.9 Total 585.2 555.9 Total $ 4,826.7 $ 4,335.7 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 60
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| GREAT PLAINS ENERGY Consolidated Balance Sheets December 31 2007 2006 LIABILITIES AND CAPITALIZATION (millions, except share amounts)
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| Current Liabilities Notes payable $ 42.0 $
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| Commercial paper 365.8 156.4 Current maturities of long-term debt 0.3 389.7 EIRR bonds classified as current 144.7 Accounts payable 406.5 322.7 Accrued taxes 24.8 24.1 Accrued interest 16.7 14.1 Accrued compensation and benefits 22.5 33.3 Pension and post-retirement liability 1.3 1.0 Derivative instruments 81.0 91.5 Other 29.3 25.5 Total 990.2 1,203.0 Deferred Credits and Other Liabilities Deferred income taxes 624.8 622.8 Deferred investment tax credits 27.0 28.5 Asset retirement obligations 94.5 91.8 Pension and post-retirement liability 157.2 176.2 Regulatory liabilities 144.1 114.7 Derivative instruments 1.6 61.1 Other 77.5 49.2 Total 1,126.7 1,144.3 Capitalization Common shareholders' equity Common stock-1 50,000,000 shares authorized without par value 86,325,136 and 80,405,035 shares issued, stated value 1,065.9 896.8 Retained earnings 506.9 493.4 Treasury stock-90,929 and 53,499 shares, at cost (2.8) (1.6)
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| Accumulated other comprehensive loss (2.1) (46.7)
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| Total 1,567.9 1,341.9 Cumulative preferred stock $100 par value 3.80% - 100,000 shares issued 10.0 10.0 4.50% - 100,000 shares issued 10.0 10.0 4.20% - 70,000 shares issued 7.0 7.0 4.35% - 120,000 shares issued 12.0 12.0 Total 39.0 39.0 Long-term debt (Note 19) 1,102.9 607.5 Total 2,709.8 1,988.4 Commitments and Contingencies (Note 13)
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| Total $ 4,826.7 $ 4,335.7 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 61
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| GREAT PLAINS ENERGY Consolidated Statements of Cash Flows Year Ended December 31 2007 2006 2005 Cash Flows from Operating Activities (millions)
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| Net income $ 159.2 $ 127.6 $ 162.3 Adjustments to reconcile income to net cash from operating activities:
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| Depreciation and amortization 183.8 160.5 153.1 Amortization of:
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| Nuclear fuel 16.8 14.4 13.4 Other 7.4 9.4 10.5 Deferred income taxes, net 23.8 (11.0) (23.2)
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| Investment tax credit amortization (1.5) (1.2) (3.9)
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| Loss from equity investments, net of income taxes 2.0 1.9 0.4 (Gain) loss on property (0.6) 3.3 Minority interest in subsidiaries 7.8 Fair value impacts from energy contracts (52.8) 56.7 (2.5)
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| Fair value impacts from interest rate hedging 17.9 Other operating activities (Note 3) (24.4) (48.8) 95.6 Net cash from operating activities 332.2 308.9 416.8 Cash Flows from Investing Activities Utility capital expenditures (511.5) (475.9) (327.3)
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| Allowance for borrowed funds used during construction (14.4) (5.7) (1.6)
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| Purchases of investments (15.0)
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| Purchases of nonutility property (4.5) (4.2) (6.8)
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| Proceeds from sale of assets and investments 0.1 0.4 17.4 Purchases of nuclear decommissioning trust investments (58.0) (49.7) (34.6)
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| Proceeds from nuclear decommissioning trust investments 54.3 46.0 31.0 Purchase of additional indirect interest in Strategic Energy (0.7)
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| Hawthorn No. 5 partial insurance recovery 10.0 Hawthorn No. 5 partial litigation recoveries 15.8 Other investing activities (13.0) (1.7) (0.9)
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| Net cash from investing activities (547.0) (475.7) (327.8)
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| Cash Flows from Financing Activities Issuance of common stock 10.5 153.6 9.1 Issuance of long-term debt 495.6 - 334.4 Issuance fees (5.7) (6.2) (4,5)
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| Repayment of long-term debt (372.5) (1.7) (339.2)
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| Net change in short-term borrowings 251.4 118.5 17.9 Dividends paid (144.5) (132.6) (125.5)
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| Equity forward settlement (12.3)
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| Other financing activities (2.4) (6.1) (5.9)
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| Net cash from financing activities 220.1 125.5 (113.7)
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| Net Change in Cash and Cash Equivalents 5.3 (41.3) (24.7)
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| Cash and Cash Equivalents at Beginning of Year (includes $0.6 million of cash included in assets of discontinued operations in 2005) 61.8 103.1 127.8 Cash and Cash Equivalents at End of Year $ 67.1 $ 61.8 $ 103.1 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 62
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| GREAT PLAINS ENERGY Consolidated Statements of Common Shareholders' Equity Year Ended December 31 2007 2006 2005 Shares Amount Shares Amount Shares Amount Common Stock (millions, except share amounts)
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| Beginning balance 80,405,035 $ 896.8 74,783,824 $ 744.5 74,394,423 $ 732.0 Issuance of common stock 5,571,574 174.1 5,574,385 153.6 313,026 9.4 Issuance of restricted common stock 348,527 11.1 46,826 1.3 76,375 2.3 Common stock issuance fees (5.2)
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| Equity compensation expense 2.1 2.6 1.4 Equity forward settlement (12.3)
| |
| Unearned Compensation Issuance of restricted common stock (11.1) (1.4) (2.4)
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| Forfeiture of restricted common stock 0.2 0.1 0.3 Compensation expense recognized 4.8 1.3 1.4 Other 0.2 0.1 Ending balance 86,325,136 1,065.9 80,405,035 896.8 74,783,824 744.5 Retained Earnings Beginning balance 493.4 498.6 462.1 Cumulative effect of a change in accounting principle (Note 10) (0.9)
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| Net income 159.2 127.6 162.3 Dividends:
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| Common stock (142.9) (131.0) (123.8)
| |
| Preferred stock - at required rates (1.6) (1.6) (1.6)
| |
| Performance shares (0.3) (0.2) (0.3)
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| Options (0.1)
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| Ending balance 506.9 493.4 498.6 Treasury Stock Beginning balance (53,499) (1.6) (43,376) (1.3) (28,488) (0.9)
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| Treasury shares acquired (37,430) (1.2) (11,338) (0.3) (18,385) (0.5)
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| Treasury shares reissued - 1,215 3,497 0.1 Ending balance (90,929) (2.8) (53,499) (1.6) (43,376) (1.3)
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| Accumulated Other Comprehensive Income (Loss)
| |
| Beginning balance (46.7) (7.7) (41.0)
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| Derivative hedging activity, net of tax 43.2 (74.7) 28.4 Change in unrecognized pension expense, net of tax 1.4 Minimum pension obligation, net of tax 15.9 4.9 Adjustment to initially apply SFAS No. 158, net of tax (170.2)
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| Regulatory adjustment 190.0 Ending balance (2.1) (46.7) (7.7)
| |
| Total Common Shareholders' Equity $ 1,567.9 $ 1,341.9 $ 1,234.1 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 63
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| GREAT PLAINS ENERGY Consolidated Statements of Comprehensive Income Year Ended December 31 2007 2006 2005.
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| (millions)
| |
| Net income $ 159.2 $ 127.6 $.162.3 Other comprehensive income (loss)
| |
| Gain (loss) on derivative hedging instruments (8.4) (181.5) 84.1 Income taxes -2.4 75.0 (34.7)
| |
| Net gain (loss) on derivative hedging instruments (6.0) (106.5) 49.4 Reclassification to expenses, net of tax 49.2 31.8 (21.0)
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| Derivative hedging activity, net of tax 43.2 (74.7) 28.4 Defined benefit pension plans Net gains arising during period 2.0 --
| |
| Less: amortization of net gains included in net periodic benefit costs 0.4 --
| |
| Prior service costs arising during the period (0.3) --
| |
| Less: amortization of prior service costs included in net periodic benefit costs 0.1 --
| |
| Income taxes (0.8) --
| |
| Net change in unrecognized pension expense 1.4 --
| |
| Change in minimum pension obligation - 25.5 8.7 Income taxes (9.6) (3.8)
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| Net change in minimum pension obligation -15.9 4.9 Comprehensive income $ 203.8 $ 68.8 $ 195.6 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 64
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| KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Income Year Ended December 31 2007 2006 2005 Operating Revenues (millions)
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| Electric revenues $.1,292.7 $ 1,140.4 $ 1,130.8 Other revenues - 0.1 Total 1,292.7 1,140.4 1,130.9 Operating Expenses Fuel 245.5 229.5 208.4 Purchased power 101.0 26.4 61.3 Skill set realignment (deferral) cost (Note 8) (8.9) 9.3 Operating expenses 295.8 260.3 263.4 Maintenance 90.9 .83.8 90.0 Depreciation and amortization 175.6 152.7 146.6 General taxes 113.7 108.0 104.7 (0.6)
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| (Gain) loss on property 4.6 Other 0.2 2.4 Total 1,013.8 869.4 881.4 Operating income 278.9 271.0 249.5 Non-operating income 8.0 15.0 16.1 Non-operating expenses (3.7) (5.4) (4.3)
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| Interest charges (67.2) (61.0) (61.8)
| |
| Income before income taxes and minority interest in subsidiaries 216.0 219.6 199.5 Income taxes (59.3) (70.3) (48.0)
| |
| Minority interest in subsidiaries - (7.8)
| |
| Net income $ 156.7 $ 149.3 $ 143.7 The-disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 65
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| KANSAS CITY POWER & LIGHT COMPANY Consolidated Balance Sheets December 31 2007 2006 ASSETS (millions, except share amounts)
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| Current Assets Cash and cash equivalents $ 3.2 $ 1.8 Receivables, net 176.4 114.3 Fuel inventories, at average cost 35.9 27.8 Materials and supplies, at average cost 64.0 59.8 Deferred refueling outage costs ,6.5 13.9 Refundable income taxes 16.6 7.2 Deferred income taxes 3.4 0.1 Prepaid expenses 10.4 9.7 Derivative instruments 0.7 0.2 Total .317.1 234.8 Nonutility Property and Investments Nuclear decommissioning trust fund 110.5 104.1 Other 6.2 6.4 Total 116.7 110.5 Utility Plant, at Original Cost Electric 5,450.6 5,268.5 Less-accumulated depreciation 2,596.9 2,456.2 Net utility plant in service 2,853.7 2,812.3 Construction work in progress 530.2 214.5 Nuclear fuel, net of amortization of $120.2 and $103.4 60.6 39.4
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| *Total 3,444.5 3,066.2 Deferred Charges and Other Assets Regulatory assets 400.1 434.4 Other 13.6 13.6 Total 413.7 448.0 Total $ 4,292.0 $ 3,859.5 The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 66
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| KANSAS CITY POWER & LIGHT COMPANY Consolidated Balance Sheets December 31 2007 2006 LIABILITIES AND CAPITALIZATION (millions, except share amounts)
| |
| Current Liabilities
| |
| *Notes payable to Great Plains Energy $ 0.6 $ 0.6 Commercial paper 365.8 156.4 Current maturities of long-term debt 225.5 EIRR bonds classified as current 144.7 Accounts payable 243.4 181.8 Accrued taxes 19.0 18.2 Accrued interest 9.6 12.5 Accrued compensation and benefits 21.6 24.6 Pension and post-retirement liability 1.1 0.8 Derivative instruments 28.0 2.7 Other 8.7 8.5 Total 697.8 776.3 Deferred Credits and Other Liabilities Deferred income taxes 642.2 660.0 Deferred investment tax credits 27.0 28.5 Asset retirement obligations 94.5 91.8 Pension and post-retirement liability 149.4 164.2 Regulatory liabilities 144.1 114.7 Other 54.2 33.7 Total 1,111.4 1,092.9 Capitalization Common shareholder's equity Common stock-1,000 shares authorized without par value 1 share issued, stated value 1,115.6 1,021.6 Retained earnings 371.3 354.8 Accumulated other comprehensive income (loss) (7.5) 6.7 Total 1,479.4 1,383.1 Long-term debt (Note 19) 1,003.4 607.2 Total 2,482.8 1,990.3 Commitments and Contingencies (Note 13)
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| Total $ 4,292.0 $ 3,859.5 The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 67
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| KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Cash Flows Year Ended December 31 2007 2006 2005 Cash Flows from Operating Activities (millions)
| |
| Net income $ 156.7 $ 149.3 $ 143.7 Adjustments to reconcile income to net cash from operating activities:
| |
| Depreciation and amortization 175.6. 152.7 146.6 Amortization of:
| |
| Nuclear fuel 16.8 14.4 13.4 Other 4.6 6.6 7.7 Deferred income taxes, net 19.7 17.4 (33.6)
| |
| Investment tax credit amortization (1.5) (1.2) (3.9)
| |
| Fair value impacts from interest rate hedging 1.4 (Gain) loss on property (0.6) 4.6 Minority interest in subsidiaries 7.8 Other operating activities (Note 3) (18.5) (39.4) 79.3 Net cash from operating activities 354.8 299.2 365.6 Cash Flows from Investing Activities Utility capital expenditures (511.5) (475.9) (332.1)
| |
| Allowance for borrowed funds used during construction (14.4) (5.7) (1.6)
| |
| Purchases of nonutility property (0.1) (0.1) (0.1)
| |
| Proceeds from sale of assets 0.1 0.4 0.5 Purchases of nuclear decommissioning trust investments (58.0) (49.7) (34.6)
| |
| Proceeds from nuclear decommissioning trust investments 54.3 46.0 31.0 Hawthorn No. 5 partial insurance recovery - - 10.0 Hawthorn No. 5 partial litigation recoveries - 15.8 -
| |
| Other investing activities (7.6) (0.9) (0.9)
| |
| Net cash from investing activities (537.2) (470.1) (327.8)
| |
| Cash Flows from Financing Activities Issuance of long-term debt 396.1 334.4 Repayment of long-term debt (372.0) - (335.9)
| |
| Net change in short-term borrowings 209.4 124.6 32.4 Dividends paid to Great Plains Energy (140.0) (89.0) (112.7)
| |
| Equity contribution from Great Plains Energy 94.0 134.6 Issuance fees (3.7) (0.5) (4.6)
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| Net cash from financing activities 183.8 169.7 (86.4)
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| Net Change in Cash and Cash Equivalents 1.4 (1.2) (48.6)
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| Cash and Cash Equivalents at Beginning of Year 1.8 3.0 51.6 Cash and Cash Equivalents at End of Year $ 3.2 $ 1.8 $ 3.0 The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 68
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| KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Common Shareholder's Equity Year Ended December 31 2007 2006 2005 Shares Amount Shares Amount Shares Amount Common Stock (millions, except share amounts)
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| Beginning balance 1 $ 1,021.6 1 $ 887.0 1 $ 887.0 Equity contribution from Great Plains Energy - 94.0 - 134.6 -
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| Ending balance 1 1,115.6 1 1,021.6 1 887.0 Retained Earnings Beginning balance 354.8 294.5 263.5 Cumulative effect of a change in accounting principle (Note 10) (0.2)
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| Net income 156.7 149.3 143.7 Dividends:
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| Common stock held by Great Plains Energy (140.0) (89.0) (112.7)
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| Ending balance 371.3 354.8 294.5 Accumulated Other Comprehensive Income (Loss)
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| Beginning balance 6.7 (29.9) (40.3)
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| Derivative hedging activity, net of tax (14.2) (0.7) 7.6 Minimum pension obligation, net of tax 15.9 2.8 Adjustment to initially apply SFAS No. 158 (168.6)
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| Regulatory adjustment 190.0 Ending balance .(7.5) 6.7 (29.9)
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| Total Common Shareholder's Equity $ 1,479.4 $ 1,383.1 $ 1,151.6 The disclosures regarding consolidated KCP&L included inthe accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 69
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| KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Comprehensive Income Year Ended December 31 2007 2006 2005 (millions)
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| Net income $ 156.7 $ 149.3 $ 143.7 Other comprehensive income Gain (loss) on derivative hedging instruments (22.1) (0.8) 12.7 Income taxes 8.3 0.3 (4.8)
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| Net gain (loss) on derivative hedging instruments (13.8) (0.5) 7.9 Reclassification to expenses, net of tax (0.4) (0.2) (0.3)
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| Derivative hedging activity, net of tax (14.2) (0.7) 7.6 Change in minimum pension obligation - 25.5 5.4 Income taxes - (9.6) (2.6)
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| Net change in minimum pension obligation - 15.9 2.8 Comprehensive income $ 142.5 $ 164.5 $ 154.1 The disclosures regarding consolidated KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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| 70
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| GREAT PLAINS ENERGY INCORPORATED KANSAS CITY POWER & LIGHT COMPANY Notes to Consolidated Financial Statements The notes to consolidated financial statements that follow are a combined presentation for Great Plains Energy Incorporated and Kansas City Power & Light Company, both registrants under this filing. The terms "Great Plains Energy," "Company," "KCP&L" and "consolidated KCP&L" are used throughout this report. "Great Plains Energy" and the "Company" refer to Great Plains Energy Incorporated and its consolidated subsidiaries, unless otherwise indicated. "KCP&L" refers to Kansas City Power & Light Company, and "consolidated KCP&L" refers to KCP&L and its consolidated subsidiaries.
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| : 1.
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| ==SUMMARY==
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| OF SIGNIFICANT ACCOUNTING POLICIES Organization Great Plains Energy, a Missouri corporation incorporated in 2001, is a public utility holding company and does not own or operateany significant assets other than the stock of its subsidiaries. Great Plains Energy has four wholly owned direct subsidiaries with operations or active subsidiaries:
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| " KCP&L is an integrated, regulated electric utility that provides electricity to customers primarily in the states of Missouri and Kansas. At the end of 2007, KCP&L had two wholly owned subsidiaries, Kansas City Power & Light Receivables Company (Receivables Company) and Home Service Solutions Inc. (HSS). HSS has no active operations and effective January 2, 2008, its ownership was transferred to KLT Inc.
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| * KLT Inc. is an intermediate holding company that primarily holds indirect interests in Strategic Energy, L.L.C. (Strategic Energy), which provides competitive retail electricity supply services in several electricity markets offering retail choice, and holds investments in affordable housing limited partnerships. KLT Inc. also wholly owns KLT Gas Inc. (KLT Gas) and KLT Telecom Inc.,
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| which have no active operations.
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| * Innovative Energy Consultants Inc. (IEC) is an intermediate holding company that holds an indirect interest in Strategic Energy. IEC does not own or operate any assets other than its indirect interest in Strategic Energy. When combined with KLT Inc.'s indirect interest in Strategic Energy, the Company indirectly owns 100% of Strategic Energy.
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| * Great Plains Energy Services Incorporated (Services) provides services at cost to Great Plains Energy and its subsidiaries, including consolidated KCP&L.
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| The operations of Great Plains Energy and its subsidiaries are divided into two reportable segments, KCP&L and Strategic Energy. Great Plains Energy's legal structure differs from the functional management and financial reporting of its reportable segments. Other activities not considered a reportable segment include HSS, Services, all KLT Inc. activity other than Strategic Energy, and holding company operations.
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| Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less at acquisition. For Great Plains Energy, this includes Strategic Energy's cash held in trust of $8.8 million at December 31, 2006.
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| 71
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| Prior to September 30, 2007, Strategic Energy had entered into collateral arrangements with selected electricity power suppliers that required selected customers to remit payment to lockboxes that were held in trust and managed by a trustee. As part of the trust administration, the trustee remitted payment to the supplier of electricity purchased by Strategic Energy. On a monthly basis, any remittances into the lockboxes in excess of disbursements to the supplier were remitted back to Strategic Energy.
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| Restricted Cash Restricted cash consists of certain Strategic Energy customer deposits that are either legally restricted or restricted by Strategic Energy's business practice.
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| Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value.
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| Nonutility property and investments - Consolidated KCP&L's nonutility property and investments includes nuclear decommissioning trust fund assets recorded at fair value. Fair value is based on quoted market prices of the investments held by the fund. In addition to consolidated KCP&L's investments, Great Plains Energy's nonutility property and investments include KLT Investments Inc.'s (KLT Investments) affordable housing limited partnerships. The fair value of KLT Investments' affordable housing limited partnership total portfolio, based on the discounted cash flows generated by tax credits, tax deductions and sale of properties, approximates book value. 'The fair values of other various investments are not readily determinable and the investments are therefore stated atcost.
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| Long-term debt - The incremental borrowing rate for similar debt was used to determine fair value if quoted market prices were not available. Great Plains Energy's and consolidated KCP&L's book values of long-term debt approximated fair values at December 31, 2007..
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| Derivative instruments - The fair value of derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlation among power and fuel prices, net of estimated credit risk.
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| Pension plans - For financial reporting purposes, the market value of plan assets is the fair value. For regulatory reporting purposes, fair value is determined using a five-year smoothing of assets.
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| Derivative Instruments The Company accounts for derivative instruments in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
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| as amended. This statement generally requires derivative instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships.
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| The Company enters into derivative contracts to manage its exposure to commodity price fluctuations and interest rate risk. Derivative instruments designated as normal purchases and normal sales (NPNS) and cash flow hedges are used solely for hedging purposes and are not issued or held for speculative reasons.
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| 72
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| The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception. The Company may elect the NPNS exception, which requires the effects of the derivative to be recorded when the underlying contract settles. The Company accounts for derivative instruments that are not designated as NPNS as cash flow hedges or non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value. In addition, if a derivative instrument is designated as a cash flow hedge, the Company documents its method of determining hedge effectiveness and measuring ineffectiveness. See Note 22 for additional information regarding derivative financial instruments and hedging activities.
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| Investments in Affordable Housing Limited Partnerships At December 31, 2007, KLT Investments had $17.3 million of investments in affordable housing limited partnerships. Approximately 77% of these investments were-recorded at cost; the equity method was used for the remainder. The investments generate future cash flows from tax credits and tax losses of the partnerships. The investments also generate cash flows from the sales of the properties. For most investments, tax credits are received over ten years. Tax expense is reduced in the year tax credits are generated. A change in accounting principle relating to investments made after May 19, 1995, requires the use of the equity method when a company owns more than 5% in a limited partnership investment.
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| Of the investments recorded at cost, $13.0 million exceed this 5% level but were made before May 19, 1995. Management does not anticipate making significant additional investments in affordable housing limited partnerships at this time.
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| On a quarterly basis, KLT Investments compares the cost of those properties accounted for by the cost method to the total of projected residual value of the properties and remaining tax credits to be received. Based on the latest comparison, KLT Investments reduced its investments in affordable housing limited partnerships by $2.0 million, $1.2 million and $10.0 million in 2007, 2006 and 2005, respectively. These amounts are included in non-operating expenses on Great Plains Energy's consolidated statements of income. The properties underlying the partnership investments are subject to certain risks inherent in real estate ownership and management.
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| Other Nonutility Property Great Plains Energy's and consolidated KCP&L's other nonutility property includes land, buildings and improvements (43-year life), general office equipment (5- to 7-year life) and software (3- to 5-year life) and is recorded at historical cost, net of accumulated depreciation.
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| Utility Plant KCP&L's utility plant is stated at historical cost. These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits. Replacements, improvements and additions, to units of property are capitalized. Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under Deferred Refueling Outage Costs). When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation. Substantially all utility plant is pledged as collateral for KCP&L's mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented.
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| As prescribed by the Federal Energy Regulatory Commission (FERC), Allowance for Funds used During Construction (AFDC) is charged to the cost of the plant. AFDC is included in the rates charged to customers by KCP&L over the service life of the property. AFDC equity funds are included as a non-.
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| cash item in non-operating income and AFDC borrowed funds are a reduction of interest charges. The rates used to compute gross AFDC are compounded semi-annually and averaged 6.3% in 2007, 7.8%
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| in 2006 and 7.1% in 2005.
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| 73
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| The balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following table.
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| December 31 2007 2006 Utility Plant, at original cost (millions)
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| Production (23 - 42 years) $ 3,197.2 $ 3,135.6 Transmission (27 - 76 years) 382.8 364.3 Distribution (8 - 75 years) 1,542.5 1,465.7 General (5 - 50 years) 328.1 302.9 Total (a) $ 5,450.6 $ 5,268.5 (a) Includes $40.4 million and $40.3 million at December 31, 2007 and 2006, respectively, of land and other assets that are not depreciated.
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| Depreciation and Amortization Depreciation and amortization of KCP&L's utility plant other than nuclear fuel is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities. Annual depreciation rates average approximately 3%. Nuclear fuel is amortized to fuel expense based on the quantity of heat produced during the generation of electricity.
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| Depreciation of nonutility property is computed using the straight-line method. Consolidated KCP&L's nonutility property annual depreciation rates for 2007, 2006 and 2005 were 11.6%, 11.5% and 11.2%,
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| respectively. Other Great Plains Energy nonutility property annual depreciation rates for 2007, 2006 and 2005 were 22.2%, 23.4% and 20.4%, respectively. Other Great Plains Energy's nonutility property includes Strategic Energy's depreciable assets, which are primarily software costs and are amortized over a shorter period, three years, resulting in a higher annual amortization rate.
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| Great Plains Energy's depreciation expense was $142.0 million, $131.9 million and $131.6 million for 2007, 2006 and 2005, respectively. Consolidated KCP&L's depreciation expense was $140.9 million,
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| $130.7 million and $130.3 million for 2007, 2006 and 2005, respectively. Great Plains Energy's and consolidated KCP&L's depreciation and amortization expense includes $25.7 million, $13.8 million and
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| $7.8 million for 2007, 2006 and 2005, respectively, of additional amortizations to help maintain cash flow levels pursuant to MPSC and KCC orders.
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| As part of an acquisition of an additional interest in Strategic Energy, IEC recorded intangible assets with finite lives. These intangible assets include the fair value of customer relationships that are being amortized over 72 months. Intangible assets for the fair value of asset information systems were fully amortized at December 31, 2007, and acquired supply contracts were fully amortized at December 31, 2006.
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| Nuclear Plant Decommissioning Costs Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration. Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek Generating Station (Wolf Creek). Related liabilities for decommissioning are included on KCP&L's balance sheet in Asset Retirement Obligations (AROs). As a result of the authorized regulatory treatment and related regulatory accounting, differences between the decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability. See Note 16 for discussion of AROs including those associated with nuclear plant decommissioning costs.
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| 74
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| Deferred Refueling Outage Costs KCP&L uses the deferral method to account for operations and maintenance expenses incurred in support of Wolf Creek's scheduled refueling outages and amortizes them evenly (monthly) over the unit's operating cycle of 18 months until the next scheduled outage. Replacement power costs during an outage are expensed as incurred.
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| Regulatory Matters KCP&L is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Pursuant to SFAS No. 71, KCP&L defers items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L were not regulated. See Note 6 for additional information concerning regulatory matters.
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| Revenue Recognition KCP&L and Strategic Energy recognize revenues on sales of electricity when the service is provided.
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| Revenues recorded include electric services provided but not yet billed by KCP&L and Strategic Energy. Unbilled revenues are recorded for kWh usage in the period following the customers' billing cycle to the end of the month. KCP&L's estimate is based on net system kWh usage less actual billed kWhs. KCP&L's estimated unbilled kWhs are allocated and priced by state across the rate classes based on estimfnated billing rates. Strategic Energy's estimate is based on estimated kWh usage compared to actual billed kWhs. The estimate is recorded at the estimated billing value.
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| As a public utility, KCP&L collects from customers gross receipts taxes levied by state and local governments. These taxes are recorded gross in operating revenues and general taxes on Great Plains Energy's and consolidated KCP&L's statements of income. KCP&L's gross receipts taxes collected were $44.7 million, $34.1 million and $39.3 million in 2007, 2006 and 2005, respectively.
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| Strategic Energy purchases electricity from power suppliers based on forecasted peak demand for its retail customers. Actual customer demand does not always equate to the volume purchased based on forecasted peak demand. Consequently, Strategic Energy sells any excess retail electricity supply over-actual customer requirements back into the wholesale market. The proceeds from excess retail supply sales are recorded as a reduction of purchased power, as they do not represent the quantity of electricity consumed by Strategic Energy's customers. The amount of excess retail supply sales that reduced purchased power was $76.4 million, $80.0 million and $158.5 million in 2007, 2006 and 2005, respectively.
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| KCP&L and Strategic Energy record sale and purchase activity on a net basis in purchased power when Regional Transmission Organization (RTO)/Independent System Operator (ISO) markets require them to sell and purchase power from the RTO/ISO rather than directly transact with suppliers and end-use customers.
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| KCP&L collects sales taxes from customers and remits to state and local governments. 'These taxes are presented on a net basis on Great Plains Energy's and consolidated KCP&L's statements of income.
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| Allowance for Doubtful Accounts This reserve represents estimated uncollectible accounts receivable and is based on management's judgment considering historical loss experience and the characteristics of existing accounts. Provisions for losses on receivables are charged to income to maintain the allowance at a level considered adequate to cover losses. Receivables are charged off against the reserve when they are deemed uncollectible.
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| 75
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| Property Gains and Losses Net gains and losses from the sales of assets, businesses and asset impairments are recorded in operating expenses.
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| Asset Impairments Long-lived assets and finite lived intangible assets subject to amortization are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets." SFAS No. 144 requires that if the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment recognized is the excess of the carrying value of the asset over its fair value.
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| Goodwill and indefinite lived intangible assets are tested for impairment at least annually and more frequently when indicators of impairment exist as prescribed under SFAS No. 142, "Goodwill and Other Intangible Assets." The annual test must be performed at the same time each year. SFAS No. 142 requires that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill would be compared with its carrying value. See Note 7 for additional information.
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| Income Taxes In accordance with SFAS No. 109, "Accounting for Income Taxes," Great Plains Energy has recognized deferred taxes for temporary book to tax differences using the liability method.. The liability method requires that deferred tax balances be adjusted to reflect enacted tax rates that are anticipated to be in effect when the temporary differences reverse. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.
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| In accordance with Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes," an interpretation of SFAS No. 109, "Accounting for Income Taxes," Great Plains Energy and consolidated KCP&L recognize tax benefits based on a "more-likely-than-not" recognition threshold. In addition, Great Plains Energy and consolidated KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.
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| Great Plains Energy and its subsidiaries file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss. In accordance with the Company's intercompany tax allocation agreement, the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive taxable income of each company in'!
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| the consolidated federal or combined state returns. KCP&L's income tax provision includes taxes allocated based on its separate company income or loss adjusted for the allocation of parent company tax benefits.
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| KCP&L has established a net regulatory asset for the additional future revenues to be collected from customers for deferred income taxes. Tax credits are recognized in the year generated except for certain KCP&L investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.
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| 76
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| Environmental Matters Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.
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| Basic and Diluted Earnings per Common Share Calculation To determine basic EPS, preferred stock dividend requirements are deducted from income from continuing operations and net income before dividing by the average number of common shares outstanding. The earnings (loss) per share impact of discontinued operations, net of income taxes, is determined by dividing discontinued operations, net of income taxes, by the average number of common shares outstanding. The effect of dilutive securities, calculated using the treasury stock method, assumes the issuance of common shares applicable to stock options, performance shares, restricted stock, a forward sale agreement and FELINE PRIDESsM.
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| The following table reconciles Great Plains Energy's basic and diluted EPS from continuing operations.
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| 2007 2006 2005 Income (millions, except per share amounts)
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| Income from continuing operations $ 159.2 $ 127.6 $ 164.2 Less: preferred stock divdend requirements 1.6 1.6 1.6 Income available for common stockholders- $ 157.6 $ 126.0 $ 162.6 Common Shares Outstanding Average number of common shares outstanding 84.9 78.0 .74.6 Add: effect of dilutive securities 0.3 0.2 0.1 Diluted average number of common shares outstanding 85.2 78.2 74.7 Basic EPS from continuing operations $ 1.86 $ 1.62 $ 2.18 Diluted EPS from continuing operations $ 1.85 $ 1.61 $ 2.18 The computation of diluted EPS excludes anti-dilutive shares for 2007 of 128,716 performance shares and 381,451 -restricted stock shares. In 2007, there were no anti-dilutive shares applicable to FELINE PRIDES, stock options or a forward sale agreement. FELINE PRIDES settled in the first quarter of 2007 and the forward sale agreement settled in the second quarter of 2007.
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| The computation of diluted EPS excludes anti-dilutive shares for 2006 of 96,601 performance shares and 116,469 restricted stock shares. The computation of diluted EPS excludes anti-dilutive shares for 2005 of 20,493 performance shares. Additionally, for 2006 and 2005, 6.5 million of anti-dilutive FELINE PRIDES were excluded from the computation of diluted EPS and there were no anti-dilutive shares applicable to stock options or a forward sale agreement.
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| Dividends Declared.
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| In February 2008, the Board of Directors declared a quarterly dividend of $0.415 per share on Great Plains Energy's common stock. The common dividend is payable March 20, 2008, to shareholders of record as of February 28, 2008. The Board of Directors also declared regular dividends on Great Plains Energy's preferred stock, payable June 1, 2008, to shareholders of record as of May 9, 2008.
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| 77
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| : 2. ANTICIPATED ACQUISITION OF AQUILA, INC.
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| On February 6, 2007, Great Plains Energy entered into an agreement to acquire Aquila, Inc. (Aquila) for
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| $1.80 in cash plus 0.0856 of a share of Great Plains Energy common stock for each share of Aquila common stock. Immediately prior to Great Plains Energy's acquisition of Aquila, Black Hills Corporation will acquire Aquila's electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. Each of the two transactions is conditioned on the completion of the other transaction and is expected to close in the first hbilfof.2008. Following closing, Great Plains Energy will own Aquila and its Missouri-based utilities consisting of the Missouri Public Service and St. Joseph Light & Power divisions, as well as Aquila's merchant service operations, which primarily consists of the 340MW Crossroads power generating facility and residual natural gas contracts.
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| During 2007, Great Plains Energy's acquisition of Aquila was unanimously approved by both Great Plains Energy's and Aquila's Boards of Directors and Great Plains Energy received approval from its shareholders to issue common stock in connection with the anticipated acquisition of Aquila and Aquila's shareholders approved the acquisition of Aquila by Great Plains Energy. The transaction is still subject to regulatory approvals from the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC); the closing of the asset sale to Black Hills Corporation (Black Hills) (which is still subject to regulatory approvals from KCC); as well as other customary conditions.
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| The Colorado Public Utilities Commission, the Iowa Utilities Board and the Nebraska Public Service Commission have approved Aquila's and Black Hills' applications seeking approval of the sale of assets to Black Hills and a settlement has been submitted in the KCC proceedings.
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| On May 25, 2007, Great Plains Energy, KCP&L, Aquila and Black Hills filed a joint application (which.
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| was amended in June 2007) with FERC seeking approval of the proposed acquisition by Great Plains Energy of Aquila and certain Aquila Colorado electric assets by Black Hills, and for a declaratory order that the transfer of proceeds from Aquila to Great Plains Energy will not constitute a payment of funds properly included in a capital account in a manner contrary to the Federal Power Act. On October 18, 2007, FERC granted the joint application. Great Plains Energy and Aquila submitted their respective Hart-Scott-Rodino pre-merger notifications in July 2007 relating to the acquisition of Aquila by Great Plains Energy, and received early termination of the waiting period on August 27, 2007.
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| In 2007, Great Plains Energy, KCP&L and Aquila submitted joint applications to the MPSC and KCC seeking approval of the proposed acquisition by Great Plains Energy of Aquila. In the original MPSC filing, the companies requested that Aquila be authorized to use an additional amortization mechanism to maintain credit ratios once Aquila achieves financial metrics necessary to support an investment-grade credit rating. Aquila and KCP&L also requested authorization to amortize transaction and incremental transition-related costs over five years, and to collectively retain for a five year period 50 percent of estimated synergy savings resulting from the transaction. Aquila further requested approval to transfer to Great Plains Energy approximately $677 million of the proceeds from the sale of its non-Missouri utility operations to Black Hills to fund substantially all of the cash portion of the merger consideration payable to its shareholders by Great Plains Energy. In the KCC filing, KCP&L requested similar regulatory treatment of costs and synergies. In updates filed with the MPSC and KCC on August 8, 2007, Great Plains Energy and KCP&L proposed to retain for a five year period 50 percent of the estimated utility operational synergies, net of estimated transition costs.
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| On February 25, 2008, Great Plains Energy and KCP&L filed supplemental direct testimony in the pending MPSC proceedings regarding the proposed Great Plains Energy - Aquila transaction. The filing withdrew the request for recovery of Aquila's actual debt interest cost, and proposed to follow the debt interest cost recovery procedure utilized in the most recent Aquila Missouri rate cases, which is 78
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| the assigning to non-investment grade debt investment-grade interest rates for comparable debt. The filing also withdrew the proposal for a specific synergy savings sharing mechanism, and instead proposed to utilize the natural regulatory lag that occurs between rate cases to retain any portion of synergy savings. The filing further withdrew the request for an additional amortization provision in this case, with the intention to begin discussions after closing of the proposed transaction to develop a regulatory plan for Aquila that may include an additional amortization provision. The filing continued the request for the deferral and amortization of transaction and transition costs over a five-year period beginning with the first post-transaction rate cases, but withdrew from that request the estimated approximate $17 million of transaction costs associated with Aquila senior management potential severance costs. The Company requested that hearings resume in late April 2008.
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| On February 27, 2008, Great Plains Energy, KCP&L, the Staff of the Kansas Corporation Commission (Staff), the Citizens' Utility Ratepayers Board (CURB), Aquila, Inc. d/b/a Aquila Networks (Aquila),- Black Hills Corporation and Black Hills/Kansas Gas Utility Company, LLC, filed a joint motion and settlement agreement (Agreement) in the pending Kansas Corporation Commission (KCC) proceedings regarding the proposed Great Plains Energy - Aquila transaction. The Agreement provides, among other things, for the exclusion from Kansas rate recovery of all transaction costs (currently estimated to total approximately $82 million), exclusion of acquisition premium and recovery of $10 million of transition costs (currently estimated to be approximately $59 million) over five years beginning with rates expected to be effective in 2010. The Agreement establishes certain quality of service performance metrics with a maximum annual penalty exposure of $5.7 million. The Agreement further provides that KCP&L's rate case expected to be filed in 2008 will not include any of the costs or benefits associated with the transaction, and the allocation factors used in such case will not reflect the proposed transaction. The parties also agreed to not contest the rights of Staff and CURB to request KCC to amend its order to reflect any conditions contained in an order in the Missouri proceedings that are detrimental to Kansas or more favorable to KCP&L.
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| The Agreement is subject to KCC approval, and the Agreement is void if not approved in its entirety. It is possible that KCC may approve the Agreement with changes, or may not approve the Agreement. A hearing on the Agreement is anticipated to occur on March 7, 2008.
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| Direct transaction costs of the acquisition incurred by Great Plains Energy of $21.1 million at December 31, 2007, are deferred and will be included in purchase accounting treatment upon consummation of the acquisition unless regulatory accounting treatment is authorized. Non-labor transition-related costs were $6.7 million in 2007. Decisions in these cases are currently expected in the first half of 2008.
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| Two purported shareholder class action lawsuits were filed against Aquila and certain of its individual directors and officers on February 8, 2007, in Jackson County, Missouri, Circuit Court seeking, among other things, an injunction against the consummation of the proposed transaction. The lawsuits alleged, among other things, breaches of fiduciary duties and self-dealing by Aquila directors and officers. In July 2007, the plaintiff in one of the suits amended his petition to include Great Plains Energy and Black Hills as defendants, alleging that they aided and abetted alleged breaches of fiduciary duties by the named Aquila directors and officers. On July 26, 2007, the Court consolidated the two cases. Aquila, Great Plains Energy and Black Hills filed motions to dismiss this case, which were granted on October 29, 2007. Plaintiffs did not appeal and a joint stipulation of dismissal was filed on December 4, 2007.
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| 79
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| : 3. SUPPLEMENTAL CASH FLOW INFORMATION Great Plains Energy Other Operating Activities 2007 2006 2005 Cash flows affected by changes in: (millions)
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| Receivables $ (80.0) $ (80.8) $ 6.6 Fuel inventories (9.3) (10.7) 4.9 Materials and supplies (4.2) (2.8) (2.6)
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| Accounts payable 43.3 68.1 12.4 Accrued taxes 17.3 (22.5) (23.1)
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| Accrued interest (0.7) 0.7 1.6 Deferred refueling outage costs 7.4 (5.9) (4.0)
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| Pension and post-retirement benefit obligations 17.6 3.6 8.4 Allowance for equity funds used during construction (2.5) (5.0) (1.8)
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| Deferred merger costs (18.3) (2.8) -
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| Proceeds from the sale of SO 2 emission allowances 24.0 0.8 61.0 (Payment of) proceeds from T-Locks (4.5) - 12.0 Proceeds from forward starting swaps 3.3 -
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| Other (17.8) 8.5 20.2 Total other operating activities $ (24.4) $ (48.8) $ 95.6 Cash paid during the period:
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| Interest $ 91.8 $ 67.7 $ 68.9 Income taxes $ 33.6 $ 77.7 $ 84.4 Non-cash investing activities:
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| Liabilities assumed for capital expenditures $ 72.5 $ 38.7 $ 13.4 ConsolidatedKCP&L Other OperatingActivities 2007 2006 2005 Cash flows affected by changes in: (millions)
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| Receivables $ (60.0) $ (44.7) $ (8.5)
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| Fuel inventories (9.3) (10.7) 4.9 Materials and supplies (4.2) (2.8) (2.6)
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| Accounts payable 20.6 52.4 16.3 Accrued taxes 5.9 (16.5) (17.2)
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| Accrued interest (2.9) 0.9 1.7 Deferred refueling outage costs 7.4 (5.9) (4.0)
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| Pension and post-retirement benefit obligations 15.4 0.7 4.6 Allowance for equity funds used during construction (2.5) (5.0) (1.8)
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| Proceeds from the sale of S02 emission allowances 24.0 0.8 61.0 Proceeds from T-Locks - 12.0 Proceeds from forward starting swaps 3.3 Other (16.2) (8.6) 12.9 Total other operating activities $ (18.5) $ (39.4) $ 79.3 Cash paid during the period:
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| Interest $ 68.3 $ 57.9 $ 57.6 Income taxes $ 39.8 $ 70.9 $ 104.1 Non-cash investing activities:
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| Liabilities assumed for capital expenditures $ 72.4 $ 38.2 $ 12.8 80
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| | |
| Significant Non-Cash Items In February 2007, Great Plains Energy issued 5.2 million shares of common stock in satisfaction of the FELINE PRIDES stock purchase contracts and the redemption of the $163.6 million FELINE PRIDES Senior Notes.
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| Unrecognized Pension Expense In December 2006, the Company adopted SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Post Retirement Plans." The adoption of SFAS No. 158 had no impact on Great Plains Energy's and consolidated KCP&L's 2007 and 2006 cash flows. The following table summarizes the SFAS No. 158 impact on Great Plains Energy's and consolidated KCP&L's balance sheets at December 31, 2007 and 2006.
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| December 31 2007 2006 Increase (decrease) in: (millions)
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| Prepaid benefit cost $ $ (46.8)
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| Intangible asset (12.1)
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| Regulatory asset (20.0) 155.7 Current liability 0.3 1.0 Accrued benefit cost - (31.4)
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| Pension liability (24.8) 143.2 Postretirement liability 2.3 33.0 Minimum pension liability adjustment - (46.5)
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| Deferred taxes 0.8 (0.9)
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| Accumulated OCI, net of tax 1.4 (1.6)
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| Asset Retirement Obligations In 2006, Wolf Creek Nuclear Operating Corporation (WCNOC) submitted an application to the Nuclear Regulatory Commission (NRC) for a new operating license for Wolf Creek, which would extend Wolf Creek's operating period to 2045. Due to the effect of computing the present value of the ARO at the end of the extended operating period, KCP&L recorded a $65.0 million decrease in the ARO to decommission Wolf Creek with a $25.8 million net decrease in property and equipment. The regulatory asset for ARO decreased $8.2 million and a $31.0 million regulatory liability was established to recognize funding of the related decommissioning trust in excess of the ARO due to the extended operating period. This activity had no impact to Great Plains Energy's or consolidated KCP&L's 2006 cash flows.
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| During 2005, KCP&L recorded AROs totaling $26.7 million, increased net utility plant by $13.0 million and increased regulatory assets by $13.7 million. This activity had no impact on Great Plains Energy and consolidated KCP&L's 2005 net income and had no effect on 2005 cash flows. See Note 16 for additional information.
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| 81
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| : 4. RECEIVABLES The Company's receivables are detailed in the following table.
| |
| December 31 2007 2006 Consolidated KCP&L (millions)
| |
| Customer accounts receivable (a) $ 45.3 $ 35.2 Allowance for doubtful accounts (1.2) (1.1)
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| Intercompany receivable from Great Plains Energy 10.5 -
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| Other receivables 121.8 80.2 Consolidated KCP&L receivables 176.4 114.3 Other Great Plains Energy Other receivables 268.4 229.2 Elimination of intercompany receivable (10.5) -
| |
| Allowance for doubtful accounts (6.9) (4.1)
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| Great Plains Energy receivables $ 427.4 $ 339.4 (a)Customer accounts receivable included unbilled receivables of $37.7 million and $32.0 million at December 31, 2007 and 2006, respectively.
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| Consolidated KCP&L's other receivables at December 31, 2007 and 2006, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables. Great Plains Energy's other receivables at December 31, 2007 and 2006, consisted of accounts receivable held by Strategic Energy of $268.3 million and $229.1 million, respectively. Strategic Energy's accounts receivable at December 31, 2007 and 2006 include unbilled receivables of $131.5 million and
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| $95.0 million, respectively.
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| Sale of Accounts Receivable - KCP&L KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts'receivable to Victory Receivables Corporation, an independent outside investor. In accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities," the sales under these agreements qualify as a sale under which the creditors of Receivables Company are entitled to be satisfied out of the assets of Receivables Company prior to any value being returned to KCP&L or its creditors. Accounts receivable sold by Receivables Company to the outside investor under this revolving agreement totaled $70.0 million at December 31, 2007 and 2006. KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprise KCP&L's loss on the sale of accounts receivable. KCP&L services the receivables and receives an annual servicing fee of 2.5% of the outstanding principal amount of the receivables sold to Receivables Company. KCP&L does not recognize a servicing asset or liability because management determined the collection agent fee earned by KCP&L approximates market value. The agreement expires in 2008 and KCP&L intends to renew the agreement.
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| 82
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| Information regarding KCP&L's sale of accounts receivable to Receivables Company is reflected. in the following tables.
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| Receivables Consolidated 2007 KCP&L Company KCP&L (millions)
| |
| Receivables (sold) purchased $(1,082.6) $1,082.6 $ -
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| Gain (loss) on sale of accounts receivable (a) (13.3) 13.0 (0.3)
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| Servicing fees 3.1 (3.1.)
| |
| Fees to outside investor - (4.1) (4.1)
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| Cash flows during the period Cash from customers transferred to Receivables Company (1,078.8) 1,078.8 Cash paid to KCP&L for receivables purchased 1,065.9 (1,065.9)
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| Servicing fees 3.1 (3.1)
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| Interest on intercompany note 3.1 (3.1)
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| Receivables Consolidated 2006 KCP&L Company KCP&L (millions)
| |
| Receivables (sold) purchased $ (977.9) $ 977.9 $
| |
| Gain (loss) on sale of accounts receivable (a) (9.9) 9.9 Servicing fees 2.9 (2.9)
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| Fees to outside investor - (3.8) (3.8)
| |
| Cash flows during the period Cash from customers transferred to Receivables Company (980.7) 980.7 Cash paid to KCP&L for receivables purchased 974.6 (974.6)
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| Servicing fees 2.9 (2.9)
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| Interest on intercompany note 2.4 (2.4)
| |
| (a) Anynetgain (loss) is the resultofthe timing difference inherent in collecting receivables and over the life of the agreement will net to zero.
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| Sale of Accounts Receivable - Strategic Energy In 2007, Strategic Energy entered into an agreement to sell all of its retail accounts receivable to its wholly owned subsidiary, Strategic Receivables, LLC (Strategic Receivables), which in turn sells undivided percentage ownership interests in the accounts receivable to Market Street Funding LLC (Market Street) and Fifth Third Bank (collectively, the Purchasers) ratably based on each purchaser's commitments. In accordance with SFAS No. 140, the sales under these agreements qualify as a sale, under which the creditors of Strategic Receivables are entitled to be satisfied out of the assets of Strategic Receivables prior to any value being returned to Strategic Energy or its creditors. Strategic Energy sells its receivables at a price equal to the amount of the accounts receivable less a discount based on the prime rate and days sales outstanding (as defined in the agreement). In addition to its ability to sell accounts receivable to the purchasers for cash, Strategic Receivables may also request the issue of letters of credit on behalf of Strategic Energy. Under the agreement, in the event of a draw against an issued and outstanding letter of credit, Strategic Receivables must reimburse the amount or the amount will be considered a sale of undivided percentage ownership interest in the accounts receivable to the Purchasers. At December 31, 2007, Strategic Receivables had issued letters of credit 83
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| totaling $82.9 million and had no sales of accounts receivables to the Purchasers. Market Street's and Fifth Third Bank's obligation to purchase accounts receivable is limited to $112.5 million and $62.5 million, respectively, less the proportionate aggregate amount of letters of credit issued pursuant to the agreement. Strategic Energy services the receivables and receives an annual servicing fee of 1.0%
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| times the daily average aggregate outstanding balance of receivables. Strategic Energy does not recognize a servicing asset or liability because management determined the annual servicing fee earned by Strategic Energy approximates market value. This agreement was entered into in conjunction with a new revolving credit facility described in Note 18 and terminates in October 2010.
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| Information regarding Strategic Energy's sale of accounts receivable to Strategic Receivables is reflected in the following tables.
| |
| Consolidated Strategic Strategic Strategic 2007 Energy Receivables Energy (millions)
| |
| Receivables (sold) purchased $ (838.3) $ 838.3 $ -
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| Gain (loss) on sale of accounts receivable (5.3) 5.3 Receivables contributed as capital (10.0). 10.0 Servicing fees 0.7 (0.7)
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| Fees to outside investor, (0.1) (0.1)
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| Cash flows during the period Cash paid to Strategic Energy for receivables purchased 560.7 (560.7)
| |
| : 5. NUCLEAR PLANT KCP&L owns 47% of WCNOC, the operating company for Wolf Creek, its only nuclear generating unit.
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| Wolf Creek is regulated by the NRC, with respect to licensing, operations and safety-related requirements.
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| Spent Nuclear Fuel and Radioactive Waste Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel: KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal ofspent nuclear fuel.
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| These disposal costs are charged to fuel expense. In July 2006, the DOE announced plans to submit a license application to the NRC for a nuclear waste repository at Yucca Mountain, Nevada, no later than June 30, 2008. The DOE also announced that if requested legislative changes are enacted, the repository could be able to accept spent nuclear fuel and high-level waste starting in early 2017. In January 2008, the DOE announced that its anticipated license application date of June 30, 2008, is in jeopardy due to budget allocation reductions. A submittal during 2008 is still possible; however, operation of the repository in 2017 is unlikely. Management cannot predict when this site may be available for Wolf Creek. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel first from the owners with the older spent fuel. Wolf Creek has completed an on-site storage facility designed to hold all spent fuel generated at the plant through 2025. If the DOE meets its revised timetable for accepting spent fuel for disposal by 2017, management expects that the DOE could begin accepting some of Wolf Creek's spent fuel by 2025. Management can make no assurance that the DOE will meet its revised timetable and will continue to monitor this activity. See Note 15 for a related legal proceeding.
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| 84
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| Nuclear Plant Decommissioning Costs The MPSC and KCC require KCP&L and the other owners of Wolf Creek to submit an updated decommissioning cost study every three years and to propose funding levels. The most recent study was submitted to the MPSC and KCC in 2005 and is the basis for the current cost of decommissioning estimates in the following table.
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| Total KCP&L's Station 47% Share (millions)
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| Current cost of decommissioning (in 2005 dollars) $ . 518 $ 243 Future cost of decommissioning (in 2045-2053. dollars) (a) 3,327 1,564 Annual escalation factor 4.40%
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| Annual return on trust assets (b) 6.48%
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| (a)
| |
| Total future cost over an eight year decommissioning period.
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| (b)
| |
| The 6.48% rate of return is thru 2025. The rate then systematicallydecreases through 2053 to 2.82% based on the assumption that the fund's investment mix will become increasingly more conservative as the decommissioning period approaches.
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| In 2007, KCP&L received orders from the MPSC and KCC, approving the funding schedules for this cost estimate above based on an anticipated extension of the operating period to 2045. KCP&L currently contributes approximately $3.7 million annually to a tax-qualified trust fund to be used to decommission Wolf Creek. Amounts funded are charged to other operating expense and recovered in customers' rates. If the actual return on trust assets is below the anticipated level, management believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the station.
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| The following table summarizes the change in Great Plains Energy's and consolidated KCP&L's decommissioning trust-fund.
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| December 31 2007 2006 Decommissioning Trust (millions)
| |
| Beginning balance $ 104.1 $ 91.8 Contributions 3.7 3.7 Earned income, net of fees 1.6 1.9 Net realized gains 3.3 4.1 Unrealized gains/(losses) (2.2) 2.6 Ending balance $ 110.5 $ 104.1 85
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| The decommissioning trust is reported at fair value on the balance sheets and is invested in assets as detailed in the following table.
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| December 31 2007 2006 Fair Unrealized Fair Unrealized Value Gains Value Gains (millions)
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| Equity securities $ 51.6 $ 7.6 $ 50.6 $ 10.8 Debt securities 55.9 0.5 50.4 (0.5)
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| Other 3.0 - 3.1 -
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| Total $110.5 $ 8.1 $104.1 $ 10.3 The weighted average maturity of debt securities held by the trust at December 31, 2007 and 2006, was 7.0 years and 6.8 years, respectively. The costs of securities sold are determined on the basis of specific identification. The following table summarizes the gains and losses from the sale of securities by the nuclear decommissioning trust fund.
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| 2007 2006 2005 (millions)
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| Realized Gains $ 6.1 $ 5.0 $ 3.0 Realized Losses (2.8) (0.9) (1.0)
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| Nuclear Insurance The owners of Wolf Creek (Owners) maintain nuclear insurance for Wolf Creek in three areas: nuclear liability, nuclear property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war. Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts of terrorism and related losses, as defined by the Terrorism Risk Insurance Act, including replacement power costs. An industry aggregate limit of $0.3 billion exists for liability claims, regardless of the number of non-certified acts affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), the Owners' insurance provider, exists for property claims,, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. For certified acts of terrorism, the individual policy limits apply. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.
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| In the event of a catastrophic loss at Wolf Creek, the insurance coverage may not be adequate to cover property damage and extra expenses incurred. Uninsured losses, to the extent not recovered through rates, would be assumed by KCP&L and the other owners and could have a material adverse effect on KCP&L's results of operations, financial position and cash flows.
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| Nuclear LiabilityInsurance Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of 2005, the Owners are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently $10.8 billion. This limit of liability consists of the maximum available commercial insurance of $0.3 billion and the remaining $10.5 86
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| | |
| billion is provided through an industry-wide retrospective assessment program mandated by law, known as the Secondary Financial Protection (SFP) program. Under the SFP program, the Owners can be assessed up to $100.6 million ($47.3 million, KCP&L's 47% share) per incident at any commercial reactor in the country, payable at no more than $15 million ($7.1 million, KCP&L's 47% share) per incident per year. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.
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| Nuclear PropertyInsurance The Owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share). NEIL provides this insurance.
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| In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. KCP&L's share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs. Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted.
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| Accidental Nuclear Outage Insurance The Owners also carry additional insurance from NEIL to cover costs of replacement power and other extra expenses incurred in the event of a prolonged outage resulting from accidental property damage at Wolf Creek.
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| Under all NEIL policies, the Owners are subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy. The estimated maximum amount of retrospective assessments under the current policies could total approximately
| |
| $25.7 million ($12.1 million, KCP&L's 47% share) per policy year.
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| Low-Level Waste The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact) and selected a site in northern Nebraska to locate a disposal facility. WCNOC and the owners of the other five nuclear units in the Compact provided most of the pre-construction financing for this project.
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| After many years of effort, Nebraska regulators denied the facility developer's license application in December 1998, a prolonged lawsuit ensued, and Nebraska eventually settled the case by paying the Compact Commission $145.8 million in damages. The Compact Commission then paid pro rata portions of the settlement money to the various parties who originally funded the project. To date, WCNOC has received refunds totaling $21.3 million (KCP&L's 47% share being $10 million), including
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| $1.7 million ($0.8 million, KCP&L's 47% share) received in 2006. The Compact Commission continues to explore alternative long-term waste disposal capability and has retained an insignificant portion of the settlement money.
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| 87
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| : 6. REGULATORY MATTERS KCP&L's Comprehensive Energy Plan KCP&L continues to execute on its Comprehensive Energy Plan. In 2006, the 100.5 MW Spearville-Wind Energy Facility went into service. The first phase of environmental upgrades at LaCygne No. 1, installation of selective catalytic reduction equipment, was completed and placed into service during the second quarter of 2007. Environmental upgrades at latan No. 1 are underway and completion is currently scheduled for late 2008. An outage at latan No. 1 is planned to complete and place in service these environmental upgrades during the fourth quarter of 2008. Construction of latan No. 2 is on-going and currently scheduled for completion in 2010.
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| In March 2007, KCP&L, the Sierra Club and the Concerned Citizens of Platte County entered into a Collaboration Agreement that resolved disputes among-the parties. KCP&L agreed to pursue a set of initiatives including energy efficiency, additional wind generation, lower emission permit levels at its latan and LaCygne generating stations and other initiatives designed to offset carbon dioxide emissions. KCP&L will address these matters in its future integrated energy resource plan in collaboration with stakeholders. Full implementation of the terms of the agreement will necessitate approval from the appropriate authorities, as some of the initiatives in this agreement require either enabling legislation or regulatory approval. Pursuant to the terms of the agreement, the Sierra Club agreed to dismiss its appeal of the approval of KCP&L's regulatory plan by KCC. The appeal by the Sierra Club and Concerned Citizens of Platte County of the MPSC's approval of KCP&L's regulatory plan was also dismissed. The parties filed a joint stipulation of dismissal with prejudice of the appeal'of the latan air permit and the appeal was subsequently dismissed.
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| The construction environment entering 2008 for the latan No. 1 and latan No. 2 projects is challenging, particularly the tight market conditions for skilled labor and the lengthening lead times for deliveries of materials. KCP&L is conducting a thorough assessment of the impact of the current environment on the projects' cost and schedule. The results of the assessment are expected to be available in the second quarter of 2008.
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| KCP&L Regulatory Proceedings KCP&L Missouri Rate Cases 2006 Rate Case Appeal On December 21, 2006, the MPSC issued an order approving an approximate $51 million increase in annual revenues effective January 1, 2007. Appeals of the MPSC order were filed in February 2007 with the Circuit Court of Cole County, Missouri, by the Office of Public Counsel, Praxair, Inc., and Trigen-Kansas City Energy Corporation, seeking to set aside or remand the order to the MPSC. The court affirmed the MPSC's decision in December 2007 and this decision hasbeen appealed byTrigen-Kansas City Energy Corporation. Although subject to-the appeal, the MPSC order remains in effect pending the court's decision.
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| 2007 Rate Case Order In February 2007, KCP&L filed a request with the MPSC for an annual rate increase of $45 million or, 8.3%. The request was based on a return on equity of 11.25% and an equity ratio of about 53%.
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| KCP&L received a rate order from the MPSC in December 2007 approving an approximate $35 million increase in annual revenues, reflecting an authorized return on equity of 10.75% and an equity ratio of approximately 58%. Approximately $11 million of the rate increase results from additional amortization to help maintain cash flow levels. The rates established by the order reflect an annual offset of approximately $51 million ($29 million Missouri jurisdiction) related to non-firm wholesale electric sales margin. If the actual margin amount exceeds this level, the difference will be recorded as a regulatory liability and will be returned, with interest, to Missouri retail customers in a future rate case. The ordered rates were implemented January 1, 2008, and are subject to appeal until March 3, 2008.
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| 88
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| The order implemented various other provisions, including but not limited to: (i) establishing for regulatory purposes annual pension cost for the period beginning January 1, 2008, of approximately
| |
| $21 million and (ii) deferring and amortizing over five years the costs incurred in 2006 of approximately
| |
| $9 million ($5 million on a Missouri jurisdictional basis) associated with the skill set realignment.
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| KCP&L Kansas Rate Case Order- 2007 In March 2007, KCP&L filed a request with KCC for an annual rate increase of $47 million in annual revenues" with about $13 million of that amount treated for accounting purposes as an increase to the depreciation reserve. KCP&L received a rate order from KCC in November 2007 approving a $28 million increase in annual revenues effective January 1, 2008, with $11 million of that amount treated for accounting purposes as an increase to the depreciation reserve to help maintain cash flow levels.
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| The order also implements an Energy Cost Adjustment (ECA) tariff. The ECA tariff will reflect the projected annual amount of fuel, purchased power, emission allowances, transmission costs and asset-based off-system sales margin. The ECA tariff provides that these projected amounts are subject to quarterly re-forecasts. Any difference between the ECA revenue collected and the actual ECA amounts for a given year (which may be positive or negative) will be recorded as an increase to or reduction of retail revenues and deferred as a regulatory asset or liability to be recovered from or refunded to Kansas retail customers over twelve months beginning April 1 of the succeeding year.
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| Theorder implemented various other provisions, including but not limited to: (i) establishing an energy efficiency rider as an interim mechanism to recover deferred costs incurred for affordability, energy efficiency and demand side management programs; (ii) establishing for regulatory purposes annual pension cost for the period beginning January 1, 2008, of approximately $17 million and (iii) deferring and amortizing over ten years the Costs incurred in 2006 of approximately $9 million ($4 million on a Kansas jurisdictional basis) associated with the skill set realignment.
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| Regulatory Assets and Liabilities KCP&L is subject to the provisions of SFAS No. 71 and has recorded assets and liabilities on its -
| |
| balance sheet resulting from the effects of the ratemaking process, which would not otherwise be recorded under Generally Accepted Accounting Principles (GAAP). Regulatory assets represent incurred costs that are probable of recovery from future revenues. Regulatory liabilities represent:
| |
| amounts imposed by rate actions of KCP&L's regulators that may require refunds to customers; amounts provided in current rates that are intended to recover costs that are expected to be incurred in the future for which KCP&L remains accountable; or a gain or other reduction of allowable costs to be given to customers over future periods. Future recovery of regulatory assets is not assured, but is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Future reductions in revenue or refunds for regulatory liabilities generally are not mandated, pending future rate proceedings or actions by the regulators. Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC on KCP&L's rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to KCP&L; and changes in laws and regulations. If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations. KCP&L's continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by restructuring and deregulation in the electric industry. In the event that SFAS No. 71 no longer applied to a deregulated portion of KCP&L's operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of utility plant assets if the cost of the assets could not be expected to be recovered in customer rates. Whether an asset has been impaired is determined pursuant to the requirements of SFAS No. 144.
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| 89
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| KCP&L's regulatory assets and liabilities are detailed in the following table.
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| December 31 2007 2006 Regulatory Assets (millions Taxes recoverable through future rates $ 66.5 $ 81.7 Loss on reacquired debt 5.9 6.4 Change in depreciable life of Wolf Creek 45.4 45.4 Cost of removal 8.4 8.2 Asset retirement obligations 18.5 16.9 SFAS 158 pension and post-retirement costs 146.8 190.0 Other pension and post-retirement costs 76.1 66.9 Surface Transportation Board litigation expenses 1.8 1.7' Deferred customer programs 11.6 5.9 Rate case expenses 3.2 2.6 Skill set realignment costs 8.9 Other 7.0 8.7 Total $ 400.1 $ 434.4 Regulatory Liabilities Emission allowances $ 87.5 $ 64.5 Asset retirement obligations 39.4 35.6 Additional Wolf Creek amortization (Missouri) 14.6 - 14.6 Other 2.6-Total $ ý144.1 $ 1114.7 Except as noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in KCP&L's rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base. The regulatory asset for SFAS No. 158 pension and post-retirement costs at December 31, 2007, is more than offset by related liabilities, not included in rate base, representing the difference between funding and expenses recognized for the pension and post-retirement plans, which will be amortized in accordance with SFAS No. 87, "Employers' Accounting for Pensions." The regulatory asset for other pension and post-retirement costs at December 31, 2007, includes $41.2 million representing pension settlements and financial and regulatory accounting method differences. The pension settlements, totaling $12.4 million, will be amortized over a five-year period beginning January 1, 2008. The accounting method difference will be eliminated over the life of the pension plans. Certain insignificant items in Regulatory Assets - Other are also not included in rate base.
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| Revenue Sufficiency Guarantee Since the April 2005 implementation of Midwest Independent Transmission System Operator Inc.
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| (MISO) market operations, MISO's business practice manuals and other instructions to market participants have stated that Revenue Sufficiency Guarantee (RSG) charges will not be imposed on day-ahead virtual offers to supply power not supported by actual generation. RSG charges are collected by MISO in order to compensate generators that are standing by to supply electricity when called upon by MISO. In April 2006, FERC issued an order regarding MISO RSG charges. In its order, FERC interpreted MISO's tariff to require that virtual supply offers be included in the calculation of RSG charges and that to the extent that MISO did not charge market participants RSG charges on virtual supply offers, MISO violated its tariff. The FERC order required MISO to recalculate RSG rates back to April 1, 2005, and make refunds to customers who paid RSG charges on imbalances, with interest, 90
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| reflecting the recalculated charges. In order to make such refunds, RSG charges could have been retroactively imposed on market participants who submitted virtual supply offers during the recalculation period. Strategic Energy was among the MISO participants that could have been subject to a retroactive assessment from MISO for RSG charges on virtual supply offers it submitted during the recalculation period. In October 2006, FERC issued an order on rehearing of the April 2006 order stating it would not assess RSG charges on virtual supply offers going back to April 1, 2005, but ordered prospective allocation of RSG to virtual transactions and directed MISO to propose a tariff change that would assess RSG costs to virtual supply offers based on principles of cost causation within 60 days of the October 2006 order.
| |
| In March 2007, FERC issued an order denying requests for rehearing of its October 2006 order, which refused to allow MISO to retroactively assess RSG charges on virtual supply offers. Also in March 2007, FERC rejected MISO's tariff filing that would have established a new RSG charge prospectively and instructed MISO to recalculate RSG charges from April 2006 forward. Parties, including Strategic Energy, appealed and filed requests for rehearing. In November 2007, FERC issued further orders denying rehearing, affirming its prior orders and accepting MISO's compliance filing. Strategic Energy filed a petition for review of the underlying orders. Should certain parties seeking imposition of RSG charges back to April 1, 2005, succeed in their appeal to the U.S. District Court for the District of Columbia, there could be a retroactive resettlement. Management has estimated the potential exposure could range from $0 to $7 million. The range of potential exposure is based on management's judgments and assumptions and does not contemplate all possible outcomes. The actual exposure, if any, could ultimately be greater than management's estimate. Management is unable to predict the outcome of any appeals or further requests for rehearing.
| |
| Seams Elimination Charge Adjustment Seams Elimination Charge Adjustment (SECA) was a transitional pricing mechanism authorized by FERC and intended to compensate transmission owners for the revenue lost as a result of FERC's elimination of regional through and out rates between PJM Interconnection, LLC (PJM) and MISO during a 16-month transition period from December 1, 2004, through March 31, 2006. Each relevant PJM and MISO zone and the load-serving entities within that zone were allocated a portion of SECA based on transmission services provided to that zone during 2002 and 2003. In 2007, Strategic Energy recorded a reduction of purchased power expense of $1.9 million to reflect recoveries obtained through settlements primarily with Transmission Owners. In 2006, Strategic Energy recorded a reduction of purchased power expense of $2.4 million for SECA recoveries, which partially offset $2.7 million of expense recorded in the first quarter. In 2005, Strategic Energy recorded purchased power expense totaling $13.6 million for SECA. Strategic Energy billed $1.3 million and $5.4 million in 2006 and 2005, respectively, of its SECA costs to its retail customers. No further retail customer billings are anticipated pending the outcome of proceedings discussed below.
| |
| There are several unresolved matters and legal challenges related to SECA that are pending before' FERC on rehearing. In 2006, FERC held hearings on the justness and reasonableness of the SECA rate and on attempts by suppliers to shift SECA to wholesale counterparties and subsequently, a favorable initial decision was extended by an administrative law judge, which could potentially result in a refund of prior SECA payments, including payments made by Strategic Energy. Management is awaiting FERC action and is unable to predict the outcome of legal and regulatory challenges to the SECA mechanism.
| |
| 91
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| : 7. GOODWILL AND INTANGIBLE PROPERTY Great Plains Energy's consolidated balance sheets reflect goodwill associated with the Company's ownership in Strategic Energy of $88.1 million at December 31, 2007 and 2006. Annual impairment tests, conducted in September of each year, have been completed, fair value as determined exceeded the carrying amount and; therefore, there were no impairments of goodwill in 2007, 2006 or 2005.
| |
| Other Intangible Assets and Related Liabilities Great Plains Energy and consolidated KCP&L's intangible assets and related liabilities are detailed in the following table.
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| December 31, 2007 December 31, 2006 Gross Carrying Accumulated Gross Carrying Accumulated Amount Amortization Amount Amortization Consolidated KCP&L (millions)
| |
| Computer software (a) $ 111.9 $ (84.7) $ 100.4 $ (76.2)
| |
| Other Great Plains Energy Computer software (a) 17.8 (12.3) 15.5 (8.5)
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| Acquired intangible assets Customer relationships 17.0 (10.4) 17.0 (7.6)
| |
| Asset information systems 1.9 (1.9) 1.9 (1.4)
| |
| Unamortized intangible assets Strategic Energy trade name 0.7 0.7 Total intangible assets $ 149.3 $ (109.3) $ 135.5 $ (93.7)
| |
| (a) Coin puter software is included in electric utility plant or other nonutility property; as applicable, on the consolidated balance sheets.
| |
| The fair values of acquired supply (intangible asset) and retail (liability) contracts were amortized over 28 months and were fully amortized by December 31, 2006. The fair value of acquired asset information systems were amortized over 44 months and were fully amortized by December 31, 2007.
| |
| Other intangible assets recorded that have finite lives and are subject to amortization include customer relationships, which are being amortized over 72 months.
| |
| Amortization expense for the -acquired share of intangible assets and related liabilities is detailed in the following table.
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| Estimated Amortization Expense 2007 2006 2005 2008 2009 2010 (millions)
| |
| Intangible assets $ 3.3 $ 10.6 $ 15.0 $ 2.8 $ 2.9 $ 0.9 Related liabilities - (7.2) (11.6) - - -
| |
| Net amortization expense $ 3.3 $ 3.4 $ 3.4 $ 2.8 $ 2.9 $ 0.9
| |
| : 8. PENSION PLANS, OTHER EMPLOYEE BENEFITS AND SKILL SET REALIGNMENT COSTS Pension Plans and Other Employee Benefits The Company maintains defined benefit pension plans for substantially all employees, including officers, of KCP&L, Services and WCNOC and incurs significant costs in providing the plans, with the majority incurred by KCP&L. Pension benefits under these plans reflect the employees' compensation, years of service and age at retirement. For financial reporting purposes, the market value of plan assets is the fair value. For regulatory reporting purposes, fair value is determined using a five-year smoothing of assets.
| |
| 92
| |
| | |
| Effective January 1, 2008, the Company amended the defined benefit pension plan for management employees (other than WCNOC employees) to allow current employees the option to remain in the existing program or to choose a new retirement program which will provide, among other things, an enhanced benefit under the employee savings plan and a lower benefit accrual rate under the defined pension benefit plan. Employees hired after September 1, 2007, have been placed in the new retirement program.
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| KCP&L records pension expense in accordance with rate orders from the MPSC and KCC that allow the difference between pension costs under SFAS No. 87 and SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," and pension costs for ratemaking to be recognized as a regulatory asset or liability.
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| In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits for substantially all retired employees of KCP&L, Services and WCNOC. In January 2007, the post-retirement plan was amended to enhance medical benefits for the management employees. The change increased the accumulated post-retirement benefit obligation $19.5 million and increased the 2007 post-retirement expense $2.9 million. The cost of post-retirement benefits charged to KCP&L are accrued during an employee's years of service and recovered through rates.
| |
| The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans on an aggregate basis as well as the components of net periodic benefit costs.
| |
| The plan measurement date for the majority of plans is September 30. The Company will adopt a fiscal year-end measurement date for the fiscal year ending December 31, 2008. In 2007, contributions of
| |
| $6.8 million and $7.2 million were made to the pension and post-retirement benefit plans, respectively, after the measurement date and in 2006, contributions of $1.2 million and $4.6 million were made to the pension plan and post-retirement benefit plans, respectively, after the measurement date. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.
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| 93
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| | |
| Pension Benefits Other Benefits 2007 2006 2007 2006 Change in projected benefit obligation (PBO) (millions)
| |
| PBO at beginning of year $ 508.8 $ 554.6 $ 51.5 $ 53.0 Service cost 18.4 18.8 1.2 0.9 Interest cost 29.8 30.9 3.9 3.0 Contribution by participants - - 2.0 1.3 Amendments (0.8) - 19.5 -
| |
| Actuarial loss (gain) (9.6) 6.5 (1.7) (1.8)
| |
| Benefits paid (35.5) (17.9) (2.9) (4.2)
| |
| Benefits paid by Company (0.4) (0.4) (0.7) (0.7)
| |
| Special termination benefits 2.2 - 0.9 Settlements paid - (837) - -
| |
| PBO at end of plan year $ 512.9 $ 508.8 $ 73.7 $ 51.5 Change in plan assets Fair value of plan assets at beginning of year $ 364.5 , $ 412.2 $ 13.4 $ 12.2 Actual return on plan assets 44.1 34.3 (3.2) 0.6 Contributions by employer and participants 27.0 18.8 6.7 4.8 Benefits paid (35.5) (17.9) (2.9) (4.2)
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| Settlements paid - (82.9) - -
| |
| Fair value of plan assets at end of plan year $ 400.1 $ 364.5 $ 14.0 $ 13.4 Funded status at end of year $(112.8) $(144.3) $ (59.7) $ (38.1)
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| Amounts recognized in the consolidated balance sheets Current pension and other post-retirement liability $ (0.5) $ (0.5) $ (0.8) $ (0.5)
| |
| Noncurrent pension liability and other post-retirement liability (112.3) (143.8) (58.9) (37.6)
| |
| Contributions and changes after measurement date 6.8 0.6 7.2 4.6 Net amount recognized before regulatory treatment (106.0) (143.7) (52.5) (33.5)
| |
| Accumulated OCI or regulatory asset 185.4 240.3 37.8 19.2 Net amount recognized at December 31 $ 79.4 $ 96.6 $ (14.7) $ (14.3)
| |
| Amounts in accumulated OCI or regulatory asset not yet recognized as a component of net periodic cost:
| |
| Actuarial loss $ 86.1 $ 144.8 $ 13.8 $ 11.6 Prior ser\ice cost 23.1 28.3 18.1 0.6 Transition obligation 0.2 0.3 5.8 7.0 Other 76.0 66.9 0.1 -
| |
| Net amount recognized at December 31 $ 185.4 $ 240.3 $ 37.8 $ 19.2 94
| |
| | |
| Pension Benefits Other Benefits Year to Date December 31 2007 2006 2005 2007 2006 2005 Components of net periodic benefit cost (millions)
| |
| Ser\Ace cost $ 18.4 $ 18.8 $ 17.3 $ 1.2 $ 0.9 $ 0.9 Interest cost 29.8 30.9 29.8 3.9 3.0 2.9 Expected return on plan assets (29.5) (32.7) (32.4) (0.7) (0.6) (0.6)
| |
| Amortization of prior service cost 4.3 4.3 4.3 2.1 0.2 0.2 Recognized net actuarial loss 35.3 31.8 18.6 0.5 0.9 0.5 Transition obligation 0.1 0.1 0.1 1.2 1.2 1.2 Special termination benefits 1.5 - - 0.2 - -
| |
| Settlement charges - 23.1 - - - -
| |
| Net periodic benefit cost before regulatory adjustment 59.9 76.3 37.7 8.4 5.6 5.1 Regulatory adjustment (9.1) (52.3) (14.6) (0.1) - -
| |
| Net periodic benefit cost 50.8 24.0 23.1 8.3 5.6 5.1 Other changes in plan assets and benefit obligations recognized in OCI or regulatory assets Current year net loss (gain) (23.4) - - 2.7 -
| |
| Amortization of loss (gain) (35.3) - (0.5) -
| |
| Prior service cost (credit) (0.9) - - 19.6 -
| |
| Amortization of prior service cost (4.3) - - (2.1) -
| |
| Amortization of transition obligation (0.1) - - (1.2) -
| |
| Other regulatory activity 9.1 - - 0.1 Total recognized in OCI or regulatory asset (54.9) - - 18.6 -
| |
| Total recognized in net periodic benefit cost and OCI or regulatory asset $ (4.1) $ 24.0 $ 23.1 $ 26.9 $ 5.6 $ 5.1 The estimated prior service cost, net loss and transition costs for the defined benefit plans that will be amortized from accumulated 001 or a regulatory asset into net periodic benefit cost in 2008 are $4.2 million, $32.3 million and $0.1 million, respectively. The estimated prior service cost, net loss, and transition costs for the other post-retirement benefit plans that will be amortized from accumulated 001 or a regulatory asset into net periodic benefit cost in 2008 are $2.7 million, $0.6 million and $1.2 million, respectively. For financial reporting purposes, net actuarial gains and losses are recognized on a rolling five-year average basis. For regulatory reporting purposes, net actuarial gains and losses are amortized over ten years.
| |
| 95
| |
| | |
| The accumulated benefit obligation (ABO) for all defined benefit pension plans was $423.8 million and
| |
| $427.1 million at December 31, 2007 and 2006, respectively. The PBO, ABO and the fair value of plan assets at plan year-end are aggregated by funded and under funded plans in the following table.
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| 2007 2006 Pension plans with the ABO in excess of plan assets (millions)
| |
| Projected benefit obligation $ 327.5 $ 323.9 Accumulated benefit obligation 266.4 268.5 Fair value of plan assets 220.1 193.4 Pension plans with plan assets in excess of the ABO Projected benefit obligation $ 185.4 $ 184.9 Accumulated benefit obligation 157.4 158.6 Fair value of plan assets 180.0 171.1 The expected long-term rate of return on plan assets represents the Company's estimate of the long-term return on plan assets and is based on historical and projected rates of return for current and planned asset classes in the plans' investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes. Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolio was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions.
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| The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.
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| Weighted average assumptions used to determine Pension Benefits Other Benefits the benefit obligation at plan year-end 2007 2006 2007 2006 Discount rate 6.23% 5.87% 6.23% 5.89%
| |
| Rate of compensation increase 4.22% 3.81% 4.25% 3.90%
| |
| Weighted average assumptions used to determine Pension Benefits Other Benefits net costs for years ended at December 31 2007 2006 2007 2006 Discount rate 5.87% 5.62% 5.89% 5.62%
| |
| Expected long-term return on plan assets 8.25% 8.25% 4.00%
| |
| * 4.23%
| |
| * Rate of compensation increase 3.81% 3.57% 3.90% 3.60%
| |
| * after tax 96
| |
| | |
| Pension plan assets are managed in accordance with "prudent investor" guidelines contained in the Employee Retirement Income Security Act (ERISA) requirements. The investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets within a reasonable and prudent level of risk. Investments are diversified across classes and within each class to minimize risks. At December 31, 2007 and 2006, respectively, the fair value of plan assets was $400.1 million, not including a $6.8 million contribution made after the plan year-end, and $364.5 million, not including a $1.2 million subsequent contribution. The asset allocation for the Company's pension plans at December 31, 2007 and 2006, and the target allocation for 2008 are reported in the following table.
| |
| The portfolio is periodically rebalanced to generally meet target allocation percentages.
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| Plan Assets at Target December 31 Asset Category Allocation 2007 2006 Equity securities 59% 57% 67%
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| Debt securities 33% 31% 22%
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| Real estate 6% 6% 6%
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| Other 2% 6% 5%
| |
| Total 100% 100% 100%
| |
| Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The cost trend assumed for 2007 and 2008 is 8% and the rate will continue to decline through 2014 to the ultimate cost trend rate of 5%. The health care plan requires retirees to make monthly contributions on behalf of themselves and their dependents in an amount determined by the Company.
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| The effects of a one-percentage point change in the assumed health care cost trend rates, holding all other assumptions constant, at December 31, 2007, are detailed in the following table.
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| Increase Decrease (millions)
| |
| Effect on total service and interest component $ 0.1 $ (0.1)
| |
| Effect on postretirement benefit obligation 0.7 (1.1) 97
| |
| | |
| The Company expects to contribute $29.3 million to the plans in 2008 to meet ERISA funding requirements and regulatory orders, all of which will be paid by KCP&L. The Company's funding policy is to contribute amounts sufficient to meet the ERISA minimum funding requirements and MPSC and KCC rate orders plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions. The Company also expects to contribute $7.2 million to other post-retirement benefit plans in 2008, $6.8 million of which will be paid by KCP&L. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid through 2017.
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| Pension Other Benefits Benefits (millions) 2008 $ 40.7 $ 7.2 2009 38.2 7.7 2010 40.5 8.4 2011 40.3 9.3 2012 45.8 9.9 2013-2017 243.8 62.1 Employee Savings Plans Great Plains Energy has defined contribution savings plans that cover substantially all employees. The Company matches employee contributions, subject to limits. The annual cost of the plans was approximately $5.0 million in 2007 and $4.8 million in 2006 and 2005. Consolidated KCP&L's annual cost of the plans was approximately $4.3 million in 2007 and $4.0 million in 2006 and 2005.
| |
| Cash-Based Long-Term Incentives Strategic Energy has long-term incentives designed to reward officers and key members of management with Great Plains Energy restricted stock (issued under the Company's Long-Term Incentive Plan) and a cash performance payment for achieving specific performance goals over stated periods of time, commencing January 1, 2005. The restricted stock compensation expense is discussed in Note 9. In 2007, 2006 and 2005, compensation expense of $1.4 million, $3.8 million and
| |
| $1.6 million, respectively, was recognized for the cash-based incentives.
| |
| Skill Set Realignment (Deferral) Cost In 2005 and early 2006, management undertook a process to assess, improve and reposition the skill sets of employees for implementation of the Comprehensive Energy Plan. In 2006, Great Plains Energy and consolidated KCP&L recorded $9.4 million and $9.3 million, respectively, related to this process reflecting severance, benefits and related payroll taxes provided to employees. In 2007, KCP&L received authorization from the MPSC and KCC to establish an $8.9 million regulatory asset for these costs and amortize them over five years for the Missouri jurisdictional portion and ten years for the Kansas jurisdictional portion effective with new rates on January 1, 2008.
| |
| : 9. EQUITY COMPENSATION Great Plains Energy's Long-Term Incentive Plan is an equity compensation plan approved by Great Plains Energy's shareholders. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights, director shares, director deferred share units and performance shares to directors, officers and other employees of Great Plains Energy and KCP&L.
| |
| The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 5.0 million. Common stock shares delivered by Great Plains Energy under the Long-Term Incentive Plan may be authorized but unissued, held in the treasury or purchased on the open market (including private purchases) in accordance with applicable security laws. Great Plains Energy has a policy of delivering newly issued shares, or shares surrendered by Long-Term Incentive Plan 98
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| | |
| participants on account of withholding taxes and held in treasury, or both, to satisfy share option exercises and does not expect to repurchase common shares during 2008 to satisfy stock option exercises.
| |
| Forfeiture rates are based on historical forfeitures and future expectations and are reevaluated annually. The following table summarizes Great Plains Energy's and KCP&L's equity compensation expense and associated income tax benefits.
| |
| 2007 2006 2005 Great Plains Energy (millions)
| |
| Compensation expense $ 6.4 $ 3.9 $ 2.8 Income tax benefits 2.1 1.2 1.1 KCP&L Compensation expense 4.3 2.4 1.7 Income tax benefits 1.4 0.8 0.6 Stock Options Granted 2001 - 2003 Stock options were granted under the plan at market value of the shares on the grant date. The options vested three years after the grant date and expire in ten years if not exercised. The fair value for the stock options granted in 2001 - 2003 was estimated at the date of grant using the Black-Scholes option-pricing model. Compensation expense and accrued dividends related to stock options were recognized over the stated vesting period. Exercise prices range from $24.90 to $27.73 and all stock options are fully vested and have a remaining weighted average contractual term of 3.9 years at December 31, 2007. There was no stock option activity in 2007. At December 31, 2007, there were 109,472 outstanding and exercisable stock options at a weighted-average exercise price of $25.52. At December 31, 2007, the aggregate intrinsic value of the outstanding options was $0.4 million.
| |
| Performance Shares The payment of performance shares is contingent upon achievement of specific performance goals over a stated period of time as approved by the Compensation and Development Committee of Great Plains Energy's Board of Directors. The number of performance shares ultimately paid can vary-from the number of shares initially granted depending on Great Plains Energy's performance, based on internal and external measures, over stated performance periods. Performance shares have a value equal to the market value of the shares on the grant date with accruing dividends. Compensation expense, calculated by multiplying shares by the related grant-date fair value related to performance shares, is recognized over the stated period.
| |
| 99
| |
| | |
| Performance share activity for 2007 is summarized in the following table. Performance adjustment represents the number of shares of common stock related to performance shares ultimately issued that can vary from the number of performance shares initially granted depending on Great Plains Energy's performance, based on internal and external measures, over stated performance periods.
| |
| Grant Date Performance Shares Fair Value*
| |
| Beginning balance 254,771 $ 29.56 Performance adjustment (22,070)
| |
| Granted 123,542 32.00 Issued (42,169) 30.27 Forfeited (4,385) 32.35 Ending balance 309,689 30.34
| |
| * weighted-average At December 31, 2007, the remaining weighted-average contractual term was 1.1 years. The weighted-average grant-date fair value of shares granted was $32.00, $28.20 and $30.34 in 2007, 2006 and 2005, respectively. At December 31, 2007, there was $3.3 million of total unrecognized compensation expense, net of forfeiture rates, related to performance shares granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term.
| |
| The total fair value of shares of common stock related to performance shares issued was $1.3 million during 2007 and $0.3 million during 2006. No shares of common stock were issued related to performance shares during 2005.
| |
| Restricted Stock Restricted stock cannot be sold or otherwise transferred by the recipient prior to vesting and has a value equal to the fair market value of the shares on the issue date. Restricted stock shares vest over a stated period of time with accruing reinvested dividends. Compensation expense, calculated by multiplying shares by the related grant-date fair value related to restricted stock, is recognized over the stated vesting period. Restricted stock activity for 2007 is summarized in the following table.
| |
| Nonvested Grant Date Restricted stock Shares Fair Value*
| |
| Beginning balance 140,603 $ 29.75 Granted and issued 348,527 31.93 Vested (36,406) 30.34 Forfeited (5,842) 31.40 Ending balance 446,882 31.38
| |
| * weighted-average At December 31, 2007, the remaining weighted-average contractual term was 1.4 years. The weighted-average grant-date fair value of shares granted was $31.93, $28.22 and $30.47 during 2007, 2006 and 2005, respectively. At December 31, 2007, there was $6.9 million of total unrecognized compensation expense, net of forfeiture rates, related to nonvested restricted stock granted under the Long-Term Incentive Plan, which will be recognized over the remaining weighted-average contractual term. The total fair value of shares vested was $1.1 million, $0.8 million and $0.8 million in 2007, 2006 and 2005, respectively.
| |
| 100
| |
| : 10. TAXES Components of income tax expense (benefit) are detailed in the following tables.
| |
| Great Plains Energy 2007 2006 2005 Current income taxes (millions)
| |
| Federal $ 44.3 $ 59.2 $ 64.3 State 6.5 0.9 1.3 Total 50.8 60.1 65.6 Deferred income taxes Federal 22.5 (7.2) (4.2)
| |
| State 1.3 (3.8) (19.0)
| |
| Total 23.8 (11.0) (23.2)
| |
| Noncurrent income taxes (a)
| |
| Federal (0.7)--
| |
| State (0.9)--
| |
| Total (1.6)--
| |
| Investment tax credit amortization (1.5) (1.2) (3.9)
| |
| Total income tax expense 71.5 47.9 38.5 Less: taxes on discontinued operations Current tax (benefit) expense - - (1.0)
| |
| Income taxes on continuing operations $ 71.5 $ 47.9 $ 39.5 Consolidated KCP&L 2007 2006 2005 Current income taxes (millions)
| |
| Federal $ 38.7 $ 49.3 $ 79.9 State 4.4 4.8 5.6 Total 43.1 54.1 85.5 Deferred income taxes Federal 17.7 15.6 (14.3)
| |
| State 2.0 1.8 (19.3)
| |
| Total 19.7 17.4 (33.6)
| |
| Noncurrent income taxes (a)
| |
| Federal (1.7) --
| |
| State (0.3)--
| |
| Total (2.0)--
| |
| lnvastment tax credit amortization (1.5) (1.2) (3.9)
| |
| Total $ 59.3 $ 70.3 $ 48.0 (a) For 2007, this includes amounts recognized under FIN No. 48. Tax contingency reserves for 2006 and 2005 are included in current income tax expense.
| |
| 101
| |
| | |
| Income Tax Expense (Benefit) and Effective Income Tax Rates Income tax expense and the effective income tax rates reflected in continuing operations in the financial statements and the reasons for their differences from the statutory federal rates are detailed in the following tables.
| |
| Income Tax Expense Income Tax Rate Great Plains Energy 2007 2006 2005 2007 2006 2005 (millions)
| |
| Federal statutory income tax $ 80.7 $ 61.4 $ 71.3 35.0 % 35.0 % 35.0 %
| |
| Differences between book and tax depreciation not normalized 2.0 (0.3) 2.3 0.9 (0.2) 1.1 Amortization of investment tax credits (1.5) (1.2) (3.9) (0.6) (0.7) (1.9)
| |
| Federal income tax credits (7.9) (9.3) (10.0) (3.4) (5.3) (4.9)
| |
| State income taxes 4.9 0.5 2.7 2.1 0.3 1.3 Changes in uncertain tax positions, net (a) 0.5 0.1 (7.9) 0.2 - (3.9)
| |
| Rate change on deferred taxes - (11.7) - (5.8)
| |
| Aquila transaction costs (3.7) (1.6) -
| |
| Other (3.5) (3.3) (3.3) .(1.6) (1.8) (1.5)
| |
| Total $ 71.5 $ 47.9 $ 39.5 31.0 % 27.3 % 19.4 %
| |
| (a) For 2007, this includes amounts recognized under FIN No. 48.
| |
| Income Tax Expense Income Tax Rate Consolidated KCP&L 2007 2006 2005 2007 2006 2005 (millions)
| |
| Federal statutory income tax $ 75.6 $ 76.9 $ 67.0 35.0 % 35.0 % 35.0 %
| |
| Differences between book and tax depreciation not normalized 2.0 (0.3) 2.3 0.9 (0.2) 1.2 Amortization of investment tax credits (1.5) (1.2) (3.9) (0.7) (0.6) (2.0)
| |
| Federal income tax credits (6.4) (4.6) - (2.9) (2.1)
| |
| State income taxes 4.7 5.5 4.2 2.2 2.5 2.2 Changes in uncertain tax positions, net (a) (0.3) 0.6 (1.7) (0.1) 0.3 (0.9)
| |
| Parent company tax benefits (12.0) (4.7) (5.4) (5.6) (2.1) (2.8)
| |
| Rate change on deferred taxes - (11.7) - (6.1)
| |
| Other (2.8) (1.9) (2.8) (1.4) (0.8) (1.6)
| |
| Total $ 59.3 $ 70.3 $ 48.0 27.4 % 32.0 % 25.0 %
| |
| (a) For 2007, this includes amounts recognized under FIN No. 48.
| |
| SFAS No. 109 requires the companies to adjust deferred tax balances to reflect tax rates that are anticipated to be in effect when the differences reverse. In 2005, Great Plains Energy and KCP&L adjusted their deferred tax balances to reflect lower composite tax rates due to the impact of sustained audited positions and state tax planning, which resulted in deferred tax benefits for Great Plains Energy and consolidated KCP&L of $11.7 million in 2005.
| |
| 102
| |
| | |
| Deferred Income Taxes The tax effects of major temporary differences resulting in deferred income tax assets (liabilities) in the consolidated balance sheets are in the following tables.
| |
| Great Plains Energy Consolidated KCP&L December 31 2007 2006 2007 2006 Current deferred income taxes (millions)
| |
| Nuclear fuel outage $ (2.4) $ (5.2) $ (2.4) $ (5.2)
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| Derivative instruments 9.8 34.1 (0.1) 0.2 Accrued vacation 4.8 4.5 4.7 4.4 Other 7.6 6.2 1.2 0.7 Net current deferred income tax asset 19.8 39.6 3.4 0.1 Noncurrent deferred income taxes Plant related (573.7) (566.3) (573.7) (566.3)
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| Income taxes on future regulatory recoveries (66.5) (81.7) (66.5) (81.7)
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| Derivative instruments (3.6) 19.3 4.5 (4.3)
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| Pension and postretirement benefits (23.3) (28.9) (25.8) (31.2)
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| Storm related costs - (0.1) - (0.1)
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| Debt issuance costs (2.3) (2.5) (2.3) (2.5)
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| Gas properties related (0.8) (1.1) -
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| SO 2 emission allowance sales 33.4 24.5 33.4 24.5 Tax credit carryforwards 19.2 15.0 - -
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| State net operating loss carryforward 0.4 0.5 -
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| Other (7.2) (0.8)- (11.8) 1.6 Net noncurrent deferred tax liability before valuation allowance (624.4) (622.1) (642.2) (660.0)
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| Valuation allowance (0.4) (0.5) - -
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| Net noncurrent deferred tax liability (624.8) (622.6) (642.2) (660.0)
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| Net deferred income tax liability $ (605.0) $ (583.0) $ (638.8) $ (659.9)
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| Great Plains Energy Consolidated KCP&L December 31 2007 2006 2007 2006 (millions)
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| Gross deferred income tax assets $ 231.0 $ 251.3 $ 183.0 $ 166.9 Gross deferred income tax liabilities (836.0) (834.3) (821.8) (826.8)
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| Net deferred income tax liability $ (605.0) $ (583.0) $ (638.8) $ (659.9)
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| Tax Credit Carryforwards At December 31, 2007, the Company had $19.2 million of state income tax credit carryforwards. These credits relate primarily to the Company's Missouri affordable housing investment portfolio, and the carryforwards expire in years 2009 to 2012. Management believes the credits will be fully utilized within the carryforward period.
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| Net Operating Loss Carryforwards At December 31, 2007, KLT Inc. and its subsidiaries had Kansas state net operating loss carryforwards of $9.4 million primarily resulting from losses associated with DTI Holdings, Inc. and its subsidiaries, Digital Teleport, Inc. and Digital Teleport of Virginia, Inc. KLT Inc. and its subsidiaries moved its corporate headquarters to Missouri in 2003, and as a result, will not have sufficient presence in Kansas to utilize the losses. The Kansas state net operating loss carryforwards expire in years 2011 to 2012.
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| Management has determined that the loss carryforwards will more likely than not expire unutilized and has provided a valuation allowance against the entire $0.4 million deferred state income tax benefit.
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| Uncertain Tax Positions In 2006, the FASB issued FIN No. 48, "Accounting for Uncertainty in Income Taxes," an interpretation of SFAS No. 109, "Accounting for Income Taxes." FIN No. 48 establishes a "more-likely-than-not" recognition threshold that must be met before a tax benefit can be recognized in the financial statements with various additional disclosures required and is effective for fiscal years beginning after December 15, 2006. Upon adoption of FIN No. 48 on January 1, 2007, Great Plains Energy recognized an $18.8 million increase in the liability for unrecognized tax benefits. This increase was offset by a $0.9 million decrease to the January 1, 2007, balance of retained earnings, a $17.9 million decrease in deferred taxes, a $4.0 million decrease in accrued taxes and a $4.0 million increase in accrued interest. The total amount of unrecognized tax benefits at January 1, 2007, was $23.5 million of which $3.5 million would impact the effective tax rate, if recognized. Consolidated KCP&L recognized a $19.8 million increase in the liability for unrecognized tax benefits. This increase was offset by a $0.2 million decrease to the January 1, 2007, balance of retained earnings, a $15.7 million decrease in deferred taxes and a $3.9 million decrease in accrued taxes. The total amount of unrecognized tax benefits at January 1, 2007, was $21.6 million of which $1.6 million would impact the effective tax rate, if recognized.
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| In addition with the adoption of FIN No. 48, Great Plains Energy and consolidated KCP&L elected to make an accounting policy change to recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses. As of the date of adoption, Great Plains Energy and consolidated KCP&L had $6.4 million and $2.4 million, respectively, accrued for the payment of interest. No amounts were accrued for penalties with respect to unrecognized tax benefits.
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| At December 31, 2007, accrued interest related to unrecognized tax benefits for Great Plains Energy and consolidated KCP&L was $8.4 million and $3.4 million, respectively.
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| The following table reflects activity subsequent to the adoption of FIN No. 48 for Great Plains Energy and consolidated KCP&L related to the liability for unrecognized tax benefits.
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| Great Plains Consolidated Energy KCP&L (millions)
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| Balance at January 1, 2007 $ 23.5 $ 21.6 Additions for current year tax positions 4.1 2.9 Additions for prior year tax positions 0.1 0.1 Reductions for prior year tax positions (5.0) (4.9)
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| Statute expirations (0.8) (0.1)
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| Balance at December 31, 2007 $ 21.9 $ 19.6 The total amount of uncertain tax benefits which would impact the effective tax rate, if recognized at December 31, 2007, is $3.6 million and $1.3 million for Great Plains Energy and consolidated KCP&L, respectively.
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| Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant.
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| Great Plains Energy and its subsidiaries have completed examinations by federal and state taxing authorities for taxable years prior to 2000; however several tax issues remain unresolved for tax years 2000 through 2003. During 2006, the IRS commenced an audit of Great Plains Energy and its subsidiaries for taxable years 2004 through 2005 and is expected to complete the audit by the end of 2008.
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| 104
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| It is reasonably possible that, as a result of a settlement agreement for the federal audit of the 2000 through 2003 tax years expected to be reached by December 2008, federal and state unrecognized tax benefits related primarily to the timing of tax deductions would be recognized by Great Plains Energy and consolidated KCP&L. An estimate of the amount of unrecognized tax benefits that may be recognized in the next twelve months was $9 million to $11 million as of the date of adoption and $8 million to $10 million at December 31, 2007, for Great Plains Energy and $7 million to $9 million as of the date of adoption and at December 31, 2007, for consolidated KCP&L.
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| : 11. KLT GAS DISCONTINUED OPERATIONS The KLT Gas natural gas properties (KLT Gas portfolio) was reported as discontinued operations in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" after the 2004 Board of Directors approval to sell the KLT Gas portfolio and discontinue the gas business.
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| During 2004 and 2005, KLT Gas completed sales of the KLT Gas portfolio and in 2006 KLT Gas had no active operations. During 2005, KLT Gas had losses from operations before income taxes of $2.9 million and an income tax benefit of $1.0 million, resulting in a net loss from discontinued operations of
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| $1.9 million.
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| : 12. RELATED PARTY TRANSACTIONS AND RELATIONSHIPS Consolidated KCP&L receives various support and administrative services from Services. These services are billed to consolidated KCP&L at cost, based on payroll and other expenses, incurred by Services for the benefit of consolidated KCP&L. These costs totaled $14.9 million, $18.5 million and
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| $42.6 million for 2007, 2006 and 2005, respectively. These costs consisted primarily of employee compensation, benefits and fees associated with various professional services. At December 31, 2007 and 2006, consolidated KCP&L had a short-term intercompany payable to Services of $1.8 million and
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| $2.5 million, respectively. In 2005, approximately 80% of Services' employees were transferred to KCP&L to better align resources with the operating business. Also at December 31, 2007 and 2006, consolidated KCP&L had a long-term intercompany payable to Services of $1.5 million and $5.7 million, respectively, related to unrecognized pension expense recorded under the provision of SFAS No. 158.
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| At December 31, 2007 and 2006, consolidated KCP&L's balance sheets reflect a note payable from HSS to Great Plains Energy of $0.6 million. Also at December 31, 2007, consolidated KCP&L had a short-term intercompany receivable from Great Plains Energy of $10.5 million.
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| : 13. COMMITMENTS AND CONTINGENCIES Environmental Matters The Company is subject to regulation by federal, state and local authorities with regard to air quality and other environmental matters primarily through KCP&L's operations. The generation, transmission and distribution of electricity produces and requires disposal of certain hazardous products that are subject to these laws and regulations. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. Failure to comply with these laws and regulations could have a material adverse effect on consolidated KCP&L and Great Plains Energy.
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| KCP&L seeks to use current environmental technology. KCP&L conducts environmental audits designed to ensure compliance with governmental regulations. At December 31, 2007 and 2006, KCP&L had $0.3 million accrued for environmental remediation expenses. The accrual covers water monitoring at one site. The amounts accrued were established on an undiscounted basis and KCP&L does not currently have an estimated time frame over which the accrued amounts may be paid.
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| 105
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| Environmental-related legislation is continually introduced and such legislation typically includes various compliance dates and compliance limits. It is possible that legislation could be enacted at the federal or state level to address global climate change, including efforts to reduce and control the emission of -
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| greenhouse gases, such as C0 2 , which is created in the combustion of fossil fuels* In addition, there could be national and state mandates to produce a set percentage of electricity from renewable forms of energy, such as wind. The probability and impact of such legislation cannot be reasonably estimated at this time, including the cost to install new equipment to achieve compliance, but such legislation could have the potential for a significant financial and operational impact on KCP&L. KCP&L would seek recovery of capital costs and expenses for such compliance through rate increases; however, there can be no assurance that such rate increases would be granted. KCP&L will continue to monitor proposed legislation.
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| The Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to reduce emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in regulated emissions. The Sierra Club and Concerned Citizens of Platte County have claimed that modifications were made to latan No. 1 in violation of Clean Air Act regulations. Although KCP&L has entered into a Collaboration Agreement with those parties that provides, among other things, for the release of such claims, the Collaboration Agreement does not bind any other entity. KCP&L is aware of subpoenas issued by a Federal grand jury to certain third parties seeking documents relating to capital projects at latan No. 1. KCP&L has not received a subpoena, and has not been informed of the scope of the grand jury inquiry. The ultimate outcome of these grand jury activities cannot presently be determined, nor can the costs and other liabilities that could potentially result from a negative outcome presently be reasonably estimated. There is no assurance these costs, if any, could be recovered in rates and failure to. recover such costs could have a significant adverse affect on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.
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| The following table contains current estimates of KCP&L's capital expenditures (exclusive of allowance for funds used during construction and property taxes) to comply with environmental laws and regulations described below, including accelerated environmental upgrade expenditures outlined in KCP&L's Comprehensive Energy Plan. The following table does not reflect any costs for complying with future laws or regulations. The ultimate cost could be significantly different from the amounts estimated. The construction environment entering 2008 for the latan No. 1 and latan No. 2 projects is challenging, particularly the tight market conditions for skilled labor and the lengthening lead times for deliveries of materials. KCP&L is conducting a thorough assessment of the impact of the current environment on the projects' cost and schedule. The results of the assessment are expected to be available in the second quarter of 2008. KCP&L continues to refine its cost estimates detailed in the table below and explore alternatives. The allocation between states is based on location of the facilities and has no bearing as to recovery in jurisdictional rates.
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| The table does not reflect potential costs relating to additional wind generation, energy efficiency and other CO 2 emission offsets contemplated by the Collaboration Agreement. Potential costs relating to the additional wind generation and energy efficiency investments that are subject to regulatory approval cannot be reasonably estimated at this time. As well, the potential costs relating to the additional offset of approximately 711,000 tons of CO 2 emissions under the Collaboration Agreement cannot be reasonably estimated at this time. KCP&L will evaluate the available operational and capital resource alternatives, and will select the most cost-effective mix of actions to achieve this additional offset. The potential capital costs of the Collaboration Agreement provisions relating to emission limits at latan and LaCygne generating stations are within the overall estimated capital cost ranges disclosed below.
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| KCP&L expects to seek recovery of the costs associated with the Collaboration Agreement through rate increases; however, there can be no assurance that such rate increases would be granted.
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| Clean Air Estimated Required Environmental Expenditures (a) Missouri Kansas Tota I (millions)
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| CAIR $426 - 1,020 $ - $426 - 1,020 Incremental BART - 538 - 657 538 - 657 (b)
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| Incremental CAMR 11 - 15 5 - 6 16 - 21 Less: expenditures through December 31, 2007 (103) - (103)
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| Estimated remaining required environmental expenditures $334 - 932 $543 - 663 $877 - 1,595 (a)The amounts reflect KCP&L's portion of the cost of projects at jointly-owned units.
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| (b) Reflects an estimated $261 million to $318 million associated with the LaCygne No. 1 baghouse and scrubber project included in the Comprehensive Energy Plan.
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| Clean Air InterstateRule The Environmental Protection Agency (EPA) Clean Air Interstate Rule (CAIR) requires reductions in S02 and NO, emissions in 28 states, including Missouri. The reduction in both SO 2 and NO, emissions will be accomplished through establishment of permanent statewide caps for NOx effective January 1, 2009, and SO 2 effective January 1, 2010. More restrictive caps will be effective January 1, 2015.
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| KCP&L's fossil fuel-fired plants located in Missouri are subject to CAIR, while its fossil fuel-fired plants in Kansas are not.
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| KCP&L expects to meet the emissions reductions required by CAIR at its Missouri plants through a combination of pollution control capital projects and the purchase of emission allowances as needed.
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| CAIR establishes a market-based cap-and-trade program with an emission allowance allocation.
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| Facilities will demonstrate compliance with CAIR by holding sufficient allowances for each ton of S02 and NOx emitted in any given year. KCP&L will also be allowed to utilize unused SO 2 emission allowances that it has accumulated during previous years of the Acid Rain Program to meet the more stringent CAIR requirements. At December 31, 2007, KCP&L had accumulated unused S02 emission allowances sufficient to support just over 80,000 tons of S02 emissions under the provisions of the Acid Rain program, which are recorded in inventory at zero cost. KCP&L is permitted to sell excess SO 2 emission allowances in accordance with KCP&L's Comprehensive Energy Plan as approved by the MPSC and KCC and in 2007, KCP&L sold 41,500 SO 2 emission allowances.
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| Analysis of the final CAIR rule indicates that NOx and SO 2 control may be required for KCP&L's Montrose Station in Missouri, in addition to the environmental upgrades at latan No. 1 included in the Comprehensive Energy Plan. NOx and SO 2 control for KCP&L's Montrose Station could be achieved through a combination of pollution control equipment and the use of or purchase of emission allowances as needed. The timing and necessity of the installation of such control equipment is currently being developed, and as required by the Collaboration Agreement, a study will be completed in 2008 to assess potential future use of Montrose Station, including without limitation, retiring, re-powering and upgrading the units. As discussed below, some of the control technology for S02 and NOx will also aid in the control of mercury.
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| Best Available Retrofit Technology Rule The EPA best available retrofit technology rule (BART) directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions. BART applies to specific eligible facilities including LaCygne Nos. 1 and 2 in Kansas and latan No. 1 and Montrose No. 3 in Missouri. Initially, in Missouri, compliance with CAIR is compliance with BART for individual sources. Depending on the timing of installation of environmental control equipment and the availability of SO 2 emission allowances, the estimated required environmental expenditures presented in the table above could shift from CAIR to incremental BART for Missouri. In the Collaboration Agreement, KCP&L agreed to seek a consent agreement, which it has done, with the Kansas Department of Health and Environment 107
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| (KDHE) incorporating limits for stack particulate matter emissions, as well as limits for NOx and S02 emissions at its LaCygne Station that will be below the presumptive limits under BART. KCP&L further agreed to use its best efforts to install emission control technologies to reduce those emissions from the LaCygne Station prior to the required compliance date under BART, but in no event later than June 1, 2015. KCP&L further agreed to issue requests for proposal for the equipment required to comply with BART by December 31, 2008, requesting that construction commence by December 31, 2010.
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| Mercury Emissions The EPA Clean Air Mercury Rule (CAMR) regulates mercury emissions from coal-fired power plants located in 48 states, including Kansas and Missouri, under the Clean Air Act. In February 2008, a court vacated and remanded CAMR back to the EPA. 'The court's order is subject to an appeals process and the EPA has not taken any action in response to the court's order. Environmental groups have filed a motion with the court asking the court itself to mandate the imposition of maximum achievable control technology (MACT) standards when reviewing permits for new plants now, without waiting for further EPA action. Management cannot predict the outcome of these or further judicial or regulatory actions or their financial or operational effects on KCP&L. The following discussion is based on CAMR prior to the court's action and future regulations regarding mercury emissions, and the costs to KCP&L, may be materially different than CAMR.
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| CAMR established a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two phases, the first phase is effective January 1, 2010, and .the second phase is effective January 1, 2018. Facilities will be required to hold allowances for each ounce of mercury emitted in any given year. Under the cap-and-trade program, KCP&L would be able to purchase mercury allowances or elect to install pollution control equipment to achieve compliance.
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| Management anticipates meeting the first phase cap by taking advantage of KCP&L's mercury reductions achieved through capital expenditures to comply with CAIR and BART or purchasing allowances as needed. While it is expected that mercury allowances will be available in sufficient quantities for purchase in the 2010-2018 timeframe, the significant reduction in the nationwide cap in 2018 may hamper KCP&L's ability to obtain reasonably priced allowances beyond 2018. Management expects capital expenditures would be required to install additional pollution control equipment to meet the second phase cap. During the ensuing years, management will closely monitor advances in technology for removal of mercury and expects to make decisions regarding second phase removal based on then available technology to meet the 2018 compliance date.
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| Carbon Dioxide Many bills concerning greenhouse gases, including C02, are being debated at the federal and state levels. There are various compliance dates and reduction strategies stipulated in the bills. While legislation at both the federal and state level has been introduced, it is difficult to predict when or if the legislation will be enacted. The U.S. Supreme Court has determined that the EPA has statutory authority to regulate C02 from new motor vehicles if EPA forms a judgment that such emissions contribute to climate change. If EPA forms such a judgment, it may ultimately regulate other sources of C02, which may include KCP&L facilities. The KDHE has indicated that it intends to engage industries and stakeholders to establish goals for reducing CO 2 emissions and strategies to achieve those goals.
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| Greenhouse gas regulation has the potential for a significant financial and operational impact on KCP&L in connection with achieving compliance with limits that may be established. However, the financial and operational consequences to KCP&L cannot be determined until final legislation is passed or regulations enacted. Management will continue to monitor the progress of bills and regulations. As previously discussed, KCP&L has entered into a Collaboration Agreement that includes various provisions regarding wind generation, energy efficiency and other C02 offsets.
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| Ozone In June 2007, monitor data indicated that the Kansas City area violated the eight-hour ozone national ambient air quality standard. Missouri and Kansas have implemented the responses established in the maintenance plans for control of ozone. The responses in both states do not require additional controls at KCP&L's generation facilities beyond the currently proposed controls for CAIR and BART. EPA has various options over and above the implementation of the maintenance plans for control of ozone to address a confirmed violation. These options include, but are not limited to, designating the area "non-attainment" and requiring a new regulatory plan to reduce emissions or leaving the designation unchanged, but still requiring a new regulatory plan. At this time, management is unable to predict how the EPA will respond or how that response will impact KCP&L's operations, but the EPA's response could have a significant impact on Great Plains Energy's and consolidated KCP&L's results of operations and financial position.
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| Also in June 2007, EPA issued a proposal for comment to reduce the existing eight-hour ozone national ambient air quality standard. The proposal recommends an ozone standard within a range of 0.07 to 0.075 parts per million (ppm). EPA also is taking comments on alternative standards within a range from 0.06 ppm up to the level of the current eight-hour ozone standard, which is 0.08 ppm. The Kansas City area may have difficulty attaining a revised standard in the future. EPA has taken public comments and has indicated it will issue final standards by March 12, 2008. Although it is difficult to determine the ultimate impact of the proposal at this time, it could have a significant impact on Great Plains Energy's and consolidated KCP&L's results of operations and financial position.
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| Sulfuric Acid Mist BACT Analysis - latan Station As a requirement of the latan Station air permit and the Collaboration Agreement, KCP&L submitted a best available control technology (BACT) analysis for sulfuric acid mist to Missouri Department of Natural Resources (MDNR) in June 2007. MDNR will conduct its own BACT analysis and determine the final emission limit. Although KCP&L believes the emission limit submitted is a BACT limit and can be achieved by the currently proposed emission control equipment, MDNR may ultimately determine a BACT limit for sulfuric acid mist that could require additional control equipment. The above Clean Air Estimated Required Environmental Expenditures table does not reflect the potential costs for additional controls that may be required to meet such a determination. If MDNR does make such a determination, KCP&L will evaluate the available operational and capital resource alternatives, and will select the most cost-effective mix of actions to achieve compliance.
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| Water Use Regulations The Clean Water Act (Act) establishes standards for cooling water intake structures. EPA had previously issued regulations pursuant to Section 316(b) of the Act regarding cooling water intake structures. Subsequent to a court ruling, EPA suspended the regulations and is engaged in further rulemaking on this matter. At this time, management is unable to predict how the EPA will respond or how that response will impact KCP&L's operations.
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| KCP&L holds a permit from the MDNR covering water discharge from its Hawthorn Station. The permit authorizes KCP&L, among other things, to withdraw water from the Missouri river for cooling purposes and return the heated water to the Missouri river. KCP&L has applied for a renewal of this permit and the EPA has submitted an interim objection letter regarding the allowable amount of heat that can be contained in the returned water. Until this matter is resolved, KCP&L continues to operate under its current permit. KCP&L cannot predict the outcome of this matter; however, while less significant outcomes are possible, this matter may require KCP&L to reduce its generation at Hawthorn Station, install cooling towers or both, any of which could have a material adverse effect on KCP&L. The outcome could also affect the terms of water permit renewals at KCP&L's latan and Montrose Stations.
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| 109
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| Contractual Commitments Great Plains Energy's and consolidated KCP&L's expenses related to lease commitments are detailed in the following table.
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| 2007 2006 2005 (millions)
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| Consolidated KCP&L $ 17.3 $ 17.6 $ 19.4 Other Great Plains Energy (a) 1.3 1.3 1.4 Total Great Plains Energy $ 18.6 $ 18.9 $ 20.8 (a)Includes insignificant amounts related to discontinued operations.
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| Great Plains Energy's and consolidated KCP&L's contractual commitments at December 31, 2007, excluding pensions and long-term debt, are detailed in the following tables.
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| Great PlainsEnergy ContractualCommitments 2008 2009 2010 2011 2012 After 2012 Total (millions)
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| Lease commitments $ 18.8 $ 15.3 $ 9.1 $ 8.2 $ 8.0 $ 75.1 $ 134.5 Purchase commitments Fuel (a) 120.0 68.1 65.4 12.2 15.3 187.3 468.3 Purchased capacity 9.0 8.6 6.3 4.7 4.7 10.8 44.1 Purchased power 738.9 382.9 261.4 146.8 34.5 - 1,564.5 Comprehenshie energy plan 705.4 286.7 53.1 - - - 1,045.2 Other 101.3 19.5 27.8 10.2 11.3 22.4 192.5 Total contractual commitments $1,693.4 $781.1 $423.1 $182.1 $ 73.8 $295.6 $3,449.1 (a) Fuel commitments consists of commitments for nuclearfuel, coal, coal transportation costs and natural gas.
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| ConsolidatedKCP&L ContractualCommitments 2008 2009 2010 2011 2012 After 2012 Total (millions)
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| Lease commitments $ 17.4 $ 14.1 $ 8.7 $ 7.8 $ 7.7 $ 74.7 $ 130.4 Purchase commitments Fuel (a) 120.0 68.1 65.4 12.2 15.3 187.3 468.3 Purchased capacity 9.0 8.6 6.3 4.7 4.7 10.8 44.1 Comprehensive energy plan 705.4 286.7 53.1 - - - 1,045.2 Other 101.3 19.5 27.8 10.2 11.3 22.4 192.5 Total contractual commitments $ 953.1 $397.0 $161.3 $ 34.9 $ 39.0 $295.2 $1,880.5 (a)Fuel commitments consists of commitments for nuclear fuel, coal, coal transportation costs and natural gas.
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| Lease commitments end in 2028 and include capital and operating lease obligations; capital lease obligations are $0.2 million per year for the years 2008 through 2012 and total $3.7 million after 2012.
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| Lease obligations also include railcars to serve jointly-owned generating units where KCP&L is the managing partner.' KCP&L will be reimbursed by the other owners for approximately $2.0 million per year ($19.3 million total) of the amounts included in the tables above.
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| KCP&L purchases capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total $11.2 million per year for 2008 through 2011, $6.9 million in 2012 and $1.6 million in 2013.
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| 110
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| Purchased power represents Strategic Energy's agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Strategic Energy has energy sales contracts for 2008 not included above totaling $16.8 million.
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| Comprehensive Energy Plan represents KCP&L's contractual commitment for projects included in its Comprehensive Energy Plan including jointly owned units. KCP&L expects to be reimbursed by other owners for their respective share of latan No. 2 and environmental retrofit costs included in the Comprehensive Energy Plan contractual commitments. Other represents individual commitments entered into in the ordinary course of business.
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| : 14. GUARANTEES In the normal course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on, behalf of certain subsidiaries. Such agreements include, for example, guarantees and indemnification of letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended business purposes. The majority of these agreements guarantee the Company's own future performance, so a liability for the fair value of the obligation is not recorded. Great Plains Energy has provided $279.0 million of credit support for certain Strategic Energy power purchases and regulatory requirements. At December 31, 2007, credit support related to Strategic Energy is as follows:
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| * Great Plains Energy direct guarantees to counterparties totaling $167.4 million, which expire in 2008,
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| * Great Plains Energy indemnifications to surety bond issuers totaling $0.5 million, which expire in 2008,
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| " Great Plains Energy guarantee of Strategic Energy's revolving credit facility totaling $12.5 million, which expires in 2010 and
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| " Great Plains Energy letters of credit totaling $98.6 million, which expire in 2008.
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| At December 31, 2007, KCP&L had guaranteed, with a maximum potential of $2.9 million, energy savings under an agreement with a customer that expires over the next three years. A subcontractor would indemnify KCP&L for any payments made by KCP&L under this guarantee. This guarantee was entered into before December 31, 2002; therefore, a liability was not recorded in accordance with FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others."
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| : 15. LEGAL PROCEEDINGS Kansas City Power & Light Company v. Union Pacific Railroad Company In October 2005, KCP&L filed a rate complaint case with the Surface Transportation Board (STB) charging that Union Pacific Railroad Company's (Union Pacific) rates for transporting coal from the PRB in Wyoming to KCP&L's Montrose Station are unreasonably high. Prior to the end of 2005, the rates were established under a contract with Union Pacific. Efforts to extend the term of the contract were unsuccessful and Union Pacific is the only service for coal transportation from the PRB to Montrose Station. KCP&L charged that Union Pacific possesses market dominance over the traffic and requested the STB prescribe maximum reasonable rates.
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| In February 2006, the STB instituted a rulemaking to address issues regarding the cost test used in rail rate cases and the proper calculation of rail rate relief. As part of that order, the STB delayed hearing KCP&L's case pending the outcome of the rulemaking, and declared that the results of the rulemaking would apply to KCP&L's test. In October 2006, the STB issued its decision, adopting the proposals set 111
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| out in its rulemaking. On March 29, 2007, the STB issued an order stating that the rate complaint filed by KCP&L could proceed. A final decision.on the rate complaint is anticipated by the end of the second quarter of 2008. Until the STB case is decided, KCP&L is paying the higher tariff rates, subject to refund.
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| Hawthorn No. 5 Subrogation Litigation KCP&L received reimbursement for the 1999 Hawthorn No. 5 boiler explosion under a property damage insurance policy with Travelers Property Casualty Company of America (Travelers). Travelers filed suit in the U.S. District Court for the Eastern District of Missouri in November 2005, against National Union Fire Insurance Company of Pittsburgh, Pennsylvania, and KCP&L was added as a defendant in June 2006. The case was subsequently transferred to, and is pending in, the U.S. District Court for the Western District of Missouri. Travelers seeks recovery of $10 million that KCP&L recovered through subrogation litigation.
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| Emergis Technologies, Inc.
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| In March 2006, Emergis Technologies, Inc. f/k/a BCE Emergis Technologies, Inc. (Emergis) filed suit against KCP&L in U.S. District Court for the Western District of Missouri, alleging infringement of a patent, entitled "Electronic Invoicing and Payment System" and seeking unspecified monetary damages and injunctive relief. This patent relates to automated electronic bill presentment and payment systems, particularly those involving Internet billing and collection. In March 2006, KCP&L filed a response and denied infringing the patent. KCP&L counterclaimed for a declaration that the patent is invalid and not infringed. The parties filed a joint stipulation of dismissal and the court ordered the case dismissed in February 2008.
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| Spent Nuclear Fuel and Radioactive Waste In 2004, KCP&L and the other two Wolf Creek owners filed suit against the United States in the U.S.
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| Court of Federal Claims seeking an unspecified amount of monetary damages resulting from the government's failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982. Approximately sixty-five other similar cases were filed with that court, a few of which have settled. To date, the court has rendered final decisions in twelve of the cases, most of which are on appeal now. The Wolf Creek case is on a court-ordered stay until further order of the court to allow for some of the earlier cases to be decided first by an appellate court. Another Federal appellate court has already determined that the government breached its obligation to begin accepting spent fuel for disposal. The questions now before the court in the pending cases are whether and to what extent the utilities are entitled to monetary damages for that breach.
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| Class Action Complaint Tech Met, Inc., et al. v. Strategic Energy On November 21, 2005, a class action complaint for breach of contract was filed against Strategic Energy in the Court of Common Pleas of Allegheny County, Pennsylvania. The five named plaintiffs purportedly represent the interests of customers in Pennsylvania who entered into Power Supply Coordination Service Agreements (Agreements) for electricity service. The complaint seeks monetary damages, attorney fees and costs and a declaration that the customers may terminate their Agreements with Strategic Energy. In response to Strategic Energy's preliminary objections, the plaintiffs filed an amended complaint. After additional objections from Strategic Energy, the plaintiffs agreed to file a second amended complaint. Management is awaiting the second amended complaint.
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| 112
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| Weinstein v. KLT Telecom Richard D. Weinstein (Weinstein) filed suit against KLT Telecom Inc. (KLT Telecom) in September 2003 in the Circuit Court of St. Louis County, Missouri. KLT Telecom acquired a controlling interest in DTI Holdings, Inc. (Holdings) in February 2001 through the purchase of approximately two-thirds of the Holdings stock held by Weinstein. In connection with that purchase, KLT Telecom entered into a put option in favor of Weinstein, which granted Weinstein an option to sell to KLT Telecom his remaining shares of Holdings stock. The put option provided for an aggregate exercise price for the remaining shares equal to their fair market value with an aggregate floor amount of $15 million and was exercisable between September 1, 2003, and August 31, 2005. In June 2003, the stock of Holdings was cancelled and extinguished pursuant to the joint Chapter 11 plan confirmed by the Bankruptcy Court. In September 2003, Weinstein delivered a notice of exercise of his claimed rights under the put option. KLT Telecom rejected the notice of exercise, and Weinstein filed suit alleging breach of contract. Weinstein sought damages of at least $15 million, plus statutory interest. In April 2005, summary judgment was granted in favor of KLT Telecom, and Weinstein appealed this judgment to the Missouri Court of Appeals for the Eastern District, which affirmed the judgment. Weinstein filed a motion for transfer of this case to the Missouri Supreme Court, which was granted. The Missouri Supreme Court reversed the decision of the trial court which granted summary judgment in favor of KLT Telecom and remanded the case to the trial court for further handling on May 29, 2007. On July 26, 2007, Weinstein filed a Renewed Motion for Summary Judgment in the Circuit Court. A hearing on the motion is scheduled to occur on March 10, 2008. The case is set for trial on May 15, 2008. A $15 million reserve was recorded in 2001 for this matter.
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| : 16. ASSET RETIREMENT OBLIGATIONS Asset retirement obligations associated with tangible long-lived assets are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel. These liabilities are recognized at estimated fair value as incurred and capitalized as part of the cost of the related long-lived assets and depreciated over their useful lives. Accretion of the liabilities due to the passage of time is recorded as an: operating expense.
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| Changes in the estimated fair values of the liabilities are recognized when known.
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| In 2006, KCP&L incurred an ARO for decommissioning and site remediation of its Spearville Wind Energy Facility, a 100.5 MW wind project in western Kansas. KCP&L is obligated to remove the wind turbine towers and perform site remediation within 12 months after the end of the associated 30-year land lease agreements. The ARO was derived from a third party estimate of decommissioning and remediation costs. To estimate the ARO, KCP&L used a credit-adjusted risk free discount rate of 6.68%. This rate was based on the rate at which KCP&L could issue 30-year bonds. KCP&L recorded a $3.1 million ARO for the decommissioning and site remediation and increased property and equipment by $3.1 million.
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| In 2006, WCNOC submitted an application for a new operating license for Wolf Creek with the NRC, which would extend Wolf Creek's operating period to 2045. Management determined the fair value of KCP&L's ARO for nuclear decommissioning should reflect the change in timing in the undiscounted estimated cash flows to decommission Wolf Creek as a result of the extended operating period.
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| Management calculated an ARO revision based on KCP&L's most recent cost estimates to decommission Wolf Creek. To estimate the ARO layer attributable to the change in timing, KCP&L used a credit-adjusted risk free discount rate of 6.26%. The rate was based on the rate at which KCP&L could issue 40-year bonds. KCP&L recorded a $65.0 million decrease in the ARO to decommission Wolf Creek with a $25.8 million net decrease in property and equipment. The regulatory asset for ARO decreased $8.2 million and a $31.0 million regulatory liability was established to recognize funding of the related decommissioning trust in excess of the ARO due to the extended operating period.
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| 113
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| KCP&L also has AROs related to asbestos in certain fossil fuel plants and for an ash pond and landfill.
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| KCP&L is a regulated utility subject to the provisions of SFAS No. 71 and management believes it is probable that any differences between expenses under FIN No. 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143" or SFAS No. 143, "Accounting for Asset Retirement Obligations" and expense recovered currently in rates will be recoverable in future rates. The following table summarizes the change in Great Plains Energy's and'consolidated KCP&L's AROs.
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| December 31 2007 2006 (millions)
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| Beginning balance $ 91.8 $ 145.9 Additions - 3.1 Extension of Wolf Creek life - (65.0)
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| Settlements (1.1) -
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| Accretion 3.8 7.8 Ending balance $ 94:5 $ 91.8
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| : 17. SEGMENTS AND RELATED INFORMATION Great Plains Energy Great Plains Energy has two reportable segments based on its method of internal reporting, which generally segregates the reportable segments based on products and services, management responsibility and regulation. The two reportable business segments are KCP&L, an integrated, regulated electric utility, and Strategic Energy, a competitive electricity supplier. Other includes HSS, Services, all KLT Inc. activity other than Strategic Energy, unallocated corporate charges, consolidating entries and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing-related activities. The summary of significant accounting policies applies to all of the reportable segments. For segment reporting, each segment's income taxes include the effects of allocating holding company tax benefits. Segment performance is evaluated based on net income.
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| The following tables reflect summarized financial information concerning Great Plains Energy's reportable segments.
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| Strategic Great Plains 2007 KCP&L Energy Other Energy (millions)
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| Operating revenues $1,292.7 $ 1,974.4 $ $ 3,267.1 Depreciation and amortization (175.6) (8.2) - (183.8)
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| Interest charges (67.2) (2.9) (23.7) (93.8)
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| Income taxes (59.3) (25.8) 13.6 (71.5)
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| Loss from equity investments - - (2.0) (2.0)
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| Net income (loss) 156.8 38.4 (36.0) 159.2 114
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| Strategic Great Plains 2006 KCP&L Energy Other Energy (millions)
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| Operating revenues $1,140.4 $ 1,534.9 $ $ 2,675.3 Depreciation and amortization (152.7) (7.8) (160.5)
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| Interest charges (60.9) (2.1) (8.2) (71.2)
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| Income taxes (71.6) 12.7 11.0 (47.9)
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| Loss. from equity investments - - (1.9) (1.9)
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| Net income (loss) 149.6 (9.9) (12.1) 127.6 Strategic Great Plains 2005 KCP&L Energy Other Energy (millions)
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| Operating revenues $1,130.8 $ 1,474.0 $ 0.1 $ 2,604.9 Depreciation and amortization (146.5) (6.4) (0.2) (153.1)
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| Interest charges (61.8) (3.4) (8.6) (73.8)
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| Income taxes (49.1) (16.6) 26.2 (39.5)
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| Loss from equity investments (0.4) (0.4)
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| Discontinued operations - (1.9) (1.9)
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| Net income (loss) 145.2 28.2 (11.1) 162.3 Strategic Great Plains KCP&L Energy Other Energy 2007 (millions)
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| Assets $ 4,290.7 $ 493.0 $ 43.0 $ 4,826.7 Capital expenditures 511.5 3.7 0.7 515.9 2006 Assets $ 3,858.0 $ 459.6 $ 18.1 $ 4,335.7 Capital expenditures 476.0 3.9 0.2 480.1 2005 Assets $ 3,336.3 $ 441.8 $ 63.7 $ 3,841.8 Capital expenditures 332.2 6.6 (4.7) 334.1 Consolidated KCP&L The following tables reflect summarized financial information concerning consolidated KCP&L's reportable segment, KCP&L. Other includes HSS and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing-related activities.
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| Consolidated 2007 KCP&L Other KCP&L (millions)
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| Operating revenues $1,292.7- $ - $ 1,292.7 Depreciation and amortization (175.6) - (175.6)
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| Interest charges (67.2) - (67.2)
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| Income taxes (59.3) - (59.3)
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| Net income (loss) 156.8 (0.1) 156.7 115
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| Consolidated 2006 KCP&L Other KCP&L (millions)
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| Operating revenues $1,140.4 $ $ 1 ;140.4 Depreciation and amortization (152.7) (152.7)
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| Interest charges (60.9) (0.1) (61.0),
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| Income taxes (71.6) 1.3 (70.3)
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| Net income (loss) 149.6 (0.3) 149.3.
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| Consolidated 2005 KCP&L Other KCP&L (millions)
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| Operating revenues $1,130.8 $ 0.1 $ 1,130.9 Depreciation and amortization (146.5) (0.1) (146.6)
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| Interest charges (61.8) (61.8)
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| Income taxes (49.1) 1.1 (48.0)
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| Net income (loss) 145.2 (1.5) 143.7 Consolidated KCP&L Other KCP&L 2007 (millions)
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| Assets $ 4,290.7 $ 1.3 $ 4,292.0 Capital expenditures 511.5- - 511.5 2006 Assets $ 3,858.0 $ 1.5 $ 3,859.5 Capital expenditures 476.0 - 476.0 2005 Assets $ 3,336.3 $ 3.9 $ 3,340.2 Capital expenditures 332:2 332.2
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| : 18. SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT In July 2007, pursuant to the terms of their credit agreements, Great Plains Energy and KCP&L transferred $200 million of unused lender commitments from the Great Plains Energy credit agreement to the KCP&L credit agreement. The maximum aggregate amount available under the Great Plains Energy credit agreement was reduced to $400 million from $600 million, and the maximum aggregate amount available under the KCP&L credit agreement was increased to $600 million from $400 million.
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| Great Plains Energy's $400 million revolving credit facility with a group of banks expires in May 2011.
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| A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of this agreement, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2007, Great Plains Energy was in compliance with this covenant. At December 31, 2007, Great Plains Energy had
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| $42.0 million of outstanding borrowings with a weighted average interest rate of 5.44% and had issued letters of credit totaling $98.6 million under the credit facility as credit support for Strategic Energy. At December 31, 2006, Great Plains Energy had no cash borrowings and had issued letters of credit totaling $103.7 million under the credit facility as credit support for Strategic Energy.
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| 116
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| KCP&L's $600 million revolving credit facility with a group of banks to provide support for its issuance of commercial paper and other general corporate purposes expires in May 2011. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of the agreement, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2007, KCP&L was in compliance with this covenant. At December 31, 2007, KCP&L had $365.8 million of commercial paper outstanding, at a weighted-average interest rate of 5.92%,
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| $11.9 million of letters of credit and no outstanding cash borrowings under the facility. At December 31, 2006, KCP&L had $156.4 million of commercial paper outstanding, at a weighted-average interest rate of 5.38%, $8.7 million of letters of credit and no cash borrowings under the facility.
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| During 2007, Strategic Energy entered into a new revolving credit facility with a group of banks, expiring in October 2010. The new facility replaced a $135 million revolving credit facility with a group of banks.
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| The new facility provides for loans and letters of credit not exceeding an aggregate of the lesser of $50 million or the borrowing base, which is generally 85% of Strategic Energy's retail accounts receivables plus the amount of a Great Plains Energy guarantee less usage under Strategic Energy's receivable facility. Great Plains Energy issued an initial guarantee in the amount of $12.5 million and may increase the guarantee up to a maximum of $27.5 million to increase the borrowing base or to cure a default of the minimum fixed charge coverage ratio, provided that Great Plains Energy maintains investment grade ratings on its senior unsecured debt. Under the terms of the new agreement, Strategic Energy is required to maintain, as of the end of each quarter, a minimum fixed charge coverage ratio of at least 1.05 to 1.0 and a minimum EBITDA, as defined in the agreement, for the four quarters then ended of $15 million through March 31, 2008, and thereafter increasing to $17.5 million (through September 30, 2008), $20 million (through March 31, 2009) and $22.5 million through maturity. At December 31, 2007, Strategic Energy was in compliance with this covenant. At December 31, 2007, there were no cash borrowings or letters of credit issued under this facility. At December 31, 2006, $59.8 million in letters of credit had been issued and there were no cash borrowings under the
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| $135 million agreement.
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| At the same time in 2007, Strategic Energy entered into an agreement to sell its retail accounts receivable to its wholly owned subsidiary, Strategic Receivables, which in turn sells undivided percentage ownership interests in the accounts receivable to Market Street and Fifth Third Bank (collectively, the Purchasers) ratably based on each purchaser's commitments. In addition to its ability to sell accounts receivable to the purchasers for cash, Strategic Receivables may request the issue of letters of credit on behalf of Strategic Energy. Market Street's and Fifth Third Bank's obligation to purchase accounts receivable is limited to $112.5 million and $62.5 million, respectively, less the proportionate aggregate amount of letters of credit issued pursuant to the agreement. Under the terms of the agreement, Strategic Receivables is required to maintain a tangible net worth of no less than $10 million at any time. At December 31, 2007, Strategic Receivables was in compliance with this covenant. At December 31, 2007, $82.9 million of letters of credit had been issued.
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| 117
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| : 19. LONG-TERM DEBT AND EIRR BONDS CLASSIFIED AS CURRENT LIABILITIES Great Plains Energy and consolidated KCP&L's long-term debt is detailed in the following table.
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| December 31 Year Due 2007 2006 Consolidated KCP&L (millions)
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| General Mortgage Bonds 7.95% Medium-Term Notes $ - $ 0.5 4.59%* EIRR bonds 2012-2035 158.8 158.8 Senior Notes 6.00% - 225.0 6.50% 2011 150.0 150.0 5.85% 2017 250.0 -
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| 6.05% 2035 250.0 250.0 Unamortized discount (1.9) (1.6)
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| EIRR bonds 4.75% Series 1998A & B 105.2 4.75% Series 1998D - 39.5 4.65% Series 2005 2035 50.0 50,0 4.75% Series 2007A 2035 73.3 -
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| 4.25% Series 2007B 2035 73.2 Current liabilities Current maturities - (225.5)
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| EIRR bonds classified as current - (144.7)
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| Total consolidated KCP&L excluding current maturities 1,003.4 607.2 Other Great Plains Energy 6.875% Senior Notes 2017 100.0 -
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| Unamortized discount (0.5) -
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| 7.74% Affordable Housing Notes 2008 0.3 0.9 4.25% FELINE PRIDES Senior Notes - 163.6 Current maturities (0.3) (164.2)
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| Total consolidated Great Plains Energy excluding current maturities $ 1,102.9 $ 607.5 Weighted-average interest rates at December 31, 2007.
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| Amortization of Debt Expense Great Plains Energy's and consolidated KCP&L's amortization of debt expense is detailed in the following table.
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| 2007 2006 2005 (millions)
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| Consolidated KCP&L $ 1.6 $ 1.9 $ 2.3 Other Great Plains Energy 1.0 0.7 0.7 Total Great Plains Energy $ 2.6 $ 2.6 $ 3.0 KCP&L General Mortgage Bonds KCP&L has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented. The Indenture creates a mortgage lien on substantially all utility plant. Mortgage bonds secure $158.8 million and $159.3 million, respectively, of medium-term notes and Environmental Improvement Revenue Refunding (EIRR) bonds at December 31, 2007 and 2006.
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| 118
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| KCP&L Unsecured Notes KCP&L had $650.0 Million and $625.0 million, respectively, of outstanding unsecured senior notes at December 31, 2007 and 2006. As a result of amortizing the gain recognized in other comprehensive income.(OCI) on KCP&L's 2005 Treasury Locks (T-Locks), the effective interest rate on KCP&L's
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| $250.0 million of 6.05% Senior Notes is 5.78%. During 2007, KCP&L issued $250.0 million of 5.85%
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| unsecured Senior Notes, maturing in 2017. As a result of amortizing the gain recognized in OCI on KCP&L's 2006 Forward Starting Swaps (FSS), the effective interest rate on KCP&L's 5.85% Senior Notes is 5.72%.
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| KCP&L had $196.5 million of unsecured EIRR bonds outstanding at December 31, 2007 and 2006, excluding the fair value of interest rate swaps of a $1.8 million liability in 2006. The interest rate swaps resulted in an effective rate of 5.85% for the Series 1998A, B and D EIRR bonds in 2006.
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| KCP&L classified its 4.75% Series 1998A, B and D EIRR bonds with maturity dates of 2015 and 2017 as current liabilities at December 31, 2006, in accordance with Emerging Issues Task Force (EITF) D-.
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| 61 "Classification by the Issuer of Redeemable Instruments That Are Subject to Remarketing Agreements." The cash proceeds of $146.5 million from KCP&L's unsecured EIRR Bonds Series 2007A and 2007B issued during 2007 were used to repay the 4.75% Series 1998A, B and D EIRR bonds.
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| Municipal Bond Insurance Policies KCP&L's EIRR Bonds Series 2007A and 2007B totaling $146.5 million are covered by a municipal bond insurance policy issued by Financial Guaranty Insurance Company (FGIC). The insurance agreement between KCP&L and FGIC provides for reimbursement by KCP&L for any amounts that FGIC pays under the municipal bond insurance policy. The insurance policy is in effect for the term of the bonds. The policy also restricts the amount of secured debt KCP&L may issue. In the event KCP&L issues debt secured by liens not permitted by the agreement, KCP&L is required to issue and deliver to FGIC first mortgage bonds or similar securities equal in principal amount to the principal amount of the EIRR Bonds Series 2007A and 2007B then outstanding.
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| KCP&L's secured 1992 Series EIRR bonds totaling $31.0 million, secured Series 1993A and 1993B EIRR bonds totaling $79.5 million, and secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, are covered by a municipal bond insurance policy between KCP&L and XL Capital Assurance, Inc (XLCA). The insurance agreements between KCP&L and XLCA provide for reimbursement by KCP&L for any amounts that XLCA pays under the municipal bond insurance policies. The insurance policies are in effect for the term of the bonds. The insurance agreements contain a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00. At December 31, 2007, KCP&L was in compliance with this covenant. KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor's or Moody's Investors Service would be at or below A- or A3, respectively.
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| The insurance agreement covering the unsecured EIRR Bond Series 2005 also requires KCP&L to provide XLCA with $50.0 million of general mortgage bonds as collateral for KCP&L's obligations under the insurance agreement in the event KCP&L issues general mortgage bonds (other than refundings of outstanding general mortgage bonds) resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. In the event of a default under the insurance agreements, XLCA may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.
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| 11.9
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| The interest rates on $257.0 million of these EIRR bonds are periodically reset through auction processes. Both FGIC and XLCA, and the supported KCP&L auction rate bonds,.wvere downgraded by at least two rating agencies in January and February 2008. Concerns related to municipal bond insurers' credit have adversely affected the ordinary course of operation of auctions for these types of bonds. The interest rates set in recent auctions of KCP&L's auction rate bonds have been adversely affected by these concerns, and the adverse effects are expected to continue until the bonds are changed to another interest rate mode.
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| Other Great Plains Energy Long-Term Debt During 2007, Great Plains Energy issued $100.0 million of 6.875% unsecured Senior Notes, maturing in 2017. As a result of amortizing the loss recognized in OCI on Great Plains Energy's 2007 T-Locks, the effective interest rate on Great Plains Energy's 6.875% Senior Notes is 7.33%.
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| KLT Investments' affordable housing notes are collateralized by the affordable housing investments.
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| Most of the notes also require the greater of 15% of the outstanding note balances or the next annual installment to be held as cash, cash equivalents or marketable securities. At December 31, 2007 and 2006, the collateral was held entirely as cash and totaled $0.3 million and $0.6 million, respectively.
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| Great Plains Energy's $163.6 million of FELINE PRIDES each with a stated amount of $25, initially consisted of an interest in a senior note due February 16, 2009, and a contract requiring the holder to purchase the Company's common stock on February 16, 2007. Great Plains Energy made quarterly contract adjustment payments at the rate of 3.75% per year and interest payments at the rate of 4.25%
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| per year both payable in February, May, August and November of each year. Each purchase contract obligated the holder of the purchase contract to purchase, and Great Plains Energy to sell, on February 16, 2007, for $25 in cash, newly issued shares of the Company's common stock equal to the settlement rate. The settlement rate was determined according to the applicable market value of the Company's common stock at the settlement date. The applicable market value of $31.58 was measured by the average of the closing price per share of the Company's common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding February 16, 2007. The settlement rate of 0.7915 was applied to the 6.5 million FELINE PRIDES at February 16, 2007, and Great Plains Energy issued 5.2 million shares of common stock. The $163.6 million FELINE PRIDES senior notes originally matured in 2009, but were to be remarketed between August 16, 2006 and February 16, 2007. In February 2007, Great Plains Energy exercised its rights to redeem the $163.6 million FELINE PRIDES senior notes in full satisfaction of each holder's obligation to purchase'the Company's common stock under the purchase contracts.
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| Scheduled Maturities Great Plains Energy's and consolidated KCP&L's long-term debt maturities for the next five years are detailed in the following table.
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| 2008 2009 2010 2011 2012 (millions)
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| Consolidated KCP&L $ - $ - $ $ 150.0 $ 12.4 Other Great Plains Energy 0.3 - -
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| Total Great Plains Energy $ 0.3 $ $ $ 150.0 $ 12.4 120
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| : 20. COMMON SHAREHOLDERS' EQUITY Great Plains Energy filed a shelf registration statement with the Securities and Exchange Commission (SEC) in 2006 relating to Senior Debt Securities, Subordinated Debt Securities, shares of Common Stock, Warrants, Stock Purchase Contracts and Stock Purchase Units. In 2006, Great Plains Energy issued 5.2 million shares of common stock at $27.50 per share under the shelf registration statement with $144.3 million in gross proceeds and issuance costs of $5.2 million.
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| In 2006, Great Plains Energy entered into a forward sale agreement with Merrill Lynch Financial Markets, Inc. (forward purchaser) for 1.8 million shares of Great Plains Energy common stock. In April 2007, Great Plains Energy elected to terminate the forward sale agreement and settle it in cash. Based on the difference between Great Plains Energy's average stock price of $32.60 over the period used to determine the settlement and the then-applicable forward price of $25.58, Great Plains Energy paid
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| $12.3 million to Merrill Lynch Financial Markets, Inc.
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| Treasury shares are held for future distribution upon issuance of shares in conjunction with the Company's Long-Term Incentive Plan.
| |
| Great Plains Energy has 4.0 million shares of common stock registered with the SEC for its Dividend Reinvestment and Direct Stock Purchase Plan. The plan allows for the purchase of common shares by reinvesting dividends or making optional cash payments. Great Plains Energy can issue new shares or purchase shares on the open market for the Plan. At December 31, 2007, 0.7 million shares remained available for future issuances.
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| In 2007, Great Plains Energy registered an additional 2.0 million shares of common stock with the SEC for a defined contribution savings plan, bringing the total number of shares registered under this plan to 12.3 million. Shares issued under the plans may be either newly issued shares or shares purchased in the open market. At December 31, 2007, 3.2 million shares remained available for future issuances.
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| Great Plains Energy's Articles of Incorporation contain a restriction related to the payment of dividends in the event common equity falls to 25% of total capitalization. If preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of Directors necessary to constitute a majority of the full Board of Directors. Under the Federal Power Act, KCP&L can only pay dividends out of retained or current earnings. Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L have committed to maintain consolidated common equity of not less than 30% and 35%, respectively.
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| Great Plains Energy made a capital contribution to KCP&L of $94.0 million in 2007. This contribution was used by KCP&L to repay a portion of its outstanding commercial paper. Great Plains Energy made capital contributions to KCP&L of $134.6 million in 2006. These contributions were made to fund Comprehensive Energy Plan projects. At December 31, 2007, KCP&L's capital contributions from Great Plains Energy totaled $628.6 million and are reflected in common stock in the consolidated KCP&L balance sheet.
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| : 21. PREFERRED STOCK At December 31, 2007, 1.6 million shares of Cumulative No Par Preferred Stock, 390,000 shares of Cumulative Preferred Stock, $100 par value and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy's Articles of Incorporation. All of the 390,000 authorized shares of Cumulative Preferred Stock are issued-and outstanding. Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices ranging from 101% to 103.7%
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| 121
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| of par value. If Great Plains Energy voluntarily files for dissolution or liquidation, the Cumulative Preferred Stock holders are entitled to receive the redemption prices. If a proceeding for dissolution or liquidation is filed against Great Plains Energy, the Cumulative Preferred Stock holders are entitled to receive the $100 par value per share plus accrued and unpaid dividends.
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| : 22. DERIVATIVE INSTRUMENTS The Company is exposed to a variety of market risks including interest rates and commodity prices.
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| Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on the Company's operating results. The risk management activities, including the use of derivative instruments, are subject to the management, direction and control of internal risk management committees. Management's interest rate risk management strategy uses derivative instruments to adjust the Company's liability portfolio to optimize the mix of fixed and floating rate debt within an established range. In addition, the Company uses derivative instruments to hedge against future interest rate fluctuations on anticipated debt issuances.
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| Management maintains commodity-price risk management strategies that use derivative instruments to reduce the effects of fluctuations in fuel and purchased power expense caused by commodity price volatility. Counterparties to commodity derivatives and interest rate swap agreements expose the Company to credit loss in the event of nonperformance. This credit loss is limited to the cost of replacing these contracts at current market rates less the application of counterparty collateral held.
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| Derivative instruments, excluding those instruments that qualify for the NPNS election, which are accounted for by accrual accounting, arerecorded on the balance sheet at fair value as an asset or liability. Changes in the fair value are recognized currently in net income unless specific hedge accounting criteria are met.
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| Interest Rate Risk Management FairValue Hedges In 2002, KCP&L remarketed its Series 1998 A, B and D EIRR bonds totaling $146.5 million to a five-year fixed interest rate of 4.75% ending October 1, 2007. Simultaneously with the remarketing, KCP&L entered into an interest rate swap for the $146.5 million based on the London Interbank Offered Rate (LIBOR) to effectively create a floating interest rate obligation, which expired on October 1, 2007. The transaction was a fair value hedge with no ineffectiveness. Changes in the fair market value of the swap were recorded on the balance sheet as an asset or liability with an offsetting entry to the respective debt balances with no net impact on net income.
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| ForwardStarting Swaps In July 2007, Great Plains Energy entered into three FSS, with a total notional amount of $250.0 million, to hedge against interest rate fluctuations on future issuances of long-term debt. The long-term debt issuance is contingent on the consummation of the acquisition of Aquila. The FSS was designed to effectively remove most of the interest rate and, to the extent that swap spreads correlate with credit spreads, some degree of credit spread uncertainty with respect to the debt to be issued, thereby enabling Great Plains Energy to predict with greater assurance its future interest costs on that debt.
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| The transaction is an economic hedge (non-hedging derivative) that does not qualify for cash flow hedge accounting. The change in the fair value of this derivative instrument increased interest expense by $16.4 million in 2007.
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| In 2006, KCP&L entered into two FSS to hedge against interest rate fluctuations on the $250.0 million 10-year long-term debt that KCP&L issued in the second quarter of 2007. The FSS settled simultaneously with the issuance of the long-term fixed rate debt. The FSS were accounted for as a cash flow hedge and no ineffectiveness was recorded on the FSS. A pre-tax gain of $3.3 million on the FSS was recorded to OCI and is being reclassified to interest expense over the life of the 10-year debt.
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| 122
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| An insignificant amount was reclassified from OCI to interest expense subsequent to the debt issuance.
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| At December 31, 2007, KCP&L had $3.1 million recorded in OCI for the FSS.
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| Treasury Locks In 2007, Great Plains Energy entered into three T-Locks, with a notional amount of $350.0 million, to hedge against interest rate fluctuations on the U.S. Treasury rate component on future issuances of long-term debt. Following a change.in financing plans, Great Plains Energy assigned the T-Locks to KCP&L. The T-Locks will settle simultaneously with the issuance of future long-term fixed rate debt issued by KCP&L. The T-Locks remove the uncertainty with respect to the U.S. Treasury rate component of the debt to be issued, thereby enabling KCP&L to predict with greater assurance its future interest costs on that debt. The T-Locks are accounted for as cash flow hedges and the fair value is recorded as a current asset or liability with an offsetting entry to OCI, to the extent the hedges are effective, until the forecasted transaction occurs. KCP&L's interest expense for 2007 includes a loss of $1.4 million due to ineffectiveness of the cash flows. The pre-tax gain or loss on the T-Locks recorded to OCI will be reclassified to interest expense over the life of the future debt issuance.
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| In 2007, Great Plains Energy entered into a T-Lock to hedge against interest rate fluctuations on the U.S. Treasury rate component of the $100.0 million 10-year long-term debt that Great Plains Energy issued in the third quarter of 2007. The T-Lock settled simultaneously with the issuance of the long-term fixed rate debt. The T-Lock was accounted for as a cash flow hedge and no ineffectiveness was recorded on the T-Lock. A pre-tax loss of $4.5 million on the T-Lock was recorded to OCI and is being reclassified to interest expense over the life of the issued 10-year debt. An insignificant amount was reclassified from OCI to interest expense subsequent to the debt issuance. At December 31, 2007, Great Plains Energy had $4.4 million recorded in OCI for this T-Lock. Great Plains Energy had originally hedged this debt in 2006 using a T-Lock. In the first quarter of 2007, Great Plains Energy allowed the T-Lock to expire while the terms of the debt offering were re-evaluated. The $0.2 million gain recorded in OCI at'December 31, 2006, and the first quarter fair value loss of $0.1 million was reclassified to interest expense as cash flow ineffectiveness.
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| Commodity Risk Management KCP&L KCP&L's risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales. At December 31, 2007, KCP&L had hedged 35% and 4% of its 2008 and 2009, respectively, projected natural gas usage for retail load and firm MWh sales, primarily by utilizing fixed forward physical contracts. The fair values of these instruments are recorded as current assets or current liabilities with an offsetting entry to OCI for the effective portion of the hedge.
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| To the extent the hedges are not effective, the ineffective portion of the change in fair market value is recorded currently in fuel expense. KCP&L did not record any gains or losses due to ineffectiveness during 2007, 2006 and 2005.
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| Strategic Energy Strategic Energy maintains a commodity-price risk management strategy that uses forward physical energy purchases and other derivative instruments to reduce the effects of fluctuations in purchased power expense caused by commodity-price volatility. Derivative instruments are used to limit the unfavorable effect that price increases will have on electricity purchases, effectively fixing the future purchase price of electricity for the applicable forecasted usage and protecting Strategic Energy from significant price volatility. The maximum term over which Strategic Energy hedged its exposure and variability of future cash flows was 5.0 years and 5.5 years at December 31, 2007 and 2006, respectively.
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| 123
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| Certain forward fixed price purchases and swap agreements are designated as cash flow hedges. The fair values of these instruments are recorded as assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, the ineffective portion of the change in fair market value is recorded currently in purchased power. When the forecasted purchase is completed, the amounts in OCI are reclassified to purchased power. Purchased power expense for 2007, 2006 and 2005 included a gain of $3.1 million, a loss of $1.9 million, and a gain of
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| $1.7 million, respectively, due to the change in ineffectiveness of the cash flow hedges. In addition, Strategic Energy recorded a gain of $16.7 million, a loss of $24.8 million and a gain of $1.6 million for 2007, 2006 and 2005, respectively, for the change in the components of cash flow hedges that were excluded from the measurement of cash flow ineffectiveness.
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| As part of its commodity-price risk management strategy, Strategic Energy also enters into economic.
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| hedges (non-hedging derivatives) that do not qualify for cash flow hedge accounting. The changes in the fair value of these derivative instruments recorded as a component of purchased power expense for 2007, 2006 and 2005 included a gain of $33.0 million, a loss of $30.0 million and a loss of $0.8 million, respectively.
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| The fair value of non-hedging derivatives at December 31, 2007, also includes certain forward contracts at Strategic Energy that were amended during 2005. Prior to being amended, the contracts were accounted for under the NPNS election in accordance with SFAS No. 133. As a result of being amended, the contracts no longer qualify for NPNS exceptions or cash flow hedge accounting and are now accounted for as non-hedging derivatives with the fair value at amendment being recorded as a deferred liability that will be reclassified to net income as the contracts settle. In 2007, 2006 and 2005, Strategic Energy amortized $0.7 million, $5.1 million and an insignificant amount, respectively, of the deferred liability to purchased power expense related to the delivery of power under the contracts.
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| Strategic Energy will amortize the remaining deferred liability over the remaining original contract lengths, which end in the first quarter of 2008. After the amendment, Strategic Energy is recording the change in fair value of these contracts to purchased power expense.
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| 124
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| The notional and recorded fair values of the companies' open positions for derivative instruments are summarized in the following table. The fair values of these derivatives are recorded on the consolidated balance sheets.
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| December 31 2007 2006 Notional Notional Contract Fair Contract Fair Amount Value Amount Value Great Plains Energy (millions)
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| Swap contracts Cash flow hedges $ 267.7 $ (9.5) $ 477.5 $ (38.9)
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| Non-hedging derkiatives 80.8 (2.9) 37.1 (6.8)
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| Forward contracts Cash flow hedges 954.6 24.1 871.5 (69.7)
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| Non-hedging derivatives 300.3 3.5 250.7 (24.8)
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| Anticipated debt issuance Forward starting swap - - 225.0 (0.4)
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| Treasury lock 350.0 (28.0) 77.6 0.2 Non-hedging derivatives 250.0 (16.4) - -
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| Interest rate swaps Fair value hedges - 146.5 (1.8)
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| Consolidated KCP&L Swap contracts Cash flow hedges 5.5 0.7 - -
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| Forward contracts Cash flow hedges 1.4 - 6.1 (0.5)
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| Anticipated debt issuance Treasury lock 350.0 (28.0) - -
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| Forward starting swap - 225.0 (0.4)
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| Interest rate swaps Fair value hedges 146.5 (1.8) 125
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| The amounts recorded in accumulated OCI related to the cash flow hedges are summarized in the following table.
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| Great Plains Energy Consolidated KCP&L December 31 December 31 2007 2006 2007 2006 (millions)
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| Current assets $ 14.1 $ -12.7 $ 14.6 $ 12.0 Deferred charges 31.5 1.7 - -
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| Current liabilities (48.1) (56.3) (26.6) (1.3)
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| Deferred income taxes 0.4 32.1 4.5 (4.0)
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| Deferred credits 0.2 (35.3) - -
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| Total $ (1.9) $(45.1) $ (7.5) $ 6.7 Great Plains Energy's accumulated OCI in the table above at December 31, 2007, includes $17.1 million that is expected to be reclassified to expenses over the next twelve months. Consolidated KCP&L's accumulated OCI includes $1.0 million that is expected to be reclassified to expense over the next twelve months.
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| The amounts reclassified to expenses are summarized in the following table.
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| 2007 2006 2005 Great Plains Energy (millions)
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| Fuel expense $ - $ - $ (0.5)
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| Purchased power expense 83.7 54.6 (35.6)
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| Interest expense (0.4) (0.4) -
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| Income taxes (34.1) (22.4) 15.1 OCI $ 49.2 $ 31.8 $ (21.0)
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| Consolidated KCP&L Fuel expense $ - $ - $ (0.5)
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| Interest expense (0.6) (0.4) -
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| Income taxes 0.2 0.2 0.2 OCI $ (0.4) $ (0.2) $ (0.3) 126
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| : 23. JOINTLY OWNED ELECTRIC UTILITY PLANTS KCP&L's share of jointly owned electric utility plants at December 31, 2007, is detailed in the following table.
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| Wolf Creek LaCygne latan No. I latan No. 2 Unit Units Unit Unit (millions, except MW amounts)
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| KCP&L's share 47% 50% 70% 55%
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| Utility plant in service $1,381.9 $ 389.9 $ 275.4 $ -
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| Accumulated depreciation 747.7 262.8 199.8 Nuclear fuel, net 60.6 - -
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| Construction work in progress 27.1 5.1 120.9 294.9 KCP&L's 2008 accredited capacity-MWs 545 709 456 (a) NA (a) The latan No. 2 air permit limits KCP&L's accredited capacityof latan No. 1 to 456 MWs from 469 MWs until the air qualitycontrol equipment included in the Comprehensive Energy Plan is operational.
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| Each owner must fund its own portion of the plant's operating expenses and capital expenditures.
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| KCP&L's share of direct expenses is included in the appropriate operating expense classifications in Great Plains Energy's and consolidated KCP&L's financial statements.
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| : 24. NEW ACCOUNTING STANDARDS SFAS No. 157 In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements." This statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. The statement does not require any new fair value measurements but provides guidance on how to measure fair value when required. SFAS No. 157 also emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. The provisions of this statement are effective for Great Plains Energy and consolidated KCP&L January 1, 2008. In February 2008, the FASB issued FASB Staff Position (FSP) FAS No. 157-2 delaying the effective date for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. This includes items such as AROs, reporting units and long-lived asset groups measured at fair value for impairment testing, nonfinancial assets and liabilities measured at fair value in a business combination and not measured at fair value in subsequent periods, etc. For these items, the provisions of this statement are effective for Great Plains Energy and consolidated KCP&L beginning January 1, 2009, and interim periods within that fiscal year. The impact to the financial statements of Great Plains Energy and consolidated KCP&L upon adoption of SFAS No. 157 in 2008 is expected to be insignificant. Management is currently evaluating the impact of adoption to those nonfinancial assets and liabilities delayed by FSP FAS No. 57-2 and has not yet determined the impact on Great Plains Energy's and consolidated KCP&L's financial statements. In January 2008, the FASB proposed FSP FAS No. 157-c, "Measuring Liabilities under FASB Statement No. 157" to amend the standard to clarify the principles on fair value measurement of liabilities. Management is currently evaluating the impact of the proposed FSP and will continue to monitor for a final FSP expected in the first quarter Of 2008.
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| 127
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| SFAS No. 160 In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51." This statement amends ARB No. 51, "Consolidated .
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| Financial Statements," to establish accounting and reporting standards for the noncontrolling interests (referred to as minority interest in current practice) in a subsidiary and for the deconsolidation of a subsidiary. This statement requires, among other things, noncontrolling interests to be classified as a separate component of equity and no longer limits accumulated losses to the original carrying amount of noncontrolling interest. The provisions of this statement are effective for Great Plains Energy and consolidated KCP&L beginning January 1, 2009. Management has evaluated the impact of SFAS No.
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| 160 and has determined there will be no impact on Great Plains Energy and consolidated KCP&L consolidated financial statements.
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| SFAS No. 141(R)
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| In December 2007, the FASB issued SFAS No. 141 (revised 2007), "Business Combinations." This statement significantly changes how business combinations are accounted for in current practice.
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| Changes to current practice include, among other things, requiring all assets acquired and liabilities assumed in a business combination to be measured at fair value in accordance with SFAS No. 157 as of the acquisition date, an acquirer to expense transaction costs and equity securities issued as consideration in a business combination be recorded at fair value as of the acquisition date. The provisions of this statement are effective for Great Plains Energy and consolidated KCP&L prospectively for business combinations occurring on or after January 1, 2009, except it requires the prospective application of the provisions related to income taxes to business combinations occurring in 2008. As the anticipated Aquila acquisition is expected to close in 2008, management is currently evaluating the impact of the income tax provisions of SFAS No. 141(R) and has not yet determined the impact on the Aquila acquisition.
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| FSP FIN 39-1 In April 2007, the FASB issued FSP FIN 39-1 "Amendment of FASB Interpretation No. 39." This FSP amends FIN 39, "Offsetting of Amounts Related to Certain Contracts - an interpretation of APB Opinion No. 10 and FASB Statement No. 105," to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with FIN 39. The provisions of this position are effective for Great Plains Energy and consolidated KCP&L beginning January 1, 2008, and are to be applied retrospectively, allowing a change in accounting policy upon adoption to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. Great Plains Energy and consolidated KCP&L currently offset fair value amounts recognized for derivatives instruments under master netting arrangements, which will include rights and obligations to cash collateral, if any, upon adoption.
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| 128
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| : 25. QUARTERLY OPERATING RESULTS (UNAUDITED)
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| Quarter Great Plains Energy 1st 2nd 3rd 4th 2007 (millions, except per share amounts)
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| Operating revenue $ 664.3 $ 804.6 $ 992.0 $ 806.2 Operating income 54.4 54.3 113.0 98.1 Net income 23.4 25.6 62.1 48.1 Basic and diluted earnings per common share 0.28 0.29 0.72 0.56 2006 Operating revenue $- 559.2 $ 642.1 $ 818.5 $ 655.5 Operating income 7.6 73.3 93.6 60.9 Net income (loss) (1.1) 38.4 55.9 34.4.
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| Basic and diluted earnings (loss) per common share (0.02) 0.49 0.69 0.42 Quarter Consolidated KCP&L 1st 2nd 3rd 4th 2007 (millions)
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| Operating revenue $ 255.7 .$ 319.1 $ 416.0 $ 301.9 Operating income 13.1 70.1 127.0 68.7 Net income .2.0 36.5 76.6 41.6 2006 -
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| Operating revenue $ 240.4 $ 290.9 $ 359.3 $ 249.8 Operating income 31.7 69.2 118.4 51.7 Net income 13.0 36.6 69.5 30.2 Quarterly data is subject to seasonal fluctuations with peak periods occurring in the summer months.
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| 129
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| REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Great Plains Energy Incorporated Kansas City, Missouri We have audited the accompanying consolidated balance sheets of Great Plains Energy Incorporated and subsidiaries (the "Company") as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
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| We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
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| In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
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| As discussed in Note 3 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standard (SFAS) No. 158, Employers' Accounting for Defined Benefit Pension and Other PostretirementPlans - an amendment of FASB Statements No. 87, 88, 106, and 132(R) on December 31, 2006. As discussed in Note 10 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation (FIN) No. 48 Accounting for Uncertainty in Income Taxes - an interpretationof FASB Statement No. 109 on January 1, 2007.
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| We have also audited, in accordance with the standards of the PCAOB, the Company's internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2008, expressed an unqualified opinion on the Company's internal control over financial reporting.
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| /s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 28, 2008 130
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| REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Kansas City Power & Light Company Kansas City, Missouri We have audited the accompanying consolidated balance sheets of Kansas City Power & Light Company and subsidiaries (the "Company") as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
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| We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
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| In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
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| As discussed in Note 3 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standard (SFAS) No. 158, Employers' Accounting for Defined Benefit Pension and Other PostretirementPlans- an amendment of FASB Statements No. 87, 88, 106, and 132(R), on December 31, 2006. As discussed in Note 10 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation (FIN) No. 48.Accounting for Uncertainty in Income Taxes - an interpretationof FASB Statement No. 109, on January 1, 2007.
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| We have also audited, in accordance with the standards of the PCAOB, the Company's internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2008, expressed an unqualified opinion on the Company's internal control over financial reporting.
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| /s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 28, 2008 131
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| ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
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| ITEM 9A. CONTROLS AND PROCEDURES Disclosure Controls and Procedures Great Plains Energy carried out evaluations of its disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended). These evaluations were conducted under the supervision, and with the participation, of the Company's management, including the chief executive officer, chief financial officer, and the Company's disclosure committee.
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| Based upon these evaluations, the chief executive officer and chief financial officer of Great Plains Energy have concluded as of the end of the period covered by this report that the disclosure controls and procedures of Great Plains Energy are functioning effectively to provide reasonable assurance that: (i) the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and (ii) the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to their respective management, including the principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
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| Changes in Internal Control Over Financial Reporting There has been no change in Great Plains Energy's internal control over financial reporting that occurred during the quarterly period ended December 31, 2007, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
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| Management's Report on Internal Control Over Financial Reporting Because of the inherent'limitations of internal control over financial reporting, including the possibility of collusion or improper override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
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| Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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| GreatPlains Energy Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended) for Great Plains Energy. Under the supervision and with the participation of Great Plains Energy's chief executive officer and chief financial officer, management evaluated the effectiveness of Great Plains Energy's internal control over financial reporting as of December 31, 2007. Management used for this evaluation the framework in Internal Control- Integrated Framework issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Management has concluded that, as of December 31, 2007, Great Plains Energy's internal control over financial reporting is effective based on the criteria set forth in the COSO framework. Deloitte & Touche LLP, the independent registered public accounting firm that audited the financial statements included in this annual report on Form 10-K, has issued its report on Great Plain's Energy's internal control over financial reporting, which is included below.
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| 132
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| REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Great Plains Energy Incorporated Kansas City, Missouri We have audited the internal control over financial reporting of Great Plains Energy Incorporated and subsidiaries (the "Company") as of December 31, 2007, based on criteria established in Internal Control-IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over FinancialReporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
| |
| We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an 'understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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| A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
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| Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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| In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. -
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| 133
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| We have also audited, in accordance with the standards of the PCAOB, the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2007, of the Company, and our report dated February 28, 2008, expressed an unqualified opinion on those consolidated financial statements and financial statement schedules and included an explanatory paragraph regarding the Company's adoption of new accounting standards.
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| /s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 28, 2008 ITEM 9A (T). CONTROLS AND PROCEDURES Disclosure Controls and Procedures KCP&L carried out evaluations of its disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-1 5(e) under the Securities Exchange Act of 1934, as amended). These evaluations were conducted under the supervision, and with the participation, of KCP&L's management, including the chief executive officer and chief financial officer, and KCP&L's disclosure committee.
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| Based upon these evaluations, the chief executive officer and chief financial officer of KCP&L have concluded as of the end of the period covered by this report that the disclosure controls and procedures of KCP&L are functioning effectively to provide reasonable assurance that: (i) the information required to be disclosed by KCP&L in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified, in the SEC's rules and forms; and (ii) the information required to be disclosed by KCP&L in the reports that it files or submits under the Securities Exchange Act of 1934,.as amended, is accumulated and communicated to their respective management, including the principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
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| Changes in Internal Control Over Financial Reporting There has been no change in KCP&L's internal control over financial reporting that occurred during the quarterly period ended December 31, 2007, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
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| Management's Report on Internal Control Over Financial Reporting Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
| |
| Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or-procedures may deteriorate.
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| 134
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| KCP&L Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 15d-1 5(f) under the Securities Exchange Act of 1934, as amended) for KCP&L. Under the supervision and with the participation of KCP&L's chief executive officer and chief financial officer, management evaluated the effectiveness of KCP&L's internal control over financial reporting as of December 31, 2007. Management used for this evaluation the framework in Internal Control - IntegratedFramework issued by the COSO of the Treadway Commission. Management has concluded that, as of December 31, 2007, KCP&L's internal control over financial reporting is effective based on the criteria set forth in the COSO framework. Deloitte & Touche LLP, the independent registered public accounting firm that audited the financial statements included in this annual report on Form 10-K, has issued its report on KCP&L's internal control over financial reporting, which is included below.
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| REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Kansas City Power & Light Company Kansas City, Missouri We have audited the internal control over financial reporting of Kansas City Power & Light Company and subsidiaries (the "Company") as of December 31, 2007, based on criteria established in Internal Control-IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over FinancialReporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
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| We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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| A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
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| 135
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| Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or'detected on a timely basis. Also, projections of any evaluation of the -
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| effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may 'deteriorate.
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| In our opinion, the Company maintained, in all -material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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| We have also audited, in accordance with the standards of the PCAOB, the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2007, of the Company, and our report dated February 28, 2008, expressed an unqualified opinion on those consolidated financial statements and financial statement schedules and included an explanatory paragraph regarding the Company's adoption of new accounting standards.
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| /s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 28, 2008 ITEM 9B. OTHER INFORMATION The following information was required to be disclosed by Great Plains Energy under Item 5.02(e) of Form 8-K but was not reported.
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| In January 2008, the Compensation and Development Committee of the Great Plains Energy Board clarified the treatment of outstanding grants of restricted stock and performance shares held by employees of Strategic Energy under Great Plains Energy's Long-Term Incentive Plan dated as of May 7, 2002 (Plan) in order to provide that such awards would vest, and thus would become payable, in the event that Great Plains Energy were to cease to own, directly or indirectly, more than 80% of the outstanding equity interest in Strategic Energy. Shahid Malik, who is Executive Vice President of Great Plains Energy and the President and Chief Executive Officer of Strategic Energy, is a "named executive officer" of Great Plains Energy (as defined in applicable SEC regulations) and a participant in the Plan.
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| Pursuant to the guidance provided by the SEC Division of Corporation Finance in the Current Report on Form 8-K Frequently Asked Questions dated November 23, 2004, the following information is provided.
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| pursuant to the requirements of Item 1.01 of Form 8-K.
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| On February 27, 2008, Great Plains Energy, KCP&L, the Staff of the Kansas Corporation Commission (Staff), the Citizens' Utility Ratepayers Board (CURB), Aquila, Inc. d/b/a Aquila Networks (Aquila), Black Hills Corporation and Black Hills/Kansas Gas Utility Company, LLC, filed a joint motion and settlement agreement (Agreement) in the pending Kansas Corporation Commission (KCC) proceedings regarding the proposed Great Plains Energy - Aquila transaction. The Agreement provides, among other things, for the exclusion from Kansas rate recovery of all transaction costs (currently estimated to total approximately $82 million), exclusion of acquisition premium and recovery of $10 million of transition costs (currently estimated to be approximately $59 million) over five years beginning with rates. .
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| expected to be effective in 2010. The Agreement establishes certain quality of service performance metrics with a maximum annual penalty exposure of $5.7 million. The Agreement further provides that KCP&L's rate case expected to be filed in 2008 will not include any of the costs or benefits associated with the transaction, and the allocation factors used in such case will not reflect the proposed transaction. The parties also agreed to not contest the rights of Staff and CURB to request KCC to 136
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| amend its order to reflect any conditions contained in an order in the Missouri proceedings that are detrimental to Kansas or more favorable to KCP&L.
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| The Agreement is subject to KCC approval, and the Agreement is void if not approved in its entirety. It is possible that the KCC may approve the Agreement with changes, or may not approve the Agreement. A hearing on the Agreement is-anticipated to occur on March 7, 2008.
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| PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Great Plains Energy Directors The information required by this item is incorporated by reference from the Great Plains Energy 2008 Proxy Statement, which will be filed with the SEC no later than April 29, 2008 (Proxy Statement):
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| * Information regarding the directors of Great Plains Energy required by this item is contained in the Proxy Statement section titled "Election of Directors."
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| *- Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934 required by this item is contained in the Proxy Statement section titled "Section 16(a) Beneficial Ownership Reporting Compliance."
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| * Information regarding the Audit Committee of Great Plains Energy required by this item is contained in the Proxy Statement section titled "Corporate Governance."-
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| Great Plains Energy and KCP&L Executive Officers Information required by this item regarding the executive officers of Great Plains Energy and KCP&L is contained in this report in the Part I, Item 1 sections titled "Officers of Great Plains Energy" and "Officers of KCP&L".
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| Great Plains Energy and KCP&L Code of Ethics The Company has adopted a Code of Ethical Business Conduct (Code), Which applies to all directors, officers and employees of Great Plains Energy, KCP&L and their subsidiaries. The Code is posted on the investor relations page of our Internet websites at www.greatplainsenergy.com and www.kcpl.com. A copy of the Code is available, without charge, upon written request to Corporate Secretary, Great Plains Energy Incorporated, 1201 Walnut, Kansas City, Missouri 64106. Great Plains Energy and KCP&L intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or a waiver from, a provision of the Code that applies to the principal executive officer, principal financial officer, principal accounting officer or controller of those companies by posting such information on the investor relations page of their Internet websites.
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| Other KCP&L Information The other information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).
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| 137
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| ITEM 11. EXECUTIVE COMPENSATION GREAT PLAINS ENERGY The information required by this item regarding compensation of Great Plains Energy directors and named executive officers contained in the sections titled "Corporate Governance," "Executive Compensation," "Director Compensation," "Compensation Discussion and Analysis" and "Compensation Committee Report" of the Proxy Statement is incorporated by reference.
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| KCP&L The information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).
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| ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS GREAT PLAINS ENERGY The information required by this item regarding security ownership of the directors and executive officers of Great Plains Energy contained in the section titled "Security Ownership of Certain Beneficial Owners, Directors and Officers" of the 2008 Proxy Statement is incorporated by reference.
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| KCP&L The information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).
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| Equity Compensation Plan The information required by this item regarding Great Plains Energy's equity compensation plan is in Item 5. Market for the Registrants' Common Equity and Related Shareholder Matters, of this report and is incorporated by reference.
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| ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE GREAT PLAINS ENERGY The information required by this item contained in the sections titled "Director Independence" and, if applicable, "Certain Relationships and Related Transactions" of the 2008 Proxy Statement is incorporated by reference.
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| KCP&L The information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).
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| ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES GREAT PLAINS ENERGY The information required by this item regarding the independent auditors of Great Plains Energy and its subsidiaries contained in the section titled "Audit Committee Report" of the 2008 Proxy Statement is incorporated by reference.
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| 138
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| KCP&L The Audit Committee of the Great Plains Energy Board functions as the Audit Committee of KCP&L.
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| The following table sets forth the aggregate fees billed by Deloitte & Touche LLP for audit services rendered in connection with the consolidated financial statements and reports for 2007 and 2006 and for other services rendered during 2007 and 2006 on behalf of KCP&L and its subsidiaries, as well as all out-of-pocket costs incurred in connection with these services:
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| Fee Category 2007 2006 Audit Fees $ 1,020,636 $ 984,256 Audit-Related Fees 59,000 44,200 Tax Fees 36,689 21,831 All Other Fees Total Fees $1,116,325 $1,050,287 Audit Fees: Consists of fees billed for professional services rendered for the audits of the annual consolidated financial statements of KCP&L and its subsidiaries and reviews of the interim condensed consolidated financial statements included in quarterly reports. Audit fees also include: services provided by Deloitte & Touche LLP in connection With statutory and regulatory filings or engagements; audit reports on audits of the effectiveness of internal control over financial reporting and on management's assessment of the effectiveness of internal control over financial reporting and other attest services, except those not required by statute or regulation; services related to filings with the SEC, including comfort letters, consents and assistance with and review of documents filed with the SEC; and accounting research in support of the audit.
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| Audit-Related Fees: Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of consolidated financial statements of KCP&L and its subsidiaries and are not reported under "Audit Fees". These services include consultation concerning financial accounting and reporting standards.
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| Tax Fees: Consists of fees billed for tax compliance and related support of tax returns and other tax services, including assistance with tax audits, and tax research and planning.
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| All Other Fees: Consists of fees for all other services other than those reported above.
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| Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent auditor to KCP&L and its subsidiaries. These services may include audit services, audit-related services, tax services and other services. The Audit Committee has adopted for KCP&L and its subsidiaries policies and procedures for the pre-approval of services provided by the independent auditor. Under these policies and procedures, the Audit Committee may pre-approve certain types of services, up to aggregate fee levels established by the Audit Committee. The Audit Committee as well may specifically approve audit and permissible non-audit services on a case-by-case basis. Any proposed service within a pre-approved type of service that would cause the applicable fee level to be exceeded cannot be provided unless the Audit Committee either amends the applicable fee level or specifically approves the proposed service. Pre-approval is generally provided for up to one year, unless the Audit Committee specifically provides for a different period. The Audit Committee receives quarterly reports regarding the pre-approved services performed by the independent auditor. The Chairman of the Audit Committee may between meetings pre-approve audit and non-audit services provided by the independent auditor, and report such pre-approval at the next Audit Committee meeting.
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| 139
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| PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES Financial Statements Great Plains Energy Page No.
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| : a. Consolidated Statements of Income for the years ended December 31, 2007, 59 2006 and 2005
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| : b. Consolidated Balance Sheets - December 31, 2007 and 2006 60
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| : c. Consolidated Statements of Cash Flows for the years ended December 31, 62 2007, 2006 and 2005
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| : d. Consolidated Statements of Common Shareholders' Equity for the years ended 63 December 31, 2007, 2006 and 2005
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| : e. Consolidated Statements of Comprehensive Income for the years ended 64 December 31, 2007, 2006 and 2005
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| : f. Notes to Consolidated Financial Statements 71
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| : g. Report of Independent Registered Public Accounting Firm 130 KCP&L
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| : h. Consolidated Statements of Income for the years ended December 31, 2007, 65 2006 and 2005
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| : i. Consolidated Balance Sheets - December 31, 2007 and 2006 66
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| : j. Consolidated Statements of Cash Flows for the years ended December 31, 68 2007, 2006 and 2005
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| : k. Consolidated Statements of Common Shareholder's Equity for the years ended 69 December 31, 2007, 2006 and 2005
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| : 1. Consolidated Statements of Comprehensive Income for the years ended 70 December 31, 2007, 2006 and 2005
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| : m. Notes to Consolidated Financial Statements 71
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| : n. Report of Independent Registered Public Accounting Firm 131 Financial Statement Schedules Great Plains Energy
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| : a. Schedule I - Parent Company Financial Statements 149
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| : b. Schedule II - Valuation and Qualifying Accounts and Reserves 154 KCP&L
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| : c. Schedule II - Valuation and Qualifying Accounts and Reserves 155 140
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| Exhibits Great Plains Energy Documents Exhibit Description of Document Number 2.1.1 Agreement and Plan of Merger among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of February 6, 2007 (Exhibit 2.1 to Form 8-K dated February 7, 2007).
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| 2.1.2 Mutual Notice of Extension among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of January 31, 2008.
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| 3.1.1
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| * Articles of Incorporation of Great Plains Energy Incorporated dated as of February 26, 2001 and corrected as of October 13, 2006 (Exhibit 3.1 to Form 10-Q for the quarter ended September 30, 2006).
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| 3.1.2
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| * By-laws of Great Plains Energy Incorporated, as amended May 1, 2007 (Exhibit 3.1 to Form 8-K dated May 1, 2007).
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| 4.1.5 Indenture, dated June 1, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.5 to Form 8-A/A, dated June 14, 2004).
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| 4.1.6 First Supplemental Indenture, dated June 14, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.5 to Form 8-A/A, dated June 14, 2004).
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| 4.1.7 Second Supplemental Indenture dated as of September 25, 2007, between Great Plains Energy Incorporated and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K dated September 25, 2007).
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| 10.1.1 *+ Amended Long-Term Incentive Plan, effective as of May 7, 2002 (Exhibit 10.1.a to Form 10-K for the year ended December 31, 2002).
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| 10.1.2 *+ Great Plains Energy Incorporated Long-Term Incentive Plan as amended May 1, 2007 (Exhibit 10.1 to Form 8-K filed May 4, 2007).
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| 10.1.3 *+ Great Plains Energy Incorporated Long-Term Incentive Plan Awards Standards and Administration effective as of February 7, 2006 (Exhibit 10.1.b to Form 10-K for the year ended December 31, 2005).
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| 10.1.4 *+ Form of 2005 three-year Restricted Stock Agreement Pursuant to theGreat Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.2 to Form 8-K dated February 4, 2005).
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| 10.1.5 *+ Form of 2006 Restricted Stock Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.e to Form 10-K for the year ended December 31, 2005).
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| 10.1.6 *+ Form of Restricted Stock Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.6 to Form 10-K for the year ended December 31, 2006).
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| 10.1.7 *+ Form of 2005 three-year Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1.a to Form 10-Q for the quarter ended March 31, 2005).
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| 141
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| 10.1.8 *+ Form of 2006 three-year Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 (Exhibit 10.1 .h to Form 10-K for the year ended December 31, 2005).
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| 10.1.9 *+ Form of 2007 three-year Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 for Great Plains Energy and KCP&L officers (Exhibit 10.1.10 to Form 10-K for the year ended December 31, 2006).
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| 10.1.10 *+ Form of 2007 three-year Performance Share Agreement Pursuant to the Great Plains Energy Incorporated Long-Term Incentive Plan Effective May 7, 2002 for Strategic Energy officers (Exhibit 10.1.11 to Form 10-K for the year ended December 31, 2006).
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| 10.1.11 *+ Form of Amendment to 2003 Stock Option Grants (Exhibit 10.1.9 to Form 10-Q for the quarter ended September 30, 2007).
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| 10.1.12 *+ Strategic Energy, L.L.C. Long-Term Incentive Plan Grants 2005, as amended May 2, 2005 and October 31, 2006 (Exhibit 10.1 .g to Form 10-Q for the quarter ended September 30, 2006).
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| 10.1.13 *+ Strategic Energy, L.L.C. Executive Long-Term Incentive Plan 2006 (Exhibit 10.1.j to Form 10-K for the year ended December 31, 2005).
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| 10.1.14 *+ Strategic Energy, L.L.C. Executive Committee Long-Term Incentive Plan dated as of January 1, 2007, (Exhibit 10.1.6 to Form 10-Q for the quarter ended June 30, 2007).
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| 10.1.15 *+ Great Plains Energy Incorporated Kansas City Power & Light Company Annual Incentive Plan amended effective as of January 1, 2007 (Exhibit 10.2 to Form 8-K filed May 4, 2007).
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| 10.1.16 *+ Strategic Energy,. L.L.C. Executive Committee Annual Incentive Plan dated as of January 1, 2007 (Exhibit 10.3 to Form 8-K filed May 4, 2007).
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| 10.1.17 *- Form of Indemnification Agreement with each officer and director (Exhibit 10-f to Form 10-K for year ended December 31, 1995).
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| 10.1.18 *+ Form of Conforming Amendment to Indemnification Agreement with.each officer and director (Exhibit 10.1 .a to Form. 10-Q for the quarter ended March 31, 2003).
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| 10.1.19 '+ Form of Indemnification Agreement with officers and directors (Exhibit 10.1.p to Form 10-K for the year ended December 31, 2005).
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| 10.1.20 *+ Form of Change in Control Severance Agreement with Michael J. Chesser (Exhibit 10.1 .a to Form 10-Q for the quarter ended September 30, 2006).
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| 10.1.21 *+ Form of Change in Control Severance Agreement with William H. Downey (Exhibit 10.1.b to Form 10-Q for the quarter ended September 30, 2006).
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| 10.1.22 *+ Form of Change in Control Severance Agreement with John R. Marshall (Exhibit 10.1 .c to Form 1 0-Q for the quarter ended September 30, 2006).
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| 10.1.23 *, Form of Change in Control Severance Agreement with Shahid Malik (Exhibit 10.1 .d to Form 1 0-Q for the quarter ended September 30, 2006).
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| 10.1.24 *+ Form of Change in Control Severance Agreement with other executive officers of Great Plains Energy Incorporated and Kansas City Power & Light Company (Exhibit 10.1 .e to Form 10-Q for the quarter ended September 30, 2006).
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| 142
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| 10.1.25 *+ Great Plains Energy Incorporated Supplemental Executive Retirement Plan (As Amended and Restated for I.R.C. §409A) (Exhibit 10.1.10 to Form 10-Q for the quarter ended September 30, 2007) 10.1.26 *+ Great Plains Energy Incorporated Nonqualified Deferred Compensation Plan (As Amended and Restated for I.R.C. §409A) (Exhibit 10.1.10 to Form 10-Q for the quarter ended September 30, 2007) 10.1.27 + Description of Compensation Arrangements with Directors and Certain Executive Officers.
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| 10.1.28 *+ Employment Agreement among Strategic Energy, L.L.C., Great Plains Energy Incorporated and Shahid J. Malik, dated as of November 10, 2004 (Exhibit 10.1.p to Form 10-K for the year ended December 31, 2004).
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| 10.1.29 *+ Severance Agreement among Strategic Energy, L.L.C., Great Plains Energy Incorporated and Shahid J. Malik, dated as of November 10, 2004 (Exhibit 10.1 .q to Form 10-K for the year ended December 31, 2004).
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| 10.1.30
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| * Credit Agreement dated as of May 11, 2006, among Great Plains Energy Incorporated, Bank of America, N.A., JPMorgan Chase Bank, N.A., BNP Paribas, The Bank of Tokyo-Mitsubishi UFJ, Limited, Chicago Branch, Wachovia Bank N.A., The Bank of New York, Keybank National Association, The Bank of Nova Scotia, UMB Bank, N.A., and Commerce Bank, N.A. (Exhibit 10.1.a to Form 10-Q for the quarter ended June 30, 2006).
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| 10.1.31
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| * Notice of Election to Transfer Unused Commitment between the Great Plains Energy Incorporated and Kansas City Power & Light Company Credit Agreements dated as of May 11, 2006, with Bank of America, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, BNP Paribas, The Bank of Tokyo-Mitsubishi UFJ, Limited, Chicago Branch and Wachovia Bank N.A., as Co-Documentation Agents, The Bank of New York, KeyBank National Association, The Bank of Nova Scotia, UMB Bank, N.A., and Commerce Bank, N.A. (Exhibit 10.1.2 to Form 10-Q for the quarter ended June 30, 2007).
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| 10.1.32
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| * General Agreement of Indemnity issued by Great Plains Energy Incorporated and Strategic Energy, L.L.C. in favor of Federal Insurance Company and subsidiary or affiliated insurers dated May 23, 2002 (Exhibit 10.1 .a. to Form 10-Q for the quarter ended June 30, 2002).
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| 10.1.33
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| * Agreement of Indemnity issued by Great Plains Energy Incorporated and Strategic Energy, L.L.C. in favor of Federal Insurance Company and subsidiary or affiliated insurers dated May 23, 2002 (Exhibit 10.1 .b. to Form 10-Q for the quarter ended June 30, 2002).
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| 10.1.34
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| * Asset Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.1 to Form 8-K dated February 7, 2007).
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| 10.1.35 Partnership Interests Purchase Agreement by and among Aquila, Inc., Aquila Colorado, LLC, Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp., dated February 6, 2007 (Exhibit 10.2 to Form 8-K dated February 7, 2007).
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| 143
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| 10.1.36 Letter Agreement dated as of June 29, 2007 to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated, and Gregory Acquisition Corp.,
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| dated February 6, 2007 (Exhibit 10.1.1 to Form 10-Q for the quarter ended June 30, 2007).:
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| 10.1.37 Letter Agreement dated as of August 31, 2007, to Asset Purchase Agreement and.
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| Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp (Exhibit 10.1.4 to Form 1 0-Q for the quarter ended September 30, 2007).
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| 10.1.38 Letter Agreement dated as of September 28, 2007, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp (Exhibit 10.1.5 to Form 1 0-Q for the quarter ended September 30, 2007).
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| 10.1.39 Letter Agreement dated as of October 3, 2007, to Agreement and Plan of Merger, Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp (Exhibit 10.1.6 to Form 10-Q for the quarter ended September 30, 2007).
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| 10.1.40 Letter Agreement dated as of November 30, 2007, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory. Acquisition Corp 10.1.41 Letter Agreement dated as of January 30, 2008, to Asset Purchase Agreement and Partnership Interests Purchase Agreement by and among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp.
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| 10.1.42 * $50,000,000 Revolving Credit Facility Credit Agreement by and among Strategic Energy, L.L.C., the lenders party thereto and PNC Bank, National Association, as Administrative Agent, dated as of October 3, 2007 (Exhibit 10.11.1 to Form 10-Q for the quarter ended September 30, 2007).
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| 10.1.43
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| * Receivables Purchase Agreement dated as of October 3, 2007, by and among Strategic Receivables, LLC, as Seller, Strategic Energy, L.L.C., as initial Servicer, the Conduit Purchasers party thereto, the Purchaser Agents party thereto, the Financial Institutions from time to time party thereto as LC Participants, and PNC Bank, National Association, as-Administrator and as LC Bank (Exhibit 10.1.2 to Form 10-Q for the quarter ended September 30, 2007).
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| 10.1.44
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| * Purchase and Sale Agreement dated as of October 3, 2007, by and among the various entities from time to time party thereto as Originators, Strategic Energy, L.L.C., as Servicer, and Strategic Receivables, LLC, as Buyer (Exhibit 10.1.3 to Form 10-Q for the quarter ended September 30, 2007).
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| 12.1 Computation of Ratio of Earnings to Fixed Charges.
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| 21.1. List of Subsidiaries of Great Plains Energy Incorporated.
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| 23.1 Consent of Independent Registered Public Accounting Firm.
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| 24.1 Powers of Attorney.
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| 31.1.a Rule 13a-14(a)/15d-14(a) Certifications of Michael J. Chesser.
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| 31.1.b Rule 13a-14(a)/15d-14(a) Certifications of Terry Bassham.
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| 144
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| 32.1 Section 1350 Certifications.
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| *Filed with the SEC as exhibits to prior SEC filings and are incorporated herein by reference and made a part hereof. The SEC filing and the exhibit number of the documents so filed, and incorporated herein by reference, are stated in parenthesis in the description of such exhibit.
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| + Indicates management contract or compensatory plan or arrangement.
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| Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from Great Plains Energy upon written request.
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| Great Plains Energy agrees to furnish to the SEC upon request any instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of total assets of Great Plains Energy and its subsidiaries on a consolidated basis.
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| KCP&L Documents Exhibit Description of Document Number 3.2.1 Restated Articles of Consolidation of Kansas City Power & Light Company, as amended October 1, 2001 (Exhibit 3-(i) to Form 1O-Q for the quarter ended September 30, 2001).
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| 3.2.2 By-laws of Kansas City Power & Light Company, as amended November 1, 2005 (Exhibit 3.2.b to Form 10-K for the year ended December 31, 2005).
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| 4.2.1 General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, n.a. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4-bb to Form 10-K for the year ended December 31, 1986).
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| 4.2.2 Fourth Supplemental Indenture dated as of February 15, 1992, to Indenture dated as of December 1', 1986 (Exhibit 4-y to Form 10-K for the year ended December 31, 1991).
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| 4.2.3 Fifth Supplemental Indenture dated as of September 15, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-a to quarterly report on Form 10-Q for the quarter ended September 30, 1992).
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| 4.2.4 Seventh Supplemental Indenture dated as of October 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4-a to quarterly report on Form 10-Q for the quarter ended September 30,- 1993).
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| 4.2.5
| |
| * Eighth Supplemental Indenture dated as of December 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4 to Registration Statement, Registration No. 33-51799).
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| 4.2.6
| |
| * Eleventh Supplemental Indenture dated as of August 15, 2005, to the General Mortgage and Deed of Trust dated as of. December.1, 1986, between Kansas City Power & Light Company and UMB Bank, nma. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2005).
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| 4.2.7 Indenture for Medium-Term Note Program dated as of February 15, 1992, between Kansas City Power & Light Company and The Bank of New York (Exhibit 4-bb to Registration Statement, Registration No. 33-45736).
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| 145
| |
| | |
| 4.2.8 Indenture for $150 million aggregate principal amount of 6.50% Senior Notes due November 15, 2011 and $250 million aggregate principal amount of 7.125% Senior Notes due December 15, 2005 dated as of December 1, 2000, between Kansas City Power & Light Company and The Bank of New York (Exhibit 4-a to Report On Form 8-K dated December 18, 2000).
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| 4.2.9
| |
| * Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light Company (Exhibit 4.1 .b. to Form 10-Q for the quarter ended March 31, 2002).
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| 4.2.10
| |
| * Supplemental Indenture No. 1 dated as of November 15, 2005, to Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light
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| *Company (Exhibit 4.2.j to Form 10-K for the year ended December 31, 2005).
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| 4.2.11
| |
| * Indenture dated as of May 1, 2007, between Kansas City Power & Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K dated June 4, 2007).
| |
| 4.2.12
| |
| * Supplemental Indenture No. 1 dated as of June 4, 2007 between Kansas City Power &
| |
| Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K dated June 4, 2007).
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| 10.2.1
| |
| * Insurance agreement between Kansas City Power & Light Company and XL Capital Assurance Inc., dated December 5, 2002 (Exhibit 10.2.f to Form 10-K for the year ended December 31, 2002).
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| 10.2.2
| |
| * Insurance Agreement dated as of August 1, 2004, between Kansas City Power & Light Company and XL Capital Assurance Inc. (Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2004).
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| 10.2.3
| |
| * Insurance Agreement dated as of September 1, 2005, between Kansas City Power &
| |
| Light Company and XL Capital Assurance Inc. (Exhibit 10.2.e to Form 10-K for the year ended December 31, 2005).
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| 10.2.4
| |
| * Insurance Agreement dated as of September 1, 2005, between Kansas City Power &
| |
| Light Company and XL Capital Assurance Inc. (Exhibit 10.2.e to Form 10-K for the year ended December 31, 2005).
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| 10.2.5 Insurance Agreement dated as of September 19, 2007, by and between Financial Guaranty Insurance Company and Kansas City Power & Light Company (Exhibit 10.2.2 1 to Form 1OQ for the quarter ended September 30, 2007).
| |
| 10.2.6 latan Unit 2 and Common Facilities Ownership Agreement, dated as of May 19, 2006, among Kansas City Power & Light Company, Aquila, Inc., The Empire District Electric Company, Kansas Electric Power Cooperative, Inc., and Missouri Joint Municipal Electric Utility Commission (Exhibit 10.2.a to Form 10-Q for the quarter ended June 30, 2006).
| |
| 10.2.7 Contract between Kansas City Power & Light Company and ALSTOM Power Inc. for Engineering, Procurement, and Constructions Services for Air Quality Control Systems and Selective Catalytic Reduction Systems at latan Generating Station Units 1 and 2 and the Pulverized Coal-Fired Boiler at latan Generating Station Unit 2, dated as of August 10, 2006 (Exhibit 10.2.a to Form 10-Q for the quarter ended September 30, 2006).
| |
| 146
| |
| | |
| 10.2.8 Credit Agreement dated as of May 11, 2006, among Kansas City Power & Light Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., BNP Paribas, The Bank of Tokyo-Mitsubishi UFJ, Limited, Chicago Branch, Wachovia Bank N.A., The Bank of New York, Keybank National Association, The Bank of Nova Scotia, UMB Bank, N.A., and Commerce Bank, N.A. (Exhibit 10.2.b to Form 10-Q for the quarter ended June 30, 2006).
| |
| 10.2.9 Stipulation and Agreement dated March 28, 2005, among Kansas City Power & Light Company, Staff of the Missouri Public Service Commission, Office of the Public Counsel, Missouri Department of Natural Resources, Praxair, Inc., Missouri Independent Energy Consumers, Ford Motor Company, Aquila, Inc., The Empire District Electric Company, and Missouri Joint Municipal Electric Utility Commission (Exhibit 10.2 to Form 1 0-Q for the quarter ended March 31, 2005).
| |
| 10.2.10 Stipulation and Agreement filed April 27, 2005, among Kansas City Power & Light Company, the Staff of the State Corporation Commission of the State of Kansas, Sprint, Inc., and the Kansas Hospital Association (Exhibit 10.2.a to Form 10-Q for the quarter ended June 30, 2005).
| |
| 10.2.11 Purchase and Sale Agreement dated as of July 1, 2005, between Kansas City Power & Light Company, as Originator, and Kansas City Power & Light Receivables Company, as Buyer (Exhibit 10.2.b to Form 10-Q for the quarter ended June 30, 2005).
| |
| 10.2.12
| |
| * Receivables Sale Agreement dated as of July 1, 2005, among Kansas City Power &
| |
| Light Receivables Company, as the Seller, Kansas City Power & Light Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation (Exhibit 10.2.c to Form 10-Q for the quarter ended June 30, 2005).
| |
| 10.2.13
| |
| * Collaboration Agreement dated as of March 19, 2007, among Kansas City Power &
| |
| Light Company, Sierra Club and Concerned Citizens of Platte County, Inc (Exhibit 10.1 to Form 8-K filed on March 20, 2007).
| |
| 10.2.14
| |
| * Amendment No. 1 dated as of April 2, 2007, among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation to the Receivables Sale Agreement date as of July 1, 2005 (Exhibit 10.2.2 to Form 10-Q for the quarter ended March 31, 2007).
| |
| 10.2.15 Notice of Election to Transfer Unused Commitment between the Great Plains Energy Incorporated and Kansas City Power & Light Company Credit Agreements dated as of May 11, 2006, with Bank of America, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, BNP Paribas, The Bank of Tokyo-Mitsubishi UFJ, Limited, Chicago Branch and Wachovia Bank N.A., as Co-Documentation Agents, The Bank of New York, KeyBank National Association, The Bank of Nova Scotia, UMB Bank, N.A., and Commerce Bank, N.A. (Exhibit 10.1.2 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).
| |
| 12.2 Computation of Ratio of Earnings to Fixed Charges.
| |
| 23.2 Consent of Independent Registered Public Accounting Firm.
| |
| 24.2 Powers of Attorney.
| |
| 31.2.a Rule 13a-14(a)/15d-14(a) Certifications of William H. Downey.
| |
| 147
| |
| | |
| 31.2.b Rule 13a-14(a)/15d-14(a) Certifications of Terry Bassham.
| |
| 32.2 Section 1350 Certifications.
| |
| * Filed with the SEC as exhibits to prior SEC filings and are incorporated herein by reference and made a part hereof. The SEC filings and the exhibit number of the documents so filed, and incorporated herein by reference, are stated in parenthesis in the description of such exhibit.
| |
| Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from KCP&L upon written request.'
| |
| KCP&L agrees to furnish to the SEC upon request any instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of total assets of KCP&L and its subsidiaries on a consolidated basis.
| |
| | |
| 10.2.8 Credit Agreement dated as of May 11, 2006, among Kansas City Power & Light Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., BNP Paribas, The Bank of Tokyo-Mitsubishi UFJ, Limited, Chicago Branch, Wachovia Bank N.A., The Bank of New York, Keybank National Association, The Bank of Nova Scotia, UMB Bank, N.A., and Commerce Bank, N.A. (Exhibit 10.2.b to Form 10-Q for the quarter ended June 30, 2006).
| |
| 10.2.9 Stipulation and Agreement dated March 28, 2005, among Kansas City Power & Light Company, Staff of the Missouri Public Service Commission, Office of the Public Counsel, Missouri Department of Natural Resources, Praxair, Inc., Missouri Independent Energy Consumers, Ford Motor Company, Aquila, Inc., The Empire District Electric Company, and Missouri Joint Municipal Electric Utility Commission (Exhibit 10.2 to Form 1 0-Q for the quarter ended March 31, 2005).
| |
| 10.2.10 Stipulation and Agreement filed April 27, 2005, among Kansas City Power & Light Company, the Staff of the State Corporation Commission of the State of Kansas, Sprint, Inc., and the Kansas Hospital Association (Exhibit 10.2.a to Form 10-Q for the -
| |
| quarter ended June 30, 2005).
| |
| 10.2.11 Purchase and Sale Agreement dated as of July 1, 2005, between Kansas City Power & Light Company, as Originator, and Kansas City Power & Light Receivables Company, as Buyer (Exhibit 10.2.b to Form 10-Q for the quarter ended June 30, 2005).
| |
| 10.2.12
| |
| * Receivables Sale Agreement dated as of July 1, 2005, among Kansas City Power &
| |
| Light Receivables Company, as the Seller, Kansas City Power & Light Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation (Exhibit 10.2.c to Form 10-Q for the quarter ended June 30, 2005).
| |
| 10.2.13
| |
| * Collaboration Agreement dated as of March 19, 2007, among Kansas City Power &
| |
| Light Company, Sierra Club and Concerned Citizens of Platte County, Inc (Exhibit 10.1 to Form 8-K filed on March 20, 2007).
| |
| 10.2.14 Amendment No. 1 dated as of April 2, 2007, among Kansas City Power & Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation to the Receivables Sale Agreement date as of July 1, 2005 (Exhibit 10.2.2 to Form 10-Q for the quarter ended March 31, 2007).
| |
| 10.2.15 Notice of Election to Transfer Unused Commitment between the Great Plains Energy Incorporated and Kansas City Power & Light Company Credit Agreements dated as of May 11, 2006, with Bank of America, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, BNP Paribas, The Bank of Tokyo-Mitsubishi UFJ, Limited, Chicago Branch and Wachovia Bank N.A., as Co-Documentation Agents, The Bank of New York, KeyBank National Association, The Bank of Nova Scotia, UMB Bank, N.A., and Commerce Bank, N.A. (Exhibit 10.1.2 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).
| |
| 12.2 Computation of Ratio of Earnings to Fixed Charges.
| |
| 23.2 Consent of Independent Registered Public Accounting Firm.
| |
| 24.2 Powers of Attorney.
| |
| 31.2.a Rule 13a-14(a)/15d-14(a) Certifications of William H. Downey.
| |
| 147
| |
| | |
| 31.2.b Rule 13a-14(a)/15d-14(a) Certifications of Terry Bassham.
| |
| 32.2 Section 1350 Certifications.
| |
| * Filed with the SEC as exhibits to prior SEC filings and are incorporated herein by reference and made a part hereof. The SEC filings and the exhibit number of the documents so filed, and incorporated herein by reference, are stated in parenthesis in the description of such exhibit.
| |
| Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from KCP&L upon written request.
| |
| KCP&L agrees to furnish to the SEC upon request any instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of total assets of KCP&L and its subsidiaries on a consolidated basis.
| |
| 148
| |
| | |
| Schedule I - Parent Company Financial Statements GREAT PLAINS ENERGY INCORPORATED Income Statements of Parent Company Year Ended December 31 2007 2006 2005 Operating Expenses (millions, except per share amounts)
| |
| Selling, general and administrative $ 18.5 $ 7.1 $ 7.1 Maintenance 0.8 -
| |
| General taxes 0.3 0.3 0.3 Total 19.6 7.4 7.4 Operating loss (19.6) (7.4) (7.4)
| |
| Equity from earnings in subsidiaries 195.1 143.0 178.2 Non-operating income 4.2 1.1 1.6 Non-operating expenses (0.1)
| |
| Interest charges (26.8) (8.9) (9.4)
| |
| Income before income taxes 152.9 127.8 162.9 Income taxes 6.3 (0.2) (0.6)
| |
| Net income 159.2 127.6 162.3 Preferred stock dividend requirements 1.6 1.6 1.6 Earnings available for common shareholders $ 157.6 $ 126.0 $ 160.7 Average number of basic common shares outstanding 84.9 78.0 74.6 Average number of diluted common shares outstanding 85.2 78.2 74.7 Basic earnings per common share $ 1.86 $ 1.62 $ 2.15 Diluted earnings per common share $ 1.85 $ 1.61 $ 2.15 Cash dividends per common share $ 1.66 $ 1.66 $ 1.66 The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.
| |
| 149
| |
| | |
| GREAT PLAINS ENERGY INCORPORATED Balance Sheets of Parent Company December 31 2007 2006 ASSETS (millions, except share amounts)
| |
| Current Assets Cash and cash equivlents $ 6.6 $ 5.8 Accounts receivable from subsidiaries 1.0 1.6 Notes receivable from subsidiaries 0.6 2.3 Taxes receivable 3.7 1.9 Other 0.4 0.5 Total 12.3 12.1 Nonutility Property and Investments Investment in KCP&L 1,479.4 1,383.1 Investments in other subsidiaries 256.8 178.6 Other 0.7 Total 1,736.9 1,561.7 Deferred Charges and Other Assets Deferred Income Taxes 8.0 0.8 Other 23.7 4.6 Total 31.7' 5.4 Total $ 1,780.9 $ 1,579.2 The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.
| |
| 150
| |
| | |
| GREAT PLAINS ENERGY INCORPORATED Balance Sheets of Parent Company December 31 2007 2006 LIABILITIES AND CAPITALIZATION (millions, except share amounts)
| |
| Current Liabilities Notes payable $ 42.0 $
| |
| Notes. payable to subsidiaries 13.2 Current maturities of long-term debt 163.6 Accounts payable to subsidiaries 10.8 15.6 Accounts payable 0.1 Accrued interest 2.0 1.6 Other 1.3 1.9 Derivative instruments 16.4 Total 72.6 195.9 Deferred Credits and Other Liabilities Payable to subsidiaries 0.2 2.1 Other 1.7 0.3 Total 1.9 2.4 Capitalization Common shareholders' equity Common stock-150,000,000 shares authorized without par value 86,325,136 and 80,405,035 shares issued, stated value 1,065.9 896.8 Retained earnings 506.9 493.4 Treasury stock-90,929 and 53,499 shares, at cost (2.8) (1.6)
| |
| Accumulated other comprehensive loss (2.1) (46.7)
| |
| Total 1,567.9 1,341.9 Cumulative preferred stock $100 par value 3.80% - 100,000 shares issued 10.0 10.0 4.50% - 100,000 shares issued 10.0 10.0 4.20% - 70,000 shares issued 7.0 7.0 4.35% - 120,000 shares issued 12.0 12.0 Total 39.0 39.0 Long-term debt 99.5 Total 1,706.4 1,380.9 Commitments and Contingencies Total $ 1,780.9 $ 1,579.2 The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.
| |
| 151
| |
| | |
| GREAT PLAINS ENERGY INCORPORATED Statements of Cash Flows of Parent Company Year Ended December 31 2007 2006 2005 Cash Flows from Operating Activities (millions),
| |
| Net income $ 159.2 $ 127.6 $ 162.3 Adjustments to reconcile income to net cash from operating activities:
| |
| Amortization 1.0 0.6 0.6 Deferred income taxes, net (6.2)
| |
| Equity in earnings from subsidiaries (195.1) (143.0) (178.2)
| |
| Cash flows affected by changes in:
| |
| Accounts receivable from subsidiaries 0.6 (0.6) (0.4)
| |
| Taxes receivable (1.8) (0.1) 2.6 Accounts payable to subsidiaries (4.8) 15.1 0.5 Other accounts payable 0.1 (0.1) 0.1 Accrued interest 1.1 (0.1) 0.1 Cash dividends from subsidiaries 159.7 118.0 133.9 Other 1.8 1.7 3.0 Net cash from operating activities 115.6 119.1 124.5 Cash Flows from Investing Activities Equity contributions to subsidiaries (94.0) (134.6) -
| |
| Net change in notes receivable from subsidiaries 1.7 3.1 11.0 Purchases of nonutility property (0.7)
| |
| Net cash from investing activities (93.0) (131.5) 11.0 Cash Flows from Financing Activities Issuance of common stock 10.5 153.6 9.1 Issuance of long-term debt 99.5 -
| |
| Issuance fees (1.4) (5.7)
| |
| Net change in notes payable to subsidiaries (13.2) 13.2 Net change in short-term borrowings 42.0 (6.0) (14.0)
| |
| Equity forward settlement (12.3) -
| |
| Dividends paid (144.5) (132.7) (125.5)
| |
| Other financing activities (2.4) (6.2) (5.9)
| |
| Net cash from financing activities (21.8) 16.2 (136.3)
| |
| Net Change in Cash and Cash Equivalents 0.8 3.8 (0.8)
| |
| Cash and Cash Equivalents at Beginning of Year 5.8 2.0 2.8 Cash and Cash Equivalents at End of Year $ 6.6 $ 5.8 $ 2.0 The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.
| |
| 152
| |
| | |
| GREAT PLAINS ENERGY INCORPORATED Statements of Common Shareholders' Equity of Parent Company Statements of Comprehensive Income of Parent Company Incorporated by reference is Great Plains Energy Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Comprehensive Income.
| |
| GREAT PLAINS ENERGY INCORPORATED NOTES TO FINANCIAL STATEMENTS OF PARENT COMPANY The Great Plains Energy Incorporated Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Great Plains Energy Incorporated Parent Company Financial Statements.
| |
| 153
| |
| | |
| Schedule II- Valuation and Qualifying Accounts and Reserves Great Plains Energy
| |
| * Valuation and Qualifying Accounts Years Ended December 31, 2007, 2006 and 2005 Additions Charged Balance At To Costs Charged Balance Beginning And To Other At End Description Of Period Expenses Accounts Deductions Of Period Year Ended December 31, 2007 (millions)
| |
| Allowance for uncollectible accounts $ 8.3 $23.2 $ 6.8 (a) $27.1 (b)- $11.2 Legal reserves 6.1 2.1 - 5.9 (c) 2.3 Environmental reserves 0.3 - - - 0.3 Uncertain tax positions (d) 4.7 2.5 1.7 (e) 0.9 (f) 8.0 Year Ended December 31, 2006 Allowance for uncollectible accounts $ 6.9 $12.3 $ 5.7 (a) $16.6 (b) $ 8.3 Legal reserves 5.9 4.9 0.1 4.8 (c) 6.1 Environmental reserves 0.3 - - - 0.3 Uncertain tax positions (d) 4.6 1.1 - 1.0 (f) 4.7 Year Ended December 31, 2005 Allowance for uncollectible accounts $ 6.4 $ 6.9 $ 5.0 (a) $11.4 (b) $ 6.9 Legal reserves 3.2 4.5 - 1.8 (c) 5.9 Environmental reserves 0.3 - - - 0.3 Uncertain tax positions (d) 13.4 1.2 10.0 (f) 4.6 (a) Recoveries. Charged to other accounts for the year ended December 31, 2006 and 2005, respectively, includes the establishment of an allowance of $1.5 million and $1.6 million.
| |
| (b) Uncollectible accounts charged off.
| |
| (c) Payment of claims.
| |
| (d) Represents the total amount of taxexpense thatwould impactthe effective tax rate, if recognized, and amounts accrued for interest expense related to uncertain taxpositions, net of-tax.
| |
| Ce) Upon adoption of FIN 48 on January 1, 2007, $1.7 million was charged to retained earnings.
| |
| ( Reversal of uncertain tax positions and related interest. Deductions for the year ended December 31, 2005, includes a reclass of $0.8 million to franchise taxes payable.
| |
| 154
| |
| | |
| Kansas City Power & Light Company Valuation and Qualifying Accounts Years Ended December 31, 2007, 2006 and 2005 Additions Charged Balance At To Costs Charged Balance Beginning And To Other At End Description Of Period Expenses Accounts Deductions Of Period Year Ended December 31, 2007 (millions)
| |
| Allowance for uncollectible accounts $ 4.2 $ 5.4 $ 2.9 (a) $ 8.2 (b) $' 4.3 Legal reserves 3.9 1.9 - 3.6 (c) 2.2 Environmental reserves 0.3 - - - 0.3 Uncertain tax positions (d) 1.8 0.7 0.8 (e) 0.3 (f) 3.0 Year Ended December 31, 2006 Allowance for uncollectible accounts $ 2.6 $ 4.5 $ 4.4 (a) $ 7.3 (b) $ 4.2 Legal reserves 4.5 2.8 - 3.4 (c) 3.9 Environmental reserves 0.3 - - - 0.3 Uncertain tax positions (d) 1.2 0.8 - 0.2 (f) 1.8 Year Ended December 31, 2005 Allowance for uncollectible accounts $ 1.7 $ 3.3 $ 4.6 (a) $ 7.0 (b) $ 2.6 Legal reserves 3.2 3.1 - 1.8 (c) 4.5 Environmental reserves 0.3 - - - 0.3 Uncertain tax positions (d) 3.7 0.3 - 2.8 (f) 1.2 (a) R~~~n\/*ri*
| |
| (-.. ,h-\..r.n.-,----- *mh*_
| |
| -n......r......... 21 NI3 . l.. i li-R..th.
| |
| establishment of an allowance of $1.5 million and $1.6 million.
| |
| (b)
| |
| Uncollectible accounts charged off.
| |
| (c)
| |
| Payment of claims.
| |
| (d)
| |
| Represents the total amount of tax expense that would impact the effective tax rate, if recognized, and amounts accrued for interest expense related to uncertain tax positions,net of tax (e)
| |
| Upon adoption of FIN 48 on January 1, 2007, $0.8 million was charged to retained earnings.
| |
| (f) Reversal of uncertain tax positions and related interest. Deductions for the year ended December 31, 2005, includeE a reclass of $0.8 million to franchise taxes payable.
| |
| 155
| |
| | |
| SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| |
| GREAT PLAINS ENERGY INCORPORATED Date: February 28, 2008 By: /s/Michael J. Chesser Michael J. Chesser Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| |
| Sigqnature Title Date
| |
| /s/Michael J. Chesser Chairman of the Board and Chief Michael J. Chesser Executive Officer (Principal Executive Officer)
| |
| Executive Vice President - Finance
| |
| /s/Terry Bassham and Strategic Development and Terry Bassham Chief Financial Officer (Principal Financial Officer)
| |
| /s/Lori A. Wright Controller Lori A. Wright (Principal Accounting Officer)
| |
| David L. Bodde* Director February 28, 2008
| |
| /s/William H. Downey Director William H. Downey Mark A. Ernst* Director Randall C. Ferguson, Jr.* Director William K. Hall* Director Luis A. Jimenez* Director James A. Mitchell* Director William C. Nelson* Director Linda H. Talbott* Director Robert H. West* Director
| |
| *By /s/Michael J. Chesser Michael J. Chesser Attorney-in-Fact*
| |
| 156
| |
| | |
| SIGNATURES Pursuant to the, requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly-caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| |
| KANSAS CITY POWER & LIGHT COMPANY Date: February 28, 2008. By: /s/ William H. Downey
| |
| 'William H. Downey President and Chief Executive Officer Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on. behalf of the registrant and in the capacities and on the dates indicated.
| |
| Signature Title Date
| |
| /s/ William H. Downey President and Chief Executive ))
| |
| William H. Downey Officer and Director (Principal Executive Officer) )
| |
| )
| |
| /s/Terry Bassham Chief Financial Officer )
| |
| Terry-Bassham (Principal Financial Officer) )
| |
| )
| |
| /s/Lori A. Wright )
| |
| Controller Lori A. Wright (Principal Accounting Officer) )
| |
| )
| |
| David L. Bodde* Director ) February 28, 2008
| |
| )
| |
| /s/Michael J. Chesser Chairman of the Board )
| |
| Michael J. Chesser )
| |
| )
| |
| Mark A. Ernst* Director )
| |
| )
| |
| Randall C. Ferguson, Jr.* Director )
| |
| )
| |
| Luis'A. Jimenez* Director )
| |
| )
| |
| James A. Mitchell* Director )
| |
| )
| |
| William C. Nelson" Director )
| |
| )
| |
| Linda H. Talbott* Director )
| |
| *By -/s/Michael J. Chesser
| |
| - Michael J. Chesser Attorney-in-Fact*
| |
| 157
| |
| | |
| Exhibit 31.1 .a CERTIFICATIONS I, Michael J. Chesser, certify that:
| |
| : 1. I have reviewed this annual report on Form 10-K of Great Plains Energy Incorporated;
| |
| : 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
| |
| : 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report:
| |
| : 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
| |
| (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures; as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
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| : 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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| (a) All significant deficiencies and material weaknesses in the design Or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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| Date: February 28, 2008 Mich el J. Chesser Ch ýrmran of the Board and Chief Executive Offiber
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| Exhibit 31.1.b CERTIFICATIONS I, Terry Bassham, certify that:
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| : 1. 1 have reviewed this annual report on Form 10-K of Great Plains Energy Incorporated;
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| : 2. Based on my knowledge, -this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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| : 3. Based on my knowledgeithe financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report:
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| : 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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| (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
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| : 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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| (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves manaeh- emern oyees who have a significant role in the registrant's internal control over. cial repo Date: February 28, 2008 _____. _"_____
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| Terry Bassh'anm Executive Vice President - Finance and Strategic Development and Chief Financial Officer
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| (This page intentionally left blank.)
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| DIRECTORS AND OFFICERS BOARD OF DIRECTORS: James A. Mitchell Terry Bassham Lora C. Cheatum Charles H. Tickles GREAT PLAINS ENERGY Executive Fellow-Leadership, Executive Vice President- Vice President- Vice President-Centerfor EthticalBusiness Financeand Strategic Administrative Services Information Technology Michael J.Chesser Cultures,a not-for-profit Development and Chief Chairmanof the Board and Michael W. Cline Lori A. Wright orgttanizationassisting busi- FinancialOfficer Chief Executive Officer ness leaders in creatingethical Treasurer Controller and profitablecultures Michael W. Cline Dr. David L. Bodde Vice Presideat-ftnvestor Dana Crawford OFFICERS:
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| Senior Fellow and Professor, William C. Nelson Relations and Treasurer Vice Presidentt-STRATEGIC ENERGY Arthur M. Spiro htstitutefor Plant Operations EntrepreneurialLeadership Chairman,George K. Bautn Barbara B. Curry Shahid Malik Asset Managenment,a Barbara B. Curry Presidentand at Clemson University Senior Vice President-leading provider of invest- Corporate Secretary Chief Executive Officer CorporateServices and William H. Downey ttent mtanagement services CorporateSecretary Stephen T. Easley Jeffrey T. Buxton President and Chief to individuals,foundations Senior Vice President- Chieflnforntation Officer Operating Officer and institutions Michael L. Deggendorf Supply and Executive Vice Vice President-PublicAffairs Mark A. Ernst Dr. Linda H. Talbott President-Information Chris B. Giles Former Chairmanof the President and CEO, Talbott Mark G. English Technology e&Associates, consultants in Vice President-Board, Presidentand Chief GeneralCounsel and Executive Officer, HdvR strategic planning,philan- Assistant Secretary Regulatory Affatirs Jan L. Fox General Counsel, Corporate Block, Inc., a global provider thropic management and William P. Herdegen, Ill of tax preparation,investment development to foundations, Shahid Malik Vice Presidett-Secretary and Executive Executive Vice President Vice President-Market and accounting services corporationsanti nonprofit CustomerOperations Development organizations Lori A. Wright Randall C. Ferguson, Jr. John R. Marshall Robert H. West Controller Janis D. Shaw Former Senior Partnerfor Senior Vice President-Retired Chairmanof the Executive Vice President-Business Development, OFFICERS: Delivery Human Resources and Tshibatda& Associates, Board, Butler Manufacturing KANSAS CITY POWER Todd A. Kobayashi Corporate Services LLC, a consultingandproject Company,a supplier of
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| & LIGHT Vice President-Energy management services first non-residentialbuilding sys- Andrew J.Washburn tents, specialty components Michael J.Chesser Resource Management Chief FinancialOfficer Dr. William K. Hall and construction services Chairmanof the Board William G. Riggins Chairman, Procyon Michael R. Young William H. Downey Vice President-Legaland Technologies, Inc., a holding OFFICERS: Executive Vice President-Presidentand Chief EnvironntentalAffairs and conmpany witlh investments GREAT PLAINS ENERGY Sales and Marketing Executive Officer GeneralCounsel in the aerospace and defense Michael J.Chesser industries John M. Dietrich Chairttanof the Board and Terry Bassham Marvin L. Rollison Executive Vice President-ChicfExecuttive Officer ChiefFinancialOfficer Vice President-Renewables Luis A. Jimenez Retail Operations and Gas Generation Senior Vice Presidtentand Chief Kevin E. Bryant William H. Downey Industry Policy Officer,Pitney Vice President- Richard A. Spring Presidentand Chief Bowes Inc., a global provider Operatitng Officer Energy Solutions Vice President-of integrated mail and docu- TransmissionServices tment inanagentettsolutions SHAREHOLDER INFORMATION GREAT PLAINS ENERGY FORM 10-K TWO-YEAR COMMON STOCK HISTORY Great Plains Energy's 2007 annual report on Form 10-K filed with 2007 2006 the Securities and Exchange Commission can be found at Quarter High Low High Low www.greatplainsentergy.cost?.The required Sarbanes-Oxley Section First $32.67 $30.42 $29.32 $27.89 302 certifications were filed as exhibits to the 10-K. The 10-K is available Second 33.18 28.82 28.99 27.33 at no charge upon written request to: Corporate Secretary, Great Plains Third 29.94 26.99 31.43 27.70 Energy Incorporated, P.O. Box 418679, Kansas City, MO 64141-9679.
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| Fourth 30.45 28.32 32.80 31.13 MARKET INFORMATION ANNUAL MEETING OF SHAREHOLDERS Great Plains Energy common stock is traded on the New York Stock Great Plains Energy's annual meeting of shareholders will be held at 10 a.m.,
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| Exchange under the ticker symbol GXP. We had 12,523 shareholders of May 6, 2008, at the Nelson-Atkins Museum of Art, 4525 Oak Street, record as of February 21, 2008.
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| Kansas City, Missouri.
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| INTERNET SITE REGISTERED SHAREHOLDER INQUIRIES We have a Web site on the Internet at www.greatplainsenergy.com. Information For account information or assistance, including change of address, available includes our SEC filings, company news releases, stock quotes, stock transfers, dividend payments, duplicate accounts or to report a customer account information, community and environmental efforts lost certificate, please contact Investor Relations at 800-245-5275.
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| and information of general interest to investors and customers.
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| Also located on our Web site are our Code of Ethical Business Conduct, FINANCIAL COMMUNITY INQUIRIES Corporate Governance Guidelines and the charters of the Audit Committee, Securities analysts and investment professionals seeking information Governance Committee, and Compensation and Development Committee about Great Plains Energy may contact Investor Relations of the Board of Directors, which are available at no charge upon written at 816-556-2312.
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| request to the Corporate Secretary.
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| TRANSFER AGENT AND STOCK REGISTRANT COMMON STOCK DIVIDENDS PAID Computershare Trust Company, N.A.
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| Quarter 2007 2006 Investor Services First $0.415 $0.415 P.O. Box 43078 Second $0.415 $0.415 Providence, RI 02940-3078 Third $0.415 $0.415 Tel: 800-884-4225 Fourth $0.415 $0.415 CORPORATE GOVERNANCE LISTING STANDARDS CERTIFICATION CUMULATIVE PREFERRED STOCK DIVIDENDS On May 21, 2007, the company submitted its Annual CEO Certification Quarterly dividends on preferred stock were declared in each quarter of to the New York Stock Exchange (NYSE). Mike Chesser, Chairman of the 2007 and 2006 as follows: Board and Chief Executive Officer of the company, certified that as of Series Amount Series Amott May 21, 2007, he was not aware of any violation by the company of 3 8 NYSE Corporate Governance listing standards.
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| . 0% $0.95 4.35% 1.0875 4.20% 1.05 4.50% 1.125
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| QIvTrp~fllInI"
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| ý NYSE: GXP FOR MORE INFORMATION ON GREAT PLAINS ENERGY, KANSAS CITY POWER & LIGHT OR STRATEGIC ENERGY HtN T VISIT US ONLINE: WWW.GREATPLAINSENERGY.COM WWWKCPL.COM WWW.SEL.COM}}
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