ML17132A172
| ML17132A172 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 05/03/2017 |
| From: | Hafenstine C Wolf Creek |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| RA 17-0036 | |
| Download: ML17132A172 (327) | |
Text
lNeLFCREEK 'NUCLEAR OPERATING CORPORATION May 3, 2017 Cynthia R. Hafenstine Manager Nuclear and Regulatory Affairs RA 17-0036 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555
Subject:
Docket No. 50-482: Transmittal of 2016 Annual Financial Reports To Whom It May Concern:
Wolf Creek Nuclear Operating Corporation (WCNOC) is transmitting one copy each of the enclosed 2016 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).
This letter contains no commitments. If you have any questions concerning this matter, please contact me at (620) 364-4204.
Sincerely, Cynthia R. Hafenstine CRH/rlt
Enclosure:
I Westar Energy Form 10-K 2016 Report II Great Plains Energy 2016 Annual Report Ill Kansas Electric Power Cooperative, Inc. 2016 Annual Report cc: K. M. Kennedy (NRC), w/e B. K. Singal (NRC), w/e N. H. Taylor (NRC), w/e Senior Resident Inspector (NRC), w/e P.O. Box 411 I Burlington, KS 66839 I Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET L__
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORMlO-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, 2016 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to _ _ _ __
Commission File Number 1-3523 WESTAR ENERGY, INC.
(Exact name of registrant as specified in its charter)
Kansas 48-0290150 (State or other jurisdiction of ineorporation or organization) (1.R.S. Employer Identification Number) 818 South Kansas Avenue, Topeka, Kansas 66612 (785) 575-6300 (Address, including Zip code and telephone number, including area code, ofregistrant' s principal executive offices)
Securities registered pursuant to section 12(b) of the Act:
Common Stock, par value $5.00 per share New York Stock Exchange (Title of each class) (Name of each exchange on which registered)
Securities registered pursuant to section 12(g) of the Act: None Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act). Yes __x_ No Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 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. Yes _x_ No _ _
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 mohths (or for such shorter period that the registrant was required to submit
- and post such files). Yes _x_ No _ _
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 ofregistrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Act). Check one:
Large accelerated filer _x_ Accelerated filer _ _ Non-accelerated filer _ _ Smaller reporting company _ _
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes _ _ No _x_
The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $7,947,449,144 at June 30, 2016.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Common Stock, par value $5.00 per share 142,045,033 shares (Class) (Outstanding at February 15, 2017)
DOCUMENTS INCORPORATED BY
REFERENCE:
Information required by Items 10-14 of Part III of this Form 10-K will be incorporated by reference to Westar Energy, Inc. 's definitive proxy statement with respect to its 2017 Annual Meeting of Shareholders, if such definitive proxy statement is filed with the Securities and Exchange Commission on or before April 30, 2017. Due to the pending merger with Great Plains Energy Incorporated, we may not be required to file a definitive proxy statement, in which case we will file an amendment to this Form 1O-K on or before April 30, 2017 to include the information that is otherwise incorporated by reference.
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORMlO-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, 2016 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to _ _ _ __
Commission File Number 1-3523
~arEnergy. WESTAR ENERGY, INC.
(Exact name ofregistrant as specified in its charter)
Kansas 48-0290150 (State or other jurisdiction of incorporation or organization) (I.RS. Employer Identification Number) 818 South Kansas Avenue, Topeka, Kansas 66612 (785) 575-6300 (Address, including Zip code and telephone number, including area code, of registrant's principal executive offices)
Securities registered pursuant to section 12(b) of the Act:
Common Stock, par value $5.00 per share New York Stock Exchange (Title of each class) (Name of each exchange on which registered)
Securities registered pursuant to section 12(g) of the Act: None Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act). Yes __x_ No Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 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. Yes __x_ No _ _
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes __x_ No _ _
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 ofregistrant's knowledge, in definitive proxy or information statements incorporated.by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,* a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Act). Check one:
Large accelerated filer __x_ Accelerated filer _ _ Non-accelerated filer _ _ Smaller reporting company _ _
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes _ _ No __x_
The aggregate market value of the voting co~on equity held by non-affiliates of the registrant was approximately $7,947,449,144 at June 30, 2016.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Common Stock, par value $5.00 per share 142,045,033 shares (Class) (Outstanding at February 15, 2017)
DOCUMENTS INCORPORATED BY
REFERENCE:
Information required by Items 10-14 of Part III of this Form 10-K will be incorporated by reference to Westar Energy, Inc. 's defmitive proxy statement with respect to its 2017 Annual Meeting of Shareholders, if such definitive proxy statement is filed with the Securities and Exchange Commission on or before April 30, 2017. Due to the pending merger with Great Plains Energy Incorporated, we may not be required to file a definitive proxy statement, in which case we will file an amendment to this Form 1O-K on or before April 30, 2017 to include the information that is otherwise incorporated by reference.
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TABLE OF CONTENTS Page PART I Item 1. Business I Item IA. Risk Factors .u Item lB. Unresolved Staff Comments 23 Item 2. Properties 24 Item 3. Legal Proceedings 26
- Item 4. Mine Safety Disclosures 26 PARTil Item 5. ,Market for Registrant's Common Equity and Related Stockholder Matters 27 Item 6. Selected Financial Data 29 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 30 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 53 Item 8. Financial Statements and Supplementary Data 55 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure ill Item 9A. Controls and Procedures ill Item 9B. Other Information ill PART III Item 10. Directors and Executive Officers of the Registrant 114 Item 11. Executive Compensation 114 Item 12. Security Ownership of Certain Beneficial Owners and Management 114 Item 13. Certain Relationships and Related Transactions ill Item 14. Principal Accountant Fees and Services 114 PART IV Item 15. Exhibits and Financial Statement Schedules Item 16. F 01m 10-K Summaiy Signatures 2
GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.
Abbreviation or Acronym Definition AFUDC Allowance for funds used during construction ARO Asset retirement obligation ASU Accounting Standard Update BNSF BNSF Railway Company Btu British thermal units CAA Clean Air Act CCR Coal combustion residuals co Carbon monoxide C02 Carbon dioxide COLI Corporate-owned life insurance CPP Clean Power Plan CWA Clean Water Act CWIP Construction work in progress DOE Department of Energy DSPP Direct Stock Purchase Plan EPA Environmental Protection Agency EPS Earnings per share Exchange Act Securities Exchange Act of 1934 FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GAAP Generally Accepted Accounting Principles GHG Greenhouse gas Great Plains Energy Great Plains Energy Incorporated HSRAct Hart-Scott-Rodino Antitrust Improvements Act IM Integrated Marketplace JEC Jeffrey Energy Center KCC Kansas Corporation Commission KCPL Kansas City Power & Light Company KDHE Kansas Department of Health and Environment KGE Kansas Gas and Electric Company La Cygne La Cygne Generating Station LTISAPlan Long-term incentive and share award plan MATS Mercury and Air Toxics Standards Merger Pending acquisition of Westar Energy, Inc. by Great Plains Energy Incorporated MPSC Public Service Commission of the State of Missouri MMBtu Millions of British thermal units Moody's Moody's Investors Service MW Megawatt(s)
MWh Megawatt hour(s)
NAAQS National Ambient Air Quality Standards NAV Net Asset Value NDT Nuclear Decommissioning Trust NEIL Nuclear Electric Insurance Limited NOx Nitrogen oxides NRC Nuclear Regulatory Commission 3
OPC Office of Public Counsel PCB Polychlorinated biphenyl PM Particulate matter PPB Parts per billion PRB Powder River Basin Prairie Wind Prairie Wind Transmission, LLC ROE Return on equity RSU Restricted share unit RTO Regional transmission organization S&P Standard & Poor's Ratings Services S&P 500 Standard & Poor's 500 Index S&P Electric Utilities Standard & Poor's Electric Utility Index SEC Securities and Exchange Commission S02 Sulfur dioxide SPP Southwest Power Pool, Inc.
SSCGP Southern Star Central Gas Pipeline TFR Transmission formula rate VaR Value-at-Risk VIE Variable interest entity Wolf Creek Wolf Creek Generating Station 4
FORWARD-LOOKING STATEMENTS Certain matters discussed in this Annual Report on Form 10-K are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe," "anticipate," "target," "expect," "estimate, "intend" and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning matters such as, but not limited to:
the pending acquisition (merger) of Westar Energy, Inc. by Great Plains Energy Incorporated (Great Plains Energy),
amount, type and timing of capital expenditures, earnings, cash flow, liquidity and capital resources, litigation, accounting matters, compliance with debt and other restrictive covenants, interest rates and dividends, environmental matters, regulatory matters, nuclear operations, and the overall economy of our service area and its impact on our customers' demand for electricity and their ability to pay for service.
What happens in each case could vary materially from what we expect because of such things as:
risks related to operating in a heavily regulated industry that is subject to tmpredictable political, legislative, judicial and regulatory developments, which can impact our operations, results of operations, and fmancial condition, the difficulty of predicting the magnitude and timing of changes in demand for electricity, including with respect to emerging competing services and technologies and conservation and energy efficiency measures, the impact of weather conditions, including as it relates to sales of electricity and prices of energy commodities, equipment damage from storms and extreme weather, economic and capital market conditions, including the impact of inflation or deflation, changes in interest rates, the cost and availability of capital and the market for trading wholesale energy, the impact of changes in market conditions on employee benefit liability calculations and funding obligations, as well as actual and assumed investment returns on invested plan assets, the impact of changes in estimates regarding our Wolf Creek Generating Station (Wolf Creek) decommissioning obligation, the existence or introduction of competition into markets in which we operate, the impact of changing laws and regulations relating to air and greenhouse gas (GHG) emissions, water emissions, waste management and other environmental matters, risks associated with execution of our planned capital expenditure program, including timing and receipt of regulatory approvals necessary for planned construction and expansion projects as well as the ability to complete planned construction projects within the terms and time frames anticipated, cost, availability and timely provision of equipment, supplies, labor and fuel we need to operate our business, availability of generating capacity and the performance of our generating plants, changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown or required modification of nuclear generating facilities, additional regulation due to Nuclear Regulatory Commission (NRC) oversight to ensure the safe operation of Wolf Creek, either related to Wolf Creek's performance, or potentially relating to events or performance at a nuclear plant anywhere in the world, uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal, homeland and information and operating systems security considerations, our inability to fully utilize expected tax credits, changes in accounting requirements and other accounting matters, changes in the energy markets in which we participate and the effect of the retroactive repricing of transactions in such markets following execution because of changes or adjustments in market pricing mechanisms by regional transmission organizations (RTOs) and independent system operators, 5
reduced demand for coal-based energy because of actual or potential climate impacts and the development of alternate energy sources, current and future litigation, regulatory investigations, proceedings or inquiries, cost of fuel used in generation and wholesale electricity prices, certain risks and uncertainties associated with the merger, including, without limitation, those related to:
the timing of, and the conditions imposed by, regulatory approvals required for the merger, the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement or could otherwise cause the failure of the merger to close, the failure of Great Plains Energy to obtain all financing necessary to complete the merger, the outcome of any legal proceedings, regulatory proceedings or enforcement matters that have been or may be instituted in connection with the merger, the receipt of an unsolicited offer from another party to acquire our assets or capital stock (or those of Great Plains Energy) that could interfere with the proposed merger, the timing to consummate the proposed transaction, disruption from the proposed transaction making it more difficult to maintain relationships with customers, employees, regulators or suppliers, the diversion of management time and attention on the transaction, the amount of costs, fees, expenses and charges related to the merger, and the effect and timing of changes in laws or in governmental regulations (including environmental laws and regulations) that could adversely affect our participation in the merger, and other factors discussed elsewhere in this report, including in "Item IA. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and in other reports we file from time to time with the Securities and Exchange Commission (SEC), including the proxy statement and other materials that we have filed or will file with the SEC in connection with the merger.
These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety and in conjunction with the other reports we file from time to time with the SEC. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our consolidated financial results may be included in the other reports we file from time to time with the SEC. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.
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PART I ITEM 1. BUSINESS GENERAL Overview We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to "the Company," we," "us," "our" and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term "Westar Energy" refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.
We provide electric generation, transmission and distribution services to approximately 704,000 customers in Kansas.
Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy's wholly-owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.
Strategy We expect to continue operating as a vertically integrated, regulated electric utility. Significant elements of our strategy include maintaining a flexible, clean and diverse energy supply portfolio. In doing so, we continue to expand renewable generation, build and upgrade our energy infrastructure and develop systems and programs with regard to how our customers use energy and interact with us. In addition, we have entered into an agreement and plan of merger with Great Plains Energy pursuant to which, at closing, we would become a wholly-owned subsidiary of Great Plains Energy. The closing of the merger is subject to customary closing conditions, including receipt ofregulatory approvals. See "Item IA. Risk Factors" and Note 3 of the Notes to Consolidated Financial Statements, "Pending Merger," for additional information.
OPERATIONS General As noted above, we supply electric energy at retail to customers in Kansas. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas, and have contracts for the sale or purchase of wholesale electricity with other utilities.
Following *is the percentage of our revenues by customer classification. Classification of customers as residential, commercial and industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification.
Year Ended December 31, 2016 2015 2014 Residential ................. . 33% 31% 31%
Commercial .............. .. 29% 29% 28%
Industrial. ................... . 16% 16% 16%
Wholesale .................. . 12% 13% 15%
Transmission ............ .. 9% 10% 9%
Other ......................... .. 1% 1% 1%
Total. ..................... . 100% 100% 100%
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The percentage of our retail electricity sales by customer class was as follows:
Year Ended December 31, 2016 2015 2014 Residential ................. . 33% 33% 34%
Commercial ............... . 39% 39% 38%
Industrial.. .................. . 28% 28% 28%
Total. ..................... . 100% 100% 100%
Generating Capability and Firm Capacity Purchases We have 6,292 megawatts (MW) of generating capability in service. See "Item 2. Properties" for additional information about our generating units. Further, we purchase electricity pursuant to long-term contracts from renewable generation facilities with an installed design capacity of 1,231 MW. Our generating capability and net generation by source as of December 31, 2016, are summarized below.
Capability Percent of Net Generation Percent of Total Source (MW) Total Capability (MWh) Net Generation Coal .................................. 3,235 43% 15,902,924 63%
Nuclear ............................. 551 7% 3,875,637 16%
Natural gas/diesel ............. 2,357 32% 1,724,276 7%
Renewable (a) ................... 1,380 18% 3,448,091 14%
Total .......................... 7,523 100% 24,950,928 100%
(a) Due to the intermittent nature of wind generation, 191 MW of net accredited generating capacity is associated with our wind generation facilities.
In March 2017, we expect to complete construction and start operation of Western Plains Wind Farm, a wind generating facility with a designed installed capability of 281 MW.
Our aggregate 2016 peak system net load of 5,184 MW occurred in July 2016. Our net accredited generating capacity, combined with firm capacity purchases and sales and potentially interruptible load, provided a capacity margin of 17% above system peak responsibility at the time of our 2016 peak system net load, which satisfied Southwest Power Pool, Inc. (SPP) planning requirements.
Under wholesale agreements, we provide firm generating capacity to other entities as set forth below.
Utility (a) Capacity (MW) Expiration Midwest Energy, Inc........................................ 120 May2017 Midwest Energy, Inc........................................ 35 May 2017 Mid-Kansas Electric Company, LLC............... 172 January 2019 Midwest Energy, Inc. (b ).................................. 115 May 2022
. Kansas Power Pool ............ ...... ........ ... ............. 59 December 2022 Midwest Energy, Inc........................................ 150 May 2025 Total 651 (a) Under a wholesale agreement that expires in May 2039, we provide base load capacity to the city of McPherson, Kansas, and in return the city provides peaking capacity to us. During 2016, we provided approximately 90 MW to, and received approximately 147 MW from, the city. The amount of base load capacity provided to the city is based on a fixed percentage of its annual peak system load. The city is a full requirements customer of Westar Energy. The agreement for the city to provide capacity to us is treated as a capital lease.
(b) Effective June 2017.
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Fuel Matters The effectiveness of a fuel to produce heat is measured in British thermal units (Btu). The higher the Btu content of a fuel, the smaller the volume of fuel that is required to produce a given amount of electricity. We measure the quantity of heat consumed during the generation of electricity in millions of British thermal units (MMBtu).
The table below provides our weighted average cost of fuel, including transportation costs.
2016 2015 2014 PerMMBtu:
Nuclear ................................. $ 0.68 $ 0.66 $ 0.66 Coal ...................................... 1.80 1.77 1.80 Natural gas ............................ 3.24 3.64 5.71 Diesel. ................................... 11.51 15.55 21.31 All generating stations .......... 1.76 1.74 1.90 Per MWh Generation:
Nuclear ................................. $ 6.91 $ 6.72 $ 6.79 Coal ...................................... 19.71 19.78 20.04 Natural gas/diesel ................. 31.80 37.16 62.84 All generating stations .......... 18.37 18.44 20.27 Our wind production, which produced 14% of our total generation, has no associated fuel costs and is, therefore, not included in the table above.
Fossil Fuel Generation Coal Jeffrey Energy Center (JEC): The three coal-fired units at JEC have an aggregate capacity of2,l 78 MW, of which we own or consolidate through a variable interest entity (VIE) a combined 92% share, or 2,004 MW. We have a long-term coal supply contract with Alpha Natural Resources, Inc. to supply coal to JEC from surface mines located in the Powder River Basin (PRB) in Wyoming. The contract contains a schedule of minimum annual MMBtu quantities or assesses a charge to the extent the minimum quantities are not achieved. All of the coal used at JEC is purchased under this contract, which expires December 31, 2020. The contract provides for price escalation based on certain costs of production. The price for quantities purchased in excess of the scheduled annual minimum is subject to renegotiation every five years to provide an adjusted price for the ensuing five years that reflects the market prices at the time of renegotiation. The most recent price adjustment was effective January 1, 2013.
The BNSF Railway Company (BNSF) and Union Pacific Railroad Company transport coal to JEC under a long-term rail transportation contract. The contract term continues through December 31, 2020, at which time we plan to enter into a new contract. The contract provides for minimum annual deliveries or assesses a charge to the extent the minimum deliveries are not achieved. The contract price is subject to price escalation based on certain costs incurred by the railroads.
La Cygne Generating Station (La Cygne): The two coal-fired units at La Cygne have an aggregate generating capacity of 1,384 MW. Our share of the units is 50%, or 692 MW, of which we either own directly or consolidate through a VIE. La Cygne uses primarily PRB coal but one of the two units also uses a small portion of locally-mined coal. The operator of La Cygne, Kansas City Power & Light Company (KCPL), arranges coal purchases and transportation services for La Cygne.
Approximately 100% and 30% of La Cygne 's PRB coal requirements are under contract for 2017 and 2018, respectively.
About 90% and 100% of those commitments under contract are fixed price for 2017 and 2018, respectively. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market.
All of the La Cygne PRB coal is transported under KCPL's rail transportation agreements with BNSF through 2018 and Kansas City Southern Railroad through 2020. These contracts provide for minimum annual deliveries or assess a charge to the extent the minimum deliveries are not achieved.
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Lawrence and Tecumseh Energy Centers: Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 539 MW. We purchase PRB coal for these energy centers under a contract with Arch Coal, Inc. that provides for 100% of the coal requirements for these facilities through 2017. The contract provides for minimum annual deliveries or assesses a charge to the extent the minimum deliveries are not achieved. BNSF transports coal for these energy centers under a contract that expires in December 2020.
Natural Gas We use natural gas as a primary fuel at our Gordon Evans, Murray Gill, Hutchinson, Spring Creek and Emporia Energy Centers and at the State Line facility. We can also use natural gas as a supplemental fuel in the coal-fired units at Lawrence and Tecumseh Energy Centers. Natural gas accounted for approximately 7% of the total l\1l\18tu of fuel we consumed and approximately 14% of our total fuel expense in 2016. From time to time, we may enter into contracts, including the use of derivatives, in an effort to manage the cost of natural gas. For additional information about our exposure to commodity price risks, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."
We maintain a natural gas transportation arrangement for Hutchinson Energy Center with Kansas Gas Service. The agreement has historically expired on April 30 of each year and is renegotiated for an additional one-year term. We meet a portion of our natural gas transportation requirements for Gordon Evans, Murray Gill, Lawrence, Tecumseh and Emporia Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Gas Pipeline (SSCGP).
We meet all of the natural gas transportation requirements for the State Line facility through a :firm transportation agreement with SSCGP. The firm transportation agreement that serves Gordon Evans and Murray Gill Energy Centers expires in April 2020, and the agreement for Lawrence and Tecumseh Energy Centers expires in April 2030. The agreement for the State Line facility extends through October 2022, while the agreement for Emporia Energy Center is in place until December 2028, and is renewable for five-year terms thereafter. We meet all of the natural gas transportation requirements for Spring Creek Energy Center through an interruptible month-to-month transportation agreement with ONEOK Gas Transportation, LLC.
Diesel We use diesel to start some of our coal generating stations, as a primary fuel in the Hutchinson No. 4 combustion turbine and in our diesel generators. We purchase No. 2 diesel in the spot market. We maintain quantities in inventory that we believe will allow us to facilitate economic dispatch of power and satisfy emergency requirements. We do not use significant amounts of diesel in our operations.
Nuclear Generation General Wolf Creek is a 1, 172 MW nuclear power plant located near Burlington, Kansas. KGB owns a 4 7% interest in Wolf Creek, or 551 MW. Wolf Creek's operating license, issued by the NRC, is effective until 2045. Wolf Creek Nuclear Operating Corporation, an operating company owned by each of the plant's owners in proportion to their ownership share of the plant, operates the plant. The plant's owners pay operating costs proportionate to their respective ownership share.
Fuel Supply Wolf Creek has on hand or under contract all of the uranium and conversion services needed to operate through March 2027. The owners also have under contract 97% of the uranium enrichment and all of the fabrication services required to operate Wolf Creek through March 2027 and September 2025, respectively. All such agreements have been entered into in the ordinary course of business.
Operations and Regulation Plant performance, including extended or unscheduled shutdowns of Wolf Creek, could cause us to purchase replacement power, rely more heavily on our other generating units and/or reduce amounts of power available for us to sell in the wholesale market. Plant performance also affects the degree of regulatory oversight and related costs.
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Wolf Creek normally operates on an 18-month planned refueling and maintenance outage schedule. As authorized by our regulators, incremental maintenance costs of planned refueling and maintenance outages are deferred and amortized ratably over the period between planned refueling and maintenance outages. In the fall of2016, Wolf Creek underwent a planned refueling and maintenance outage. Our share of the outage costs was approximately $24.2 million. The next refueling and maintenance outage is planned for the spring of2018.
The NRC evaluates, monitors and rates various inspection findings and performance indicators for Wolf Creek based on safety significance. Although not expected, the NRC could impose an unscheduled plant shutdown due to security or safety concerns. Those concerns need not be related to Wolf Creek specifically, but could be due to concerns about nuclear power generally or circumstances at other nuclear plants in which we have no ownership.
See Note 14 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies," for additional information regarding our nuclear operations.
Wind Generation Wind is our primary source ofrenewable energy. As of December 31, 2016, we owned approximately 149 MW of designed installed wind capability and had under contract the purchase of wind energy produced from approximately 1,225 MW of designed installed wind capability. In March 2017, we expect to complete construction and start operation of Western Plains Wind Farm, a wind generating facility with a designed installed capability of 281 MW.
Purchased Power In addition to generating electricity, we also purchase power. Factors that cause us to purchase power include contractual arrangements, planned and unscheduled outages at our generating plants, favorable wholesale energy prices compared to our costs of production, weather conditions and other factors. In 2016, purchased power comprised approximately 32% of our total fuel and purchased power expense. Our weighted average cost of purchased power per Megawatt hour (MWh) was $24.82 in 2016, $27.28 in 2015 and $37.26 in 2014.
Transmission Regional Transmission Organization The Federal Energy Regulatory Commission (FERC) requires owners of regulated transmission assets to allow third parties nondiscriminatory access to their transmission systems. We are a member of the SPP RTO and transferred the functional control of our transmission system, including the approval of transmission service, to the SPP. The SPP coordinates the operation of our transmission system within an interconnected transmission system that covers all or portions of 14 states. The SPP collects revenues for the use of each transmission owner's transmission system. Transmission customers transmit power purchased and generated for sale or bought for resale in the wholesale market throughout the entire SPP system. Transmission capacity is sold on a first come/first served non-discriminatory basis. All transmission customers are charged rates applicable to the transmission system in the zone where energy is delivered, including transmission customers that may sell power inside our certificated service territory. The SPP then distributes as revenue to transmission owners the amounts it collects from transmission users less an amount it retains to cover administrative expenses.
Southwest Power Pool Integrated Marketplace We participate in the SPP Integrated Marketplace (IM), which is similar to organized power markets currently operating in other RTOs. The IM impacts how we commit and sell the output from our generation facilities and buy power to meet the needs of our customers. The SPP has the authority to start and stop generating units participating in the market and selects the lowest cost resource mix to meet the needs of the various SPP customers while ensuring reliable operations of the transmission system.
Transmission Investments We own a 50% interest in Prairie Wind Transmission, LLC (Prairie Wind), which is a joint venture between us and Electric Transmission America, LLC, which itself is a joint venture between affiliates of American Electric Power Company, Inc. and Berkshire Hathaway Energy Company. In 2014, Prairie Wind completed construction on, and energized, a 108-mile 345 kV double-circuit transmission line that is now being used to provide transmission service in the SPP.
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In 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid, along with the corresponding process for allocating the costs of such expansions. Among other things, Order No. 1000 sets forth a framework pursuant to which certain transmission projects that are approved by the RTOs become subject to a competitive bidding process whereby qualified entities can build and own the transmission facilities, even if the entities are not located in the service territory covered by the transmission facilities. This process is complicated, and is governed by Order No. 1000 and the tariff each RTO has with the FERC. In addition, notwithstanding the competitive processes created by Order No. 1000, incumbent utilities maintain a right of first refusal for certain transmission projects, depending on, among other things, the date by which the projects must be completed, the size of the projects and whether the incumbent utilities have pre-existing facilities that are being impacted by the projects.
We are participating in tran~mission planning activities and implementation of Order No. 1000 in areas where we believe it makes sense to do so. We believe we have opportunities to develop transmission infrastructure, including projects pursuant to which we, as the incumbent, have a right of first refusal and those projects that are subject to the Order No. 1000 competitive processes. However, due in part to the long-term nature of transmission planning activities, the uncertainty surrounding the implementation of the Clean Power Plan (CPP) and its impact .on the region's generating fleet and the infancy of implementation of Order No. 1000, we are unable to predict the impact of Order No. 1000. Accordingly, in our forecasted capital expenditure table, there are no dollars of investment associated with Order No. 1000 projects. In addition, the merger will change the manner and extent to which we continue to participate in the Order No. 1000 process.
Regulation and Our Prices Kansas law gives the Kansas Corporation Commission (KCC) general regulatory authority over our retail prices, extensions and abandonments of service and facilities, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction ofFERC, which has authority over wholesale electricity sales, including prices, the transmission of electric power and the issuance of some securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. Regulatory authorities have established various methods permitting adjustments to our prices for the recovery of costs., For portions of our cost of service, regulators allow us to adjust our prices periodically through the application of a formula that tracks changes in our costs, which reduces the time between making expenditures or investments and reflecting them in the prices we charge customers. However, for the remaining portions of our cost of service, we must file a general rate review, which lengthens the period of time between when we make and recover expenditures and a return on our investments. See Note 4 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation," for information regarding our rate proceedings with the KCC and FERC.
Environmental Matters We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting our operations are overlapping, complex, subject to changes, have become more stringent over time and are expensive to implement. Such laws and regulations relate primarily to air quality, water quality, the use of water and the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, including coal combustion residuals
( CCRs ). These laws and regulations oftentimes require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for new, existing or modified facilities. Ifwe fail to comply with such laws, regulations and permits, or fail to obtain and maintain necessary permits, we could be fined or otherwise sanctioned by regulators, and such fines or the cost of sanctions may not be recoverable in our prices. We have incurred and will continue to incur capital and other expenditures to comply with environmental laws and regulations.
See "Item IA. Risk Factors" and Notes 4 and 14 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation - KCC Proceedings - Environmental Costs" and "Commitments and Contingencies -'Environmental Matters,"
respectively, for more information regarding environmental trends, risks and laws and regulations.
Safety and Health Regulation The safety and health of our employees is vital to our business. We are subject to a number of federal and state laws and regulations, including the Occupational Safety and Health Act of 1970. We have measures in place to promote the safety and health of our employees and to monitor our compliance with such laws and regulations:
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Information Technology We rely upon information technology networks and systems to process, transmit and store electronic information, and to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions and the invoicing and collection of payments from our customers. These networks and systems are in some cases owned or managed by third-party service providers. Cybersecurity breaches, criminal activity, terrorist attacks and other disruptions to our information technology infrastructure, including infrastructure owned by third-parties we utilize, could interfere with our operations, could expose -us or our customers or employees to a risk of loss and could expose us to liability or regulatory penalties or cause us reputational damage or other harm to our business. We have taken
.measures to secure our network and systems, but such measures may not be sufficient, especially due to the increasing sophistication of cyberattacks. See "Item lA. Risk Factors" for additional information.
SEASONALITY Our electricity sales and revenues are seasonal, with the third quarter typically accounting for the greatest of each. Our electricity sales are impacted by weather conditions, the ec01wmy of our service territory and other factors affecting customers' demand for electricity.
EMPLOYEES As of February 15, 2017, we had 2,254 employees, 1,157 of which were covered by a contract with Locals 304 and 1523 of the International Brotherhood of Electrical Workers that extends through June 30, 2018.
ACCESS TO COMPANY INFORMATION Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K are available free of charge either on oll.r Internet website at www.westarenergy.com or through requests addressed to our investor relations department. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. The information contained on our Internet website is not part of this document.
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EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During the Past Five Years Mark A. Ruelle 55 Director, President and Chief Executive Officer (since August 2011)
Bruce A. Akin 52 Senior Vice President, Power Delivery Westar Energy, Inc.
(since January 2015) Vice President, Power Delivery (February 2012 to December 2014)
Vice President, Operations Strategy and Support (July 2007 to February 2012)
Jerl L. Banning 56 Senior Vice President, Operations Support Westar Energy, Inc.
and Administration Vice President, Human Resources and IT (January 2014 (since January 2015) to December 2014)
Vice President, Human Resources (February 2010 to December 2013)
John T. Bridson 47 Senior Vice President, Generation and Westar Energy, Inc.
Marketing Vice President, Generation (February 2011 to December (since January 2015) 2014)
Gregory A. Greenwood 51 Senior Vice President, Strategy (since August 2011)
Anthony D. Somma 53 Senior Vice President, Chief Financial Officer and Treasurer (since August 2011)
Larry D. Irick 60 Vice President, General Counsel and Corporate Secretary (since February 2003)
Kevin L. Kongs 54 Vice President, Controller Westar Energy, Inc.
(since November 2013) Assistant Controller (October 2006 to November 2013)
Executive officers serve at the pleasure of the board of directors. There are no family relationships among any of the executive officers, nor any arrangements or understandings between any executive officer and other persons pursuant to which he was appointed as an executive officer.
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ITEM lA. RISK FACTORS We operate in market and regulatory environments that involve significant risks, many of which are beyond our control. In addition to other information in this Form 10-K, including "Item 1. Business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and in other documents we file with the SEC from time to time, the following factors may affect our results of operations, our cash flows and the value of our equity and debt securities. These factors may cause results to differ materially from those expressed in any forward-looking statements made by us or on our behalf. The factors listed below are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.
Risks Relating to our Business Weather conditions, including mild and severe weather, may adversely impact our consolidated financial results.
Weather conditions directly influence the demand for electricity. Our customers use electricity for heating in winter months and cooling in summer months. Because of air conditioning demand, typically we produce our highest revenues in the third quarter. Milder temperatures reduce demand for electricity and have a corresponding impact on our revenues. Unusually mild weather in the future could adversely affect our consolidated financial results.
In addition, severe weather conditions can produce storms that can inflict extensive damage to our equipment and facilities, which can require us to incur additional operating and maintenance expense and additional capital expenditures. Our prices may not always be adjusted timely or adequately to reflect these higher costs. Additionally, because many of our power plants use water for cooling, persistent or severe drought conditions could result in limited power production. High water conditions can also impair planned deliveries of fuel to our plants.
Our prices are subject to regulatory review and may not prove adequate to recover our costs and provide a fair return.
We must obtain from state and federal regulators the authority to establish terms and prices for our services. The KCC and, for most of our wholesale customers, FERC, use a cost-of-service approach that takes into account operating expenses, fixed obligations and recovery of and return on capital investments. Using this approach, the KCC and FERC set prices at levels calculated to recover such costs and a permitted return on investment. Except for wholesale transactions for which the price is not so regulated, and except to the extent the KCC and FERC permit us to modify our prices through the application of a formula that tracks changes in certain of our costs, our prices generally remain fixed until changed following a rate review.
Further, the adjustments may be modified, limited or eliminated by regulatory or legislative actions. We may apply to change our prices or intervening parties may request that our prices be reviewed for possible adjustment.
Rate proceedings through which our prices and terms of service are determined typically involve numerous parties including electricity consumers, consumer advocates and governmental entities, some of whom take positions that are adverse to us. In addition, regulators' decisions may be appealed to the courts by us or other parties to the proceedings. These factors may lead to uncertainty and delays in obtaining or implementing changes to our prices or terms of service. There can be no assurance that our regulators will find all of our costs to have been prudet;itly incurred. A finding that costs have been imprudently incurred can lead to disallowance of recovery for those costs. Further, the prices approved by the applicable regulatory body may not be sufficient for us to recover our costs and to provide for an adequate return on and of capital investments.
We cannot predict the outcome of any rate review or the actions of our regulators. The outcome of rate proceedings, or delays in implementing price changes to reflect changes in our costs, could have a material effect on our consolidated financial results.
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Our costs of compliance with environmental laws and regulations, including those relating to GHG emissions, are significant, and the future costs of compliance with environmental laws and regulations could adversely impact our operations and consolidated financial results.
We are subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources and health and safety. Compliance with these legal requirements, which change frequently and have tended to become more restrictive, requires us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of air and water quality control equipment and purchases of air emission allowances and/or offsets. These laws and regulations oftentimes require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for new, existing or modified facilities. If we fail to comply with such laws, regulations and permits, or fail to obtain and maintain necessary permits, we could be fined or otherwise sanctioned by regulators, and such fines or the cost of sanctions may not be recoverable in our prices.
Costs of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our prices, could adversely impact our operations and/or consolidated financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated or the number and types of assets we operate increases. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our prices, due to our inability to predict the requirements and timing of implementation of environmental rules or regulations. See "Item 1. Business -
Environmental Matters," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -
Executive Summary - Current Trends and Uncertainties - Environmental Regulation" and Notes 4 and 14 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation - KCC Proceedings - Environmental Costs" and "Commitments and Contingencies - Environmental Matters," respectively, for additional information. In addition, compliance with environmental laws and regulations could alter the manner in which we had planned to manage our assets, which in turn could require us to retire assets earlier than expected or record asset retirement obligations (AROs ).
In addition, we combust large amounts of fossil fuels as we produce electricity. This results in significant emissions of carbon dioxide (C0 2) and other GHGs through the operation of our power plants. Federal legislation regulates the emission of GHGs and numerous states and regions have adopted programs to stabilize or reduce GHG emissions. The Environmental Protection Agency (EPA) regulates GHGs under the Clean Air Act. In October 2015, the EPA published a rule establishing new source performance standards that limit C02 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per MWh depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate C0 2 emissions from existing power plants. The standards for existing plants are known as the CPP. Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including us, and in February 2016 the U.S. Supreme Court temporarily stayed implementation of the CPP. See Note 14 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies - Environmental Matters" for additional information. We believe these rules, if implemented, could have a material impact on our operations and consolidated financial results.
Further, in the course of operating our coal generation plants, we produce CCRs, including fly ash, gypsum and bottom ash, which we must handle, recycle, process or dispose of. We historically have recycled some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which will require additional CCR handling, processing and storage equipment and potential closure of certain ash disposal areas. We have recorded, and may need to record additionalAROs, in connection with the rule. See Note 14 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies - Environmental Matters" for additional information. The impact of this rule on our operations and consolidated financial results could be material.
We could be subject to penalties as a result of mandatory reliability standards, which could adversely affect our consolidated financial results.
As a result of the Energy Policy Act of2005, owners and operators of the bulk power transmission system, including Westar Energy and KGE, are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by FERC. Ifwe were found to be out of compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which we might not be able to recover in the prices we charge our customers. This could have a material adverse effect on our consolidated financial results.
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Adverse economic conditions could adversely impact our operations and consolidated financial results.
Our operations are impacted by economic conditions. Adverse economic conditions, including a prolonged recession, no or low economic growth or capital market disruptions, may:
reduce demand for our service; increase delinquencies or non-payment by customers; adversely impact the financial condition of suppliers, which may in turn limit our access to inventory, including coal and natural gas, or capital equipment or increase our costs; and increase deductibles and premiums and result in more restrictive policy terms under insurance policies regarding risks we typically insure against, or make insurance claims more difficult to collect.
A number of commercial and industrial customers have geographically dispersed facilities, and localized factors, including economic conditions, governmental or other incentives and other factors that influence customer operating or capital expenses, which may cause these customers to curtail or eliminate operations at facilities in our service territory and move them to other facilities with competitive advantages. In addition, unexpectedly strong economic conditions can result in increased costs and shortages. Any of the aforementioned events, and others we may not be able to identify, could have an adverse impact on our consolidated financial results.
We are exposed to various risks associated with the ownership and operation of Wolf Creek, any of which could adversely impact our consolidated financial results.
Through KGE's ownership interest in Wolf Creek, we are subject to the risks of nuclear generation, which include:
the risks associated with storing, handling and disposing of radioactive materials and the current lack of a long-term off-site disposal solution for radioactive materials; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; uncertainties with respect to the technological and financial aspects of decommissioning Wolf Creek at the end of its life; and costs of measures associated with public safety.
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements enacted by the NRC could necessitate substantial capital expenditures at Wolf Creek.
An incident at Wolf Creek could have a material impact on our consolidated financial results. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities anywhere in the world could result in increased regulation of the industry or a retrospective premium assessment under our nuclear insurance coverage, both of which could increase Wolf Creek's costs and impact our consolidated financial results. Such events could also result in a shutdown of Wolf Creek.
Significant decisions about capital investments are based on forecasts of long-term demand for energy incorporating assumptions about multiple, uncertain factors. Our actual experience may differ significantly from our assumptions, which may adversely impact our consolidated financial results.
We attempt to forecast demand to determine the timing and adequacy of our energy and energy delivery resources.
Long-term forecasts involve risks because they rely on assumptions we make concerning uncertain factors including weather, technological change, environmental and other regulatory requirements, economic conditions, social pressures and the responsiveness of customers' electricity demand to conservation measures and prices. Both actual future demand and our ability to satisfy such demand depend on these and other factors and may vary materially from our forecasts. If our actual experience varies significantly from our forecasts, we could be required to record AROs or impairment charges, and our consolidated fmancial results may be adversely impacted.
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Our planned capital investment for the next few years is large in relation to our size, subjecting us to significant risks.
Our anticipated capital expenditures for 2017 through 2019 are approximately $2.3 billion. In addition to risks discussed above associated with recovering capital investments through our prices, and risks associated with our reliance on the capital markets and short-term credit to fund those investments, our capital expenditure program poses risks, including, but not necessarily limited to:
shortages, disruption in the delivery and inconsistent quality of equipment, materials and labor; contractor or supplier non-performance; delays in or failure to receive necessary permits, approvals and other regulatory authorizations; impacts of new and existing laws and regulations, including environmental and health and safety laws, regulations and permit requirements; adverse weather; unforeseen engineering problems or changes in project design or scope; environmental and geological conditions; and unanticipated cost increases with respect to labor or materials, including basic commodities needed for our infrastructure such as steel, copper and aluminum.
These and other factors, or any combination of them, could cause us to defer or limit our capital expenditure program and could adversely impact our consolidated financial results.
Our ability to fund our capital expenditures and meet our working capital and liquidity needs may be limited by conditions in the bank and capital markets, by our credit ratings or the market price of Westar Energy's common stock.
Further, capital market conditions can cause fluctuations in the values of assets set aside for employee benefit obligations and the Wolf Creek nuclear decommissioning trust (NDT) and may increase our funding requirements related to these obligations.
To fund our capital expenditures and for working capital and liquidity, we rely on access to capital markets and to short-term credit. Disruption in capital markets, deterioration in the financial condition of the financial institutions on which we rely, any credit rating downgrade or any decrease in the market price of Westar Energy's common stock may make capital more difficult and costly for us to obtain, may restrict liquidity available to us, may require us to defer or limit capital investments or impact operations or may reduce the value of our financial assets. These could adversely impact our business and consolidated fmancial results, including our ability to pay dividends and to make investments or undertake programs necessary to meet regulatory mandates and customer demand.
Further, we have significant future fmancial obligations with respect to employee benefit obligations and the Wolf Creek NDT. The value of the assets needed to meet those obligations are subject to market fluctuations and will yield uncertain returns, which may fall below our expectations for meeting our obligations. Additionally, inflation and changes in interest rates impact the value of future liabilities. In general, when interest rates decline, the value of future liabilities increase. While the KCC allows us to implement a regulatory accounting mechanism to track certain of our employee benefit plan expenses, this mechanism does not allow us to make automatic price adjustments. Only in future rate proceedings may we be allowed to adjust our prices to reflect changes in our funding requirements. Further, the tracking mechanism for these benefit plan expenses is part of our overall rate structure, and as such, it is subject to KCC review and may be modified, limited or eliminated in the future. If these assets are not managed successfully, our consolidated financial results and cash flows could be adversely impacted.
Physical and cybersecurity breaches, criminal activity, terrorist attacks and other disruptions to our facilities or our information technology infrastructure could interfere with our operations, expose us or our customers or employees to a risk of loss and expose us to liability or regulatory penalties or cause reputational damage and other harm to our business.
We rely upon information technology networks and systems to process, transmit and store electronic information, and to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology networks and systems to record, process and summarize fmancial information and results of operations for internal reporting purposes and to comply with fmancial reporting, legal and tax requirements. These networks and systems are in some cases owned or managed by third-party service providers. In the ordinary course of business, we collect, store and transmit sensitive data including operating information, proprietary business information belonging to us and third parties and personal information belonging to our customers and employees.
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Our information technology networks and infrastructure, as well as the networks and infrastructure belonging to third-party service providers that we utilize, may be vulnerable to damage, disruptions or shutdowns due to attacks or breaches by hackers or other unauthorized third parties; error or malfeasance by one or more of our or our service providers' employees; software or hardware upgrades; additions or replacements; malicious software code; telecommunication failures; natural disasters or other catastrophic events. The occurrence of any of these events could, among other things, impact the reliability or safety of our generation, transmission and distribution systems; result in the erasure of data or render our equipment unusable; impact our ability to conduct business in the ordinary course; expose us and our customers, employees and vendors to a risk of loss or misuse of information; and result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. We can provide no assurance that we will identify and remedy all security or system vulnerabilities or that unauthorized access or error will be identified and remedied.
Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. Our facilities could be direct targets or indirect casualties of such attacks. The effects of such attacks could include disruption to our generation, transmission and distribution systems or to the electrical grid in general, and could increase the cost of insurance coverage or result in a decline in the U.S. economy. Any of the foregoing could adversely impact our operations or financial results.
Equipment failures and other events beyond our control may cause extended or unplanned plant outages, which may adversely impact our consolidated financial results.
The generation, distribution and transmission of electricity require the use of expensive and complicated equipment, much of which is aged, and all of which requires significant ongoing maintenance. Our power plants and equipment are subject to extended outages because of equipment failure, weather, transmission system disruption, operator error, contractor or subcontractor failure and other factors. In such events, we must either produce replacement power from our other plants, which may be less efficient or more expensive to operate, purchase power from others at unpredictable and potentially higher costs in order to meet our sales obligations, or suffer outages. Such events could also limit our ability to make sales to customers.
Therefore, the occurrence of extended or unplanned outages could adversely affect our consolidated financial results.
We may not be able to fully utilize net operating loss, tax credit or other tax carryforwards, or realize expected production tax credits related to our wind farms, all of which could adversely impact our consolidated financial results and liquidity.
Our income tax obligations have been reduced due to the continued use of bonus depreciation provisions that allow for an acceleration of deductions for tax purposes and recent IRS guidance on tax deductions for repairs. We estimate our ability to use tax benefits, including those in the form of net operating loss, tax credit and other tax carryforwards, that are recorded as deferred tax assets on our balance sheets. A disallowance of these tax benefits resulting from a legislative change or adverse determination by a taxing jurisdiction could have an adverse impact on our consolidated fmancial results and liquidity.
Additionally, changes in corporate income tax rates or policy changes, as well as any inability to generate enough taxable income in the future to use all of our tax benefits before they expire, could have an adverse impact on our consolidated fmancial results and liquidity.
In addition, we operate wind farms that generate production tax credits for us to use to reduce our federal income tax obligations. The amount of production tax credits we earn is dependent on the level of electricity output generated by our wind farms and the applicable tax credit rate. A variety of operating and economic parameters, including transmission constraints, adverse weather conditions and breakdown or failure of equipment, could significantly reduce the production tax credits generated by our wind farms, which could have an adverse impact on our consolidated fmancial results.
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Our regulated business model may be threatened by technological advancements that could adversely affect our financial condition and results of operations.
Significant technological advancements have taken and will continue to take place in the electric industry, including advancements related to self-generation and distributed energy technologies such as fuel cells, micro turbines, wind turbines and solar cells, as well as related to the storage of energy produced by these systems. Adoption of these technologies may increase because of advancements or govermnent subsidies reducing the cost of generating or storing electricity through these technologies to a level that is competitive with our current methods of generating electricity. There is also a perception that generating or storing electricity through these technologies is more environmentally friendly than generating electricity with fossil fuels. Increased adoption of these technologies could reduce electricity demand and the pool of customers from whom fixed costs are recovered, resulting in under recovery of our fixed costs. Increased self-generation and the related use of net energy metering, which allows self-generating customers to receive bill credits for surplus power, could put upward price pressure on our remaining customers. If we were unable to adjust our prices to reflect reduced electricity demand and increased self-generation and net energy metering, our financial condition and results of operations could be adversely affected.
Risks Relating to the Pending Merger We cannot provide any assurance that the merger will be completed.
The closing of the merger is subject to certain conditions, including, among others, (i) receipt of all required regulatory approvals, including from the FERC, the NRC and the KCC (provided that such approvals do not result in a material adverse effect on Great Plains Energy and its subsidiaries after giving effect to the merger), (ii) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the merger, (iii) the continued effectiveness of the Great Plains Energy registration statement on Form S-4 that was filed with the SEC, (iv) the absence of any material adverse effect with respect to us and our subsidiaries and (v) subject to certain materiality exceptions, the accuracy of the representations and warranties of, and compliance and covenants by, each of the parties to the merger agreement.
Although we and Great Plains Energy have agreed in the merger agreement to use our reasonable best efforts to take, or cause to be taken, all actions, and do, or cause to be done, and assist and cooperate with the other parties in doing, all things necessary to cause the conditions to the closing of the merger to be satisfied or to effect the closing of the merger as promptly as reasonably practicable, the conditions to the merger may not be satisfied and the merger agreement could be terminated. In addition, satisfying the conditions to the merger may take longer than, and could cost more than, we and Great Plains Energy expect. The occurrence of any of these events individually or in combination may adversely affect the benefits that we and Great Plains Energy expect to achieve from the merger and the trading price of our common stock.
The merger is subject to the receipt of consent or approval from governmental entities that could delay the completion of the merger or impose conditions that could have a material adverse effect on the combined company.
Completion of the merger is conditioned upon receipt of consents, orders, approvals or clearances, as required, from, among others, the FERC, the NRC and the KCC (provided that such approvals do not result in a material adverse effect on Great Plains Energy and its subsidiaries after giving effect to the merger).
On June 28, 2016, we and Great Plains Energy filed a joint application with the KCC requesting approval of the merger. Unless otherwise agreed to by the applicants, Kansas law imposes a 300-day time limit on the KCC's review of the joint application. On September 27, 2016, KCC issued an order setting a procedural schedule for the application, with a KCC order date of April 24, 2017.
On December 16, 2016, KCC staff and its representatives filed testimony that, among other things, objected to the proposed merger, stated that no changes could be made to the joint application filed by us and Great Plains Energy that would satisfy the KCC staff and recommended that the KCC reject the merger. A number of intervening parties also filed testimony against approval of the merger.
On January 9, 2017, we and Great Plains Energy filed rebuttal testimony in response to KCC staff and the other intervenors explaining why we and Great Plains Energy believe the joint application meets the KCC's merger standards and why the merger is in the public interest. An evidentiary hearing was held at the KCC from January 30, 2017 to February 7, 2017.
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In addition, there are two open dockets in Missouri related to the merger. In the first docket, Great Plains Energy sought approval from the Public Service Commission of the State of Missouri (MPSC) to waive certain affiliate transaction rules following the closing of the merger. In this docket, on October 12, 2016, and on October 26, 2016, the MPSC staff and the Office of Public Counsel (OPC), respectively, announced that each had entered into a Stipulation andAgreement with Great Plains Energy that, among other things, provided that MPSC staff and the OPC would not file a complaint, or support another complaint, to assert that the MPSC has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the MPSC. Regarding the second docket, on October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the MPSC seeking to have the MPSC assert jurisdiction over the merger, and various parties have intervened in these complaints. The MPSC dismissed the complaint against us on December 6, 2016, but the complaint against Great Plains Energy remains open. On February 16, 2017, the MPSC indicated at a public meeting that it would assert jurisdiction over the merger, and it requested that an order be prepared to assert jurisdiction. Accordingly, we believe Great Plains Energy will also need approval of the MPSC in order to consummate the merger.
On July 11, 2016, we and Great Plains filed a joint application with the FERC requesting approval of the merger.
Approval of the merger application requires action by the FERC commissioners because it is a contested application. The Federal Power Act requires a quorum of three or more commissioners to act on a contested application. Following the resignation of the FERC Chairman effective February 3, 2017, the FERC commission is comprised only of two commissioners and is therefore unable to act on the application. A new commissioner must be appointed by the President of the United States, with the advice and consent of the United States Senate, before FERC will be able to act on the application. If the FERC commissioners do not issue an order on the application within 180 days after the application was deemed complete because of the lack of a quorum, approval of the application may be deemed granted by operation of law, unless an order is issued extending the time for review. The FERC staff has authority to issue an order extending the period for review of the application. Under these circumstances, we do not believe it is likely that the FERC staff will allow approval of our application to be deemed granted. We are unable to predict when FERC will regain a quorum or how the change in commissioners will impact the review of the application.
In addition, completion of the merger is conditioned upon the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act). We and Great Plains Energy filed the antitrust notifications required under the HSR Act on September 26, 2016, and received early termination of the statutory waiting period under the HSR Act on October 21, 2016. Under the HSR Act, a new statutory waiting period will start one year from the date on which an existing waiting period expires, or October 21, 2017. Accordingly, ifthe merger has not closed prior to October 21, 2017, we and Great Plains Energy will need to re-file the necessary HSRAct notifications. Although the United States Department of Justice allowed the statutory waiting period under the HSRAct to terminate following our initial HSRAct notification, there can be no assurance that it would do so again, or that it would not impose burdensome terms or conditions on the merger that may prevent the merger from occurring or eliminate the potential benefits of the merger.
A substantial delay in obtaining satisfactory approvals or the imposition of unfavorable terms or conditions in connection with such approvals could adversely affect the business, financial condition or results of operations of us or Great Plains Energy or may result in the termination of the merger agreement. Failure to receive satisfactory approvals may also make any alternative future strategic transaction more challenging, which could in tum negatively impact the price of our common stock.
For additional information on the status of various approvals in connection with the pending merger, see Notes 4 and 14 of the Notes to Consolidated Financial Statements, "Pending Merger" and "Commitments and Contingencies," respectively.
Failure to complete the merger could negatively affect the trading price of our common stock and our future business and financial results.
Completion of the merger is not assured and is subject to risks. If the merger is not completed, it could negatively affect the trading price of our common stock and our future business and financial results, and could subject us to additional risks, including the following:
negative reactions from the financial markets, including declines in the price of our common stock due to the fact that the current price may reflect a market assumption that the merger will be completed; performance shortfalls and missed opportunities as a result of the diversion of our management's attention by the merger; and potential payments by us to Great Plains Energy for damages, or if the merger agreement is terminated under certain circumstances, a termination fee of $280.0 million.
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The anticipated benefits of combining the companies may not be realized.
We entered into the merger agreement with the expectation that the merger would result in various benefits, including, among other things, synergies, cost savings and operating efficiencies. However, the achievement of the anticipated benefits of the merger, including the synergies, cannot be assured or may take longer than expected to materialize. In addition, we may not be able to integrate our operations with Great Plains Energy's existing operations without encountering difficulties, including inconsistencies in standards, systems and controls, and without diverting management's focus and resources from ordinary business activities and opportunities. Any of the foregoing could have a material adverse effect on the combined company.
We will incur significant transaction and transition costs in connection with the merger.
We and Great Plains Energy expect to incur significant transaction and transition costs in connection with the consummation of the merger and the subsequent integration of the companies. Prior to consummation of the merger, we may also incur additional costs to m~intain employee morale and to retain key employees. Great Plains Energy will also incur significant fees and expenses relating to the financing arrangements in connection with the merger. These expenses could reduce or eliminate the savings that we expect to achieve from the merger, and accordingly, any net benefits may not be achieved in the near term or at all. These transaction and transition expenses may result in significant charges taken against earnings by us prior to completion of the merger and by the combined company following the completion of the merger.
We will be subject to business uncertainties and contractual restrictions while the merger is pending, which could adversely affect our business.
Uncertainty about the impact of the merger, including on employees and customers, may have an adverse effect on us and Great Plains Energy and, consequently, on the combined company. These uncertainties may impair our and Great Plains Energy's ability to attract, retain and motivate personnel, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships with us and/or Great Plains Energy. If employees depart, our business or the combined company's business could be harmed. In addition, the merger agreement restricts us, without the consent of Great Plains Energy, from taking specified actions until we complete the merger or the merger agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business.
Pending litigation against us and Great Plains Energy may adversely affect the combined company's business, financial condition or results of operations following the merger.
Following the announcement of the merger agreement, two putative class action lawsuits were filed in the District Court of Shawnee County, Kansas, against Westar Energy, the members of our board of directors and Great Plains Energy, alleging breaches of various fiduciary duties by the members of our board of directors in connection with the proposed merger and alleging that we and Great Plains Energy aided and abetted such alleged breaches of fiduciary duties. A third putative derivative lawsuit was filed in the District Court of Shawnee County, Kansas, against the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, alleging breaches of various fiduciary duties by members of our board of directors in connection with the proposed merger and alleging that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such alleged breaches of fiduciary duties. Among other remedies, the plaintiffs in each case sought to enjoin the merger and rescind the merger agreement, in addition to certain unspecified damages and reimbursement of costs. On September 21, 2016, the parties in the consolidated putative class action and the putative derivative complaint independently agreed to withdraw requests for injunctive relief and otherwise agreed in principle to dismissing the actions with prejudice and to providing releases. In the future the parties will prepare and present to the court for approval Stipulations of Settlement that will, if accepted by the court, settle the actions in their entirety. The outcome of litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains umesolved at the time the merger closes may adversely affect the combined company's business, financial condition or results of operation. See Note 16 of the Notes to Consolidated Financial Statements, "Legal Proceedings," for additional information.
The exchange of our common stock for Great Plains Energy common stock and cash will be a taxable transaction for U.S. Federal income tax purposes.
The exchange of our common stock for shares of Great Plains Energy common stock and cash will be a taxable transaction for U.S. federal income tax purposes. In general, U.S. shareholders will recognize gain or loss in an amount equal to the difference, if any, between ( 1) the sum of the fair market value of the Great Plains Energy common stock as of the effective time of the merger and the cash received and (2) such U.S. shareholder's adjusted tax basis in the Company's common stock exchanged therefor.
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ITEM 2. PROPERTIES Unit Capability (MW) By Owner (a)
Total Generation and Total Renewable Renewable Year Principal Westar Company Purchased Purchased Name Location Unit No. Installed Source Energy KGE Generation Power Power Renewable Generation:
Ness& Trego (a) 2015 Wind 199 199 Cedar Bluff Counties, KS Central Plafus Wichita County, KS (af 2009 Wind 99 99 99 Flat Ridge Barber County, KS (a) 2009 Wind 50 50 50 100 Ironwood Ford County, KS (a) 2012 Wind 168 168 Kay Wind Kay County, OK (a) 2015 Wind 200 200 l{ingman County,
- Kingman II . KS (a) 2016 Wind 103 Meridian Way Cloud County, KS (a) 2008 Wind 96 96 Ninnescah 'Pratt County, KS (a) 2016 Wind 208 208 Post Rock Ellsworth & Lincoln (a) 2012 Wind 201 201 Counties, KS Shawnee County, Landfill Rolling Meadows KS 2010 Gas 6 6 Western Plains FordCounty,KS (a) (b) 2017 Wind 281 281 281 Nuclear:
Wolf Creek Generating Station Burlington, KS 1 (c) 1985 Uranium - 551 551 551 (47%):
Coal:
Jeffrey Energy Center (92%): St. Marys, KS
- - -~
Steam Turbines 1 (c) 1978 Coal 524 146 670 670 2 (c) 1980 Coal 528 147 675 675 3 (c) 1983 Coal 516 143 659 659 La Cygne Station (50%): La Cygne, KS Steam Turbines 1 (c) 1973 Coal 368 368 368 2 (d) 1977 Coal 324 324 324 Lawrence Energy Center: Lawrence, KS Steam Turbines 4 1960 Coal 108 108 108 5 1971 Coal 370 370 370 Tecumseh Energy Center: Tecumseh, KS Steam Turbines .7 1957 Coal 61 61 61 (a) Capability (except for wind generating facilities) represents accredited net generating capacity approved by the SPP. Capability for our wind generating facilities represents the installed design capacity. Due to the intermittent nature of wind generation, these facilities are associated with a total of205 MW of accredited generating capacity.
(b) In March 2017, we expect to complete construction and start operation of Western Plains Wind Farm.
(c) Westar Energy jointly owns State Line (40%) while KGB jointly owns La Cygne unit 1 (50%) and Wolf Creek (47%). We jointly own and consolidate as a VIE 92% of JEC. Unit capacity amounts reflect our ownership and leased percentages only.
(d) In 1987, KGB entered into a sale-leaseback transaction involving its 50% interest in the La Cygne unit 2. We consolidate the leasing entity as a VIE as discussed in Note 18 of the Notes to Consolidated Financial Statements, "Variable Interest Entities."*
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Unit Capability (MW) By Owner (a)
Total Generation and Total Renewable Renewable Year Principal Westar Company Purchased Purchased Name Location Unit No. Installed Source Energy KGE Generation Power Power Gas and Diesel:
Emporia Energy Center: Emporia, KS
-* -*- -o-- - -**
Combustion Turbines 1 2008 Gas 45 45 45 2 2008 Gas 44 44 44 3 2008 Gas 43 43 43 4 2008 Gas 44 44 44 5 2008 Gas 158 158 158 6 2009 Gas 155 155 155 7 2009 Gas 156 156 156 Gordon Evans Energy Center: Colwich, KS Steam Turbines 1 1961 Gas 154 154 154 2 1967 Gas 376 376 376
. - 1 Gas 73 73 . 73 Combustion Turbines 2000 2 2000 Gas 71 71 71 3 2001 Gas 148 148 148 Hutchinson Energy Center: Hutchinson, KS Combustion Turbines 1 1974 Gas 52 52 52 2 1974 Gas 55 55 55 3 1974 Gas 54 54 54 4 1975 Diesel 70 70 70 Murray Gill Energy Center: Wichita, KS Steam Turbines 3 1956 Gas 104 104 104 4 1959 Gas 86 8.6 86 Spring Creek Energy Center: Edmond, OK Combustion Turbines 1 2001 Gas 69 69 69
,,;:-~ -
2 2001 Gas 69 69 69 3 2001 Gas 67 67 67 4 2001 Gas 68 68 68 State Line (40%): Joplin, MO Combined Cycle 2-1 (c) 2001 Gas 62 62 62 2-2 (c) 2001 *Gas 63 63 63
- . , ~~. -- -
-~
2-3 (c) 2001 Gas 71 71 71 Total 4,174 2,399 6,573 1,231 7,894 (a) Capability (except for wind generating facilities) represents accredited net generating capacity approved by the SPP. Capability for our wind generating faeilities represents the installed design capacity. Due to the intermittent nature of wind generation, these facilities are associated with a total of 205 MW of accredited generating capacity.
(b) In March 2017, we expect to complete construction and start operation of Western Plains Wind Farm.
(c) Westar Energy jointly owns State Line (40%) while KGB jointly owns La Cygne unit 'l (50%) and Wolf Creek (47%). We jointly own and consolidate as a VIE 92% of JEC. Unit capacity amounts reflect our ownership and leased percentages only.
25.
We own and have in service approximately 6,400 miles of transmission lines, approximately 24,000 miles of overhead distribution lines and approximately 5,000 miles of underground distribution lines.
Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding.
ITEM 3. LEGAL PROCEEDINGS Information on legal proceedings is set forth in Notes 4, 14 and 16 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation," "Commitments and Contingencies" and "Legal Proceedings," respectively, which are incorporated herein by reference. '
ITEM 4. MINE SAFETY DISCLOSURES Not Applicable.
26.
PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS STOCK TRADING Westar Energy's common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of February 15, 2017, Westar Energy had 16,325 common shareholders ofrecord. For information regarding quarterly common stock price ranges for 20.16 and 2015, see Note 20 of the Notes to Consolidated Financial Statements, "Quarterly Results (Unaudited)."
STOCK PERFORMANCE GRAPH The following graph compares the performance .of Westar Energy's common stock during the period that began on December 31, 2011, and ended on December 31, 2016, to the performance of the Standard & Poor's 500 Index (S&P 500) and the Standard & Poor's Electric Utility Index (S&P Electric Utilities). The graph assumes a $100 investment in Westar Energy's common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.
CUMULATIVE TOTAL RETURN Based on an initial investment of $100 .on December 31, 2011 with dividends reinvested
$250
$200 fllll""' *..
~........ ~ ....****************
$150
- - ,,, ,,, ,,, --~*-**********************************:.::..=*'*;;:::::.:*..::::::..:.:.:.~::::>"" --
$100 Dec 2011
-- Dec 2012 Dec 2013 Dec 2014 Dec 2015 Dec 2016 Westar Energy, Inc. - S&P©500 ************* S&P© Electric Utilities Dec 2012 Dec2013 Dec2014 Dec 2015 WesfarEqergy;f11c.
S&P©500 $175 S&P© ~1¢ctric Jl(ilities. '$148 27
DIVIDENDS Holders of Westar Energy's common stock are entitled to dividends when and as declared by Westar Energy's board of directors.
Quarterly dividends on common 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. Westar Energy's board of directors reviews the common stock dividend policy from time to time. Among the factors the board of directors considers in determining Westar Energy's dividend policy are earnings, cash flows, capitalization ratios, regulation, competition and financial loan covenants. In 2016, Westar Energy's board of directors declared four quarterly dividends of $0.38 per share, reflecting an annual dividend of$1.52 per share, compared to four quarterly dividends of$0.36 per share in 2015, reflecting an annual dividend of $1.44 per share. On February 22, 2017, Westar Energy's board of directors declared a quarterly dividend of
$0.40 per share payable to shareholders on April 3, 2017. The indicated annual dividend rate is $1.60 per share.
The merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement, without prior approval of Great Plains Energy, limits our quarterly dividends declared in 2017 to $0.40 per
- share, which represents an annualized increase of $0.08 per share, consistent with last year's dividend increase.
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ITEM 6. SELECTED FINANCIAL DATA Year Ended December 31, 2016 2015 2014 2013 2012 (In Thousands)
~~~~-;::.-, -
- 1nconie.Statement Data:
1? ~: ,. -~fj;;, ~
Total revenues..................................................... $ 2,562,087 $ 2,459,164 $ 2,601,703 $ 2,370,654 $ 2,261,470
- .:361,ioa.*...* ......... 3~Af>3.:. _ **** 282~46!'1 Net income attributable to Westar Energy, Inc *. 346,577 291,929 313,259 292,520 273,530 As ofDecember 31, 2016 2015 2014 2013 2012
- (In Thousands) rliaian~;*sheet nat;-:***
Total assets ......................................................... $ * $ 10,705,666 $ 10,288,906 $ 9,530,903 $ 9,238,759
. ~~~~t~~ ~ili~~~~~n;~~~r:~~~**:*:*~~;:~:*~~***~**::* r.~ '
.***:3379,219~* *3,466;984 3,098,359:j
";::.~ ""' '"" ,~ _,,,;',:".'fow!
Year Ended December 31, 2016 2015 2014 2013 2012 Comµion 'Stock Data:
Basic earnings per share available for common stock. ............................................................. $ 2.43 $' 2.11 $ 2.40 $ 2.29
$ 2.15 Diluted earnings per share available for* . *>
.common sfo~k. ........ :::*.... ,; ......... :;;.':.... :::.,:.... :*>
",,;,,..">:...".. ~" ~. -..c~,;~, *o~ ..
2.'-J7
~-"".-.-,
2:1s:i Dividends declared per share ............................ . 1.52 1.44 1.40 1.32
.~f;~ii*;ii1~~Ii~iri~**"***.::*L:***'*:'.::::~*;:*.:*****;::;~:. 22:89:
(a) Includes long-term debt, net, current maturities oflong-term debt, capital leases, long-term debt ofVIEs, net and current maturities of long-term debt ofVIEs. See Note 18 of the Notes to Consolidated Financial Statements, "Variable Interest Entities," for additional information regarding VIEs.
(b) In 2014, Westar Energy issued and sold approximately 3.4 million shares of common stock realizing proceeds of $87. 7 million.
( c) In 2015, Westar Energy issued and sold approximately 9. 7 million shares of common stock realizing proceeds of $25 8.0 million.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Certain matters discussed in Management's Discussion and Analysis are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability.
Forward-looking statements may include words like we "believe," "anticipate," "target," "expect," "estimate," "intend" and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. See "Forward-Looking Statements" above for additional information.
EXECUTIVE
SUMMARY
Description of Business We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail to approximately 704,000 customers in Kansas under the regulation of the KCC. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas under the regulation of FERC. We have contracts for the sale or purchase of wholesale electricity with other utilities.
Proposed Merger with Great Plains Energy On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock. The closing of the merger is subject to customary closing conditions, including receipt of regulatory approvals. For more information, see Notes 3, 14 and 16 of the Notes to Consolidated Financial Statements, "Pending Merger," "Commitments and Contingencies" and "Legal Proceedings,
respectively, and Item "lA. Risk Factors."
- Earnings Per Share Following is a summary of our net income and basic earnings per share (EPS) for the years ended December 31, 2016 and 2015.
Year Ended December 31, 2016 2015 Change (Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc_. $ 346,577 $ 291,929 $ 54,648 Earnings per common share, basic..................... 2.43 2.11 0.32 Net income attributed to Westar Energy, Inc. and basic EPS for the year ended December 31, 2016, increased due primarily to higher retail prices and corporate-owned life insurance (COLI) proceeds. Partially offsetting these increases was higher operating and maintenance costs at our coal fired plants due to scheduled outages and higher depreciation and amortization due to air quality control additions at La Cygne.
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Key Factors Affecting Our Performance The principal business, economic and other factors that affect our operations and financial performance include:
weather conditions; the economy; customer conservation efforts; the performance, operation and maintenance of our electric generating facilities and network; conditions in the fuel, wholesale electricity and energy markets; rate and other regulations and costs of addressing public policy initiatives including environmental laws and regulations; the availability of and our access to liquidity and capital resources; and capital market conditions.
Strategy We expect to continue operating as a vertically integrated, regulated electric utility. Significant elements of our strategy include maintaining a flexible, clean and diverse energy supply portfolio. In doing so, we continue to expand renewable generation, build and upgrade our energy infrastructure and develop systems and programs with regard to how our customers use energy and interact with us. In addition, we have entered into an agreement and plan of merger with Great Plains Energy pursuant to which, at closing, we would become a wholly-owned subsidiary of Great Plains Energy. The closing of the merger is subject to customary closing conditions, including receipt of regulatory approvals. See "Item IA. Risk Factors" and Note 3 of the Notes to Consolidated Financial Statements, "Pending Merger," for additional information.
Current Trends and Uncertainties Environmental Regulation We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting our operations are overlapping, complex, subject to changes, have become more stringent over time and are expensive to implement. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and consolidated financial results, including those relating to:
- further regulation of GHGs by the EPA, ip.cluding regulations pursuant to the CPP, and future legislation that could be proposed by the U.S. Congress;
- various proposed and expected regulations governing air emissions including those relating to National Ambient Air Quality Standards (particularly those relating to particulate matter, nitrogen oxide, ozone, carbon monoxide and sulfur dioxide); and
- the regulation of CCR.
See Note 14 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies-Environmental Matters," for a discussion of environmental costs, laws, regulations and other contingencies.
Allowance for Funds Used During Construction AFUDC represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress (CWIP). We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:
Year Ended December 31, 2016 2015 2014 (In Thousands)
Borrowed funds ..................*........ $ 9,964 $ 3,505 $ 12,044 Equity funds ............................... . 11,630 2,075 17,029 Total ..................................... $ 21,594 $ 5,580 $ 29,073
==
Average AFUDC Rates .............. . 4.2% 2.7% 6.7%
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We expect AFUDC for both borrowed funds and equity funds to fluctuate based on the timing and manner in which we finance our capital expenditures.
Interest Expense We expect interest expense to modestly increase over the next several years as we issue new debt securities to fund our capital expenditure program. We continue to believe this increase will be reflected in the prices we are permitted to charge customers, as cost of capital will be a component of future rate proceedings and is also recognized in some of the other rate adjustments we are permitted to make. In addition, short-term interest rates are low by historical standards. We cannot predict to what extent these conditions will continue. See Note 10 of the Notes to Consolidated Financial Statements, "Long-Term Debt" for additional information regarding the issuance of long-term debt.
Customer Growth and Usage Retail customer additions have been growing approximately 0.5% the past few years. Additionally, weather normalized retail sales growth has largely grown in line with customer growth. With the numerous energy efficiency policy initiatives promulgated through federal, state and local governments, as well as industry initiatives, environmental regulations and the need to strengthen and modernize the grid, which will increase our prices, we believe customers will continue to adopt more energy efficiency and conservation measures, which will slow or possibly suppress the growth of demand for electricity.
2017 Outlook In 2017, we expect to maintain our current business strategy and regulatory approach. Assuming normal weather, we expect 2017 retail electricity sales to be in line with our projected retail customer growth of about 0.5%.
Absent increases in SPP transmission expense and property tax expense, which are increasing at a much higher rate than inflation and are offset with higher revenues pursuant to our regulatory mechanisms and absent incremental merger-related expenses, we anticipate operating and maintenance and selling, general and administrative expenses to be relatively flat in 2017 as compared to 2016. To help fund our capital spending as provided under "-Future Cash Requirements" below, in 2017 we may issue long-term debt, and utilize short-term borrowings by issuing commercial paper until permanent financing is in place.
CRITICAL ACCOUNTING ESTIMATES Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with Generally Accepted Accounting Principles (GAAP). Note 2 of the Notes to Consolidated Financial Statements, "Summary of Significant Accounting Policies," contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted below have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.
Regulatory Accounting We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in our prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers.
The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. Ifwe deem it no longer probable that we would recover such costs, we would record a charge against income in the amount of the related regulatory assets.
As of December 31, 2016, we had recorded regulatory assets currently subject to recovery in future prices of approximately $879.9 million and regulatory liabilities of $239.5 million, as discussed in greater detail in Note 4 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation."
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Pension and Post-Retirement Benefit Plans Actuarial Assumptions We and Wolf Creek calculate our pension benefit and post-retirement medical benefit obligations and related costs using actuarial concepts within the guidance provided by GAAP.
In accounting for our retirement plans and post-retirement benefits, we make assumptions regarding the valuation of benefit obligations and the performance of plan assets. The reported costs of our pension plans are impacted by estimates regarding earnings on plan assets, contributions to the plan, discount rates used to determine our projected benefit obligation and pension costs and employee demographics including age, life expectancy and compensation levels and employment periods. Changes in these assumptions result primarily in changes to regulatory assets, regulatory liabilities or the amount of related pension and post-retirement benefit liabilities reflected on our consolidated balance sheets. Such changes may also require cash contributions.
The following table shows the impact of a 0.5% change in our pension plan discount rate, salary scale and rate of return on plan assets.
Annual Change Change in in Projected Projected Change in Benefit Pension Actuarial Assumption Assumption Obligation (a) Costs (a)
(Dollars In Thousands)
Discount rate 0.5% decrease $ 94,763 $ 8,390 0.5% increase (84,504) (7,585)
Compensation 0.5% decrease (18,439) (3,561) 0.5% increase 19,717 3,822 Rate of return on plan assets 0.5% decrease 4,041 0.5% increase (4,041)
(a) Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities.
The following table shows the impact of a 0.5% change in the discount rate and rate of return on plan assets and a 1%
change in the annual medical trend on our post-retirement benefit plans.
Annual Change in Change in Projected Projected Post-Change in Benefit retirement Actuarial Assumption Assumption Obligation (a) Costs (a)
(Dollars In Thousands)
Discount rate 0.5% decrease $ 7,823 $ 325 0.5% increase (7,094) (309)
Rate of return on plan assets 0.5% decrease 573 0.5% increase (573),
Annual medical trend 1.0% decrease 133 20 1.0% increase (125) (19)
(a) Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities.
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Revenue Recognition We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.
Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $74.4 million as of December 31, 2016 and $66.0 million as of December 31, 2015.
Income Taxes We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.
We record deferred tax assets to the extent capital losses, operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.
The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous.
Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated fmancial statements. See Note llofthe Notes to Consolidated Financial Statements, "Taxes," for additional detail on our accounting for income taxes.
Asset Retirement Obligations Legal Liability We have recognized legal obligations associated with the disposal oflong-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of the ARO is capitalized and depreciated over the remainpig life of the asset. We estimate our AROs based on the fair value of the AROs we incurred at the time the related long-lived assets were either acquired, placed in service or when regulations establishing the obligation became effective. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.
We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (our 4 7% share), retire our wind generating facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds, close ash landfills and dispose ofpolychlorinated biphenyl contaminated oil. ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement may be conditional on a future event that may or may not be within the control of the entity. In determining our AROs, we make assumptions regarding probable future disposal costs. A change in these assumptions could have a significant impact on the AROs reflected on our consolidated balance sheets.
As of December 31, 2016 and 2015, we have rec.ordedAROs of$324.0 million and $275.3 million, respectively. For additional information on our legal AROs, see Note 15 of the Notes to Consolidated Financial Statements, "Asset Retirement Obligations."
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Contingencies and Litigation We and our subsidiaries are involved in various legal, environmental and regulatory proceedings, and we have estimated the probable cost for the resolution of these proceedings. These estimates are based on an analysis of potential results, assuming a combination of litigation and settlement strategies. It is possible that our future consolidated financial results could be materially affected by changes in our assumptions. See Notes 4, 14 and 16 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulations," "Commitments and Contingencies" and "Legal Proceedings,"
respectively, for additional information.
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OPERATING RESULTS We evaluate operating results based on BPS. We have various classifications of revenues, defined as follows:
Retail: Sales of electricity to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification. Other retail sales of electricity include lighting for public streets and highways, net of revenue subject to refund.
Wholesale: Sales of electricity to electric cooperatives, municipalities, other electric utilities and RTOs, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. Revenues from these sales are either included in the retail energy cost adjustment or used in the determinations of base rates at the time of our next general rate review.
Transmission: Reflects transmission revenues, including those based on tariffs with the SPP.
Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. This category also includes transactions unrelated to the production of our generating assets and fees we earn for services that we provide for third parties.
Electric utility revenues are impacted by things such as rate regulation, fuel costs, technology, customer behavior, the economy and competitive forces. Changing weather also affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential and commercial customers, and to a lesser extent, industrial customers. Mild weather reduces customer demand. Our wholesale revenues are impacted by, among other factors, demand, cost and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather.
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~---------------------------------- -
2016 Compared to 2015 Below we discuss our operating results for the year ended December 31, 2016, compared to the results for the year ended December 31, 2015. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.
Year Ended December 31, 2016 2015 Change %Change (Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential.......................................................................................... $ 838,998 $ 768,618 $ 70,380 9.2 Commercial ....................................................................................... . 741,066 712,400 28,666 4.0 Industrial. ........................................................................................... . 413,298 400,687 12,611 3.1 Other retail ......................................................................................... . (15,013) (17,155) 2,142 12.5 Total Retail Revenues ................................................................ . 1,978,349 1,864,550 113,799 6.1 Wholesale .......................................................................................... . 304,871 318,371 (13,500) (4.2)
Transmission...................................................................................... . 253,713 241,835 11,878 4.9 Other .................................................................................................. . 25,154 34,408 (9,254) (26.9)
Total Revenues .......................................................................... .
2,562,087 2,459,164 102,923 4.2 OPERATING EXPENSES:
Fuel and purchased power ................................................................. . 509,496 561,065 (51,569) (9.2)
SPP network transmission costs .................................. :..................... . 232,763 229,043 3,720 1.6 Operating and maintenance ............................................................... . 346,313 330,289 16,024 4.9 Depreciation and amortization ........................ ;................................. . 338,519 310,591 27,928 9.0 Selling, general and administrative ................................................... . 261,451 250,278 11,173 4.5 Taxes other than income tax .............................................................. . 191,662 156,901 34,761 22.2 Total Operating Expenses.......................................................... .
1,880,204 1,838,167 42,037 2.3 INCOME FROM OPERATIONS ............................................................. . 681,883 620,997 60,886 9.8 OTHER INCOME (EXPENSE):
Investment earnings ........................................................................... . 9,013 7,799 1,214 15.6 Other income ..................................................................................... . 34,582 19,438 15,144 77.9 Other expense .................................................................................... . (18,012) (17,636) (376) (2.1)
Total Other Income.................................................................... .
25,583 9,601 15,982 166.5 Interest expense ......................................................................................... . 161,726 176,802 (15,076) (8.5)
INCOME BEFORE INCOME TAXES..................................................... . 545,740 453,796 91,944 20.3 Income tax expense ................................................................................... . 184,540 152,000 32,540 21.4 NET INCOME .......................................................................................... . 361,200 301,796 59,404 19.7 Less: Net income attributable to noncontrolling interests ......................... . 14,623 9,867 4,756 48.2 NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC........... $ 346,577 $ 291,929 $ 54,648 18.7
==
BASIC EARNINGS PER A VERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.$ 2.43 $ 2.11 $ 0.32 15.2 DILUTED EARNINGS PER A VERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.$ 2.43 $ 2.09 $ 0.34 16.3 37
Rate Review Agreement In September 2015, the KCC issued an order in our state general rate review allowing us to adjust our prices to include, among other things, additional investment in La Cygne environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $78.3 million.
Gross Margin Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. In addition, SPP network transmission costs fluctuate due primarily to investments by us and other members of the SPP for upgrades to the transmission grid within the SPP RTO. As with fuel and purchased power costs, changes in SPP network transmission costs are mostly reflected in the prices we charge customers with minimal impact on net income. For these reasons, we believe gross margin is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin as total revenues, including transmission revenues, less the sum of fuel and purchased power costs and amounts billed by the SPP for network transmission costs. Accordingly, gross margin reflects transmission revenues and costs on a net basis. The following table summarizes our gross margin for the years ended December 31, 2016 and 2015.
Year Ended December 31, 2016 2015 Change % Change (Dollars In Thousands)
Revenues .............................................................. $ 2,562,087 $ 2,459,164 $ 102,923 4.2 Less: Fuel and purchased power expense ........... . 509,496 561,065 (51,569) (9.2)
SPP network transmission costs ................ . 232,763 229,043 3,720 1.6 Gross Margin....................................................... $ 1,819,828 $ 1,669,056 $ 150,772 9.0
==
The following table reflects changes in electricity sales for the years ended December 31, 2016 and 2015. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.
Year Ended December 31, 2016 2015 Change % Change (Thousands ofMWh)
ELECTRICITY SALES:
Residential.................................................... 6,434 6,364 70 1.1 Commercial.................................................. 7 ,544 7,500 44 0.6 Industrial....................................................... 5,499 5,502 (3) (0.1)
Other retail.................................................... 77 84 (7) (8.3)
Total Retail............................................
19,554 19,450 104 0.5
~Wholesale..................................................... 8,299 8,492 (193) (2.3)
Total......................................................
27,853 27,942 (89) (0.3)
Gross margin increased due primarily to higher retail prices, which increased approximately 6%. Gross margin also increased slightly due to weather that was modestly favorable relative to 2015. During 2016, there were approximately 10%
more cooling degree days compared to 2015.
38
Income from operations, which is calculated and presented in accordance with GAAP in our consolidated statements of income, is the most directly comparable measure to our presentation of gross margin, which is a non-GAAP measure. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the years ended December 31, 2016 and 2015.
Year Ended December 31, 2016 2015 Change % Change (Dollars In Thousands)
Income from operations ................................................. $ 681,883 $ 620,997 $ 60,886 9.8 Plus: Operating and maintenance expense ................... 346,313 330,289 16,024 4.9 Depreciation and amortization expense .............. 338,519 310,591 27,928 9.0 Selling, general and administrative expense ....... 261,451 250,278 11,173 4.5 Taxes other than income tax ............................... 191,662 156,901 34,761 22.2 Gross Margin ................................................................. $ 1,819,828 $ 1,669,056 $ 150,772 9.0 Operating Expenses and Other Income and Expense Items Year Ended December 31, 2016 2015 Change % Change (Dollars in Thousands)
Operating and maintenance expense ...... ... .... .... .. $ 346,313 $ 330,289 $ 16,024 4.9 Operating and maintenance expense increased due primarily to:
higher operating and maintenance costs at our coal fired plants of $14.1 million, due primarily to scheduled outages; higher transmission and distribution operating and maintenance costs of $4.3 million due partially to improving long-term reliability; and higher decommissioning costs of $3.0 million for Wolf Creek which is offset in retail revenues; however, partially offsetting these increases was a $9.8 million decrease in operating and maintenance costs related to our having retired three generating units in late 2015.
Year Ended December 31, 2016 2015 Change % Change (Dollars in Thousands)
Depreciation and amortization expense............... $ 338,519 $ 310,591 $ 27,928 9.0 Depreciation and amortization expense increased due primarily to air quality control additions at La Cygne.
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Year Ended December 31, 2016 2015 Change % Change (Dollars in Thousands)
. Sellillg, general and adlninistrative expe~se .. ... .. $ *261,451 $ 250,278 $ 11,173 4.5:
Selling, general and administrative expense increased due primarily to:
incurring $10.2 million of merger-related expenses in 2016; an increase in the allowance for uncollectible accounts of $3.5 million; and an increase of $2. 7 million in outside services related principally to technology services; however, partially offsetting these increases was lower employee benefit costs of$7.6 million due primarily to reduced post-retirement medical costs.
Year Ended December 31, 2016 2015 Change % Change
- - -~ ___ , -* .. ,
(Dollars in Thousands)
Taxes other than income tax................................ $ 19(662 $ '156,901 $ . 34,761 22.2 Taxes other than income tax increased due primarily to a $36.1 million increase in property tax expense, which is mostly offset in retail revenues.
Year Ended December 31, 2016 2015 Change % Change (Dollars in Thousands)
- other illcome ............... :..... :.................. .".. :.:......... $ 34,582 $ 19,438 $ 15,144 77.9 Other income increased due primarily to an increase in equity AFUDC of $9 .6 million and our having recorded
$7.2 million more in COLI benefits.
Year Ended December 31, 2016 2015 Change % Change (Dollars in Thousands)
- Interestexpense ..........................., ................... :... $
- 161,726 $ ***176,802. $ .. (i5,016)... (8.5)
Interest expense decreased due primarily to a $6.5 million increase in debtAFUDC, a $5.7 million decrease in interest on long-term debt ofVIEs due to refinancing long-term debt of the La Cygne VIE and a $4.8 million decrease in interest expense on long-term debt due to refmancing long-term debt at lower rates.
Year Ended December 31, 2016 2015 Change % Change (Dollars in Thousands)
- '!n~ome t.ax expense*****~*************;:.::**::******************* $ 184,540 $ ' 152,000 $ . '* 32,540 .21.4
~*-"~
Income tax expense increased due principally to higher income before income taxes.
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2015 Compared to 2014 Below we discuss our operating results for the year ended December 31, 2015, compared to the results for the year ended December 31, 2014. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.
Year Ended December 31, 2015 2014 Change %Change (Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential .......................................................................................... $ 768,618 $ 793,586 $ (24,968) (3.1)
Commercial........................................................................... ;............. 712,400 727,964 (15,564) (2.1)
Industrial ............................................................................................. 400,687 414,997 (14,310) (3.4)
Other retail .......................................................................................... (17,155) (24,180) 7,025 29.l Total Retail Revenues ................................................................. 1,864,550 1,912,367 (47,817) (2.5)
Wholesale ............................................................................................ 318,371 392,730 (74,359) (18.9)
Transmission ....................................................................................... 241,835 256,838 (15,003) (5.8)
Other ................................................................................................... 34,408 39,768 (5,360) (13.5)
Total Revenues ............................................................................ 2,459,164 2,601,703 (142,539) (5.5)
OPERATING EXPENSES:
Fuel and purchased power .................................................................. 561,065 705,450 (144,385) (20.5)
SPP network transmission costs.......................................................... 229,043 218,924 10,119 4.6 Operating and maintenance ................................................................ 330,289 367,188 (36,899) (10.0)
Depreciation and amortization ............................................................ 310,591 286,442 24,149 8.4 Selling, general and administrative ..................................................... 250,278 250,439 (161) (0.1)
Taxes other than income tax ............................................................... 156,901 140,302 16,599 11.8 Total Operating Expenses ........................................................... 1,838,167 1,968,745 (130,578) (6.6)
INCOME FROM OPERATIONS............................................................... 620,997 632,958 (11,961) (1.9)
OTHER INCOME (EXPENSE):
Investment earnings ............................................................................ 7,799 10,622 (2,823) (26.6)
Other income ....................................................................................... 19,438 31,522 (12,084) (38.3)
Other expense ..................................................................................... (17,636) (18,389) 753 4.1 Total Other Income (Expense) .................................................... 9,601 23,755 (14,154) (59.6)
Interest expense........................................................................................... 176,802 183,118 (6,316) (3.4)
INCOME BEFORE INCOME TAXES ...................................................... 453,796 473,595 (19,799) (4.2)
Income tax expense ..................................................................................... 152,000 151,270 730 0.5 NET INCOME ............................................................................................ 301,796 322,325 (20,529) (6.4)
Less: Net income attributable to noncontrolling interests .......................... 9,867 9,066 801 8.8 NET INCOME ATTRIBUTABLE TO WESTAR ENERGY. INC ........... $ 291,929 $ 313,259 $ (21,330) (6.8)
BASIC EARNINGS PER A VERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.$ 2.11 $ 2.40 $ (0.29) (12.1)
DILUTED EARNINGS PER A VERA GE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.$ 2.09 $ 2.35 $ (0.26) (11.1) 41
Gross Margin The following table summarizes our gross margin for the years ended December 31, 2015 and 2014.
Year Ended December 31, 2015 2014 Change % Change
.(Dollars In Thousands)
Revenues .............................................................. $ 2,459,164 $ ,2,601,703 $ (142,539) (5.5)
Less: Fuel and purchased power expense ........... . 561,065 705,450 (144,385) (20.5)
SPP network transmission costs ................ . 229,043 218,924 10,119 4.6 Gross Margin....................................................... $ 1,669,056 $ 1,677,329 $ (8,273) (0.5)
=
The following table reflects changes in electricity sales for the years ended December 31, 2015 and 2014. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.
Year Ended December 31, 2015 2014 Change % Change (Thousands ofl\1Wh)
ELECTRICITY.
SALES: .
Residential.................................................... 6,364 6,580 (216) (3.3)
Comniercial .................................................. 7,500 7,521 (21) (0.3)
Industrial....................................................... 5,502 5,601 (99) (1.8)
Other retail.................................................... 84 86 (2) (2.3)
Total Retail... ....... :.................................
19,450 19,788 (338) (1.7)
Wholesale..................................................... 8,492 9,544 (1,052) (11.0)
Total......................................................
27,942 29,332 (1,390) (4.7)
Gross margin decreased due primarily to an estimated $13.8 million transmission revenues refund obligation associated with a FERC proceeding. Energy marketing margin decreased $11.2 million due to greater volatility in 2014 of wholesale power prices. Also contributing to the decrease in gross margin was lower retail electricity sales. The lower residential and commercial electric sales were due to warm winter weather. During 2015, there were approximately 19% fewer heating degree days compared to 2014. The lower industrial sales were due to a few of our larger customers who experienced weaker global demand for their products.
Income from operations, which is calculated and presented in accordance with GAAP in our consolidated statements of income, is the most directly comparable measure to our presentation of gross margin, which is a non-GAAP measure. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the years ended December 31, 2015 and 2014.
Year Ended December 31, 2015 2014 Change % Change (Dollars In Thousands)
- Income from operations ................................................. $ 620,997 $ 632,958 $ (11,961) (1.9)
Plus: Operating and maintenance expense ................... 330,289 367,188 (36,899) (10.0)
Depreciation_ and amortization expense .............. 310,591 286,442 24,149 8.4 Selling, general and administrative expense ....... 250,278 250,439 (161) (0.1)
~ ~
Taxes other than income tax ............................... ~
156,901 140,302 16,599 11.8 Gross margin.................................................................. $ 1,669,056 $ 1,677,329 $ (8,273) (0.5) 42
Operating Expenses and Other Income and Expense Items Year Ended December 31, 2015 2014 Change % Change (Dollars in Thousands)
Operating and maintenance expense ..... ......... ..... $ 330,289 $ 367,188 $ (36,899) (10.0)
Operating and maintenance expense decreased due principally to:
lower transmission and distribution operations and maintenance expense of $14.8 million due partially to focus on capital replacement for longer term grid resiliency; lower costs at our coal fired plants of$10.5 million, which were principally the result of higher operating and maintenance costs incurred during a 2014 scheduled outage at JEC; and lower costs at Wolf Creek of$10.3 million, which were principally the result of higher operating and maintenance costs incurred during a 2014 scheduled outage.
Year Ended December 31, 2015 2014 Change % Change (Dollars in Thousands)
Depreciation and amortization expense:.............. $ 310,591 $ 286,442 $ 24,149 8.4 Depreciation and amortization expense increased due to additions at our power plants, including air quality controls, additions at Wolf Creek to enhance reliability and the addition of transmission facilities. Depreciation related to environmental equipment placed in-service at La Cygne, as approved by the KCC, was deferred until new retail prices became effective in late October 2015.
Year Ended December 31, 2015 2014 Change % Change (Dollars in Thousands)
Selling, general and administrative expense .. ..... $ 250,278 $ 250,439 $ (161) (0.1)
Selling, general and administrative expense decreased due primarily to a reduction of $4.2 million in amortization for previously deferred amounts with various energy efficiency programs; however, partially offsetting this decrease was higher labor and employee benefit costs of$5.1 million partially related to restructuring charges.
Year Ended December 31, 2015 2014 Change %Change (Dollars in Thousands)
Taxes other than income tax................................ $ 156,901 $ 140,302 $ 16,599 11.8 Taxes other than income tax increased due primarily to an increase of$16.9 million in property tax expense. This increase is mostly offset in retail revenue.
Year Ended December 31, 2015 2014 Change % Change (Dollars in Thousands)
Investment earnings ..................... -....................... . 7,799 10,622 $ (2,823) (26.6)
Investment earnings decreased due primarily to recording a $2.2 million lower gain on a trust to secure certain retirement benefit obligations.
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Year Ended December 31, 2015 2014 Change % Change (Dollars in Thousands)
Other income....................................................... $ 19,438 $ 31,522 $ (12,084) (38.3)
Other income decreased due primarily to our having recorded about $15.0 million less in equity AFUDC due primarily to completion of major construction projects. The decrease was partially offset by our having recorded $2.7 million more in COLI benefits.
Year Ended December 31, 2015 2014 Change % Change (Dollars in Thousands)
Interest expense .................................................. . 176,802 $ 183,118 $ (6,316) (3.4)
Interest expense decreased due primarily to a decrease in long-term interest expense of$14.7 million due to refinancing debt. However, partially offsetting this decrease was a reduction in debt AFUDC of $8.5 million primarily due to reduced CWIP.
Financial Condition A number of factors affected amounts recorded on our balance sheet as of December 31, 2016, compared to December 31, 2015.
As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
Property, plant and equipment, net...................... $ 9,248,359 $ 8,524,902 $ 723,457 8.5 Property, plant and equipment, net of accumulated depreciation, increased due primarily to the construction of Western Plains Wind Farm and plant additions for capital improvements to improve long-term reliability.
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As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
Regulatory assets ................................................. $ 879,862 $ 860,918 $ 18,944 2.2 Regulatory liabilities........................................... 239,453 292,811 (53,358) (18.2)
Net regulatory assets ...................................... $
640,409 $ 568,107 $ 72,302 12.7 Total regulatory assets increased due primarily to the following items:
a $32.5 million increase in amounts to be collected from our customers for the deferred cost of fuel and purchased power; a $27.3 million increase in deferred employee benefit costs; and a $7.0 million increase in unrecovered amounts related to the retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology; however, partially offsetting these decreases was a $26.8 million decrease in amounts deferred for property taxes; and a $20.1 million decrease in amounts due from customers for future income taxes.
Total regulatory liabilities decreased due primarily to the following items:
spending $48.2 million more than collected for the cost to remove retired plant assets; and a $12.7 million decrease in our refund obligations related to amounts we have collected from our customers in excess of our actual cost of fuel and purchased power; however, partially offsetting these decreases was a $5.0 million increase in amounts recognized in setting our prices in excess of actual pension and post-retirement expense; and a $1.2 million increase for the FERC settlement refund obligation and a $1.3 million increase for the KCC approved refund obligation related to the reduced return on equity in our transmission formula rate. See Note 4 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation," for a discussion of these refund obligations.
As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
Short-term debt.. .................................................. $ 366,700 $ 250,300 $ 116,400 46.5 Short-term debt increased due to increased issuances of commercial paper primarily used to fund capital expenditures, such as the construction of Western Plains Wind Farm.
As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
Current maturities oflong-term debt................... $ 125,000 $ $ 125,000 Long-term debt, net............................................. 3,388,670 3,163,950 224,720 7.1 Total long-term debt....................................... $ 3,513,670 $ 3,163,950 $ 349,720 11.1 Total long-term debt increased due to Westar Energy issuing $350.0 million in principal amount of first mortgage bonds. For more information on our long-term debt, see Note 10 of the Notes to Consolidated Financial Statements, "Long-term Debt."
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As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
,Current matllrities of long-term debt of variable interest entities ................................................... $ 26,842 $ 28,309 $ (1,467) (5.2)
Long-term debt of variable interest entities ......... 111,209 138,097 (26,888) (19.5)
Total long-term debt of variable interest entities ........................................................... $ 138,051 $ 166,406 $ (28,355) (17.0)
Total long-term debt ofVIEs decreased due principally to the VIEs that hold the JEC and La Cygne leasehold interests having made principal payments totaling $28.3 million.
As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
Deferred income tax liabilities ............................ $ 1,752,776 $ 1,591,430 $ 161,346 10.1 Long-term deferred income tax liabilities increased due primarily to the utilization of accelerated depreciation methods as well as the utilization of previously deferred net operating losses during the period.
As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
Accmed employee benefits .....>>........................... $ 512,412 $ 462,304 $ 50,108 10.8 Accmed employee benefits increased due primarily to higher pension and post-retirement benefit obligations as a result of a decrease in the discount rates used to calculate our and Wolf Creek's pension benefit obligations.
As of December 31, 2016 2015 Change % Change (Dollars in Thousands)
Asset retirement obligations................................ $ 323,951 $ 275,285 $ 48,666 17.7 AROs increased due primarily to a $39.9 million revision in our AROs related to the regulation of CCRs. See Note 14 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies." and Note 15 of the Notes to Consolidated Financial Statements, "Asset Retirement Obligations," for additional information.
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LIQUIDITY AND CAPITAL RESOURCES Overview Available sources of funds to operate our business include internally generated cash, short-term borrowings under Westar Energy's commercial paper program and revolving credit facilities and access to capital markets. We expect to meet our day-to-day cash requirements including, among other items, fuel and purchased power, dividends, interest payments, income taxes and pension contributions, using primarily internally generated cash and short-term borrowings. To meet the cash requirements for our capital investments, we expect to use internally generated cash, short-term borrowings and proceeds from the issuance of debt and equity securities in the capital markets. When such balances are of sufficient size and it makes economic sense to do so, we also use proceeds from the issuance of long-term debt and equity securities to repay short-term borrowings, which are principally related to investments in capital equipment and the redemption of bonds and for working capital and general corporate purposes. In 2017, we expect to continue our significant capital spending program and plan to contribute to our pension trust. We continue to believe that we will have the ability to pay dividends. Although the agreement and plan of merger with Great Plains Energy contains customary restrictions on our ability to raise capital and pay dividends, we do not believe these restrictions will materially adversely impact our liquidity or ability to pay dividends in 2017.
Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting revenues described in "Item IA. Risk Factors" and "-Operating Results" above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the capital markets. For additional information on our future cash requirements, see "-Future Cash Requirements" below.
Capital Structure As ofDecember 31, 2016 and 2015, our capital structure, excluding short-term debt, was as follows:
As of December 31, 2016 2015 Common equity .............................. . 51% 52%
N oncontrolling interests ................ .. <1% <1%
Long-term debt, including VIEs .... .. 49% 48%
Short-Term Borrowings Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of$1.0 billion. This program is supported by Westar Energy's revolving credit facilities. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes. As of February 15, 2017, Westar Energy had $498.3 million of commercial paper issued and outstanding.
Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million. The $730.0 million facility will expire in September 2019, $20.7 million of which will expire in September 2017. In December 2016, Westar Energy extended the term of the $270.0 million facility by one year to terminate in February 2018. As long as there is no default under the facilities, the $730.0 million and $270.0 million facilities may be extended an additional year and the aggregate amount of borrowings under the $730.0 million and $270.0 million facilities may be increased to $1.0 billion and
$400.0 million, respectively, subject to lender participation. All borrowings under the facilities are secured by KGB first mortgage bonds. Total combined borrowings under the revolving credit facilities and the commercial paper program may not exceed $1.0 billion at any given time. As of February 15, 2017, no amounts were borrowed and $12.3 million ofletters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit were issued under the $270.0 million facility as of the same date.
A default by Westar Energy or KGB under other indebtedness totaling more than $25.0 million would be a default under both revolving credit facilities. Westar Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio of 65% or less at all times. At December 31, 2016, our ratio was 51 %. See Note 9 of the Notes to Consolidated Financial Statements, "Short-Term Debt," for additional information regarding our short-term borrowings.
47
Long-Term Debt Financing As of December 31, 2016, we had $121.9 million of variable rate, tax-exempt bonds outstanding. While the interest rates for these bonds have been low, we continue to monitor the credit markets and evaluate our options with respect to these bonds.
In January 2017, Westar Energy retired $125.0 million in principal amount of first mortgage bonds bearing a stated interest at 5 .15 % maturing January 2017.
In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as "Green Bonds," and all proceeds from the bonds will be used in renewable energy projects, primarily the construction of the Western Plains Wind Farm.
Also in June 2016, KGE redeemed and reissued $50.0 million in principal amount pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.
In February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a redemption and reissuance of
$162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 18 of the Notes to Consolidated Financial Statements, "Variable Interest Entities," for additional information regarding our La Cygne sale-leaseback.
The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that can be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.
Under the Westar Energy mortgage, the issuance of bonds is subject to limitations based on the amount ofbondable property additions. In addition, so long as any bonds issued prior to January 1, 1997, remain outstanding, the mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless Westar Energy's unconsolidated net earnings available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on or 10% of the principal amount of all first mortgage bonds outstanding after giving effect to the proposed issuance. As of December 31, 2016, approximately $931.6 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with certain refundings.
Under the KGE mortgage, the amount of first mortgage bonds authorized is limited to a maximum of$3.5 billion and the issuance of bonds is subject to limitations based on the amount ofbondable property additions. In addition, the mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless KGE's net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-halftimes the annual interest charges on or 10% of the principal amount of all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. As of December 31, 2016, approximately $1.5 billion principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with certain refundings.
Some of our debt instruments contain restrictions that require us to maintain leverage ratios as defined in the credit agreements. We calculate these ratios in accordance with the agreements and they are used to determine compliance with our various debt covenants. We were in compliance with these covenants as of December 31, 2016.
Impact of Credit Ratings on Debt Financing Moody's Investors Service (Moody's) and Standard & Poor's Ratings Services (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate each agency's assessment of our ability to pay interest and principal when due on our securities.
In general, more favorable credit ratings increase borrowing opportunities and reduce the cost of borrowing. Under Westar Energy's revolving credit facilities and commercial paper program, our cost of borrowings is determined in part by credit ratings. However, Westar Energy's ability to borrow under the credit facilities and commercial paper program are not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs.
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Factors that impact our credit ratings include a combination of objective and subjective criteria. Objective criteria include typical fmancial ratios, such as total debt to total capitalization and funds from operations to total debt, among others, future capital expenditures and our access to liquidity including committed lines of credit. Subjective criteria include such items as the quality and credibility of management, the political and regulatory environment we operate in and an assessment of our governance and risk management practices.
As of February 15, 2017, our ratings with the agencies are as shown in the table below.
Westar Energy KGB First First Westar Mortgage Mortgage Energy Bond Bond Commercial Rating Rating Rating Paper Outlook Moody's A2 A2 P-2 Stable S&P (a) A A A-2 Negative (a) In May 2016, following the public announcement of the proposed merger with Great Plains Energy, S&P revised its outlook for Westar Energy and KGB to negative from stable, pending the outcome of the merger.
Common Stock Westar Energy's Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2016, Westar Energy had 141.8 million shares issued and outstanding.
Summary of Cash Flows Year Ended December 31, 2016 2015 2014 (In Thousands)
Cash flows from (used in):
Operating activities ....................._........................................ $ 822,420 $ 715,850 $ 825,230 Investing activities.............................................................. (1,012,760) (649,704) (838,748)
Financing activities ............................................................ . 190,175 (67,471) 13,587 Net (decrease) increase in cash and cash equivalents.... $ (165) $ (1,325) $ 69
==
Cash Flows from Operating Activities Cash flows from operating activities increased $106.6 million in 2016 compared to 2015 due principally to our having paid $92.8 million less for coal and natural gas and $27.0 million less for interest, while having received $91.2 million more from retail customers. Partially offsetting these increases was our having received $32. 7 million less for wholesale power sales and transmission services, while having paid $20.2 million more for purchase power and transmission services and
$13.5 million more in income tax payments.
Cash flows from operating activities decreased $109.4 million in 2015 compared to 2014 due principally to our having received $62.8 million less for wholesale power sales and transmission services, $51.8 million less from retail customers and
$10.0 million less for energy marketing activities, while having paid $25.2 million more for the Wolf Creek refueling outage.
Partially offsetting these decreases was our having paid $40.1 million less for coal and natural gas.
Cash Flows used in Investing Activities Cash flows used in investing activities increased $363.1millionin2016 compared to 2015 due primarily to our having invested $386.7 million more in additions to property, plant and equipment primarily related to the construction of Western Plains Wind Farm. Partially offsetting these increase was our having received $25.9 million more from our investment in COLI.
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Cash flows used in investing activities decreased $189.0 million in 2015 compared to 2014 due primarily to our having invested $151.8 million less in additions to property, plant and equipment and our having received $23.6 million more from our investment in COLI.
Cash Flows from (used in) Financing Activities Cash flows from financing activities increased $257.6 million in 2016 compared to 2015. The increase was due principally to our having redeemed $585.9 million less in long-term debt, issued $162.0 million more in long-term debt ofVIEs and issued $123.5 million more in commercial paper. Partially offsetting these increases was our having issued $255.6 million less in common stock, redeemed $162.4 million more in long-term debt ofVIEs, issued $147.6 million less in long-term debt, repaid $24.7 million more for borrowings against the cash surrender value of COLI and paid $18.2 million more in dividends.
Cash flows from financing activities decreased $81.1millionin2015 compared to 2014. The decrease was due primarily to our having redeemed $208.4 million more in long-term debt, issuing $129.7 million less in commercial paper, and repaying $23 .3 million more for borrowings against the cash surrender value of COLI. Partially offsetting these decreases was our having issued $170.3 million more in common stock and issuing $125.9 million more in long-term debt.
Future Cash Requirements Our business requires significant capital investments. Through 2019, we expect to need cash primarily for utility construction programs designed to improve and expand facilities related to providing electric service, which include, but are not limited to, expenditures to develop new transmission lines and other improvements to our power plants, transmission and distribution lines and equipment. We expect to meet these cash needs with internally generated cash, short-term borrowings and the issuance of securities in the capital markets.
Capital expenditures for 2016 and anticipated capital expenditures, including costs ofremoval, for 2017 through 2019 are shown in the following table.
Actual Projected 2016 2017 2018 2019 (In Thousands)
Generation:
Replacements and other ................................... $ 151,083 $ 173,500 $ 187,000 $ 148,900 Environmental .................................................. 62,307 25,000 28,300 18,600 Wind development. ........................................... 340,535 10,800 5,900 6,300 Nuclear fuel ............................................................. 20,021 45,300 21,100 24,800 Transmission............................................................ 212,168 253,300 246,300 243,700 Distribution .............................................................. 237,107 206,500 184,100 236,500.
Other ........................................................................ 63,749 88,600 87,300 75,200 Total capital expenditures................................. $ 1,086,970 $ 803,000 $ 760,000 $ . 754,000 We prepare these estimates for planning purposes and revise them from time to time. Actual expenditures will differ, perhaps materially, from our estimates due to changes following the closing of the proposed merger with Great Plains Energy, changing regulatory requirements, changing costs, delays or advances in engineering, construction or permitting, changes in the availability and cost of capital and other factors discussed in "Item lA. Risk Factors." We and our generating plant co-owners periodically evaluate these estimates and this may result in material changes in actual costs.
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We will also need significant amounts of cash in the future to meet our long-term debt obligations. The principal amounts of our long-term debt maturities as of December 31, 2016, are as follows.
Long-term Year Long-term debt debt ofVIEs (In Thousands) 2017 ............................. $ 125,000 $ 26,842 2018 ............................ . 28,538 2019 ............................ . 300,000 31,485 2020 ............................ . 250,000 32,254 2021 ............................ . 18,843 Thereafter ................... . 2,876,940 Total maturities .... . $ 3,551,940 $ 137,962 Pension Obligation The amount we contribute to our pension plan for future periods is not yet known, however, in general we expect to fup.d our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.
We contributed $20.2 million to our pension trust in 2016 and $41.0 million in 2015. We expect to contribute approximately $25.2 million in 2017. In 2016 and 2015, we also funded $14.8 million and $5.8 million, respectively, of Wolf Creek's pension plan contributions. In 2017, we plan to contribute $10.8 million to fund Wolf Creek's pension plan contributions. See Notes 12 and 13 of the Notes to Consolidated Financial Statements, "Employee Benefit Plans" and "Wolf Creek Employee Benefit Plans," for additional discussion of Westar Energy and Wolf Creek benefit plans, respectively.
OFF-BALANCE SHEET ARRANGEMENTS We have off-balance sheet arrangements in the form of operating leases and letters of credit entered into in the ordinary course of business. We did not have any additional off-balance sheet arrangements as of December 31, 2016.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS In the course of our business activities, we enter into a variety of contracts and commercial commitments. Some of these result in direct obligations reflected on our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, not reflected in our underlying consolidated financial statements.
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Contractual Cash Obligations The following table summarizes the projected future cash payments for our contractual obligations existing as of December 31, 2016.
Total 2017 2018 - 2019 2020 - 2021 Thereafter (In Thousands)
Long-term debt (a) ............................................. $ 3,551,940 $ 125,000 $ 300,000 $ 250,000 $ 2,876,940 Long-term debt ofVIEs (a)................................ 137,962 26,842 60,023 51,097 Interest on long-term debt (b) ............................ 2,739,464 152,758 288,482. 245,582 2,052,642 Interest on long-term debt ofVIEs ................ :... 8,184 3,070 4,050 1,064 Long-term debt, including interest.. ........... 6,437,550 307,670 652,555 547,743 4,929,582 Pension and post-retirement benefit expected contributions (c) .......................................... 36,600 36,600 Capital leases (d) ................................................ 77,507 5,803 10,823 8,385 52,496 Operating leases (e)............................................ 56,176 13,007 21,933 13,391 7,845 Other obligations ofVIEs (f) ............................. 10,316 5,760 4,556 Fossil fuel (g) ..................................................... 765,187 198,644 342,753 176,907 46,883 Nuclear fuel (h) .................................................. 210,641 38,018 34,832 36,882 100,909 Wind development obligations .......................... 38,076 38,076 Unconditional purchase obligations ................... 379,295 272,635 98,560 8,100 Total contractual obligations (i) .................. $ 8,011,348 $ 916,213 $ 1,166,012 $ 791,408 $ 5,137,715 (a) See Note 10 of the Notes to Consolidated Financial Statements, "Long-Term Debt," for individual maturities.
(b) We calculate interest on our variable rate debt based on the effective interest rates as of December 31, 2016.
(c) Our contribution amounts for future periods are not yet known. See Notes 12 and 13 of the Notes to Consolidated Financial Statements, "Employee Benefit Plans" and "Wolf Creek Employee Benefit Plans," for additional information regarding pension and post-retirement benefits.
(d) Includes principal and interest on capital leases.
(e) Includes leases for operating facilities, operating equipment, office space, office equipment, vehicles and rail cars as well as other miscellaneous commitments.
(f) See Note 18 of the Notes to Consolidated Financial Statements, "Variable Interest Entities," for additional information on VIEs.
(g) Coal and natural gas commodity and transportation contracts.
(h) Uranium concentrates, conversion, enrichment and fabrication.
(i) We have $1.6 million of unrecognized income tax benefits that are not included in this table because we cannot reasonably estimate the timing of the cash payments to taxing authorities assuming those unrecognized income tax benefits are settled at the amounts accrued as of December 31, 2016.
OTHER INFORMATION Changes in Prices See Note 4 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation," for information on our prices.
Wolf Creek Outage Wolf Creek normally operates on an 18-month planned refueling and maintenance outage schedule. As authorized by our regulators, incremental maintenance costs of planned refueling and maintenance outages are deferred and amortized ratably over the period between planned refueling and maintenance outages. In fall of2016, Wolf Creek underwent a planned refueling and maintenance outage. Our share of the outage costs was approximately $24.2 million. The next refueling and maintenance outage is planned for the spring of2018.
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Stock-Based Compensation We use two types ofrestricted share units (RSUs) for our stock-based compensation awards; those with service requirements and those with performance measures. See Note 12 of the Notes to Consolidated Financial Statements, "Employee Benefit Plans," for additional information. Total unrecognized compensation cost related to RSU awards with only service requirements was $5.0 million as of December 31, 2016, and we expect to recognize these costs over a remaining weighted-average period of 1.8 years. Total umecognized compensation cost related to RSU awards with performance measures was $4.5 million as of December 31, 2016, and we expect to recognize these costs over a remaining weighted-average period of 1.7 years. Upon consummation of the merger, all unrecognized compensation costs for outstanding RSU awards will be expensed on our income statement.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Our fuel procurement and energy marketing activities involve primary market risk exposures, including commodity price risk, credit risk and interest rate risk. Commodity price risk is the potential adverse price impact related to the purchase or sale of electricity and energy-related products. Credit risk is the potential adverse financial impact resulting from non-performance by a counterparty of its contractual obligations. Interest rate risk is the potential adverse financial impact related to changes in interest rates. In addition, our investments in trusts to fund nuclear plant decommissioning and to fund non-qualified retirement benefits give rise to security price risk. Many of the securities in these trusts are exposed to price fluctuations in the capital markets.
Commodity Price Risk We engage in both financial and physical trading with the goal of managing our commodity price risk, enhancing system reliability and increasing profits. We procure and trade electricity, coal, natural gas and other energy-related products by utilizing energy commodity contracts and a variety of financial instruments, including futures contracts, options and swaps.
We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers' and our exposure to these market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.
Factors that affect our commodity price exposure are the quantity and availability of fuel used for generation, the availability of our power plants and the quantity of electricity customers consume. Quantities of fossil fuel we use to generate electricity fluctuate from period to period based on availability, price and deliverability of a given fuel type, as well as planned and unscheduled outages at our generating plants that use fossil fuels. Our commodity price exposure is also affected by our nuclear plant refueling and maintenance schedule. Our customers' electricity usage also varies based on weather, the economy and other factors.
We trade various types of fuel primarily to reduce exposure related to the volatility of commodity prices. A significant portion of our coal requirements is purchased under long-term contracts to hedge much of the fuel exposure for customers. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service.
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One way by which we manage and measure the commodity price risk of our trading portfolio is by using a variance/
covariance value-at-risk (VaR) model. In addition to VaR, we employ additional risk control processes such as stress testing, daily loss limits, credit limits and position limits. We expect to use similar control processes in the future. The use ofVaR requires assumptions, including the selection of a confidence level and a measure of volatility associated with potential losses and the estimated holding period. We express VaR as a potential dollar loss based on a 95% confidence level using a one-day holding period and a 20-day historical observation period. It is possible that actual results may differ significantly from assumptions. Accordingly, VaR may not accurately reflect our levels of exposure. The energy trading portfolio VaR amounts for 2016 and 2015 were as follows:
2016 2015 (In Thousands)
High ............... $ 644 $ 514 Low ............... . 123 56 Average .. :...... . 292 199 Interest Rate Risk We have entered into numerous fixed and variable rate debt obligations. For details, see Note 10 of the Notes to Consolidated Financial Statements, "Long-Term Debt." We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other fmancial derivative instruments such as interest rate swaps. We compute and present information about the sensitivity to changes in interest rates for variable rate debt and current maturities of fixed rate debt by assuming a 100 basis point change in the current interest rates applicable to such debt over the remaining time the debt is outstanding.
We had approximately $640.5 million of variable rate debt and current maturities of fixed rate debt as of December 31, 2016. A 100 basis point change in interest rates applicable to this debt would impact income before income taxes on an annualized basis by approximately $6.3 million. As ofDecember 31, 2016, we had $121.9 million of variable rate bonds insured by bond insurers. Interest rates payable under these bonds are normally set through periodic auctions. However, conditions in the credit markets over the past few years caused a dramatic reduction in the demand for auction bonds, which led to failed auctions. The contractual provisions of these securities set forth an indexing formula method by which interest will be paid in the event of an auction failure. Depending on the level of these reference indices, our interest costs may be higher or lower than what they would have been had the securities been auctioned successfully. Additionally, should insurers of those bonds experience a decrease in their credit ratings, such event could increase our borrowing costs. Furthermore, a decline in interest rates generally can serve to increase our pension and post-retirement benefit obligations.
Security Price Risk We maintain the NDT, as required by the NRC and Kansas statute, to fund certain costs of nuclear plant decommissioning. As of December 31, 2016, investments in the NDT were allocated 49% to equity securities, 30% to debt securities, 7% to combination debt/equity/other securities, 9% to alternative investments, 5% to real estate securities and less than 1% to cash equivalents. As of December 31, 2016 and 2015, the fair value of the NDT investments was $200.1 million and $184.1 million, respectively. Changes in interest rates and/or other market changes resulting in a 10% decrease in the value of the securities would have resulted in a $20.0 million decrease in the value of the NDT as of December 31, 2016.
We also maintain a trust to fund non-qualified retirement benefits. As of December 31, 2016, investments in the trust were comprised of 66% equity securities, 33% debt securities and less than 1% cash equivalents. The fair value of the investments in this trust was $34.5 million as of December 31, 2016, and $33.9 million as of December 31, 2015. Changes in interest rates and/or other market changes resulting in a 10% decrease in the value of the securities would have resulted in a
$3.4 million decrease in the value of the trust as of December 31, 2016.
By maintaining diversified portfolios of securities, we seek to optimize the returns to fund the aforementioned obligations within acceptable risk tolerances, including interest rate risk. However, many of the securities in the portfolios are exposed to price fluctuations in the capital markets. If the value of the securities diminishes, the cost of funding the obligations rises. We actively monitor the portfolios by benchmarking the performance of the investments against relevant indices and by maintaining and periodically reviewing the asset allocations in relation to established policy targets. Our exposure to security price risk related to the NDT is in part mitigated because we are currently allowed to recover decommissioning costs in the prices we charge our customers.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS PAGE Management's Report on Internal Control Over Financial Reporting 56 Reports of Independent Registered Public Accounting Firm 57 Financial Statements:
Westar Energy, Inc. and Subsidiaries:
Consolidated Balance Sheets as of December 31, 2016 and 2015 59 Consolidated Statements of Income for the years ended December 31, 2016, 2015, and 2014 60 Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015, and 2014 fil Consolidated Statements of Changes in Eguitv for the years ended December 31, 2016, 2015, and, 2014 62 Notes to Consolidated Financial Statements 63
- 1. Description of Business 63
- 2. Summaty of Significant Accounting Policies 63
- 3. Pending Merger 69
- 4. Rate Matters and Regulation 71
- 5. Financial Instruments and Trading Securities 75
- 6. Financial Investments 78
- 7. Property, Plant and Equipment 80
- 8. Joint Ownership of Utility Plant 81
- 9. Short-Term Debt fil.
- 10. Long-Term Debt 83
- 11. Taxes 85
- 12. Employee Benefit Plans 88
- 13. Wolf Creek Employee Benefit Plans 96
- 14. Commitments and Contingencies lQ.l
- 15. Asset Retirement Obligations 106
- 16. Legal Proceedings 107
- 17. Common Stock 108
- 18. Variable Interest Entities 109
- 19. Leases llQ
- 20. Quarterly Results (Unaudited) 112 Financial Schedules:
Schedule II-Valuation and Qualifying Accounts SCHEDULES OMITTED The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in our consolidated financial statements and schedules presented:
I, III, IV and V.
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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING We are responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company's principal executive and principal financial officers 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 fmancial statements for external purposes in accordance with generally accepted accounting principles (GAAP) and includes those policies and procedures that:
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company; Provide reasonable assurance that transactions are recorded as necessary to permit preparation of fmancial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and 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 fmancial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We assessed the effectiveness of our internal control over fmancfal reporting as of December 31, 2016. In making this assessment, we used the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, we concluded that, as of December 31, 2016, our internal control over fmancial 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 fmancial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Westar Energy, Inc.
Topeka, Kansas We have audited the internal control over financial reporting of Westar Energy, Inc. and subsidiaries (the "Company") as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) 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 financial reporting. 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).
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.
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 generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance ofrecords 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.
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.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated fmancial statements and fmancial statement schedule of the Company as of and for the year ended .
December 31, 2016 and our report dated February 22, 2017 expressed an unqualified opinion on those fmancial statements and fmancial statement schedule.
Isl Deloitte & Touche LLP Kansas City, Missouri February 22, 2017 57
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Westar Energy, Inc.
Topeka, Kansas We have audited the accompanying consolidated balance sheets of Westar Energy, Inc. and subsidiaries (the "Company") as of December 31, 2016 and 2015, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
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.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Westar Energy, Inc. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the Company's internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2017 expressed an unqualified opinion on the Company's internal control over financial reporting.
Isl Deloitte & Touche LLP Kansas City, Missouri February 22, 2017 58
WESTAR ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (Dollars in Thousands, Except Par Values)
As of December 31, 2016 2015 ASSETS CURRENT ASSETS:
Cash and cash equivalents . .. . ...... .. ... . .. ... . ... ... .. ... ... . ... .. ... ... ... . ... .. ... . ... ......... ... .. ... . ... ... .. .......... .. ....... .. ... . ... $ 3,066 $ 3,231 Accounts receivable, net of allowance for doubtful accounts of $6,667 and $5,294, respectively ....... . 288,579 258,286 Fuel inventory and supplies********************************************************************************************:*********************** 300,125 301,294 Taxes receivable ..................................................................................................................................... . 13,000 Prepaid expenses .................................................................................................................................... . 16,528 16,864 Regulatory assets ................................................................................................................................... . 117,383 109,606 Other ...................................................................................................................................................... . 29,701 27,860 Total Current Assets ......................................................................................................................... . 768,382 717,141 PROPERTY, PLANT AND EQUIPMENT, NET ....................................................................................... .
9,248,359 8,524,902 PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEJ,IBST ENTITIES, NET. ...................... ----- 257,904
-'-- 268,239 OTHER ASSETS:
Regulatory assets ................................................................................................................................... . 762,479 751,312 Nuclear decommissioning trust. ............................................................................................................ . 200,122 184,057 Other ...................................................................................................................................................... . 249,828 260,015 Total Other Assets ............................................................................................................................. - - - ---
1,212,429 1,195,384 TOTAL ASSETS........................................................................................................................................... $ 11 487,074 $ 10,705,666 LIABILITIBS AND EQUITY ======= =========
CURRENT LIABILITIES:
Current maturities of long-term debt .................................................................................................... .. $ 125,000 $
Current maturities oflong-term debt of variable interest entities ......................................................... .. 26,842 28,309 Short-term debt ...................................................................................................................................... . _366,700 250,300 Accounts payable .................................................................................................................................. .. 220,522 220,969 Accrued dividends ................................................................................................................................. . 52,885 49,829 Accrued taxes ......................................................................................................................................... . 85,729 83,773 Accrued interest .................................................................................................................................... .. 72,519 71,426 Regulatory liabilities .............................................................................................................................. . 15,760 25,697 Other ....................................................................................................................................... ~ .............. . 81,236 106,632 Total Current Liabilities ................................................................................................................... . 1,047,193 836,935 LONG-TERM LIABILITIES:
Long-term debt, net. .............. :................................................................................................................ . 3,388,670 3,163,950 Long-term debt of variable interest entities, net .................................................................................... . 111,209 138,097 Deferred income taxes ........................................................................................................................... . 1,752,776 1,591,430 Unamortized investment tax credits..................................... :................................................................ .. 210,654 209,763 Regulatory liabilities .............................................................................................................................. . 223,693 267,114 Accrued employee benefits ........._. .......................................................................................................... . 512,412 462,304 Asset retirement obligations .................................................................................................................. . 323,951 275,285 Other ...................................................................................................................................................... . 83,326 88,825 Total Long-Term Liabilities............................................................................................................. . 6,606,691 6,196,768 COMMITMENTS AND CONTINGENCIES (See Notes 14 and 16)
EQUITY:
Westar Energy, Inc. Shareholders' Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,791,153 shares and 141,353,426 shares, respective to each date ........................................ .. 708,956 706,767 Paid-in capital**:_................... :........................................................................................................... : 2,018,317 2,004,124 Retained earnings ............................................................................................................................. . 1,078,602 945,830 Total Westar Energy, Inc. Shareholders' Equity....................................................................... .. 3,805,875 3,656,721 Noncontrolling Interests ......................................................................................................................... . 27,315 15,242 Total Equity................................................................................................................................ . 3,833,190 3,671,963 TOTAL LIABILITIES AND EQUITY ....................................................................................................... . $ 11 487,074 $ 10,705 666
=
The accompanying notes are an integral part of these consolidated financial statements.
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WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
Year Ended December 31, 2016 2015 2014 REVENUES ................................................................................................................ . $ 2,562,087 $ 2,459,164 $ 2,601,703 OPERATING EXPENSES:
Fuel and purchased power ..................................................................................... . 509,496 561,065 705,450 SPP network transmission costs ............................................................................ . 232,763 229,043 218,924 Operating and maintenance .................................................................................. .. 346,313 330,289 367,188 Depreciation and amortization .............................................................................. . 338,519 310,591 286,442 Selling, general and administrative ...................................................................... .. 261,451 250,278 250,439 Taxes other than income tax .................................................................................. . 191,662 156,901 140,302 Total Operating Expenses ................. , ........................ ,..................................... . 1,880,204 1,838,167 1,968,745 INCOME FROM OPERATIONS ............................................................................... . 681,883 620,997 632,958 OTHER INCOME (EXPENSE):
Investment earnings ........................_. ....................................................................... . 9,013 7,799 10,622 Other income ......................................................................................................... . 34,582 19,438 31,522 Other expense ....................................................................................................... .. (18,012) (17,636) (18,389)
Total Other Income.......................................................................................... . 25,583 9,601 23,755 Interest expense ........................................................................................................... . 161,726 176,802 183,118 INCOME BEFORE INCOME TAXES...................................................................... .. 545,740 453,796 473,595 Income tax expense .................................................................................................... .. 184,540 152,000 151,270 NET INCOME............................................................................................................. . 361,200 301,796 322,325 Less: Net income attributable to non controlling interests ........................................... . 14,623 9,867 9,066 NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC. ............................ $
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE
======= ========:::: ========:=::::
346 577 $ 291 929 $ 313 259 OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (see Note 2):
Basic earnings per common share .......................................................................... $ 2.43 $ 2.11 $ 2.40 Diluted earnings per common share ....................................................................... $ 2.43 $ 2.09 $ 2.35 AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING ....................... 142,067,558 137,957,515 130,014,941
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DIVIDENDS DECLARED PER COMMON SHARE ................................................ $ 1.52 $ 1.44 $ 1.40 The accompanying notes are an integral part of these consolidated financial statements.
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WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 2016 2015 2014 CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income.................................................................................................................................... $
Adjustments to reconcile net income to net cash provided by operatin~ activities:
Depreciation and amortization ............................................................................................... .
Amortization of nuclear fuel .................................................................................................. .
Amortization of deferred regulatory gain from sale leaseback. ............................................. .
Amortization of corporate-owned life insurance ........................................ 0.......................... .
Non-cash compensation ......................................................................................................... .
Net deferred income taxes and credits .................................................................................. ..
Allowance for equity funds used during construction .......................................................... ..
Changes in working capital items:
Accounts receivable ............................................................................................................... .
Fuel inventory and supplies ................................................................................................... .
Prepaid expenses and other .................................................................................................... .
Accounts payable ................................................................................................................... .
Accrued taxes ......................................................................................................................... .
Other current liabilities .......................................................................................................... .
Changes in other assets ................................................................................................................ .
Changes in other liabilities........................................................... :****** .......................................... - - - - - ' - -
Cash Flows from Operating Activities.............................................................................. - - - - - -
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment. .................: .............................................................. .
Purchase of securities - trusts ....................................................................................................... .
Sale of securities - tmsts .............................................................................................................. .
Investment in corporate-owned life insurance ............................................................................. .
Proceeds from investment in corporate-owned life insurance ..................................................... .
Investment in affiliated company................................................................................................. .
Other investing activities ............................................................................................................. .
Cash Flows used in Investing Activities ........................................................................... - - - - - -
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net ..................................................................................................................... .
Proceeds from long-term debt. ..................................................................................................... .
Proceeds from long-term debt of variable interest entities ......................................................... ..
Retirements of long-term debt ..................................................................................................... .
Retirements oflong-term debt of variable interest entities .......................................................... .
Repayment of capital leases ......................................................................................................... .
Borrowings against cash surrender value of corporate-owned life insurance ............................ ..
Repayment of borrowings against cash surrender value of corporate-owned life insurance ...... .
Issuance of common stock .......................................................................................................... ..
Distributions to shareholders of non controlling interests ............................................................ .
Cash dividends paid ..................................................................................................................... .
Other financing activities .............................................................................................................. ---~-'----'-
Cash Flows from (used in) Financing Activities............................................................... - - - - - ' - -
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS ................................... ..
CASH AND CASH EQUIVALENTS:
Beginning of period .............:*********** ............................................................................................. - - - - - -
End of period .............................. : ............................................................................. :***** .............. =$========= ========= ========
The accompanying notes are an integral part of these consolidated financial statements.
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WESTAR ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Dollars in Thousands)
Westar Energy, Inc. Shareholders Non-Common Common Paid-in Retained controlling Total stock shares stock capital earnings interests equity Balance as of December 31, 2013 ...... 128,254,229 $ 641,271 $ 1,696,727 $ 724,776 $ 5,757 $ 3,068,531 Net income ........................................... 313,259 9,066 322,325 Issuance of stock .................................. 3,026,239 15,131 72,538 87,669 Issuance of stock for compensation and reinvested dividends ............... 406,986 2,035 7,120 9,155 Tax withholding related to stock compensation................................. (2,092) (2,092)
Dividends declared on common stock
($1.40 per share) ............................ (182,736) (182,736)
Stock compensation expense ............... 7,193 7,193 Tax benefit on stock compensation...... 875 875 Deconsolidation of noncontrolling interests ......................................... (7,342) (7,342)
Distributions to shareholders of noncontrolling interests ................. (1,030) (1,030)
Other .................................................... (1,241) (1,241)
Balance as of December 31, 2014 ...... 131,687,454 658,437 1,781,120 855,299 6,451 3,301,307 Net income ........................................... 291,929 9,867 301,796 Issuance of stock .................................. 9,249,986 46,250 211,748 257,998 Issuance of stock for compensation and reinvested dividends ............... 415,986 2,080 8,373 10,453 Tax withholding related to stock compensation ................................. (3,277) (3,277)
Dividends declared on common stock
. ($1.44 per share) ............................ (201,398) (201,398)
Stock compensation expense ............... 8,250 8,250 Tax benefit on stock compensation...... 1,307 1,307 Distributions to shareholders of noncontrolling interests ................. (1,076) (1,076)
Other .................................................... (3,397) (3,397)
Balance as of December 31, 2015 ...... 141,353,426 706,767 2,004,124 945,830 15,242 3,671,963 Net income ........................................... 346,577 14,623 361,200 Issuance of stock .................................. 48,101 241 2,198 2,439 Issuance of stock for compensation and reinvested dividends ............... 389,626 1,948 7,737 9,685 Tax withholding related to stock compensation................................. (4,979) (4,979)
Dividends declared on common stock
($1.52 per share) ............................ (217,131) (217,131)
Stock compensation expense ............... 9,237 9,237 Distributions to shareholders of non controlling interests ................. (2,550) (2,550)
Cumulative effect of accounting change - stock compensation ........ 3,326 3,326 Balance as of December 31, 2016 ...... 141,791,153 $ 708,956 $ 2,018,317 $ 1,078,602 $ 27,315 $ 3,833,190 The accompanying notes are an integral part of these consolidated financial statements.
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WESTAR ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- 1. DESCRIPTION OF BUSINESS We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to "the Company," we," us," "our" and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term "Westar Energy" refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsi~iaries.
We provide electric generation, transmission and distribution services to approximately 704,000 customers in Kansas.
Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy's wholly-owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.
- 2.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation We prepare our consolidated fmancial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America. Our consolidated fmancial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation.
Use of Management's Estimates When we prepare our consolidated fmancial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities, at the date of our consolidated fmancial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.
Regulatory Accounting We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 4, "Rate Matters and Regulation," for additional information regarding our regulatory assets and liabilities.
Cash and Cash Equivalents We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.
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Fuel Inventory and Supplies We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately.
As of December 31, 2016 2015 (In Thousands)
Fuel inventory.............. $ 107,086 $ 113,438 Supplies ...................... . 193,039 187,856 Fuel inventory and supplies ................ $ 300,125 $ 301,294
==
Property, Plant and Equipment We record the value of property, plant and equipment, including that of VIEs, at cost. For plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the allowed cost of capital used to finance utility construction activity.
We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:
Year Ended December 31, 2016 2015 2014 (Dollars In Thousands)
Borrowed funds ..... ........ .. .. $ 9,964 $ 3,505 $ 12,044 Equity funds ...................... . 11,630 2,075 17,029 Total .............................. $ 21,594 $ 5,580 $ 29,073
=
Average AFUDC Rates. ..... 4.2% 2.7% 6.7%
We charge maintenance costs and replacements of minor items of property. to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.
Depreciation We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated 2.4% in 2016, 2.5% in 2015 and 2.4% in 2014.
Depreciable lives of property, plant and equipment are as follows.
Years Fossil fuel generating facilities ........... 6 to 78 Nuclear fuel generating facility .......... 55 to 71
'.Wind generating facilities ................... 19 to 20 Transmission facilities ........................ 15 to 75 Distribution facilities .......................... 22 to 68 Other ................................................... 5 to 30 64
Nuclear Fuel We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refmement, conversion, enrichment and fabrication. We reflect this at original cost and amortize such amounts to fuel expense based on the quantity of heat consumed during the generation of electricity as measured in millions of British thermal units. The accumulated amortization of nuclear fuel in the reactor was $40.0 million as of December 31, 2016, and $59.1 million as of December 31, 2015. The cost of nuclear fuel charged to fuel and purchased power expense was $26.8 million in 2016,
$27.3 million in 2015 and $27.3 million in 2014.
Cash Surrender Value of Life Insurance We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.
As of December 31, 2016 2015 (In Thousands)
Cash surrender value of policies .................... $ 1,267,349 $ 1,299,408 Borrowings against policies........................... (1,137,360) (1,168,794)
Corporate-owned life insurance, net ....... $ 129,989 $ 130,614
==
We record as income increases in cash surrender value and death benefits. We offset against policy income the interest expense that we incur on policy loans. Income from death benefits is highly variable from period to period.
Revenue Recognition We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.
Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $74.4 million as of December 31, 2016, and $66.0 million as of December 31, 2015.
Allowance for Doubtful Accounts We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management's judgment.
Income Taxes We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.
We record deferred tax assets to the extent capital losses, operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.
The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous.
Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 11, "Taxes," for additional detail on our accounting for income taxes.
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Sales Tax We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect sales tax in our consolidated statements of income.
Earnings Per Share We have participating securities in the form ofunvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS).
To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our forward sale agreements, if any, and RSU s with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.
The following table reconciles our basic and diluted EPS from net income.
Year Ended December 31, 2016 2015 2014 (Dollars In Thousands, Except Per Share Amounts)
Net income .................................................................................................. . $ 361,200 $ 301,796 $ 322,325 Less: Net income attributable to noncontrolling interests ......................... . 14,623 9,867 9,066 Net income attributable to Westar Energy, Inc ........................................... . 346,577 291,929 313,259 Less: Net income allocated to RSUs ......................................................... . 714 646 790 Net income allocated to common stock. ..................................................... . $ 345,863 $ 291,283 $ 312,469' Weighted average equivalent common shares outstanding - basic ............ . 142,067,558 137,957,515 130,014,941 Effect of dilutive securities:
RSUs .................................................................................................. . 407,123 299,198 181,397 Forward sale agreements ................................................................... . 1,021,510 2,628,187 Weighted average equivalent common shares outstanding- diluted (a).... . 142,474,681 139,278,223 132,824,525 Earnings per common share, basic ......... ;................................................... . $ 2.43 $ 2.11 $ 2.40 Earnings per common share, diluted .......................................................... . $ 2.43 $ 2.09 $ 2.35 (a) For the years ended December 31, 2016, 2015 and 2014, we had no antidilutive securities.
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Supplemental Cash Flow Information Year Ended December 31, 2016 2015 2014 (In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized .................................. $ 139,029 $ 161,484 $ 160,292 Interest on financing activities ofVIEs .................................~............................. 5,846 10,430 12,183 Income taxes, net of refunds................................................................................ 13,103 (410) 458 NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions ............................................................. . 151,474 105,169 143,192 Property, plant and equipment ofVIEs .. :............................................................ . (7,342)
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends ........................... . 9,685 10,453 9,155 Deconsolidation ofVIEs ..................................................................................... . (7,342)
Assets acquired through capital leases ................................................................ . 2,744 3,130 8,717 New Accounting Pronouncements We prepare our consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements that may affect our accounting and/or disclosure.
Statement of Cash Flows InAugust 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-15, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Among other clarifications, the guidance requires that cash proceeds received from the settlement of COLI policies be classified as cash inflows from investing activities and that cash payments for premiums on COLI policies may be classified as cash outflows for investing activities, operating activities or a combination of both. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Retrospective application is required. We are evaluating the guidance and do not expect it to have a material impact on our consolidated financial statements.
Stock-based Compensation In March 2016, the FASB issuedASU No. 2016-09 as part of its simplification initiative. The areas for simplification involve several aspects of the accounting for stock-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to adopt effective January 1, 2016.
Prior to the adoption ofASU 2016-09, if the tax deduction for a stock-based payment award exceeded the compensation cost recorded for financial reporting, the additional tax benefit was recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB 's decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits or expense, respectively. Prior to the adoption oftheASU, additional paid-in-capital was not recognized to the extent that an excess tax benefit had not be realized (e.g., due to a carryforward of a net operating loss). Under the ASU, all excess tax benefits previously unrecognized because the related tax deduction had not reduced taxes payable are recognized on a modified retrospective basis as a cumulative-effect adjustment to retained earnings as of the date of adoption. Upon initial adoption, we recorded a $3.3 million cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized as well as a $3.3 million increase in deferred tax assets.
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Further, the issuance ofthisASU reflects the FASB's decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities on the accompanying consolidated statements of cash flows for the years ended December 31, 2015 and 2014, as $1.3 million and $0.9 million higher than as previously reported, respectively.
We have retrospectively presented cash flows used in financing activities as $1.3 million higher for the year ended December 31, 2015, than as previously reported and cash flows from financing activities as $0.9 million lower for the year ended December 31, 2014, than as previously reported.
Leases In February 2016, the FASB issuedASU No. 2016-02, which requires a lessee to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either fmancing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The criteria used to determine lease classification will remain substantially the same, but will be more subjective under the new guidance. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The guidance requires a modified retrospective approach for all leases existing at the earliest period presented, or entered into by the date of initial adoption, with certain practical expedients permitted. In 2016, we started evaluating our current leases to assess the initial impact on our consolidated fmancial results. We continue to evaluate the guidance and believe application of the guidance will result in an increase to our assets and liabilities on our consolidated balance sheet, with minimal impact to our consolidated statement of income. We also continue to monitor unresolved industry issues, including renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts.
Financial Instruments - Credit Losses In June 2016, the FASB issuedASU No. 2016-13, which requires fmancial assets measured at amortized cost be presented at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis. The measurement of expected losses is based upon historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. This guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are evaluating the guidance and have not yet determined the impact on our consolidated fmancial statements.
Financial Instruments - Net Asset Value In May 2015, the FASB issuedASU No. 2015-07, which removes the requirement to categorize certain investments measured at net asset value (NAV) per share within the fair value hierarchy. The guidance is effective for fiscal years beginning after December 15, 2015. We have adopted this guidance as of January 1, 2016. The guidance was adopted retrospectively. The adoption was limited to disclosure and does not have a material impact on our consolidated financial statements. See Note 5, "Financial Instruments and Trading Securities."
Revenue Recognition In May 2014, the FASB issuedASU No. 2014-09, which addresses revenue from contracts with customers.
Subsequent ASU s have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of fmancial statements about the nature, amount, timing and uncertainty ofrevenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method. We continue to analyze the impact of the new revenue standard and relatedASUs. During 2016, initial revenue contract assessments were completed. In summary, material revenue streams were identified and representative contract/transaction types were sampled. We also continue to monitor unresolved industry issues, including items related to contributions in aid of construction, collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. Based upon our completed assessments, we do not expect the impact on our consolidated fmancial statements to be material.
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~
- 3. PENDING MERGER On May 29, 2016, we entered into an agreement and plan of merger (merger) with Great Plains Energy Incorporated (Great Plains Energy), a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock.
The merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement, without prior approval of Great Plains Energy, limits our quarterly dividends declared in 2017 to $0.40 per share, which represents an annualized increase of $0.08 per share, consistent with last year's dividend increase.
The closing of the merger is subject to customary conditions including, among others, receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. Unless otherwise agreed to by the applicants, Kansas law imposes a 300-day time limit on the KCC's review of the joint application. On September 27, 2016, the KCC issued an order setting a procedural schedule for the application, with a KCC order date of April 24, 2017. On December 16, 2016, KCC staff and its representatives filed testimony that, among other things, objected to the proposed merger, stated that no changes could be made to the joint application filed by us and Great Plains Energy that would satisfy the KCC staff and recommended that the KCC reject the merger. Anumber of intervening parties also filed testimony against approval of the merger. On January 9, 2017, we and Great Plains Energy filed rebuttal testimony in response to the KCC staff and the other intervenors explaining why we and Great Plains Energy believe the joint application meets the KCC's merger standards and why the merger is in the public interest. An evidentiary hearing was held at the KCC from January 30, 2017 to February 7, 2017.
In addition, there are two open dockets in Missouri related to the merger. In the first docket, Great Plains Energy sought approval from the Public Service Commission of the State of Missouri (MPSC) to waive certain affiliate transaction rules following the closing of the merger. In this docket, on October 12, 2016, and on October 26, 2016, the MPSC staff and the Office of Public Counsel (OPC), respectively, announced that each had entered into a Stipulation andAgreement with Great Plains Energy that, among other things, provided that MPSC staff and the OPC would not file a complaint, or support another complaint, to assert that the MPSC has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the MPSC. Regarding the second docket, on October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the MPSC seeking to have the MPSC assert jurisdiction over the merger, and various parties have intervened in these complaints. The MPSC dismissed the complaint against us on December 6, 2016, but the complaint against Great Plains Energy remains open. On February 16, 2017, the MPSC indicated at a public meeting that it would assert jurisdiction over the merger, and it requested that an order be prepared to assert jurisdiction. Accordingly, we believe Great Plains Energy will also need approval of the MPSC in order to consummate the merger.
On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger. Approval of the merger application requires action by the FERC commissioners because it is a contested application. The Federal Power Act requires a quorum of three or more commissioners to act on a contested application. Following the resignation of the FERC Chairman effective February 3, 2017, the FERC commission is comprised only of two commissioners and is therefore unable to act on the application. A new commissioner must be appointed by the President of the United States, with the advice and consent of the United States Senate, before FERC will be able to act on the application. If the FERC commissioners do not issue an order on the application within 180 days after the application was deemed complete because of the lack of a quorum, approval of the application may be deemed granted by operation of law, unless an order is issued extending the time for review. The FERC staff has authority to issue an order extending the period for review of the application. Under these circumstances, we do not believe it is likely that the FERC staff will allow approval of our application to be deemed granted. We are unable to predict when FERC will regain a quorum or how the change in commissioners will impact the review of the application.
On July 22, 2016, Wolf Creek filed a request with the Nuclear Regulatory Commission (NRC) to approve an indirect transfer of control of Wolf Creek's operating license.
69
On September 26, 2016, we and Great Plains Energy filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) to complete the merger. We and Great Plains Energy received early termination of the statutory waiting period under the HSRAct on October 21, 2016. Under the HSRAct, a new statutory waiting period will start one year from the date on which an existing waiting period expires, or October 21, 2017. Accordingly, ifthe merger has not closed prior to October 21, 2017, we and Great Plains Energy will need to re-file the necessary HSRAct notifications.
Also on September 26, 2016, the proposed merger was approved by our shareholders. Concurrently, shareholders of Great Plains Energy approved various matters necessary for Great Plains Energy to complete the merger.
The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. If the merger agreement is terminated under these circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million.
The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If (a) the merger agreement is terminated by either party because the end date occurred, or by us because Great Plains Energy is in breach of the merger agreement and (b) prior to such termination, an alternative acquisition proposal is made to Great Plains Energy or its board of directors or has been publicly disclosed and not withdrawn and within 12 months after termination of the merger agreement Great Plains Energy enters into an acquisition proposal, Great Plains Energy must pay us a termination fee of
$180.0 million. In addition, if either party terminates the merger agreement because the end date occurred, or if Great Plains Energy terminates the merger agreement because we are in breach of the merger agreement, and (a) prior to such termination, an alternative acquisition proposal is made to us or our board of directors or is publicly disclosed and not withdrawn, and (b) within 12 months after termination of the merger agreement, we enter into a definitive agreement or consummate a transaction with respect to an acquisition proposal, we must pay Great Plains Energy a termination fee of $280.0 million.
In connection with this transaction, we have incurred merger-related expenses. During 2016, we incurred approximately $10.2 million of merger-related expenses, which are included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately $30.0 million, with the majority of the expenses to coincide with the closing of the merger.
See also Note 16, "Legal Proceedings," for more information on litigation related to the merger.
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- 4. RATE MATTERS AND REGULATION Regulatory Assets and Regulatory Liabilities Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers through the price setting process. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.
As of December 31, 2016 2015 (In Thousands)
Regulatory Assets:
Deferred employee benefit costs ............................................. $ 381,129 $ 353,785 Amounts due from customers for future income taxes, net.... 124,020 144,120 Debt reacquisition costs.......................................................... 115,502 121,631 Depreciation ..... ... .. ............. .............................. .................. ..... 63, 171 65,797 Asset retirement obligations.................................................... 35,487 31,996 Retail energy cost adjustment................................................. 32,451 Treasury yield hedges.............................................................. 25,927 25,634 Wolf Creek outage................................................................... 20,316 16,561 Ad valorem tax........................................................................ 17,637 44,455 Disallowed plant costs............................................................ 15,453 15,639 La Cygne environmental costs................................................ 14,370 15,446 Analog meter unrecovered investment.................................... 8,500 1,454 Energy efficiency program costs............................................. 7,097 7,922 Other regulatory assets ................................. ;.......................... 18,802 16,478 Total regulatory assets ........................................................ $ 879,862 $ 860,918
==
Regulatory Liabilities:
Deferred regulatory gain from sale leaseback......................... $ 70,065 $ 75,560 Pension and other post-retirement benefits costs ................... . 37,172 32,181 Nuclear decommissioning ...................................................... . 34,094 30,659 Jurisdictional allowance for funds used during construction .. 33,119 32,673 La Cygne leasehold dismantling costs ................................... . 27,742 25,330, Kansas tax credits ................................................................... . 13,142 12,857 Purchase power agreement ..................................................... . 9,265 9,972 Removal costs ........................................................................ . 5,663 53,834 Retail energy cost adjustment ................................................ . 12,686 Other regulatory liabilities ..................................................... . 9,191 7,059 Total regulatory liabilities.................................................. $
239,453 $ 292,811
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Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.
Deferred employee benefit costs: Includes $354.6 million for pension and post-retirement benefit obligations and $26.5 million for actual pension expense in excess of the amount of such expense recognized in setting our prices. The increase from 2015 to 2016 is attributable primarily to a decrease in the discount rates used to calculate our and Wolf Creek's pension benefit obligations. During 2017, we will amortize to expense approximately $27.9 million of the benefit obligations and approximately
$6.8 million of the excess pension expense. We are amortizing the excess pension expense over a five-year period. We do not earn a return on this asset.
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Amounts due from customers for future income taxes, net: In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we receive them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled in future prices.
We do not earn a return on this net asset.
Debt reacquisition costs: Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.
Depreciation: Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.
Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 15, "Asset Retirement Obligations." We recover these amounts over the life of the related plant.
We do not earn a return on this asset.
Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. This item represents the actual cost of fuel consumed in producing electricity and the cost of purchased power in excess of the amounts we have collected from customers. We expect to recover in our prices this shortfall over a one-year period. We do not earn a return on this asset.
Treasury yield hedges: Represents the effective portion of treasury yield hedge transactions. This amount will be amortized to interest expense over the term of the related debt. We do not earn a return on this asset.
Wolf Creek outage: We defer the expenses associated with Wolf Creek's scheduled refueling and maintenance outages and amortize these expenses during the period between planned outages. We do not earn a return on this asset.
Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.
Disallowed plant costs: Originally there was a decision to disallow certain costs related to the Wolf Creek plant. Subsequently, in 1987, the KCC revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.
La Cygne environmental costs: Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.
Analog meter unrecovered investment: Represents the deferral ofunrecovered investment of analog meters retired between October 2015 and the next general rate case. Once these amounts are included in base rates established in our next general rate case, we will amortize these amounts over a five-year period. No return on this regulatory asset is allowed.
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Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.
Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.
Below we summarize the nature and period of amortization for each of the regulatory liabilities listed in the table above.
Deferred regulatory gain from sale leaseback: Represents the gain KGE recorded on the 1987 sale and leaseback of its 50% interest in La Cygne unit 2. We amortize the gain over the lease term.
Pension and other post-retirement benefits costs: Includes $7.4 million for pension and post-retirement benefit obligations and $29.8 million for pension and post-retirement expense recognized in setting our prices in excess of actual pension and post-retirement expense. During 2017, we will amortize to expense approximately $0.6 million of the benefit obligations and approximately
$3.4 million of the excess pension and post-retirement expense recognized in setting our prices. We will amortize the excess pension and post-retirement expense over a five-year period.
Nuclear decommissioning: We have a legal obligation to decommission Wolf Creek at the end of its useful life. This amount represents the difference between the fair value of the assets held in a decommissioning trust and the amount recorded for the accumulated accretion and depreciation expense associated with our ARO. See Notes 5, 6 and 15, "Financial Instruments and Trading Securities," "Financial Investments" and "Asset Retirement Obligations, respectively, for information regarding our nuclear decommissioning trust (NDT) and our ARO.
Jurisdictional allowance for funds used during construction: This item represents AFUDC that is accrued subsequent to the time the associated construction charges are included in our rates and prior to the time the related assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.
La Cygne leasehold dismantling costs: We are contractually obligated to dismantle a portion of La Cygne unit 2. This item represents amounts collected but not yet spent to dismantle this unit and the obligation will be discharged as we dismantle the unit.
Kansas tax credits: This item represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.
Purchase power agreement: This item represents the amount included in retail electric rates from customers in excess of the costs incurred by us under the purchase power agreement with Westar Generating. We amortize the amount over a three-year period.
Removal costs: Represents amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations. This liability will be discharged as removal costs are incurred.
Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period.
Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.
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KCC Proceedings General and Abbreviated Rate Reviews In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. If approved, we estimate that the new prices will increase our annual retail revenues by approximately $17.4 million. The KCC is required to issue an order on our request within 240 days of our filing, which is in June 2017.
In September 2015, the KCC issued an order in our state general rate review allowing us to adjust our prices to include, among other things, additional investment in La Cygne environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $78.3 million.
Environmental Costs In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future, we will need to seek approval from the KCC for individual projects. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:
$10.8 million effective in June 2015; and
$11.0 million effective in June 2014.
Transmission Costs We make annual filings with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate (TFR) discussed below. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:
$7.0 million effective in April 2016;
$7.2 million effective in April 2015; and
$41.0 million effective in April 2014.
In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the TFR, along with the reduced return on equity (ROE) as described below. The updated prices were retroactively effective April 2016. We have begun refunding our previously-recorded refund obligation and as of December 31, 2016, we have a remaining refund obligation of $1.3 million, which is included in current regulatory liabilities on our balance sheet.
Property Tax Surcharge We make annual filings with the KCC to adjust our prices to include the cost incurred for property taxes. In October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent four years, the KCC issued orders related to such filings allowing us to adjust our annual retail revenues by approximately:
$26.8 million decrease effective in January 2017;
$5.0 million increase effective in January 2016;
$4.9 million increase effective in January 2015; and
$12.7 million increase effective in January 2014.
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FERC Proceedings In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent four years,' we posted our TFR, which was expected to adjust our annual transmission revenues by approximately:
$29.6 million increase effective in January 2017;
$24.0 million increase effective in January 2016;
$4.6 million decrease effective in January 2015; and
$44.3 million increase effective in January 2014.
In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in a regional transmission organization (RTO). The updated prices were retroactively effective January 2016. This adjustment also reflects estimated recovery of increased transmission capital expenditures and operating costs. We have begun refunding our previously recorded refund obligation and as of December 31, 2016, we have a remaining refund obligation of $1.2 million, which is included in current regulatory liabilities on our balance sheet.
- 5. FINANCIAL INSTRUMENTS AND TRADING SECURITIES Values of Financial Instruments GAAP establishes a hierarchical framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy levels. In addition, we measure certain investments that do not have a readily determinable fair value at NAY, which are not included in the fair value hierarchy. Further explanation of these levels and NAV is summarized below.
Level 1 - Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on public exchanges.
Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable.
The types of assets and liabilities included in level 2 are typically liquid investments in funds which have a readily determinable fair value calculated using daily NAY s, other financial instruments that are comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or other financial instruments priced with models using highly observable inputs.
Level 3 - Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation.
Net Asset Value - Investments that do not have a readily determinable fair value are measured at NAY. These investments do not consider the observability of inputs, therefore, they are not included within the fair value hierarchy. We include in this category investments in private equity, real estate and alternative investment funds that do not have a readily determinable fair value. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments.
We record cash and cash equivalents, short-term borrowings and variable-rate debt on our consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed-rate debt, a level 2 measurement, based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value.
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We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our fixed-rate debt.
As of December 31, 2016 As of December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In Thousands)
Fixed-rate debt..................... $ 3,430,000 $ 3,597,441 $ 3,080,000 $ 3,259,533 Fixed-rate debt of VIEs ....... . 137,962 139,733 166,271 179,030 76
Recurring Fair Value Measurements The following table provides the amounts and their corresponding level of hierarchy for our assets that are measured at fair value.
As of December 31, 2016 Levell Level 2 Level 3 NAV Total (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .......................................... $ $ 56,312 $ $ 5,056 $ 61,368 International equity funds ..................................... 35,944 35,944 Core bond fund ..................................................... 27,423 27,423 High-yield bond fund ............................................ 18,188 18,188 Emerging market bond fund ................................. 14,738 14,738 Combination debt/equity/other funds ................... 13,484 13,484 Alternative investment fund .................................. 18,958 18,958 Real estate securities fund ..................................... 9,946 9,946 Cash equivalents ................................................... 73 73 Total Nuclear Decommissioning Trust... .. 73 166,089 33,960 200,122 Trading Securities:
Domestic equity funds .......................................... 18,364 18,364 International equity fund ....................................... 4,467 4,467 Core bond fund ..................................................... 11,504 11,504 Cash equivalents ................................................... 156 156 Total Trading Securities ............................ 156 34,335 34,491 Total Assets Measured at Fair Value ...................................... $ 229 $ 200,424 $ $ 33,960 $ 234,613 As of December 31, 2015 Level 1 Level 2 Level 3 NAV Total (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .......................................... $ $ 50,872 $ $ 6,050 $ 56,922 International equity funds ..................................... 33,595 33,595 Core bond fund ..................................................... 25,976 25,976 High-yield bond fund ........... :................................ 15,288 15,288 Emerging market bond fund ................................. 13,584 13,584 Combination debt/equity/other funds ................... 11,343 11,343 Alternative investment fund .................................. 16,439 16,439 Real estate securities fund ..................................... 10,823 10,823 Cash equivalents ................................................... 87 87 Total Nuclear Decommissioning Trust.. ... 87 150,658 33,312 184,057 Trading Securities:
Domestic equity funds .......................................... 17,876 17,876 International equity fund ....................................... 4,430 4,430 Core bond fund ..................................................... 11,423 11,423 Cash equivalents ................................................... 159 159 Total Trading Securities ............................ 159 33,729 33,888 Total Assets Measured at Fair Value ...................................... $ 246 $ 184,387 $ - $ 33,312 $ 217,945 77
Some of our investments in the NDT are measured at NAV and do not have readily determinable fair values. These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations, these investments may have redemption restrictions. The following table provides additional information on these investments.
As of December 31, 2016 As ofDecember 31, 2015 As of December 31, 2016 Unfunded Unfunded Redemption Length of Fair Value Commitments Fair Value Commitments Frequency Settlement (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .................... $ 5,056 $ 3,529 $ 6,050 $ 1,948 (a) (a)
Alternative investment fund (b) ...... 18,958 16,439 Quarterly 65 days Real estate securities fund (b) ......... 9,946 10,823 Quarterly 65 days Total Nuclear Decommissioning Trust ....................................... $ 33,960 $ 3,529 $ 33,312 $ 1,948 (a) This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in 2013.
Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner's right to extend the term for up to three additional one-year periods.
(b) There is a holdback on fmal redemptions.
Derivative Instruments Price Risk We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated fmancial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers' and our exposure to market risks through regulatory, operating and fmancing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative fmancial instruments for non-trading purposes.
Interest Rate Risk We have entered into numerous fixed and variable rate debt obligations. For details, see Note 10, "Long-Term Debt."
We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other fmancial derivative instruments such as interest rate swaps.
- 6. FINANCIAL INVESTMENTS We report our investments in equity and debt securities at fair value and use the specific identification method to determine their realized gains and losses. We classify these investments as either trading securities or available-for-sale securities as described below.
Trading Securities We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. These obligations totaled $26.8 million and $27.4 million as of December 31, 2016 and 2015, respectively.
For additional information on our benefit obligations, see Note 12, "Employee Benefit Plans."
As of December 31, 2016 and 2015, we measured the fair value of trust assets at $34.5 million and $33.9 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of 78
income. For the years ended December 31, 2016, 2015 and 2014, we recorded unrealized gains of $2.5 million, $0.4 million and $2.6 million, respectively, on assets still held.
Available-for-Sale Securities We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of December 31, 2016 and 2015.
Using the specific identification method to determine cost, we realized a loss on our available-for-sale securities of
$1.5 million and $0.9 million in 2016 and 2015, respectively. In 2014, we realized a gain on our available-for-sale securities of
$0.1 million. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets.
This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.
The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of December 31, 2016 and 2015.
Gross Unrealized Security Type Cost Gain Loss Fair Value Allocation (Dollars In Thousands)
As of December 31, 2016:
Domestic equity funds ............... $ 53,192 $ 8,295 $ (119) $ 61,368 31%
International equity funds .......... 34,502 2,075 (633) 35,944 18%
Core bond fund .......................... 27,952 (529) 27,423 14%
High-yield bond fund ................. 18,358 (170) 18,188 9%
Emerging market bond fund ...... 16,397 (1,659) 14,738 7%
Combination debt/equity/other funds ....................................... 9,171 4,313 13,484 7%
Alternative investment fund ....... 15,000 3,958 18,958 9%
Real estate securities fund .......... 9,500 446 9,946 5%
Cash equivalents ........................ 73 73 <1%
Total .................................... $ 184,145 $ 19,087 $ (3,110) $ 200,122 100%
As of December 31, 2015:
Domestic equity funds ............... $ 49,488 $ 7,436 $ (2) $ 56,922 32%
International equity funds .......... 33,458 1,372 (1,235) 33,595 18%
Core bond fund .......................... 26,397 (421) 25,976 14%
High-yield bond fund ................. 17,047 (1,759) 15,288 8%
Emerging market bond fund ...... 16,306 (2,722) 13,584 7%
Combination debt/equity/other funds ....................................... 8,239 3,104 11,343 6%
Alternative investment fund ....... 15,000 1,439 16,439 9%
Real estate securities fund .......... 11,026 (203) 10,823 6%
Cash equivalents ........................ 87 87 <1%
Total .................................... $ 177,048 $ 13,351 $ (6,342) $
- 184,057 100%
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The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of December 31, 2016 and 2015.
Less than 12 Months 12 Months or Greater Total Gross Gross Gross Unrealized Unrealized Unrealized Fair Value Losses Fair Value Losses Fair Value Losses (In Thousands)
As of December 31, 2016:
Domestic equity funds .............. $ 1,788 $ (119) $ $ $ 1,788 $ (119)
International equity funds ........ 7,489 (633) 7,489 (633)
Core bond funds ....................... 27,423 (529) 27,423 (529)
High-yield bond fund ............... 18,188 (170) 18,188 (170)
Emerging market bond fund ..... 14,738 (1,659) 14,738 (1,659)
Total ................_.................. $ 29,211 $ (648) $ 40,415 $ (2,462) $ 69,626 $ (3,110)
As of December 31, 2015:
Domestic equity funds .............. $ $ $ 668 $ (2) $ 668 $ (2)
International equity funds ......... 6,717 (1,235) 6,717 (1,235)
Core bond funds ....................... 25,976 (421) 25,976 (421)
High-yield bond fund ............... 15,288 (1,759) 15,288 (1,759)
Emerging market bond fund ..... 13,584 (2,722) 13,584 (2,722)
Real estate securities fund ........ 10,823 (203) 10,823 (203)
Total .................................. $ 41,264 $ (2,180) $ 31,792 $ (4,162) $ 73,056 $ (6,342)
- 7. PROPERTY, PLANT AND EQUIPMENT The following is a summary of our property, plant and equipment balance.
As of December 31, 2016 2015 (In Thousands)
Electric plant in service .......................................... $ 11,986,046 $ 11,449,933 Electric plant acquisition adjustment .................... . 802,318 802,318 Accumulated depreciation ..................................... . (4,404,977) (4,178,885}
. ~. ~- ------
8,383,387 8,073,366 Construction work in progress .............................. . 773,095 349,402 Nuclear fuel, net .................................................... . 61,952 68,349 Plant to be retired, net (a) ...................................... . 29,925 33,785 Net property, plant and equipment.................. $ 9,248,359 $ 8,524,902
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(a) Represents the planned retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.
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The following is a summary of property, plant and equipment ofVIEs.
As of December 31, 2016 2015 (In Thousands)
Electric plant of VIEs ... .. .............. ............. ... ......... $ 497 ,999 $ 497 ,999 Accumulated depreciation ofVIEs ....................... . (240,095) (229,760)
Net property, plant and equipment ofVIEs.... $ 257,904 $ 268,239
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We recorded depreciation expense on property, plant and equipment of$316.7 million in 2016, $287.9 million in 2015 and $263.8 million in 2014. Approximately $9.5 million, $9.6 million and $9.7 million of depreciation expense in 2016, 2015 and 2014, respectively, was attributable to property, plant and equipment ofVIEs.
- 8. JOINT OWNERSHIP OF UTILITY PLANTS Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income and each owner responsible for its own financing. Information relative to our ownership interests in these facilities as of December 31, 2016, is shown in the table below.
In-Service Accumulated Construction Net Ownership Plant Dates Investment Depreciation Work in Progress MW Percentage (Dollars in Thousands)
La Cygne unit 1 (a) ...... June 1973 $ 613,348 $ 163,234 $ 39,096 368 50 JEC unit 1 (a) ............... July 1978 817,402 203,410 7,131 670 92 JEC unit 2 (a) ............... May 1980 567,298 200,296 4,198 675 92 JEC unit 3 (a) ............... May 1983 740,170 325,701 4,108 659 92 Wolf Creek (b) ............. Sept. 1985 1,922,877 842,595 82,756 551 47 State Line ( c) ............... June 2001 111,444 62,332 861 196 40 Total...................... $ 4,772,539 $ 1,797,568 $ 138,150 3,119 (a) Jointly owned with Kansas City Power & Light Company (KCPL). Our 8% leasehold interest in Jeffrey Energy Center (JEC) that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.
(b) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
(c) Jointly owned with Empire District Electric Company.
We include in operating expenses on our consolidated statements of income our share of operating expenses of the above plants. Our share of fuel expense for the above plants is generally based on the amount of power we take from the respective plants. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.
In addition, we also consolidate a VIE that holds our 50% leasehold interest in La Cygne unit 2, which represents 324 MW of net capacity. The VIE's investment in the 50% interest was $392.1 million and accumulated depreciation was
$208. 7 million as of December 31, 2016. We include these amounts in property, plant and equipment of VIEs, net on our consolidated balance sheets. See Note 18, "Variable Interest Entities, for additional information about VIEs.
- 9. SHORT-TERM DEBT In December 2016, Westar Energy extended the term of the $270.0 million revolving credit facility to terminate in February 2018. So long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $400.0 million, subject to lender participation. All borrowings under the facility are secured by KGB first mortgage bonds. As of December 31, 2016 and 2015, Westar Energy had no borrowed amounts or letters of credit outstanding under this revolving credit facility.
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In September 2015, Westar Energy extended the term of its $730.0 million revolving credit facility to terminate in September 2019, $20.7 million of which will expire in September 2017. As long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $1.0 billion, both subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds.
As of December 31, 2016, no amounts had been borrowed and $12.3 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2015, no amounts had been borrowed and $19.2 million of letters of credit had been issued under this revolving credit facility.
Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of$1.0 billion. This program is supported by Westar Energy's revolving credit facilities. Maturities of commercial paper issuances may not exceed 3 65 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes. Westar Energy had $366. 7 million and $250.3 million of commercial paper issued and outstanding aS of December 31, 2016 and 2015, respectively.
In addition, total combined borrowings under Westar Energy's commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time. The weighted average interest rate on short-term borrowings outstanding as of December 31, 2016 and 2015, was 0.96% and 0.77%, respectively. Additional information regarding our short-term debt is as follows.
Year Ended December 31, 2016 2015 (Dollars in Thousands)
Weighted average short-term debt outstanding ........................................... $ 284,700 $ 350,380 Weighted daily average interest rates, excluding fees ................................ . 0.78% 0.48%
Our interest expense on short-term debt was $3.6 million in 2016, $3.0 million in 2015 and $2.0 million in 2014.
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- 10. LONG-TERMDEBT Outstanding Debt The following table summarizes our long-term debt outstanding.
As of December 31 2016 2015 (In Thousands)
Westar Energy First mortgage bond series:
5.15% due 2017 ................................................................................................................... . $ 125,000 $ 125,000 5.10% due 2020 ................................................................................................................... . 250,000 250,000 3.25% due 2025 ................................................................................................................... . 250,000 250,000 2.55% due 2026 ................................................................................................................... . 350,000 4.125% due 2042 ................................................................................................................. . 550,000 550,000 4.10% due 2043 ................................................................................................................... . 430,000 430,000 4.625% due 2043 ................................................................................................................ .. 250,000 250,000 4.25% due 2045 ................................................................................................................... . 300,000 300 000 2,505,000 2,155 000 Pollution control bond series:
Variable due 2032, 1.14% as of.December 31, 2016; 0.02% as of December 31, 2015 ..... . 45,000 45,000 Variable due 2032, 1.32% as of December 31, 2016; 0.02% as of December 31, 2015 ..... . 30 500 30,500 75,500 75,500 KGE First mortgage bond series:
6.70% due 2019 ................................................................................................................... . 300,000 300,000 6.15% due 2023 ................................................................................................................... . 50,000 50,000 6.53% due 2037 ................................................................................................................... . 175,000 175,000 6.64% due 2038 ................................................................................................................... . 100,000 100,000 4.30% due 2044 ................................................................................................................... . 250,000 250,000 875,000 875,000 Pollution control bond series:
Variable due 2027, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015 ..... . 21,940 21,940 4.85% due 2031 ................................................................................................................... . 50,000 2.50% due 2031 ................................................................................................................... . 50,000 Variable due 2032, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015 ..... . 14,500 14,500 Variable due 2032, 1.46% as of December 31, 2016; 0.02% as of December 31, 2015 ..... . 10,000 10,000 96,440 96440 Total long-term debt ..................................................................................................................... . 3,551,940 3,201,940 Unamortized debt discount (a) ...................................................................................................... . (10,358) (10,374)
Unamortized debt issuance expense (a) ...................................................., ................................... . (27,912) (27,616)
Long-term debt due within one year ............................................................................................. . {125,0002
- Long-term debt, net... ................................................. ,.......................................................... $ ===========
3 388 670 ~ 3,163 950 Variable Interest Entities 5.92% due 2019 (b)............................................................................................................... $ 1,157 $ 4,223 5.647% due 2021 (b) ..........................................., ................................................................ . 162,048 2.398% due 2021 (b) ......... :*********************:***************************************************************************** ----~- 136 805 Total long-term debt of variable interest entities ......................................... ,................................ . 137,962 166,271 Unamortized debt premium (a) ..................................................................................................... . 89 135 Long-term debt of variable interest entities .due within one year ................................... ,.............. ---~~~ {26,8422 {28,3092 Long-term debt of variable interest entities, net.. ................................................................. =$=======
111 209 ~ 138 097 (a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.
(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.
The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.
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The amount of Westar Energy first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is subject to certain limitations as described below. The amount of KGB first mortgage bonds authorized by the KGB Mortgage and Deed of Trust, dated April 1, 1940, as supplemented and amended, is limited to a maximum of
$3.5 billion, unless amended further. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. As of December 31, 2016, approximately $931.6 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy's mortgage. As of December 31, 2016, approximately
$1.5 billion principal amount of additional KGB first mortgage bonds could be issued under the most restrictive provisions in KGE's mortgage.
As ofDecember 31, 2016, we had $121.9 million of variable rate, tax-exempt bonds outstanding. While the interest rates for these bonds have been low, we continue to monitor the credit markets and evaluate our options with respect to these bonds.
In January 2017, Westar Energy retired $125.0 million in principal amount of first mortgage bonds bearing a stated interest at 5.15% maturing January 2017.
In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as "Green Bonds," and all proceeds from the bonds will be used in renewable energy projects, primarily the construction of the Western Plains Wind Farm.
Also in June 2016, KGB redeemed and reissued $50.0 million in principal amount pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.
In February 2016, KGB, as lessee to the La Cygne sale-leaseback, effected a redemption and reissuance of
$162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 18, "Variable Interest Entities," for additional information regarding our La Cygne sale-leaseback.
In November 2015, Westar Energy issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 3.25% and maturing December 2025. Concurrently, Westar Energy issued $300.0 million in principal amount of first mortgage bonds bearing stated interest at 4.25% and maturing December 2045.
Also in November 2015, Westar Energy redeemed $300.0 million in principal amount of first mortgage bonds bearing stated interest at 8.625% maturing in December 2018 for $360.9 million which included a call premium. The call premium was recorded as a regulatory asset and is being amortized over the term of the new bonds.
In August 2015, Westar Energy redeemed $150.0 million in principal amount of first mortgage bonds bearing stated interest at 5.875% and maturing July 2036.
In January 2015, Westar Energy redeemed $125.0 million in principal amount of first mortgage bonds bearing stated interest at 5.95% and maturing January 2035.
With the exception of Green Bonds, proceeds from issuances were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.
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Maturities The principal amounts of our long-term debt maturities as of December 31, 2016, are as follows.
Long-term Year Long-term debt debt of VIEs (In Thousands) 2017 ...................................... $ 125,000 $ 26,842' 2018 ..................................... . 28,538 2019 ..................................... . 300,000 31,485 2020 ..................................... . 250,000 32,254 2021 ..................................... . 18,843 Thereafter ............................ . 2,876,940 Total maturities.............. $ 3,551,940 $ 137,962
==
Interest expense on long-term debt, net of debtAFUDC, was $141.4 million in 2016, $152.7 million in 2015 and
$158.8 million in 2014. Interest expense on long-term debt ofVIEs was $4.2 million in 2016, $9.8 million in 2015 and
$11.4 million in 2014.
- 11. TAXES Income tax expense is comprised of the following components.
Year Ended December 31, 2016 2015 2014 (In Thousands)
Income Tax Expense (Benefit):
Current income taxes:
Federal ............................................................................. $ (1,007) $ 327 $ 416 State ................................................................................ . 318 341 (597)
Deferred income taxes:
Federal ........................................................................ :... . 155,230 124,891 124,923 State ................................................................................ . 32,892 29,484 29,657 Investment tax credit amortization .................................... . (2,893) (3,043) (3,129)
Income tax expense................................................... $ 184,540 $ 152,000 $ 151,270
==
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The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.
As of December 31, 2016 2015 (In Thousands)
Deferred tax assets:
Tax credit carryforward (a)............................................................. $ 265,750 $ 266,963 Deferred employee benefit costs .................................................... . 137,337 122,757 Net operating loss carryforward (b) ............................................... . 86,693 129,232 Deferred state income taxes ........................................................... . 73,294 67,307 Deferred compensation .................................................................. . 31,981 27,266 Deferred regulatory gain on sale-leaseback ................................... . 30,868 33,287 Alternative minimum tax carryforward (c) .................................... . 29,412 26,725 Accrued liabilities ..... :.................................................................... . 21,757 21,115 LaCygne dismantling cost .............................................................. . 10,972 10,018 Disallowed costs............................................................................. . 9,600 10,211 Capital loss carryforward ............................................................... . 1,668 Other............................................................................................... . 47,200 41,319 Total gross deferred tax assets .................................................... . 744,864 757,868 Less: Valuation allowance............................................................. .
1,668 Deferred tax assets....................................................................... $ 744,864 $ 756,200 Deferred tax liabilities:
Accelerated depreciation................................................................. $ 1,925,270 $ 1,787,457 Acquisition premium...................................................................... . 147,868 155,881 Deferred employee benefit costs .................................................... . 137,337 122,757 Amounts due from customers for future income taxes, net ........... . 124,020 144,120
~.
Deferred state income taxes ........................................................... . 61,110 59,787 Debt reacquisition costs ................................................................. . 41,753 42,314 Pension expense tracker ................................................................. . 5,560 12,051 Other............................................................................................... . 54,722 23,263 Total deferred tax liabilities......................................................... $
2,497,640 $ 2,347,630 Net deferred income tax liabilities......................................................... $ 1,752,776 $ 1,591,430
==
(a) Based on filed tax returns and amounts expected to be reported in current year tax returns (December 31, 2016), we had available federal general business tax credits of $88.4 million and state investment tax credits of $177.3 million. The federal general business tax credits were primarily generated from production tax credits. These tax credits expire beginning in 2020 and ending in 2036.
The state investment tax credits expire beginning in 2021 and ending in 2032.
(b) As of December 31, 2016, we had a federal net operating loss carryforward of $198.1 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2032 and ending in 2035.
(c) As of December 31, 2016, we had available an alternative minimum tax credit carryforward of $29.4 million, which has an unlimited carryforward period In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers at corporate income tax rates higher than current income tax rates. The price reduction will occur as the temporary differences resulting in the excess deferred income tax liabilities reverse. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. The net deferred income tax liability related to these temporary differences is classified above as amounts due from customers for future income taxes, net.
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Our effective income tax rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective income tax rates and the federal statutory income tax rates are as follows.
Year Ended December 31, 2016 2015 2014 Statutory federal income tax rate .................................................. . 35.0% 35.0% 35.0%
Effect of:
COLI policies ........................................................................ . (4.2) (4.4) (4.0)
State income taxes ................................................................. . 4.0 4.3 4.0 Flow through depreciation for plant-related differences ....... . 3.1 2.6 2.0 Production tax credits ............................................................ . (1.8) (2.1) (2.1)
Non-controlling interest ........................................................ . (0.9) (0.8) (0.7)
AFUDC equity ...................................................................... . (0.8) (0.2) (1.3)
Amortization of federal investment tax credits ..................... . (0.5) (0.7) (0.7)
Share based payments ........................................................... . (0.5) (0.1)
Capital loss utilization carryforward ..................................... . 0.4 (0.1) (0.3)
Liability for unrecognized income tax benefits ..................... . (0.2)
Other ...................................................................................... . 0.2 Effective income tax rate .............................................................. . 33.8% 33.5% 31.9%
We file income tax returns in the U.S. federal jurisdiction as well as various state jurisdictions. The income tax returns we file will likely be audited by the Internal Revenue Service or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year 2013 and forward.
The unrecognized income tax benefits decreased from $2.9 million at December 31, 2015, to $2.8 million at December 31, 2016. The decrease for unrecognized income tax benefits was primarily attributable to tax positions expected to be taken with respect to potential deductions related to an environmental settlement agreement in a tax period for which the statute of limitations has closed. We do not expect significant changes in the unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amounts of unrecognized income tax benefits is as follows:
2016 2015 2014 (In Thousands)
.Unrecognized income tax benefits as of January 1 ......... :................. :............... . $ 2,901 $ 3,188 $ 1,703 Additions based on tax positions related to the current year ............................. . 434 410 872 Additions for tax positions of prior years .......................................................... . 813 Reductions for tax positions of prior years ........................................................ . (1) (86) (200)
Lapse of statute of limitations ............................................................................ . (568) (611)
Settlements ......................................................................................................... .
Unrecognized income tax benefits as of December 31 ..................................... . $ 2,766 $ 2,901 $ 3,188
==
The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate, were $2.7 million, $2.9 million and $3.2 million (net of tax) as of December 31, 2016, 2015 and 2014, respectively.
Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of December 31, 2016 and 2015, we had no amounts accrued for interest related to unrecognized income tax benefits. We accrued no penalties at either December 31, 2016 or 2015.
As of December 31, 2016 and 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.
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- 12. EMPLOYEE BENEFIT PLANS Pension and Post-Retirement Benefit Plans We maintain a qualified non-contributory defmed benefit pension plan covering substantially all of our employees.
For the majority of our employees, pension benefits are based on years of service and an employee's compensation during the 60 highest paid consecutive months out of 120 before retirement. Non-union employees hired after December 31, 2001, and union employees hired after December 31, 2011, are covered by the same defmed benefit pension plan; however, their benefits are derived from a cash balance account formula. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain retired executive officers. We have discontinued accruing any future benefits under this non-qualified plan.
The amount we contribute to our pension plan for future periods is not yet known, however, we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.
In addition to providing pension benefits, we provide certain post-retirement health care and life insurance benefits for substantially all retired employees. We accrue and recover in our prices the costs of post-retirement benefits during an employee's years of service. In 2014 and prior years, our retirees were covered under a health insurance policy. In January 2015, we began giving our retirees a fixed annual allowance, which provides them the flexibility to obtain health coverage in the marketplace that is tailored to their needs.
As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. See Note 13, "Wolf Creek Employee Benefit Plans," for information about Wolf Creek's benefit plans.
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The following tables summarize the status of our pension and post-retirement benefit plans.
Pension Benefits Post-retirement Benefits As of December 31, 2016 2015 2016 2015 (In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year ......................................... $ 965,193 $ 1,030,645 $ 126,284 $ 141,516 Service cost ................................................................................. 18,563 21,392 1,084 1,443 Interest cost ................................................................................. 43,723 43,014 5,571 5,691 Plan participants' contributions................................................... 395 582 Benefits paid ............................................................................... (63,540) (44,945) (7,697) (6,549)
Actuarial losses (gains) ............................................................... 51,482 (90,644) 3,926 (16,399)
Amendments ............................................................................... (3,397) 5,731 Benefit obligation, end of year (a) ....................................... $ 1,012,024 $ 965,193 $ 129,563 $ 126,284 Change in Plan Assets:
Fair value of plan assets, beginning of year ................................ $ 653,945 $ 661,141 $ 115,416 $ 121,349 Actual return on plan assets ........................................................ 45,181 (6,948) 7,274 (208)
Employer contributions ............................................................... 20,200 41,000 Plan participants' contributions................................................... 356 534 Benefits paid ............................................................................... (60,852) (41,248) (7,427) (6,259)
Fair value of plan assets, end of year .................................... $ 658,474 $ 653,945 $ 115,619 $ 115,416 Funded status, end of year ................................................................... $ (353,550) $ (311,248) $ (13,944) $ (10,868)
- Amounts Recognized in the Balance Sheets Consist of:
Current liability ........................................................................... $ (2,260) $ (2,745) $ (284) $ (344)
Noncurrent liability ..................................................................... (351,290) (308,503) (13,660) (10,524)
Net amount recognized ......................................................... $ (353,550) $ (311,248) $ (13,944) $ (10,868)
Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain) .............................................................. $ 282,462 $ 254,085 $ (7,603) $ (12,208)
Prior service cost ......................................................................... 3,913 8,078 2,674 3,130 Net amount recognized ......................................................... $ 286,375 $ 262,163 $ (4,929) $ (9,078)
(a) As of December 31, 2016 and 2015, pension benefits include non-qualified benefit obligations of $26. 8 million and $2 7.4 million, respectively, which are funded by a trust containing assets of $34.5 million and $33.9 million, respectively, classified as trading securities. The assets in the aforementioned trust are not included in the table above. See Notes 5 and 6, "Financial Instruments and Trading Securities" and "Financial Investments," respectively, for additional information regarding these amounts.
Pension Benefits Post-retirement Benefits As of December 31, 2016 2015 2016 2015 (Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation........................................................ $ 1,012,024 $ 965,193 $ $
Fair value of plan assets ............................................................. . 658,474 653,945 Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation.................................................. $ 905,661 $ 864,263 $ $
Fair value of plan assets ............................................................. . 658,474 653,945 Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation........................ $ $ $ 129,563 $ 126,284 Fair value of plan assets ............................................................. . 115,619 115,416 Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate .............................................................................. . 4.25% 4.60% 4.15% 4.51%
Compensation rate increase ....................................................... . 4.00% 4.00%
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We use a measurement date of December 31 for our pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year's pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan's projected benefit payments discounted at this rate with the market value of the bonds selected. The decrease in the discount rates used as of December 31, 2016, increased the pension and post-retirement benefit obligations by approximately $50.2 million and $5.0 million, respectively.
We amortize prior service cost on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. We amortize the net actuarial gain or loss on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. The KCC allows us to record a regulatory asset or liability to track the cumulative difference between current year pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. We accumulate such regulatory asset or liability between general rate reviews and amortize the accumulated amount as part of resetting our base prices. Following is additional information regarding our pension and post-retirement benefit plans.
Pension Benefits Post-retirement Benefits Year Ended December 31, 2016 2015 2014 2016 2015 2014 (Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost..................................................... $ 18,563 $ 21,392 $ 16,218 $ 1,084 $ 1,443 $ 1,381 Interest cost .................................................... . 43,723 43,014 41,600 5,571 5,691 6,351 Expected return on plan assets ....................... . (42,653) (40,236) (36,438) (6,835) (6,614) (6,576)
Amortization of unrecognized:
Prior service costs .................................... . 768 520 526 455 455 2,524 Actuarial loss (gain), net .......................... . 20,577 32,131 19,362 (1,118) 379 (742)
Net periodic cost (benefit) before regulatory adjustment ............................................... . 40,978 56,821 41,268 (843) 1,354 2,938 Regulatory adjustment (a) .............................. . 14,528 6,886 15,479 (1,922) 4,096 4,499 Net periodic cost (benefit) .............................. $ 55,506
$ 63,707 $ 56,747 $ (2,765) $ 5,450 $ 7,437
=
Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial loss (gain).................... $ 48,954 $ (43,4.59) $ 162,569 $ 3,486 $ (9,576) $ 15,896 Amortization of actuarial (loss) gain ............. . (20,577) (32,379) (19,362) 1,118 (379) 742 Current year prior service cost ....................... . (3,397) 5,730 (7,834)
Amortization of prior service costs ................ . (768) (520) (526) (455) (455) (2,524)
Other adjustments .......................................... . 352 Total recognized in regulatory assets.............. $ 24,212 $ (70,276) $ 142,681 $ 4,149 $ (10,410) $ 6,280
=
Total recognized in net periodic cost and regulatory assets....................................... $ 79,718 $ (6,569) $ 199,428 $ 1,384 $ (4,960) $ 13,717
=
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
Discount rate .................................................. . 4 ..60% 4.17% 5.07% 4.51% 4.10% 4.88%
Expected long-term return on plan assets ...... . 6.50% 6.50% 6.50% 6.00% 6.00% 6.00%
Compensation rate increase ......... :.................* 4.00% 4.00% 4.00% 4.00% 4.00% 4.00%
(a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.
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We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2017.
Pension Post-retirement Benefits Benefits (In Thousands)
Actuarial loss (gain).............. $ 21,956 $ (780)
Prior service cost ... ......... ....... 683 455 Total................................ $ 22,639 $ (325)
We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned asset classes in the plans' investment portfolios. We select assumed projected rates ofreturn for each asset class after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, we develop an overall expected rate of return for the portfolios, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
Plan Assets We believe we manage pension and post-retirement benefit plan assets in a prudent manner with regard to preserving principal while providing reasonable returns. We have adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of our strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. We delegate the management of our pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by management, which include allowable and/or prohibited investment types. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.
We have established certain prohibited investments for our pension and post-retirement benefit plans. Such prohibited investments include loans to the company or its officers and directors as well as investments in the company's debt or equity securities, except as may occur indirectly through investments in diversified mutual funds. In addition, to reduce concentration of risk, the pension plan will not invest in any fund that holds more than 25% of its total assets to be invested in the securities of one or more issuers conducting their principal business activities in the same industry. This restriction does not apply to investments in securities issued or guaranteed by the U.S. government or its agencies.
Target allocations for our pension plan assets are approximately 39% to debt securities, 39% to equity securities, 12%
to alternative investments such as real estate securities, hedge funds and private equity investments, and the remaining 10% to a fund which provides tactical portfolio overlay by investing in futures related to debt, equity and foreign currency. Our investments in equity include investment funds with underlying investments in domestic and foreign large-, mid- and small-cap companies, derivatives related to such holdings, private equity investments including late-stage venture investments and other investments. Our investments in debt include core and high-yield bonds. Core bonds are comprised of investment funds with underlying investments in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and other debt securities. High-yield bonds include investment funds with underlying investments in non-investment grade debt securities of corporate entities, obligations of foreign governments and their agencies, private debt securities and other debt securities. Real estate securities consist primarily of funds invested in core real estate throughout the U.S. while alternative funds invest in wide ranging investments including equity and debt securities of domestic and foreign corporations, debt securities issued by U.S. and foreign governments and their agencies, structured debt, warrants, exchange-traded funds, derivative instruments, private investment funds and other investments.
Target allocations for our post-retirement benefit plan assets are 65% to equity securities and 35% to debt securities.
Our investments in equity securities include investment funds with underlying investments primarily in domestic and foreign large-, mid- and small-cap companies. Our investments in debt securities include a core bond fund with underlying investments in investment grade debt securities of domestic and foreign corporate entities, obligations of U.S. and foreign governments and their agencies, private placement securities and other investments.
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Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the pension and post-retirement benefits trusts may buy and sell investments resulting in changes within the hierarchy.
See Note 5, "Financial Instruments and Trading Securities, for a description of the hierarchal framework.
The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.
As of December 31, 2016 Level 1 Level 2 Level 3 NAV Total (In Thousands)
Assets:
Domestic equity funds .................................... $ $ 168,407 $ $ 23,580 $ 191,987 International equity fund ................................. 83,738 83,738 Emerging market equity fund ......................... 21,055 21,055 Domestic bond fund ........................................ 101,200 101,200 Core bond funds .............................................. 86,109 86,109 High-yield bond fund ...................................... 30,729 30,729 Emerging market bond fund ........................... 23,584 23,584 Combination debt/equity/other fund ............... 37,851 37,851 Alternative investment funds .......................... 43,686 43,686 Real estate securities fund .............................. 32,390 32,390 Cash equivalents ............................................. 6,145 6,145 Total Assets Measured at Fair Value ................... $ $ 558,818 $ $ 99,656 $ 658,474 As of December 31, 2015 Level 1 Level 2 Level 3 NAV Total Assets: (In Thousands)
Domestic equity funds .................................... $ $ 165,506 $ $ 25,277 $ 190,783 International equity fund ................................. 75,453 75,453 Emerging market equity fund ......................... 20,798 20,798 Domestic bond fund ........................................ 105,279 105,279 Core bond funds .............................................. 99,726 99,726 High-yield bond fund ...................................... 28,288 28,288 Emerging market bond fund ........................... 23,019 23,019 Combination debt/equity/other fund ............... 36,151 36,151 Alternative investment funds .......................... 39,557 39,557 Real estate securities fund .............................. 30,173 30,173 Cash equivalents ............................................. 4,718 4,718 Total Assets Measured at Fair Value ................... $ $ 558,938 $ $ 95,007 $ 653,945 92
The following table provides the fair value of our post-retirement benefit plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.
As of December 31, 2016 Levell Level 2 Level 3 NAV Total (In Thousands)
Assets:
Domestic equity funds ........................ $ $ 61,055 $ $ $ 61,055 International equity fund .................... 15,034 15,034 Core bond funds ................................. 38,952 38,952 Cash equivalents ................................. 578 578 Total Assets Measured at Fair Value. ...... $ $ 115,619 $ $ $ 115,619 As of December 31, 2015 Levell Level 2 Level 3 NAV Total (In Thousands)
Assets:
Domestic equity funds ........................ $ $ 59,946 $ $ $ 59,946 International equity fund .................... 14,419 14,419 Core bond funds ................................. 40,475 40,475 Cash equivalents ................................. 576 576 Total Assets Measured at Fair Value. ...... $ $ 115,416 $ $ $ 115,416 Cash Flows The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.
Pension Benefits Post-retirement Benefits (From) (From)
To/(From) Trust Company Assets To/(From) Trust Company Assets (In Millions)
Expected contributions:
2017.................................. $ 25.2 $
Expected benefit payments:
2017.................................. $ (55.7) $ (2.3) $ (7.8) $ (0.3) 2018 ................................. . (58.1) (2.3) (7.9) (0.3) 2019 ................................. . (60.2) (2.3) (8.1) (0.3) 2020 ................................. . (62.7) (2.2) (8.2) (0.2) 2021 ................................. . (64.4) (2.2) (8.3) (0.2) 2022-2026 ........................ . (325.1) (10.8) (40.2) (0.9)
Savings Plans We maintain a qualified 40l(k) savings plan in which most of our employees participate. We match employees' contributions in cash up to specified maximum limits. Our contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions totaled $8.0 million in 2016, $7.7 million in 2015 and $7.0 million in 2014.
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Stock-Based Compensation Plans We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to 8.3 million shares of common stock may be granted under the LTISA Plan. As of December 31, 2016, awards of approximately 5.2 million shares of common stock had been made under the plan.
All stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as an expense in the consolidated statement of income over the requisite service period. The requisite service periods range from one to four years. However, upon consummation of the merger, all unrecognized compensation costs for outstanding RSU awards will be expensed on our income statement. The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.
Year Ended December 31, 2016 2015 2014 (In Thousands)
Compensation expense ................................................................................... . $ 9,237 $ 8,250 $ 7,193.
Income tax benefits related to stock-based compensation arrangements ....... . 3,653 3,263 2,845 We use RSU awards for our stock-based compensation awards. RSU awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined as nonvested shares and do not include restrictions once the awards have vested.
RSU awards with only service requirements vest solely upon the passage of time. We measure the fair value of these RSU awards based on the market price of the underlying common stock as of the grant date. RSU awards with only service conditions that have a graded vesting schedule are recognized as an expense in the consolidated statement of income on a straight-line basis over the requisite service period for the entire award. Nonforfeitable dividend equivalents, or the rights to receive cash equal to the value of dividends paid on Westar Energy's common stock, are paid on these RSUs during the vesting period.
RSU awards with performance measures vest upon expiration of the award term. The number of shares of common stock awarded upon vesting will vary from 0% to 200% of the RSU award, with performance tied to our total shareholder return relative to the total shareholder return of our peer group. We measure the fair value of these RSU awards using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of the expected volatility and risk-free interest rates. Expected volatility is based on historical volatility over three years using daily stock price observations. The risk-free interest rate is based on treasury constant maturity yields as reported by the Federal Reserve and the length of the performance period. For the 2016 valuation, inputs for expected volatility ranged from 16.9% to 22.4% and the risk-free interest rate was approximately 0.9%. For the 2015 valuation, inputs for expected volatility ranged from 14.6% to 19.1 % and the risk-free interest rate was approximately 1.0%. For these RSU awards, dividend equivalents accumulate over the vesting period and are paid in cash based on the number of shares of common stock awarded upon vesting.
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During the years ended December 31, 2016, 2015 and 2014, our RSU activity for awards with only service requirements was as follows.
As ofDecember 31, 2016 2015 2014 Weighted- Weighted- Weighted-Average Average Average Grant Date Grant Date Grant Date Shares Fair Value Shares Fair Value Shares Fair Value (Shares In Thousands)
Nonvested balance, beginning of year ... . 309.9 $ 35.21 342.2 $ 31.38 352.5 $ 28.38 Granted .................................................. . 99.3 46.35 115.7 39.50 131.5 34.53 Vested .................................................... . (115.9) 32.33 (115.4) 28.77 (118.2) 26.19 Forfeited ................................................. . (3.9) 40.95 (32.6) 33.07 (23.6) 30.00 Nonvested balance, end of year ............. . 289.4 40.11 309.9 35.21 342.2 31.38
=
Total unrecognized compensation cost related to RSU awards with only service requirements was $5.0 million and
$4.5 million as of December 31, 2016 and 2015, respectively. Absent the merger, we expect to recognize these costs over a remaining weighted-average period of 1.8 years. The total fair value ofRSUs with only service requirements that vested during the years ended December 31, 2016, 2015 and 2014, was $5.2 million, $4.7 million and $3.9 million, respectively.
During the years ended December 31, 2016, 2015 and 2014, our RSU activity for awards with performance measures was as follows.
As of December 31, 2016 2015 2014 Weighted- Weighted- Weighted-Average Average Average Grant Date Grant Date Grant Date Shares Fair Value Shares Fair Value Shares Fair Value (Shares In Thousands)
Nonvested balance, beginning of year ... . 299.1 $ 36.00 345.1 $ 32.31 350.l $ 30.35 Granted .................................................. . 100.9 46.03 94.8 40.26 126.1 35.97 Vested .................................................... . (98.5) 31.59 (109.0) 28.99 (108.2) 30.56 Forfeited ................................................. . (3.8) 41.57 (31.8) 34.03 (22.9) 30.70 Nonvested balance, end of year ............. .
297.7 40.79
299.1 36.00 345.1 32.31
=
As of December 31, 2016 and 2015, total unrecognized compensation cost related to RSU awards with performance measures was $4.5 million and $4.0 million, respectively. Absent the merger, we expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value ofRSUs with performance measures that vested during the years ended December 31, 2016, 2015 and 2014, was $7.5 million, $3.1 million and $0.5 million, respectively.
Another component of the LTISA Plan is the Executive Stock for Compensation program under which, in the past, eligible employees were entitled to receive deferred common stock in lieu of current cash compensation. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. Plan participants were awarded 170 shares of common stock for dividends in 2016, 296 shares in 2015 and 403 shares in 2014. Participants received common stock distributions of2,110 shares in 2016, 2,024 shares in 2015 and 1,944 shares in 2014.
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- 13. WOLF CREEK EMPLOYEE BENEFIT PLANS Pension and Post-Retirement Benefit Plans As a co-owner of Wolf Creek, KGB is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. KGB accrues its 47% share of Wolf Creek's cost of pension and post-retirement benefits during the years an employee provides service. The following tables summarize the status ofKGB's 47%
share of the Wolf Creek pension and post-retirement benefit plans.
Pension Benefits Post-retirement Benefits As of December 31, 2016 2015 2016 2015 (In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year ......................................................... . $ 206,418 $ 210,320 $ 7,793 $ 8,240 Service cost ................................................................................................. . 6,748 7,595 127 138 Interest cost ................................................................................................. . 9,655 9,016 325 314 Plan participants' contributions................................................................... . 989 934 Benefits paid .............................................................................................. .. (6,974) (6,217) (1,531) (1,622)
Actuarial losses (gains) ............................................................................... . 13,178 (14,296) (488) (211)
Benefit obligation, end of year ............................................................. .. $ 229,025 $ 206,418 $ 7,215 $ 7,793 Change in Plan Assets:
Fair value of plan assets, beginning of year ............................................... .. $ 121,622 $ 124,660 $ 105 $ 6 Actual return on plan assets ....................................................................... .. 8,967 (2,879) (4)
Employer contributions ............................................................................... . 14,820 5,805 458 787 Plan participants' contributions................................................................... . 989 934 Benefits paid .............................................................................................. .. (6,721) (5,964) (1,531) (1,622)
Fair value of plan assets, end of year .................................................... . $ 138,688 $ 121,622 $ 17 $ 105 Funded status, end of year ................................................................................... . $ (90,337) $ (84,796) $ (7,198) $ (7,688)
Amounts Recognized in the Balance Sheets Consist of:
Current liability ............................................................................................ $ (248) $ (247) $ (538) $ (597)
Non current liability ...................................................................................... (90,089) (84,549) (6,660) (7,091)
Net amount recognized .......................................................................... $ .(90,337) $ (84,796) $ (7,198) $ (7,688)
Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain) ............................................................................... $ 66,324 $ 56,747 $ (654) $ (184)
Prior service cost .......................................................................................... 446 501 Net amount recognized .......................................................................... $ 66,770 $ 57,248 $ (654) $ (184) 96
Pension Benefits Post-retirement Benefits M of December 31, 2016 2015 2016 2015 (Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation......................................................................... $ 229,025 $ 206,418 $ $
Fair value of plan assets .............................................................................. . 138,688 121,622 Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation................................................................... $ 201,963 $ 180,718 $ $
Fair value of plan assets............................................................................... 138,688 121,622 Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation......................................... $ $ $ 7,215 $ 7,793 Fair value of plan assets .............................................................................. . 17 105 Weighted"Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate .............................................................................................. .. 4.26% 4.61% 3.95% 4.27%
Compensation rate increase ........................................................................ . 4.00% 4.00% -% -%
Wolf Creek uses a measurement date of December 31 for its pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year's pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan's projected benefit payments discounted at this rate with the market value of the bonds selected. The decrease in the discount rates used as of December 31, 2016, increased Wolf Creek's pension and post-retirement benefit obligations by approximately $11.2 million and $0.2 million, respectively.
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The prior service cost is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain or loss is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. Following is additional information regarding KGE's 47% share of the Wolf Creek pension and other post-retirement benefit plans.
Pension Benefits Post-retirement Benefits Year Ended December 31, 2016 2015 2014 2016 2015 2014 (Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost .............................................. $ 6,748 $ 7,595 $ 5,695 $ 127 $ 138 $ 173 Interest cost .............................................. 9,655 9,016 8,469 325 314 464 Expected return on plan assets ................. (9,722) (9,044) (8,084)
Amortization of unrecognized:
Prior service costs .............................. 55 57 58 Actuarial loss (gain), net .................... 4,357 5,930 2,987 (14) 3 165 Net periodic cost before regulatory adjustment ......................................... 11,093 13,554 9,125 438 455 802 Regulatory adjustment (a) ........................ 1,886 (1,485) 2,328 Net periodic cost ...................................... $ 12,979 $ 12,069 $ 11,453 $ 438 $ 455 $ 802 Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial loss (gain) ............. $ 13,934 $ (2,373) $ 38,833 $ (484) $ (211) $ (1,881)
Amortization of actuarial (gain) loss ....... (4,357) (5,930) (2,987) 14 (3) (165)
Amortization of prior service cosL ......... (55) (57) (58)
Total recognized in regulatory assets ....... $ 9,522 $ (8,360) $ 35,788 $ (470) $ (214) $ (2,046)
Total recognized in net periodic cost and regulatory assets ................................ $ 22,501 $ 3,709 $ 47,241 $ (32) $ 241 $ (1,244)
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate ............................................ 4.61% 4.20% 5.11% 4.27% 3.89% 4.70%
Expected long-term return on plan assets 7.50% 7.50% 7.50% -% -% -%
Compensation rate increase ..................... 4.00% 4.00% 4.00% -% -% .:__%
(a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.
We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2017.
Pension Post-retirement Benefits Benefits (In Thousands)
Actuarial loss (gain) .............. $ 4,979 $ (50)
Prior service cost .................. . 55 Total. ............................... $ 5,034 $ (50)
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The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans' investment portfolios. Assumed 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 allocations for each asset class, the overall expected rate ofreturn for the portfolios was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
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For measurement purposes, the assumed annual health care cost growth rates were as follows.
As of December 31, 2016 2015 Health care cost trend rate assumed for next year ...................................................... . 6.5% 7.0%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) ...... . 5.0% 5.0%
Year that the rate reaches the ultimate trend rate....................................................... .. 2020 2020 The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.
One- One-Percentage- Percentage-Point Increase Point Decrease (In Thousands)
Effect on total of service and interest cost........... $ (7) $ 7 Effect on post-retirement benefit obligation ........ (126) 133 Plan Assets Wolf Creek's pension and post-retirement plan investment strategy is to manage assets in a prudent manner with regard to preserving principal while providing reasonable returns. It has adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of its strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. Wolf Creek delegates the management of its pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.
The target allocations for Wolf Creek's pension plan assets are 31 % to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies and investment funds with underlying investments similar to those previously mentioned. The investments in debt include core and high-yield bonds. Core bonds include funds invested in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and private debt securities. High-yield bonds include a fund with underlying investments in non-investment grade debt securities of corporate entities, private placements and bank debt.
Real estate securities include funds invested in commercial and residential real estate properties while commodity investments include funds invested in commodity-related instruments.
Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the Wolf Creek pension trust may buy and sell investments resulting in changes within the hierarchy. See Note 5, "Financial Instruments and Trading Securities," for a description of the hierarchal framework.
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The following table provides the fair value ofKGE's 47% share of Wolf Creek's pension plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015.
As of December 31, 2016 Level 1 Level 2 Level 3 NAV Total (In Thousands)
Assets:
Domestic equity funds ..................... $ $ 34,586 $ $ $ 34,586 International equity funds ................ 43,269 43,269 Core bond funds .............................. 35,048 35,048 Real estate securities fund ............... 6,948 6,948 Alternative investment fund ............ 14,073 4,164 18,237 Cash equivalents .............................. 600 600 Total Assets Measured at Fair Value ...... $ $ 127,576 $ $ 11,112 $ 138,688 As of December 31, 2015 Level 1 Level 2 Level 3 NAV Total (In Thousands)
Assets:
Domestic equity funds ..................... $ $ 30,503 $ $ $ 30,503 International equity funds ................ 37,682 37,682 Core bond funds .............................. 30,287 30,287 Real estate securities fund ............... 6,123 6,434 12,557 Commodities fund ........................... 5,811 5,811 Alternative investment fund ............ 4,258 4,258 Cash equivalents, .............................. 524 524 Total Assets Measured at Fair Value ...... $ $ 110,930 $ $ 10,692 $ 121,622 Cash Flows The following table shows our expected cash flows for KGE's 47% share of Wolf Creek's pension and post-retirement benefit plans for future years.
Expected Cash Flows Pension Benefits Post-retirement Benefits (From) (From)
To/(From) Trust Company Assets To/(From) Trust Company Assets (In Millions)
Expected ~ontributions:
2017.................................. $ 10.8 $ 0.6 Expected benefit payments:
2017 .................................. $ (7.2) $ (0.3) $ (2.0) $
2018 ................................. . (8.1) (0.3) (2.3) 2019 ................................. . (9.0) (0.3) (2.6) 2020 ................................. . (9.8) (0.3) (2.9) 2021 ................................. . (10.7) (0.3) (3.2) 2022 - 2026 ..................... .. (66.0) (1.3) (20.2)
Savings Plan Wolf Creek maintains a qualified 40l(k) savings plan in which most of its employees participate. Wolf Creek matches employees' contributions in cash up to specified maximum limits. Wolf Creek's contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives provided under the plan.
KGE's portion of the expense associated with Wolf Creek's matching contributions was $1.6 million in 2016, $1.6 million in 2015 and $1.4 million in 2014.
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- 14. COMMITMENTS AND CONTINGENCIES Purchase Orders and Contracts As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under "-Fuel and Purchased Power Commitments." These commitments relate to purchase obligations issued and outstanding at year-end.
The yearly detail of the aggregate amount ofrequired payments as of December 31, 2016, was as follows.
Committed Amount (In Thousands) 2017 ........................................ :........... $ 310,711 2018 ................................................... . 73,149 2019 .................................................. .. 25,411 Thereafter ........................................... . 8,100 Total amount committed.............. $ 417,371 Environmental Matters Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. Since his inauguration in January 2017, reports and other information that have been released suggest that President Trump may alter federal environmental policy, including through executive orders and influencing changes to statutes, regulations and agency priorities. Due in part to the preliminary nature of information that is available to us, as well as the complex nature of environmental regulation, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below.
Federal Clean Air Act We must comply with the federal Clean Air Act (CAA), state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (S02), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.
Emissions from our generating facilities, including PM, S02 and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze.
Sulfur Dioxide and Nitrogen Oxide Through the combustion of fossil fuels at our generating facilities, we emit S02 and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. Ifwe exceed these limits, we could be subject to fines and penalties. In order to meet S02 and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.
We are subject to the S02 allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its S02 emissions for that year. In 2016, we had adequate S02 allowances to meet generation and we expect to have enough to cover emissions under this program in 2017.
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Cross-State Air Pollution Update Rule In September 2016, the EPA finalized the Cross-State Air Pollution Update Rule. The fmal rule addresses interstate transport ofNOx emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the fmal rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We do not believe this rule will have a material impact on our operations and consolidated fmancial results.
National Ambient Air Quality Standards Under the federal CAA, the EPA sets NAAQS for certain emissions known as the "criteria pollutants" considered harmful to public health and the environment, including two classes of PM, ozone, NOx (a precursor to ozone), CO and S02, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.
In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. In September 2016, the KDHE recommended to the EPA that they designate the state of Kansas as in attainment or in attainment/unclassifiable with the standard. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. If the EPA agrees with an attainment or attainment/unclassifiable designation for the state of Kansas, we do not believe this will have a material impact on our consolidated fmancial results.
In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or consolidated fmancial results.
In 2010, the EPA revised the NAAQS for S02
- In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific S02 emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in January 2017, KDHE formally recommended to the EPA a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the I-hour S02 Data Requirements Rule which governs the next round of the designations. By .agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated fmancial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated fmancial results.
Greenhouse Gases Burning coal and other fossil fuels releases carbon dioxide (C02 ) and other gases referred to as greenhouse gases (GHG). Various regulations under the federal CAA limit C02 and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.
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In October 2015, the EPA published a rule establishing new source performance standards that limit C02 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate C02 emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before the U.S. Court of Appeals for the D.C. Circuit to review the CPP and to conduct the review en bane. Despite the stay, the EPA issued a proposed rule formalizing the details of the CPP's Clean Energy Incentive Program. In January 2017, the EPA denied our Petition for Reconsideration and Administrative Stay of the CPP. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP could be material.
Water We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants.
Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual (CCR) handling.
Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.
In October 2014, the EPA's fmal standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule's impact on those two plants and cannot predict the resulting impact on our operations or consolidated fmancial results, but we do not expect it to be material.
In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a fmal rule, effective August 2015, defming the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion ofregulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. It is believed the stay will last into 2017. We are currently evaluating the fmal rule. We do not believe the rule will have a material impact on our operations or consolidated fmancial results.
Regulation of Coal Combustion Residuals In the course of operating our coal generation plants, we produce CCRs, including fly ash, gypsum and bottom ash.
We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017. We have recorded an ARO for our current estimate for closure of ash disposal ponds but may be required to record additional AROs in the future due to changes in existing CRR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or consolidated fmancial results could be material. See Note 15, "Asset Retirement Obligations," for additional information.
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SPP Revenue Crediting We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has recently completed the process of allocating revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP has determined sponsors are entitled to revenue credits for previously completed upgrades, and members are obligated to pay for revenue credits attributable to these historical upgrades. As a result, we paid the SPP in November 2016 $7.6 million related to revenue credits attributable to historical upgrades from March 2008 to August 2016. Most of the related charges will be recovered from our customers in future prices.
Nuclear Decommissioning Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal ofradioactive components in accordance with NRC requirements. The NRC will terminate a plant's license and release the property for umestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.
The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the updated nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval of a funding schedule prepared by the owner of the plant detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.
In 2014, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately
$360.0 million. This amount compares to the prior site study estimate of $296.2 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.
We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated fmancial results would be materially affected if we were not allowed to recover in our prices the full amount of the funding requirement.
We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately
$5.0 million in.2016, $2.8 million in 2015 and $2.8 million in 2014. We record our investment in the NDT fund at fair value, which approximated $200.1 million and $184.1 million as of December 31, 2016 and 2015, respectively.
Storage of Spent Nuclear Fuel Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE's motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE's application by the end of2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE's application. The NRC has not yet issued its decision.
Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. Wolf Creek is in discussions with the DOE to determine which of its incremental costs may be reimbursable. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.
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Nuclear Insurance We maintain nuclear liability, property and accidental outage insurance for Wolf Creek. These policies contain certain industry standard terms, conditions and exclusions, including, but not limited to, ordinary wear and tear and war. An industry aggregate limit of$3.2 billion for nuclear events ($1.8 billion of non-nuclear events) plus any reinsurance, indemnity or any other source recoverable by Nuclear Electric Insurance Limited (NEIL), our property and accidental outage insurance provider, exists for acts of terrorism affecting Wolf Creek or any other NEIL insured plant within 12 months from the date of the first act.
In addition, we are required to participate in industry-wide retrospective assessment programs as discussed below.
Nuclear Liability Insurance Pursuant to the Price-Anderson Act, we insure against public nuclear liability claims resulting from nuclear incidents to the required limit of public liability, which is approximately $13 .4 billion. This limit of liability consists of the maximum available commercial insurance of$375.0 million and the remaining $13.0 billion is provided through mandatory participation in an industry-wide retrospective assessment program. For incidents after January 1, 2017, this commercial insurance limit increased to $450.0 million. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to $127.3 million (our share is $59.8 million), payable'at no more than $19.0 million (our share is $8.9 million) per incident per year per reactor for any commercial U.S. nuclear reactor qualifying incident. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in 2018. In addition, Congress could impose additional revenue-raising measures to pay claims.
Nuclear Property and Accidental Outage Insurance The owners of Wolf Creek carry decontamination liability, nuclear property damage and premature nuclear decommissioning liability insurance for Wolf Creek totaling approximately $2.8 billion. Insurance coverage for non-nuclear property damage accidents total approximately $2.3 billion. In the event of an extraordinary nuclear accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC.
Our share of any remaining proceeds can be used to pay for property damage or, if certain requirements are met, including decommissioning the plant, toward a shortfall in the NDT fund. The owners also carry additional insurance with NEIL to help 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, we may be subject to retrospective assessments under the current policies of approximately $37.5 million (our share is
$17.6 million).
Nuclear Insurance Considerations Although we maintain various insurance policies to provide coverage for potential loss~s and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in our prices, would have a material effect on our consolidated financial results.
Fuel and Purchased Power Commitments To supply a portion of the fuel requirements for our power plants, the owners of Wolf Creek have entered into various contracts to obtain nuclear fuel and we have entered into various contracts to obtain coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. As of December 31, 2016, our share of Wolf Creek's nuclear.fuel commitments was approximately $16.5 million for uranium concentrates expiring in 2017,
$2.5 million for conversion expiring in 2017, $80.3 million for uranium hexafluoride expiring in 2024, $81.6 million for enrichment expiring in 2027 and $29.7 million for fabrication expiring in 2025. In January 2017, Wolf Creek entered into a new nuclear fuel agreement resulting in an additional commitment, at our share, of approximately $16.4 million for uranium concentrates expiring 2024 and $1.7 million for conversion expiring 2024.
As of December 31, 2016, our coal and coal transportation contract commitments under the remaining terms of the contracts were approximately $659.4 million. The contracts are for plants that we operate and expire at various times through 2020.
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As of December 31, 2016, our natural gas transportation contract commitments under the remaining terms of the contracts were approximately $105.8 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2030.
We have power purchase agreements with the owners of nine separate wind generation facilities with installed design capabilities of approximately 1,328 MW expiring in 2028 through 2036. Each of the agreements provide for our receipt and purchase of energy produced at a fixed price per unit of output. We estimate that our annual cost of energy purchased from these wind generation facilities will be approximately $140.1 million.
FERC Proceedings See Note 4, "Rate Matters and Regulation - FERC Proceedings," for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC.
- 15. ASSET RETIREMENT OBLIGATIONS Legal Liability We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of the ARO is capitalized and depreciated over the remaining life of the asset. We estimate our AROs based on the fair value of the AROs we incurred at the time the related long-lived assets were either acquired, placed in service or when regulations establishing the obligation became effective. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.
We initially recordedAROs at fair value for the estimated cost to decommission Wolf Creek (KGE's 47% share), retire our wind generation facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds, close ash landfills and dispose ofpolychlorinated biphenyl (PCB)-contaminated oil. ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement may be conditional on a future event that may or may not be within the control of the entity. In determining our AROs, we make assumptions regarding probable future disposal costs. A change in these assumptions could have significant impact on the AROs reflected on our consolidated balance sheet.
The following table summarizes our legalAROs included on our consolidated balance sheets in long-term liabilities.
As of December 31, 2016 2015 (In Thousands)
Beginning ARO ............................................................. . $ 275,285 $ 230,668 Increase in ARO liabilities ............................................ . 34,440
. Liabilities settled ........................................................... . (5,372) (1,553)
Accretion expense ......................................................... . 14,165 12,964 Revisions in estimated cash flows ................................. . 39,873 . (1,234)
Ending ARO ........................................................... . $ 323,951 $ 275,285
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In 2015, we recorded an approximately $34.4 million increase in our ARO in response to the EPA's published rule to regulate CCRs. In 2016, we revised our ARO to include an additional $39.9 million to recognize costs associated with closure and post-closure of ash disposal ponds. See Note 14, "Commitments and Contingencies - Regulation of Coal Combustion Residuals," for additional information.
We have an obligation to retire our wind generation facilities and remove the foundations. The ARO related to our owned wind generation facilities was determined based upon the date each wind generation facility was placed into service.
The amount of the retirement obligation related to asbestos disposal was recorded as of 1990, the date when the EPA published the "National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule."
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We operate, as permitted by the state of Kansas, ash landfills and ash disposal ponds at several of our power plants.
The retirement obligations for the ash landfills and ash disposal ponds were determined based upon the date each landfill was originally placed in service.
PCB-contaminated oil is contained within company electrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regulations that originally became effective in 1978.
Non-Legal Liability- Cost of Removal We collect in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of December 31, 2016 and 2015, we had $5.7 million and $53.8 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.
- 16. LEGAL PROCEEDINGS We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Notes 4 and 14, "Rate Matters and Regulation" and "Commitments and Contingencies," for additional information.
Pending Merger Following the announcement of the merger agreement, two putative class action complaints (which were consolidated and superseded by a consolidated complaint) and one putative derivative complaint challenging the merger were filed in the District Court of Shawnee County, Kansas.
The consolidated putative class action complaint, filed on July 25, 2016, is captioned In re Westar Energy, Inc.
Stockholder Litigation, Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger. It also asserts that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that (i) the merger consideration deprives our shareholders of fair consideration for their shares, (ii) the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, (iii) the disclosures are misleading and/or omit material information necessary for our shareholders to make an informed decision whether to vote in favor of the proposed transaction and (iv) ifthe proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, (i) injunctive relief enjoining the merger, (ii) rescission of the merger agreement or rescissory damages, (iii) a directive to members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties and (iv) an award for costs and disbursements, including attorneys' fees and experts' fees.
The putative derivative complaint, filed on July 5, 2016, and as amended on August 25, 2016, is captioned Braunstein
- v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as a nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger. It also asserts that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that the disclosures are false or misleading due to the omission of certain information. The complaint seeks, among other remedies, (i) a direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, (ii) a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, (iii) rescission of the merger agreement, (iv) the imposition of a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, (v) award for costs, including attorneys' fees and experts' fees, and (vi) the imposition of an injunction against the defendants and others from consummating the merger on the terms proposed.
On September 21, 2016, the parties in the consolidated putative class action and the putative derivative complaint independently agreed to withdraw requests for injunctive relief and otherwise agreed in principle to dismissing the actions with 107
prejudice and to providing releases. In exchange, the parties in the putative derivative complaint agreed that we would make supplemental disclosures to the shareholders, which disclosures were made in a Form 8-K filed on September 21, 2016, and the parties in the consolidated putative class action agreed that we would (i) make the disclosures in the Form 8-K filed on September 21, 2016, and (ii) grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in the our sale process. These agreements do not constitute any admission by any of the defendants as to the merits of any claims. In the future the parties will prepare and present to the court for approval Stipulations of Settlement that will, if accepted by the court, settle the actions in their entirety.
- 17. COMMON STOCK General Westar Energy's Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2016 and 2015, Westar Energy had issued 141.8 million shares and 141.4 million shares, respectively.
Westar Energy has a direct stock purchase plan (DSPP). Shares of common stock sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2016 and 2015, Westar Energy issued 0.4 million shares and 0.5 million shares, respectively, through the DSPP and other stock-based plans operated under the long-term incentive and share award plan. As of December 31, 2016 and 2015, a total of 1.0 million shares and 1.2 million shares, respectively, were available under the DSPP registration statement.
Issuances In September 2013, Westar Energy entered into two forward sale agreements with two banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy's common stock from third parties and sold them to a group of underwriters for $31.15 per share. Pursuant to over-allotment options granted to the underwriters, the underwriters purchased in October 2013 an additional 0.9 million shares from the banks as forward sellers, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under each agreement.
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In March 2013, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank. Both agreements expired in March 2016. The maximum amount that Westar Energy could have offered and sold under the master agreement was the lesser of an aggregate of$500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy could have offered and sold shares of its common stock from time to time. The agent received a commission equal to 1% of the sales price of all shares sold under the agreements.
The following table summarizes our common stock activity pursuant to the two forward sale agreements. There was no common stock sale activity under these agreements in 2016.
Year Ended December 31, 2015 2014 Shares that could be settled at beginning of year.............. 9,160,500 12,052,976 Transactions settled (a)..................................................... . 9,160,500 2,892,476 Shares that could be settled at end of year .... :................ . 9,160,500
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(a) The shares settled during the years ended December 31, 2015 and 2014, were settled with a physical settlement amount of approximately $254.6 million and
$82.9 million, respectively.
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The forward sale transactions were entered into at market prices; therefore, the forward sale agreements had no initial fair value. Westar Energy did not receive any proceeds from the sale of common stock under the forward sale agreements until transactions were settled. Westar Energy settled the forward sale transactions through physical share settlement and recorded the forward sale agreements within equity. The shares under the forward sale agreements were initially priced when the transactions were entered into and were subject to certain fixed pricing adjustments during the term of the agreements. The net proceeds from the forward sale transactions represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurred.
Westar Energy used the proceeds from the transactions described above to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.
- 18. VARIABLE INTEREST ENTITIES In determining the primary beneficiary ofa VIE, we assess the entity's purpose and design, including the nature of the entity's activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in JEC and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.
We assess all entities with which we become involved to determine whether such entities are VIEs and, if so, whether or not we are the primary beneficiary of the entities. We also continuously assess whether we are the primary beneficiary of the VIEs with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary.
8% Interest in Jeffrey Energy Center Under an agreement that expires in January 2019, we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust's debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 8% interest in JEC at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.
50% Interest in La Cygne Unit 2 Under an agreement that expires in September 2029, KGB entered into a sale-leaseback transaction with a trust under which the trust purchased KGE's 50% interest in La Cygne unit 2 and subsequently leased it back to KGB. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGB, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant ifthe fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGB effected a redemption and reissuance of the
$162.1 million in outstanding bonds maturing March 2021. See Note 10, "Long-term Debt," for additional information.
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Financial Statement Impact We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIEs described above.
As ofDecember 31, 2016 2015 (In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net.. ...... $ 257,904 $ 268,239 Regulatory assets (a) ........................................................................ . 10,396 9,088 Liabilities:
Current maturities of long-term debt of variable interest entities..... $ 26,842 $ 28,309 Accrued interest (b) ......................................................................... . 867 2,457 Long-term debt of variable interest entities, net.. ............................ . 111,209 138,097 (a) Included in long-term regulatory assets on our consolidated balance sheets.
(b) Included in accrued interest on our consolidated balance sheets.
All of the liabilities noted in the table above relate to the purchase of the property, plant and equipment. The assets of the VIEs can be used only to settle obligations of the VIEs and the VIEs' debt holders have no recourse to our general credit.
We have not provided financial or other support to the VIEs and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIEs.
- 19. LEASES Operating Leases We lease office buildings, computer equipment, vehicles, railcars and other property and equipment. In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term.
Rental expense and estimated future commitments under operating leases are as follows.
Total Operating Year Ended December 31, Leases (In Thousands)
Rental expense:
2014...................................................... $ 14,143 2015 ..................................................... . 14,035 2016 ..................................................... . 13,563 Future commitments:
2017...................................................... $ 13,007 2018 .................................................... .. 11,659 2019 ..................................................... . 10,274 2020 ..................................................... . 7,615 2021 ..................................................... . 5,776 Thereafter ............................................ . 7,845 Total future commitments................ $ 56,176 110
Capital Leases We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements.
Assets recorded under capital leases are listed below.
As of December 31, 2016 2015 (In Thousands)
Vehicles ..................................................... $ 15,595 $ 17,345 Computer equipment ................................ . 1,073 1,204 Generation plant ....................................... . 40,048 40,048 Accumulated amortization .... :.................. . (13,542) (13,477)
Total capital leases................................ $
------ 43,174 $ 45,120
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Capital leases are treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.
Total Capital Year Ended December 31, Leases (In Thousands) 2017 ....................................................................................................... $ 5,803 2018 ..................................................'............................ ;....................... . 5,722 2019 ...................................................................................................... . 5,101 2020 ...................................................................................................... . 4,443 2021 ...................................................................................................... . 3,942 Thereafter ............................................................................................. . 52,496 77,507 Amounts representing imputed interest................................................. (29,900)
Present value of net minimum lease payments under capital leases..... 47,607 Less: Current portion............................................................................. 3,179 Total long-term obligation under capital leases..................................... $ 44,428
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- 20. QUARTERLY RESULTS (UNAUDITED)
Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.
2016 First Second Third Fourth (In Thousands, Except Per Share Amounts)
Revenues (a) ............................................................ $ 569,450 $ 621,448 $ 764,654* $ 606,535 Net income (a) ........................................................ . 68,708 76,144 158,553 57,795 Net income attributable to Westar Energy, Inc. (a). 65,585 72,340 154,720 53,932 Per Share Data (a):
Basic:
Earnings available.......................................... $ 0.46 $ 0.51 $ 1.09 $ 0.38 Diluted:
Earnings available .......................................... $ 0.46 $ 0.51 $ 1.08 $ 0.38 Cash dividend declared per common share............. $ 0.38 $ 0.38 $ 0.38 $ 0.38 Market price per common share:
High .................................................................... $ 50.38 $ 57.25 $ 56.9.5 $ 57.50 Low ..................................................................... $ 40.01 $ 48.92 $ 52.52 $ 54.41 (a) Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.
2015 First Second Third Fourth (In Thousands, Except Per Share Amounts)
'Revenues (a) ............................................................ $ 590,807 $ 589,563 $ 732,829 $ 545,965 Net income (a) ......................................................... 53,163 66,243 140,564 41,826 Net income attributable to Westar Energy, Inc. (a). 50,980 63,710 138,003 39,235 Per Share Data (a):
Basic:
Earnings available .......................................... $ 0.38 $ 0.47 $ 0.97 $ 0.28 Diluted:
Earnings available .............. , ........................... $ 0.38 $ 0.46 $ 0.97 $ 0.28 Cash dividend declared per common share .......... ,.. $ 0.36 $ 0.36 $ 0.36 $ 0.36 Market price per common share:
High .................................................................... $ 44.03 $ 39.65 $ 40.22 $ 43.56 Low ..................................................................... $ 36.58 $ 33.88 $ 34.17 $ 37.55 (a) Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
ITEM9A. CONTROLSANDPROCEDURES We maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports under the Exchange Act is accumulated and communicated to management, including the chief executive officer and the chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of our disclosure controls and procedures, the chief executive officer and the chief financial officer have concluded that our disclosure controls and procedures were effective.
There were no changes in our internal control over financial reporting during the three months ended December 31, 2016, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
See "Item 8. Financial Statements and Supplementary I)ata" for Management's Report On Internal Control Over Financial Reporting and the Independent Registered Public Accounting Firm's report with respect to the effectiveness of internal control over fmancial reporting.
ITEM 9B. OTHER INFORMATION Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. In accordance with SEC guidance, we may also use the Investor Relations section of our website (http://
www.WestarEnergy.com, under "Investors") to communicate with investors about our company. It is possible that the fmancial and other information we post there could be deemed to be material information. The information on our website is not part of this document.
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PART III Information required by Items 10-14 of Part ill of this Form 10-K will be incorporated by reference to our definitive proxy statement with respect to our 2017 Annual Meeting of Shareholders (2017 Proxy Statement), if such definitive proxy statement is filed with the SEC on or before April 30, 2017. Due to the pending Merger with Great Plains Energy, we may not be required to file the 2017 Proxy Statement, in which case we will file an amendment to this Form 10-K on or before April 30, 2017, to include the information that is otherwise incorporated by reference.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information concerning directors required by Item 401 of Regulation S-K will be included under the caption Election of Directors in our 2017 Proxy Statement, and that information is incorporated by reference in this Form 10-K.
Information concerning executive officers required by Item 401 of Regulation S-K is located under Part I, Item 1 of this Form 10-K. The information required by Item 405 of Regulation S-K concerning compliance with Section 16(a) of the Exchange Act will be included under the caption Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance in our 2017 Proxy Statement, and that information is incorporated by reference in this Form 10-K. The information required by Item 406, 407(c)(3), (d)(4) and (d)(5) of Regulation S-K will be included under the captions Election of Directors - Corporate Governance Matters and - Board Meetings and Committees of the Board of Directors in our 2017 Proxy Statement, and that information is incorporated by reference in this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 will be set forth in our 2017 Proxy Statement under the captions Compensation Discussion and Analysis, Compensation Committee Report, Compensation of Executive Officers, Director Compensation and Compensation Committee Interlocks and Insider Participation, and that information is incorporated by reference in this Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by Item 12 will be set forth in our 2017 Proxy Statement under the captions Beneficial Ownership of Voting Securities and Equity Compensation Plan Iriformation, and that information is incorporated by reference in this Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by Item 13 will be set forth in our 2017 Proxy Statement under the caption Election of Directors - Corporate Governance Matters, and that information is incorporated by reference in this Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required by Item 14 will be set forth in our 2017 Proxy Statement under the caption of Ratification and Confirmation of Deloitte and Touche LLP as Our Independent Registered Public Accounting Firm for 2017 and its subsections captioned Independent Registered Accounting Firm Fees and Audit Committee Pre-Approval Policies and Procedures, and that information is incorporated by reference in this Form 10-K.
114
PARTN ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES FINANCIAL STATEMENTS INCLUDED HEREIN Westar Energy, Inc.
Management's Report on Internal Control Over Financial Reporting Reports of Independent Registered Public Accounting Firm Consolidated Balance Sheets as ofDecember 31, 2016 and 2015 Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014 Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014 Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015 and 2014 Notes to Consolidated Financial Statements SCHEDULES Schedule II - Valuation and Qualifying Accounts Schedules omitted as not applicable or not required under the Rules of Regulation S-X: I, III, IV and V.
EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. All exhibits marked with "*" are management contracts or compensatory plans or arrangements required to be identified by Item 15(a)(3) of Form 10-K. All exhibits marked#" are filed with this Form 10-K.
Description 2 Agreement and Plan of Merger, dated as of May 29, 2016, by and among Westar Energy, Inc., Great Plains I Energy Incorporated and a subsidiary of Great Plains Energy Incorporated (filed as Exhibit 2.1 to the Form 8-K filed on May 31, 2016) 3(a) By-laws of Westar Energy, Inc., as amended April 28, 2004 (filed as Exhibit 3(a) to the Form 10-Q for the I period 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 I Exhibit 4 to the Form S-8 Registration Statement, SEC File No. 33-23022 filed on July 15, 1988) 3(c) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3 to I the Form 10-K405 for the period ended December 31, 1998 filed on April 14, 1999) 3(d) Certificate of Correction to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(b) I to the Form 10-K for the period ended December 31, 1991 filed on March 30, 1992) 3(e) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(c) I to the Form 10-K for the period ended December 31, 1994 filed on March 30, 1995) 3(f) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3 to I the Form 10-Q for the period ended June 30, 1994 filed on August 11, 1994) 3(g) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(a) I to the Form 10-Q for the period ended June 30, 1996 filed on August 14, 1996) 3(h) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3 to I the Form 10-Q for the period ended March 31, 1998 filed on May 12, 1998) 3(i) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(1) I to the Form 10-K for the period ended December 31, 2002 filed on April 11, 2003) 3G) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(m) I to the Form 10-K for the period ended December 31, 2002 filed on April 11, 2003) 115
3(k) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(m) I to the Form S-3 Registration Statement No. 333-125828 filed on June 15, 2005) 3(1) Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(m) I to the Form 10-K for the period ended December 31, 2011 filed on February 23, 2012) 4(a) Mortgage and Deed of Trust dated July 1, 1939 between Westar Energy, Inc. and Harris Trust and Savings I Bank, Trustee (filed as Exhibit 4(a) to Registration Statement No. 33-21739) 4(b) First and Second Supplemental Indentures dated July 1, 1939 and April 1, 1949, respectively (filed as I Exhibit 4(b) to Registration Statement No. 33-21739) 4(c) Sixth Supplemental Indenture dated October 4, 1951 (filed as Exhibit 4(b) to Registration Statement No. I 33-21739) 4(d) Fourteenth Supplemental Indenture dated May 1, 1976 (filed as Exhibit 4(b) to Registration Statement No. I 33-21739) 4(e) Twenty-Eighth Supplemental Indenture dated July 1, 1992 (filed as Exhibit 4(o) to the Form 10-K for the I period ended December 31, 1992 filed on March 30, 1993) 4(f) Thirty-Second Supplemental Indenture dated April 15, 1994 (filed as Exhibit 4(s) to the Form 10-K for the I period ended December 31, 1994 filed on March 30, 1995) 4(g) Senior Indenture dated August 1, 1998 (filed as Exhibit 4.1 to the Form 10-Q for the period ended June 30, I 1998 filed on August 12, 1998) 4(h) Form of Senior Note (included in Exhibit 4(g)) I 4(i) Thirty-Fourth Supplemental Indenture dated June 28, 2000 (filed as Exhibit 4(v) to the Form 10-K for the I period ended December 31, 2000 filed on April 2, 2001) 4G) Thirty-Sixth Supplemental Indenture dated as of June 1, 2004, between Westar Energy, Inc. and BNY I Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.1 to the Form 8-K filed on January 18, 2005) 4(k) Thirty-Eighth Supplemental Indenture, dated as of January 18, 2005, between Westar Energy, Inc. and BNY I Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.3 to the Form 8-K filed on January 18, 2005) 4(1) Thirty-Ninth Supplemental Indenture dated June 30, 2005 between Westar Energy, Inc. and BNY Midwest I Trust Company (as successor to Harris Trust and Savings Bank) to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.1 to the Form 8-K filed on July 1, 2005) 4(m) Form of Forty-Second Supplemental Indenture, dated as of March 1, 2012 by and among Westar Energy, I Inc., The Bank of New York Mellon Trust Company, N.A. and Judith L. Bartolini (filed as Exhibit 4.1 to the Form 8-K filed on February 29, 2012) 4(n) Form of Forty-Second Supplemental (Reopening) Indenture, dated as of May 17, 2012 by and among I Westar Energy, Inc., The Bank of New York Mellon Trust Company, N.A. and Judith L. Bartolini (filed as Exhibit 4.1 to the Form 8-K filed on May 16, 2012) 4(o) Form of Forty-Third Supplemental Indenture, dated as ofMarch 28, 2013, by and among Westar Energy, I Inc. and The Bank of New York Mellon Trust Company, N.A., as successor trustee to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on March 22, 2013) 4(p) Form of Forty-Fourth Supplemental Indenture, dated as of August 19, 2013, by and among Westar Energy, I Inc. and The Bank of New York Mellon Trust Company, N.A., as successor trustee to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on August 14, 2013) 4(q) Form of Forty-Fifth Supplemental Indenture, dated as of November 13, 2015, by and among Westar Energy, I Inc. and The Bank of New York Mellon Trust Company, N.A., as successor to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on November 6, 2015) 4(r) Form of Forty-Sixth Supplemental Indenture, dated as of June 20, 2016, by and among Westar Energy, Inc. I and The Bank of New York Mellon Trust Company, N.A., as successor to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on June 17, 2016)
Instruments defining the rights of holders of other long-term debt not required to be filed as Exhibits will be furnished to the Commission upon request.
lO(a) Executive Salary Continuation Plan of Western Resources, Inc., as revised, effective September 22, 1995 I (filed as Exhibit lO(j) to the Form 10-K for the period ended December 31, 1995 filed on March 27, 1996)*
1O(b) Amended and Restated Long-Term Incentive and Share Award Plan (filed as Exhibit 10 to the Form 8-K I filed on May 6, 2011)*
lO(c) Amended and Restated Long-Term Incentive and Share Award Plan, effective January 1, 2016 (filed as I Appendix B to the Proxy Statement filed on April 1, 2016)*
116
lO(d) Westar Energy, Inc. Form of Restricted Share Units Award (Grant Dates Prior to February 22, 2017) (filed I as Exhibit lO(f) to the Form 10-K for the period ended December 31, 2014 filed on February 25, 2015)*
10(e) Westar Energy, Inc. Form of Performance Based Restricted Share Units Award (Grant Dates Prior to I February 22, 2017) (filed as Exhibit lO(g) to the Form 10-K for the period ended December 31, 2014 filed on February 25, 2015)*
lO(f) Westar Energy, Inc. Form of Restricted Share Units Award (Grant Dates February 22, 2017 Forward)* #
IO(g) Westar Energy, Inc. Form of Performance Based Restricted Share Units Award (Grant Dates February 22, #
2017 Forward)*
lO(h) Westar Energy, Inc. Non-Employee Director Deferred Compensation Plan, as amended and restated, dated I as of October 20, 2004 (filed as Exhibit 10.1 to the Form 8-K filed on October 21, 2004)*
lO(i) Summary of Westar Energy, Inc. Non-Employee Director Compensation (filed as Exhibit lO(f) to the Form I 10-K for the period ended December 31, 2015 filed on February 24, 2016)*
lOG) Form of Amended and Restated Change in Control Agreement with Officers of Westar Energy, Inc. (filed as I Exhibit lO(g) to the Form 10-K for the period ended December 31, 2015 filed on February 24, 2016)*
lO(k) Westar Energy, Inc. Retirement Benefit Restoration Plan (filed as Exhibit 10.1 to the Form 8-K filed on I April 2, 2010)*
10(1) Westar Energy, Inc. 401(k) Benefit Restoration Plan (filed as Exhibit 10(1) to the Form 10-K for the period I ended December 31, 2014 filed on February 25, 2015)*
lO(m) Credit Agreement dated as of February 18, 2011, among Westar Energy, Inc. and several banks and other I financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10.1 to the Form 8-K filed on February 22, 2011) lO(n) First Extension Agreement dated as of February 12, 2013, among Westar Energy, Inc. and several banks and I other financial institutions party thereto (filed as Exhibit 10.1 to the Form 8-K filed on February 15, 2013) lO(o) Second Extension Agreement dated as of February 14, 2014, among Westar Energy, Inc. and several banks I and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit lO(v) to the Form 10-K for the period ended December 31, 2013 filed on February 26, 2014) lO(p) First Amendment to Credit Agreement and Lender Joinder Agreement, dated December 19, 2016, by and I among Westar Energy, Inc. and the several banks and other financial institutions or entities from time to time parties thereto (filed as ExhibiU0.1 to the Form 8-K filed on December 20, 2016)
IO(q) Fourth Amended and Restated Credit Agreement dated as of September 29, 2011, among Westar Energy, I Inc. and 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 September 29, 2011) lO(r) First Extension Agreement dated as of July 19, 2013, among Westar Energy, Inc. and several banks and I other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit lO(a) to the Form 10-Q for the period ended September 30, 2014 filed on November 5, 2014) lO(s) Second Extension Agreement dated as of September 18, 2014, among Westar Energy, Inc. and several banks I and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit lO(b) to the Form 10-Q for the period ended September 30, 2014 filed on November 5, 2014) lO(t) Third Extension Agreement dated as of September 17, 2015, among Westar Energy, Inc. and several banks I and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10 to the Form 10-Q for the period ended September 30, 2015 filed on November 3, 2015)
IO(u) Amendment Agreement, dated December 19, 2016, by and among Westar Energy, Inc. and the several I banks and other financial institutions or entities from time to time parties thereto (filed as Exhibit 10.2 to the Form 8-K filed on December 20, 2016) 12 Computations of Ratio of Consolidated Earnings to Fixed Charges #
21 Subsidiaries of the Registrant #
23 Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP #
31(a) Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of2002 #
31(b) Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 #
32 Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of2002 (furnished and not to be #
considered filed as part of the Form 10-K) 101.INS XBRL Instance Document #
101.SCH XBRL Taxonomy Extension Schema Document #
IOI.CAL XBRL Taxonomy Extension Calculation Linkbase Document #
117
101.DEF XBRL Taxonomy Extension Definition Linkbase Document #
101.LAB XBRL Taxonomy Extension Label Linkbase Document #
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document #
118
WESTAR ENERGY, INC. ,
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Balance at Charged to Balance Beginning Costs and at End Description of Period Expenses Deductions (a) of Period
_ "(In Th°-usands)
, Year ended December 31, 2014 Allowances deducted from assets for doubtful accounts ..... ............ ...... ... $ 4,596 $ 9,752 $ (9,039) $ 5,309 Year ended December 31, 2015
! Allowances deducted from assets for doubtful accounts.......................... $ 5,309 $ 8,614 $ (8,629) $ 5,294; I Year ended December 31, 2016 Allowances deducted from assets for doubtful accounts ........... ............... $ '5,294 $ 12,197 $ (10,824) $ 6,667 (a) Result from write-offs of accounts receivable.
119
ITEM 16. FORM 10-K
SUMMARY
None.
120
SIGNATURE Pursuant to the requirements of Sections 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.
WESTAR ENERGY, INC.
Date: February 22, 2017 By: Isl ANTHONY D. SOMMA
~~~~~~~~~~~~~~~~~~~~
Anthony D. Somma Senior Vice President, Chief Financial Officer and Treasurer 121
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.
Signature
/s/ MARK A. RUELLE Director, President and Chief Executive Officer February 22, 2017 (Principal Executive Officer)
(Mark A. Ruelle)
/s/ ANTHONY D. SOMMA Senior Vice President, Chief Financial Officer and Treasurer February 22, 2017 (Principal Financial and Accounting Officer)
(Anthony D. Somma)
/s/ CHARLES Q. CHANDLER IV Chairman of the Board February 22, 2017 (Charles Q. Chandler IV)
/s/ MOLLIE H. CARTER Director February 22, 2017 (Mollie H. Carter)
/s/ R. A. EDWARDS III Director February 22, 2017 (R. A. Edwards III)
/s/ JERRY B. FARLEY Director February 22, 2017 (Jerry B. Farley)
/s/ RICHARD L. HAWLEY Director February 22, 2017 (RichardL. Hawley)
/s/ B. ANTHONY ISAAC Director February 22, 2017 (B. Anthony Isaac)
/s/ SANDRAA. J. LAWRENCE Director February 22, 2017 (Sandra A. J. Lawrence)
/s/ S. CARL SODERSTROM JR. Director February 22, 2017 (S. Carl Soderstrom Jr.)
122
SELECTED FINANCIAL DATA Year Ended December 31 2016 2015 2014'" 2013 1 2012"
!Dollars in millions except per share amounts)
GREAT PLAINS ENERGY Operating revenues $ 2 ,676 $ 2,502 $ 2,568 $ 2,446 $ 2,310 Net income $ 290 $ 213 $ 243 $ 250 $ 200 Basic earnings per common share $ 1.61 $ 1.37 $ 1.57 $ 1.62 $ 1.36 Diluted earnings per common share $ 1.61 $ 1.37 $ 1.57 $ 1.62 $ 1.35 Total assets at year end '" $ 13 ,570 $ 10,739 $ 10,453 $ 9,770 $ 9,626 Total redeemable preferred stock, mandatori ly redeemable preferred securities and long-term debt (including current maturities) $ 3,747 $ 3,746 $ 3,481 $ 3,492 $ 2,999 Cash d1v1dends per common share $ 1.0625 $ 0.9975 $ 0.935 $ 0.8825 $ 0.855 SEC ratio of earnings to combined fixed charges and preferred d1v1dend requirements 2.54 2.58 2.72 2.75 2.31 KCP&L Operating revenues $ 1,875 $ 1,714 $ 1,731 $ 1,671 $ 1,580 Net income $ 225 $ 153 $ 162 $ 169 $ 142 Total assets at year end '" $ 8 ,058 $ 7,815 $ 7,495 $ 6,821 $ 6,689 Total redeemable preferred stock, mandatorily redeemable preferred securities and long-term debt (including current maturities) $ 2 ,565 $ 2,563 $ 2,297 $ 2,294 $ 1,887 SEC ratio of earnings to fixed charges 3.30 2.57 2.69 2.76 2.58 1
- Ad1usted for adoption of Accounting Standard Update !ASUJ No. 2015-03, S1mpllfying the Presentation of Debt Issuance Costs.
GREAT PLAINS ENERGY STOCK PERFORMANCE GRAPH OPERATING REVENUES (Dollars)
!Dollars in millions)
Comparison of Cumu lative Tota l Returns* of Great Plains Energy, S&P 500 Index and EEi Index 2016 $2, 676
- Great Plains Energy S&P 500
- EEi Index
$250 2015 $ 2,502
$200 2014 $ 2.568
$150 2013 $2,446
$100 2012 $2,310
$ 50 2011 2012 2013 2014 2015 2016
-..Total Return assumes remvestment of d1v1dends. Assumes
$100, invested on December 31, 2011, in Great Plains Energy common stock, S&P 500 Index and EE/ Index.
BY EXECUTING UPON OUR PROVEN STRATEGY OF BEST-IN-CLASS OPERATIONS, ENHANCED CUSTOMER ENGAGEMENT AND GROWTH THROUGH TARGETED INVESTMENTS, GREAT PLAINS ENERGY IS PREPARING FOR THE REGION'S BRIGHT ENERGY FUTURE.
An important part of our culture at Great Plains Energy is our commitment to our communities and the environment.
TO OUR SHAREHOLDERS BRIGHT. THE FUTURE OF OUR partner in not only the Wolf Creek COMPANY AND OUR INDUSTRY nuclear power plant, but also the La 2016 was an exciting and busy year Cygne and Jeffrey Energy Center for Great Plains Energy, our region generating stations. Wh ile we were not and our industry. After completing co nvinced that a transaction to increase the last of the rate cases representing in size was necessary to be successful, a ten-year cyc le of generation and the opportunity to com bine with Westar envi ronmental co nstruction, our was compe lling. Altho ugh confident performance in 2016 was confirmation in our stand-alone plan, a combination of the strong foundation we worked with Westar presented a very unique so hard to establish with customers opportunity. Li ke us, Westar is a strong and shareholders. Although actual utility having finished a construction demand growth was lower than cycle similar to ours. After a strategic expected, management of ou r operating eva luation , Westar chose Great Plains OUR INDUSTRY and maintenance expenses, return s Energy as presenting the best merger on our Missouri Energy Efficiency opportunity for their shareholders, CONTINUES TO Investm ent Act investments and customers an d employees. Since the SEE A TRANSITION favorable weather all contributed announcement, we have spent much IN BOTH CUSTOMER to strong financial performance. Much time with shareholders, regulators, of this is the resu lt of a st rategy to invest legislators, ou r commun ities and EXPECTATIONS AND in larger, more efficient generating plants customers discussi ng the significant THEIR NEEDS. AS and add new renewable and energy opportunities for savings and growth efficient opportunities. Going forward, ahead for the most exciting util ity OUR CUSTOMERS we will continue to work in both Kansas combination in our region. The ability HAVE BECOME MORE and Missouri to establish mechanisms to save billions of dollars in costs and DEPENDENT ON for timely recove ry of investments mai ntain a local focus on customers and expenses. and communities will be unmatched ELECTRICITY, THEY by any other utility. As we work to HAVE ALSO BECOME With this sa me long-term strategy finalize regu latory approva ls we in mind , we an nounced on May 29, anticipate closing the transaction MORE EFFICIENT 2016, the acquisition of Westar, our in the second quarter of 2017.
IN THEIR USAGE. neighboring uti lity in Kansas and GREAT PLAINS ENER GY I 2016 ANNUAL REPORT
We believe in connecting with customers to help them better utilize our products. We are developing innovative RESPONSIVE solutions to allow us to better interact with our customers and communities. Through our energy efficiency initiatives we are delivering solutions that are beneficial to customers.
INNOVATE - SHAPING OUR programs to customers through the ("Transource" ), our partnership with INDUSTRY AND OUR REGION Kansas Energy Efficiency Investment Am erican Electric Power. Transource Our industry co nti nues to see a transition Act. During th e meetings with customers recently completed the second and in both customer expec tati ons and th ei r and co mmunities to revi ew th e merger larger of its Missouri transm ission needs. As ou r customers have become process, th e desire for econom ic projects. Th e new transmission line more dependent on electricity, they development and energy efficiency is expected to deliver power more have also become more efficient in programs was a common theme. We efficiently to custome rs and has enabled their usage. Due to this increased also continued to build out our electric the addition of 500 megawatts of new efficiency, demand growth in our veh icle charging network in both wind generation resources . Tran source industry has fl attened dramatica lly Missou ri and Kansas. Our legislative has also participated in numerou s across the country. We see this as an focus , offering of energy effi cient competitive transmission planning opportunity to distinguish ourselves products and services and the building opportunities and recently won a rather than a negative. During the past of our charging network have been done substantial project in the PJM region.
several years, we have worked to pass with an eye toward meeting changing Transource's portfolio of transmission energy efficiency legislation in Missouri customer needs whi le providing projects now tota ls more tha n $600 and helped create the rul es at the consistent shareholder returns. mi ll ion and it is we ll positioned to grow Missouri Public Service Commission its presence in the growing competitive that allows us to offer energy efficiency In addition to our state-regulated utility transmission market.
products to our customers. In 2015, we returns , we continue to make advances worked to pass a similar law in Kansas in the competiti ve transm ission market and expect to expand energy-saving through Tra nsource Energy, LLC ENVIRONMENTAL AND SOCIAL RESPONSIVENESS REDUCED AIR EMISSIONS GENERATION CAPACITY o so 2 o Nox 2005-2016 80 70 55%
/ Coal 60 46%
50 Coal 40 30 20 10 o 2005 2006 20012008 20092010 20 11 2012 2013 2014 2015 2016 Oil Nuclear GREAT PLAI NS ENERGY I 2016 ANNUAL REPORT
Providing safe and top tier customer service and reliability begins with our employees. Our people first culture allows us to draw upon the expertise, practices and experience of our employees to create a more diverse workforce better positioned to adapt to the future needs of our business.
Finally, we continue our strategy ENVIRONMENTAL SUSTAINABILITY Today, Great Plains Energy has nea rly of investing outside of our regulated AND COMMUITY SUPPORT 1,150 megawatts of wind, hydroelectri c, utilities in energy solutions that are An important part of our cu lture and solar capac ity and a selection of complementary to our business. at Great Plains Energy is our energy efficiency programs for our Through GXP Investments, our wholly co mmitment to our communities customers allowing us to reduce our owned subsidiary, we have sought out and the environment. Our customers carbon footp rint. Following the merger and invested in entrepreneu rial and depend on us to be good stewards wi th Westa r, we will have one of the emerging growth compan ies that are of ou r environment and we see this la rgest wind portfolios in the U.S.
working to develop technologies and build as an opportunity to be part of a sol ution and we expect to meet nearly 50 businesses vita l to our country's energy to environme ntal issues, both local percent of ou r retail customers' energy future. We plan to allocate $20 million and global. needs through non-carbon emitting annually for five years to this initiative, reso urces and a balanced, greener, and already see new opportunities that Part of this ongoi ng comm itment cleane r generation portfolio.
drive innovation in our business and includes a transition from primarily those of our customers. Although we're fossil fuel-based generation to more Finally, as we have for decades, still early in the investment cycle, we sustainable renewable and ca rbon -free Great Plains Energy continues to expect this initiative will provide us generation. Ten years ago, we had our be one of the cornerstones of the strategic value, en hanced energy 47 percent ownership in Wolf Creek, a communities we serve. Not only products and services offerings for non-carbon emi tting generation source, do we provide an essential service, our customers, and generate solid but no renewable investments. bu t we strive to be an essential part financ ial returns for our sha reholders. of the fabric of our communities through 2012-2015 2016 2017 AND BEYOND In Missouri , we expanded Ceased burning coal in Reduce annual carbon dioxide output by ENERGY EFFICIENCY PROGRAMS two older units, reducing MILLIONS OF TONS
- carbon dioxide em issions by 18%
'I,
-m-
, I' Began offering SOLAR REBATES Finished deploying more than 1,000 ELECTRIC VEHICLE ENERGY-SAVING PROGRAMS will be expanded to Kansas CHARGING STATIONS (pending approval)
Supporting the Clean Air Act, WE COMPLETED MAJOR Announced 20-year With recent wind contracts, PLANT UPGRADES agreement totaling - I we will have about By end of 2015, we ranked #9 for U.S. Investor-owned utilities 500 MW of wind capacity in Missouri
.l 1,450 MW OF RENEWABLE GENERATION CAPACITY with wind capacity (AWEA U.S.
Wind Industry Annual Market Report)
GREAT PLAINS ENERGY I 2016 ANNUAL REPORT
We are working to build a more diverse, sustainable fleet by adopting clean power and energy efficiency practices.
DIVERSIFIED From electric vehicles to solar and wind energy, we are committed to clean, affordable and reliable energy. In 2016, we completed our first owned solar array. The Greenwood Energy Center's solar panels can produce about 4,700 megawatt-hours annually, enough to serve 440 homes.
DIVIDEND GROWTH CHART ta rgeted donations and investments, Great Plains Energy is preparing 2011 - 2016 based on fourth as we ll as employee volunteerism for the region's bright energy future.
and leadership to orga nizations Wi th strategic investments, we expect quarter declared dividend across ou r footprint each year. to enhance our earnings power and provide further efficiencies and cost We also consider ourselves a cata lyst savings for custome rs. Through
$ 1.10 for econom ic development with in innovative th ought leadership, we are ou r co mmun iti es by providi ng focused on th e opportunities before competitively pri ced power, program s, us. Work ing together as a team, we and initiatives that are essentia l to expect to enhance our total performance businesses relocating to or expanding and deliver cons istent long-term within the region. A healthy business shareholder returns.
environment is essentia l for job retention
$0.98 and creati on , so we team with local and regional partners to offer tools that help strengthen and expa nd
$0.92 our communities.
TERRY BASSHAM BRIGHT - OUR ENERGY FUTURE Chairman of the Board, President By executing upon our prove n strategy and Chief Executive Officer
$0.85 of best-in-class operati ons, en hanced customer engagement and growth 2011 2012 2013 2014 2015 2016 through targeted investments, TODAY, GREAT PLAINS ENERGY HAS NEARLY 1,150 MEGAWATTS OF WIND, HYDROELECTRIC, AND SOLAR CAPACITY AND A SELECTION OF ENERGY EFFICIENCY PROGRAMS FOR OUR CUSTOMERS ALLOWING US TO REDUCE OUR CARBON FOOTPRINT.
GREAT PLAIN S ENERGY I 2016 ANNUAL REPORT
UNITED STATES
. SECURITIES AND EXCHANGE COMMISSION ,
Washington, D.C. 20549 FORM10-K
[X] ANNUAL.REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscafyear ended December 31, 2016 or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to_ __
Exact name of registrant as specified in its 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) 1200 Main Street Kansas City, Missouri 64105 (816) 556-2200 000-51873 KANSAS CITY POWER & LIGHT COMPANY 44-0308720 (A Missouri Corporation) 1200 Main Street Kansas City, Missouri 64105 (816) 556-2200 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:
Registrant Title of each class Great Plains Energy IncorjJorated Common Stock, without par value Depositary .Shares Each Representing a I/20th Interest in a Share of7.00% Series B Mandatory Convertible Preferred Stock.
Securities registered pursuant to Section 12(g) of the Act: Kansas City Power & Light Company Common Stock without par value.
Indicate by check mark ifthe registrant is a well-known seasoned issue~, as defined ill Rule 405 of the Securities Act.
Great Plains Energy Incorporated Yes
- X No Kans~s 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 Enfrgy 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 dilling 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 X No Kansas City Power & Light Company Yes X . No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web *site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Great Plains Energy Incorporated Yes X No Kansas City Power & Light Company ' Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to It~m 405 ofReguliition S-K (§229.405 of this. chapter) is not contain~d herein, and will not be contained, to the best ofregistrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to the Forni 10-K.
Great Plains Energy Incorporated X Kansas City Power & Light Conipany X Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accele;ated filer, or a smaller reporti~~ '*
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company"' in Rule 12b-2 of the *
- Exchange Act. *
- Great Plains Energy Incorporated Large accelerated filer x * **Accelerated .filer ..
Non-accelerated filer
- Smaller.reporting company Kansas City Power & Light Company Large accelerated filer *Accelerated *fileF' Non-accelerated filer x Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ; ,-
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 Incqrporated (based.
on the closing price of its common stock on the New York Stock Exchange on June 30, 2016) was approximately $4,700,571,576. 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, 2017, Great Plains Energy Incorporated had 215,384,601 shares of common stock outstanding. **
On February 21, 2017, Kansas City Power & Light Company had one share of common stock outstanding and held by Gr~at Plains Energy.
Incorporated. ,, ', . '** ,
- Kans~s City Power & Light Company meets the conditions set fo~th in General Instruction (I)(l)(a) and (b) of Form 10-K and is therefpre filing this Form 10-K with the reduced disclosure format. . * * *.
- Documents Incorporated by Reference
. . '/
Portions of the 2017 annual meeting proxy statement of Great Plains Energy Incorporated to be filed with the Securities and Exchange Commission are incorporated by reference in Part III of this report.
TABLE OF CONTENTS Page Number Cautionary Statements Regarding Certain Forward-Looking Information 3
- Glossary of Terms 5 PART I Item 1. Business 7 Item IA. Risk Factors 13 Item IB.
- Unresolved Staff Comments 29 Item 2. Properties 30 Item 3. Legal Proceedings 3)
Item4. Mine Safety Disclosures . 31 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer 32 Purchases of Equity Securities Item 6. Selected Financial Data 33 Item 7. Management's Discussion and Analysis of Financial Condition and Results of 33 Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk 55 Item 8. Financial Statements and Supplementary Data 57 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial 123 Disclosure Item 9A. Controls and Procedures 123 Item 9B. Other Information 127 PART III Item 10. Directors, Executive Officers and Corporate Governance 127 Item 11. Executive Compensation 127 Item 12. Security Ownership of Certain Beneficial Owners .and Management and Related 128 Stockholder Matters Item 13. . Certain Relationships and Related Transactions, and* Director Independence 128 Item 14. Principal Accounting Fees and Services 129 PART IV Item 15. EXhibits and Financial Statement Schedules '130.
Signatures . 149 2
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 where required 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, iI?-cluding KCP&L Greater Missouri Operations Company (GMO), does not relate to, and is not filed by, KCP&L. KCP&L makes no representation as to that information. Neither Great Plains Energy nor its other subsidiaries have any obligation in' respect of KCP&L's debt securities and holders of such securities should not consider Great Plains Energy's or its other subsidiaries' 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 or its other subsidiaries.
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. F01ward-looking statements include, but are not limited to, statements relating to Great Plains Energy's proposed acquisition of Westar Energy, Inc. (Westar), the outcome of regulatory proceedings, cost estimates of capital projects and other matters affecting future operations.
In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Great Plains Energy and KCP&L 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 regional, national and international markets and their effects on sales, prices and costs; prices and availability of electricity in regional and national wholesale markets; market perception of the energy industry, Great Plains Energy and KCP&L; changes in business strategy, operations or development plans; the outcome of contract negotiations for goods and services; 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 the Companies 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 lim~ted to, changes in interest rates and credit spreads and in availability and cost of capital and the effects on derivatives and hedges, nuclear decommissioning trust and pension plan assets and costs; impairments of long-lived assets or goodwill; credit ratfogs; inflation rates; effectiveness of risk management policies and procedures and the ability of counterparties to satisfy their contractual ?ommitments; impact of terrorist acts, including, but not limited to, cyber terrorism; ability to carry out marketing and sales plans; weather conditions including, but not limited to, weather-related damage and their effects on sales, prices and costs; cost, availability, quality an.d deliverability of fuel; the inherent uncertainties in estimating the effects of weather, economic conditions and other factors on customer consumption and financial results; ability to achieve generation goals and the occurrence and duration of planned and unplanned generation outages; delays in the anticipated in-service dates and cost increases of generation, transmission, distribution or othe'r projects; Great Plains Energy's ability to successfully manage its transmission joint ventures or to integrate or restructure the transmission joint ventures of Westar; the inherent risks associated with the ownership and operation of a nuclear facility including, but not limited to, environmental, health, safety, regulatory and financial risks; workforce risks, including, but not limited to, increased costs of retirement, health care and other benefits; the ability of Great Plains Energy to obtain the regulatory approvals necessary to complete the anticipated acquisition of Westar and the tenns of those approvals; the risk that a
. condition to the closing of the anticipated acquisition of Westar or the committed debt or equity financing may not be satisfied or that the anticipated acquisition may fail to close; the failure to obtain, or to obtain on favorable terms, any financings necessary to complete or permanently finance the anticipated acquisition of Westar and the costs of such financing; the outcome of any legal proceedings, regulatory proceedings or enforcement matters that may be instituted relating to the anticipated acquisition of Westar; the costs incurred to consummate the anticipated acquisition of Westar; the possibility that the expected value creation from the anticipated acquisition of Westar will not be realized, or will not be realized within the expected time period; the credit ratings of Great Plains Energy following the anticipated acquisition of Westar; disruption from the anticipated acquisition of Westar making it 3
more difficult to maintain relationships with customers, empfoyees, regulators or suppliers and the diversion of management.time and attention on the proposed transactions; and other risks and uncertainties.
This list of factors is not all-inclusive because it is not possible to predict all factors. Part I Item IA 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. Each forward-looking statement speaks only: as of the date of the particular statement. Great Plains.Energy and KCP&L µndertake no obligation to publicly'update or revise any forward-looking statement, whether as a result of new information, .future events. or otherwise.
I I*
4
GLOSSARY OF TERMS I , '
The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report
. * . ' ' ' f * *; . *.' ' ** ' - **
Abbreviation or Acronym Definition AEPTHC AEP Transmission Holding Company, LLC, a wholly owned subsidiary of
.American Electric Power Company, Inc ..
AFUDC Allowance for F'1uds U~ed During Construction ARO Asset Retirement Obligation *
- ASU Accounting Standards Update
- CCRs Coal combustion residuals Clean Air Act Clean Air Act Amendments of 1990 C02 Carbon dioxide Company .Great Plains En~rgy Incorporated and its con~cilidated subsidiaries Companies Great Plains Energy Incorporated and its consolidated subsidiaries and KCP&L
. and its consolidated subsidiaries * *
- DOE Department of Energy EBITDA Earnings before int~rest, inco~e* taxes, depre~iation and amortization ECA Energy Cost Adjustmept . *.* . . .
EIRR Environmental Improvement Revenue Refunding EPA Environmental Protection Agency Ei>S Earnings per common share ERISA. Employee Retirement Income Security Act of 1974, as amended FASB *Financial Accounting Standards Board FERC The Federal Energy Regulato'ryCommissiori FCC The Federal Comillunicatfons Commission FTC Federal'Trade Commission GAAP Generally Accepted Accounting Principles GMO KCP&L Greater Misso~ri Operations Coi'ilpany, a wholly owned subsidiary of
- Great Plains Energy
- GPETHC GPE Transmission Holding Co~pariy LLc,' ~ wholly OWned subsidiary of Great:
Plain1> Energy Great Plains Energy Great Plains Energy incorporated a~d its ~onsolidated subsidiaries Great Plains Energy Board Great Plains Energy Board of Directors '
HSR Hart-Scott-Rodino 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, and its consolidated subsidiaries KCP&L Receivables Kansas City Power & Light Receivables Company, a wholly owned subsidiary Company ofKCP&L . .
kWh Kilowatt hour MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations
- MDNR Missouri Department ofNaturai Resou'rces MECG .. Midwest Energy Consumers Group MEE IA Missouri Energy Efficiency Investment Act 5
Abbreviation or Acronym Definition Merger Agreement Agreement and Plan of Merger dated as of May 29, 2016, by and among Great, Plains Energy, Westar and Merger Sub Merger Sub GP Star, Inc., a Kansas corporation that will be merged with and into Westar, pursuant to the Merger Agreement MGP Manufactured gas plant MPS Merchant MPS Merchant Services, Inc., a wholly owned subsidiary of GMO MPSC Public Service Commission of the State of Missouri MW Megawatt MWh Megawatt hour NAV Net Asset Value NERC North American Electric Reiiability Corpo~ation NEIL . Nuclear Electric Insurance Limited NOL Net operating loss NO~ Nitrogen oxide NPNS Normal purchases and normal sales NRC Nuclear Regulatory Commission OCI Other Comprehensive Income OMERS OCM Credit Portfolio LP PRB Powder River Basin QCA Quarterly Cost Adjustment RCRA Resource Conservation and Recovery Act RES RAM Renewable Energy Standard Rate Adjustment Mechanism RTO Regional Transmission Organization SEC Securities and Exchange Commission SERP Supplemental Executive Retirement Plan S02 Sulfur dioxide SPP Southwest Power Pool, Inc.
TCR Transmission Congestion Right
'J'.DC: Transmission Delivery Charge Transource Transource Energy, LLC and its subsidiaries, 13.5% owned by GPETHC WCNOC Wolf Creek Nuclear Operating Corporation Westar Westar Energy, Inc. ... ,
Westar Board Westar Board of Directors Wolf Creek . 'YolfCreek Generating Station 6
PART I ITEM 1. BUSINESS General Great Plains Energy Incorporated and Kansas City Power & Light Company are separate registrants filing this combined annual report on Form-10-K. The terms "Gr,eat Plains Energy," "Company," "KCP&L" and "Companies" are used throughout this report. "Great Plains Energy" and the "Company" refer to Great Plains Energy Incorporated and its consolidated s:ubsidiaries, unless otherwise indicated. "KCP&L" refers to Kansas City Power
& Light Company and its consolidated subsidiaries. "Companies" refers to Great Plains Energy Incorporated and its consolidated subsidiaries and KCP&L and its consolidated subsidiaries.
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. ' .
GREAT PLAINS ENERGY INCORPORATED 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 and cash and cash equivalents.and a time deposit to be used to :furid a portion of the cash consideration for the anticipated acquisition of Westar Energy, Inc. (Westar). Great Plains Energy's wholly owned direct' subsidiaries with significant operations are as follows:
KCP&L is an integrated, regulated electric utility that provides electricity to customers primarili in the states of Missouri and Kansas. KCP&L has one active wholly owned subsidiary, Kansas City Power &
Light Receivables Company (KCP&L Receivables Company).
- GMO is an integrated, regulated electric utility that provides electricity to customers in the state of Missouri. GMO also provides regulated steam service to certain customers in the St. Joseph, Missouri area.
GMO has two active wholly owned subsidiaries, GMO Receivables Company and MPS Merchant Services, Inc. (MPS Merchant). MPS Merchant has certain long-term natural gas contracts remaining from its former non-regulated trading operations.
Great Plains Energy also wholly owns GPE Transmission Holding' Company, LLC (GPETHC). GPETHC owns' 13.5% ofTransowce Energy, LLC (Transource) with the remaining 86.5%ownedby AEP Transmission Holding Company, LLC (AEPTHC), a subsidiary of American Electric Power Company, Inc. GPETHC accounts for its investment in Transource under the equity method. Transource is focused on the development of competitive electric transmission projects.
- On May 29, 2016, Great Plains Energy entered into an Agreement and Plan of Merger (Merger Agreement) by and among Great Plains Energy, Westar, and, from and after its accession to the Merger Agreement, GP Star, Inc., a wholly owned subsidiary of Great Plains Energy in the State of Kansas (Merger Sub). Pursuant to the Merger Agreement, subject to the satisfaction or waiver of certain conditions, Merger Sub will merge with and into Westar, with Westar continuing as the surviving corporation. Upon closing, pursuant to the Merger Agreement, Great Plains Energy will acquire Westar for (i) $51.00 in cash and (ii) a number, rounded to the nearest 1/10,000 of.a share, of shares of Great Plains Energy common stock, equal to an exchange ratio that may vary between 0.2709. and 0.3148, based upon the volume-weighted average price per share of Great Plains Energy common stock during a 20 consecutive full trading day period' ending on (and including) the third trading day immediately prior to the closing date of the merger, for each share of Westar common stock issued and outstanding immediately prior to the effective time of the merger, with Westar becoming a wholly owned subsidiary of Great Plains Energy. See Note 2 to the consolidated financial statements for additional infonnation concerning the anticipated acquisition of Westar.
Great Plains Energy's sole reportable business segment is electric utility. For information regarding the revynues, income and assets attributable to the electric utility business segment, see Note 23 to the.consolidated financial 7
statements. Comparative financial information and discussion regarding the electric utility business segment can be found in Item 7 Management's Discussion and Analysis of Ftnancial Condition and Results of Operations (MD&A).
The electric utility segment consists ofKCP&L, a regulated utility, GMO's regulated utility operations and GMO Receivables Company. Electric utility serves approximately 855,700 customers located in western Missouri and eastern Kansas.*. Customers incfude approximately 753,500 residences, 99, 700 commercial firms and 2,500 industrials, municipalities and other electric utilities.* Electric utility's retail revenues averaged approximately 91 %
of its total operating revenues over the last three years. Wholesale finn power, bulk power sales and miscellaneous electric revenues accounted for the remainder of electric.util~ty's revenues. Electric utility is significantly impacted by seasonality with approximately one-third of its retail revenues r~corded in the third quarter. Electric utility's total electric revenues were 100% of Great Plains Energy's revenues over the last three years. Electric utility's net income accounted for approximately 101 %, 105% and 100% of Great Plains Energy's net income in 2016, 2015 and 2014, respectively.
Regulation KCP&L and GMO are regulated by the Public Service Commission of the State of Missouri (MPSC) and KCP&L is also regulated by The State Corporation Commission of the St~1te of Kansas (KCC) with respect to retail rates, certain accounting matt~rs, standards of service and, in certain cases, the issuance of securities, certification of facilities and service territories. KCP&L and GMO are also subject to regulation by The Federal Energy Regulatory Commission (FERC) with respect to transmission, wholesale sales and rates, and other matt~rs. KCP&L has a 47%
ownership interest in Wolf Creek Generating Station (Wolf Creek), which is subject to regulation by the Nuclear Regulatory Commission (NRC) with respect to licensing, operations and safety~related requirements.
The ta~le below Slillllllarizes the ra,te orders in effect for KCP&L's and GMO's retail rate jurisdictions.
Allowed Return
- Rate-Making Rate Base.
Regulator on Equity. Equity Ratio * (in billions) Effective Date KCP&L Missouri MPSC 9.5% 50.09% $2.6 September 2015 KCP&L Kansas KCC 9.3% 50.48% $2.1 October 2015 GMO MPSC 9.5% - 9.75%(a) . (a)* (a) February 2017 (a) GMO's current rate order i:efl~cts a global settlement with an implied return on equity range of 9.5% - 9.75% and does not contain an agreed upon rate-making equity ratio or rate base.
- Missouri and Kansas jurisdictional retail revenues averaged approximately 70% and 30%, respectively, of electric utility's total retail revenues over the last three years.
- See Item 7 MD&A, Critical Accounting Policies section, ~nd Note 6 to the consolidated finanCial stat~ments for additional information concerning regulatory matters.
- Competition Missouri and Kansas continue on the fully integrated retail utility model. As a result, electric utility does not compete with others to supply and deliver electricity in its franchised service territory, although other sources of energy can pro;vide alternatives to retail electric utility customers. If Missouri or Kansas were to pass and implement legislation authorizing or mandating retail choice, electric utility may no longer be able to apply regulated utility aecounting principles to deregulated portions of.its operations and may be required to write off certain regulatory assets and liabilities.
- Electric utility competes in the wholesale market to sell power in circumstances when the power it generates is not required for customers in its service territory. This competition primarily occurs within the SPP Integrated Marketplace, in which KCP&L and GMO are participants. Similar to other RegionalTransmission Organization (RTO) or Independent System Operator (ISO) markets currently operating, this marketplace determines which generating units among market participants should run, within the operating constraints of a unit, at any given time for maximum cost-effectiveness. ** *
- 8
In this regard, electric utility competes with owners of other generating stations and other power suppliers, principally other utilities within the Southwest Power Pool, Inc. (SPP) Integrated Marketplace,* on* the basis of*
availability and price. Electric utility's wholesale revenues averaged approximately 7% of its total revenues nver the last three years.
Power Supply Electric utility has approximately 6,500 MWs of owned generating capacity and also plirchases power to *rn.eeilis customers' needs, to satisfy firm power commitments or to meet renewable energy standards. Electric utility's purchased power from others, as a percentage ofMWh requirements, averaged approximately 24% over the last three years. Management believes electric utility will be able to obtain enough power to meet its future demands .
due to the coordination of planning and operations in the SPP region and existing power purchase agreements;*
- however, price and availability of power purchases may be impacted during periods of high demand.
Electric utility's total capacity by fuel type, including both owned generating capacity and power purchase
- agreements, is detailed in the table below:. ,.,,,1 Estimated 2017 Percent of Total Fuel Type MW Capacity Capacity Coal 3,474 . ': i 46 %
Nuclear 549. 7 Natural gas and' oil . 2,352 ;: 31 Wind (a) 1,089 15 Solar and hydroelectric (b) 65 .1 Total capacity 7,529 100 %
(a) MWs are based on nameplate capacity of the wind facility. Includes owned generating capacity of 149 MWs and long-term power purchase agreements of approximately 940 MWs of wind generation which expire in 2032 through 2037. Power purchase agreements for approximately 300 MWs of wind generation to begin in late 2017 and expire in 2037 are not included in the table above.
(b) Includes a long-term power purchase agreement for approximately 60 MWs of hydroelectric generation which expires in 2923: . ,-:
Electric utility's projected peak SUffill1er demand for 2017 is approximately 5,800 MWs. Electric utility eJ:1.pects to meet its projected capacity requirements for the foreseeable future with its generation assets and power and capacity purchases. . .
- KCP.&L and GMO.are members ofthe SPP. The SPP is an RTO mandated by FERC to. ensure reli~ble supply of pow~r, adequate transmission infrastrlicture and competitive wholesale prices of electricity. As members of the SPP, KCP&L and GMO are required to maintain a capacity margin of at least 12%. This net positive supply of capacity and energy is maintained through their generation assets, capacity agreements, power purchase agreements and peak demand reduction programs. The capacity margin is designed to ensure the refiabil,ity electriG eµergy in of the SPP region in the event of operational failure of power generating units utilized by the members. of the SPP.
9
Fuel
The*principal fuel sources forelectric utility's owned generation are. coal and nuclear fuel. It is expected, with.
- normal weather, that approximately 97% of 2017 owned generation will come from these sources with the remainder provided by wind, natural gas and oil. The actual 2016 and estimated 2017 fuel mix and delivered cost in*
cents per net kilowatt hour (kWh). generated are outlined in the following table.
Fuel cost in cents 1>'er .
Fuel Mlx (a). .ii~t kWh generated Estimated Actual_ Estimated * *Actuar:
Fuel 2017 2016 2017' ,* 2016 Coa.l 76 % 79 % 1.79 *. 1.84 Nuclear 21 :17 0.64 0.69 Natural gas and oil <1 *2 7.30* 13.65 Wind 3 2 .*~'.,
Total owned generation 100 % 100 % 1.45 1.46
<*)Fuel mix bas,ed on percent of net.MWhs generated.
Coal During 2017, electric utility's generating units, including jointly owned units, are projected to bum approximately l2 million tons of coal. KCP&L and GMO have entered into coal-purchase contracts with various suppliers in Wyoming's Powder River Basin (PRB), the nation's principal supply region oflow-sulfur coal, and ~ith local suppliers. The coal to be provided under these contracts is expected to satisfy approximately 100% of the projected coal requirements for 2017 and approximately 48% for 2018. The -- ;*
remainder of the coal r~quirements is expected to be fulfilled through additional contracts,or spot market *.
purchases. KCP&L and GMO have entered into coa:l contracts over time at higher average prices affecting
- coal costs for 2017 and beyond. *
- KCP&L and GMO have also entered into tail transportation contracts with va~ious railroads to transport coal fromthe PRB to their generating units. The transportation services to be provided under these *
- contracts are expected to satisfy almost all of the projected transportation requirements for 2017 and' approximately39% for 2018. The contract rates adjust for changes in railroad costs. **
Nuclear Fuel * . . * . . * .
. *' . ,. I '* *",:
KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for.
Wolf Creek, which is electric utility's only nudear generating unit Woif Creek purchases uranium, ahd lia~
it processed* for use as fuel in its reactor. This process involves conversioh of uraniilm concentrate~* to uranium hexafluoride, enrichment ofuranium hexafluoride and fabrication of nuclear fuel assemblies. The owners of Wolf Creek have on hand or under contract all of the 'Uranium and conversion shvices heeded tO-'*
- operate WolfCr~ek through March 2027. The qwners also have under contract 97% of the uranium enrichment and all of the fabrication required to operate Wolf Creek through March2027 and September 2025, respectively. '
See Note 5 to the consolidated financial statements for additionalinformation regarding nuclear plant Environmental Matters See Note 15 to the consolidated financial statements for information regarding environmental matters.
KANSAS CITY POWER & LIGHT COMPANY KCP&L, a Missouri corporation incorporated in 1922 and 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 534,400 customers located in western Missouri and eastern Kansas. Customers include 10
approximately 471,900 residences, 60,500 commercial firms, and 2,000 industrials, municipalities and other electric utilities. KCP&L's retail revenues averaged approximately 90% of its total operating revenues over the last three years. Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the reniainder of KCP&L's revenues. KCP&L ii; significantly impacted by seasonality with approximately one-third of its retail revenues recorded irt the third quarter. Missouri and Kansas jurisdictional retail revenues averaged approximately*
56% *and 44%, respectively, of total retail revenues over the last three.years. *
- Great Plains Energy and 'l(CP&L Employees At December 31, 2016, Great Plains Energy and KCP&L had 2,865 employees, including 1,750 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, 2018), with Local 1464, representing.
transmission and distribution workers (expires January 31, 2018)" and with Local 412, representing power pla:i:it workers (expires February 28, 2018).
- Executive Officers AH of the individuals in the following table have been officers or employees in the responsible positions with the Company noted below for the past five years unless otherwise indicated in the.footnotes. The executive officers were reappointed to the indicated positions by the respective boards of directors, effective January 1, 2017' to hold such positions until their resignation, removal or the appoilltment of their successors. There.are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any 0th.er person involved in officer selection. Each executive officer holds the same position with GMO as he or she does with KCP&L. *
- Year First Assumed an Officer Name Age Current Position(s) ~osition Terry Bassha~ (a) 56 Chairman of the Board, President and Chief Executive Officer: 4005 Great Plains Energy and KCP&L Scott H. Heidtbrink <W 55 Executive Vice President and Chief Operating Officer -.KCP&L 2008 Kevin K Bryant (c) 41 Senior Vfoe President -finance and Strategy and Chief Financial '2006 Officer - Great Plains Energy and KCP&L Steven P. Busser (d) 48 Vice President - Risk Management arid Controller - Great Plains 2014 Energy and KCP&L * * * .
I *.
Charles A. Caisley C*l 44
- Vice President - Marketing and Public Affairs - Great Plains 2011 Energy and KCP&L Ellen E. Fairchild (f) 55 Vice Pr~sident, Chief Compliance Officer and Corporate 2010 Secretary - Great Plains Energy aµd KCP&L He~ther A. Humphrey (gl . 46 Senior Vice President - Corporate Services and General Counsel ~ 2010 Great Plains Energy .and KCP&L Darrin R. Ives Chl.
- 47 Vice President.: Regulatory Affairs - KCP&L 2013 Lori A. Wright (i) 54 Vice President~ Corporate Planning, Investor Relations and. 2002 Treasurer - Great Plains Energy and KCP&L C*l Mr. Bassham was appointed Chairman of the Board in.May 2013 and has served as Chief Executive Officer.ofGre~t Plains Energy, KCP&L and GMO since 2012. He has served as President.of each company since 2011. He previously served as President and Chief Operating Officer of Great Plains Energy, KCP&L and GMO (2011-2012)and !!.S Executive Vi~e President - Utility Operations ofKCP&L and GMO (2010c2011). He was Executive Vice President - Finance and Strategic Development and- Chief Financial Officer of Great Plains Energy (2005-2010) and of KCP&L and. GMO (2009-2010).*
Cbl Mr. Heidtbrink was appointed Executi~e Vice President and Chief Operating Officer ofKCP&L and GMO in 2012. He previously .served as Senior Vice President - Supply ofKCP&L and GMO (2009-2012). He was Senior Vice President -
Corporate Services ofKCP&L and GMO (2008), and Vi~e President - Power Generation & Energy Resources .(2006-2008)
~~. -
11
(c) Mr. Bryant was appointed Vice President - Finance and Strategy and Chief Financial Officer ofGreatlPiains Energy, KCP&L and GMO in 2015. He previously served as Vice President - Strategic Planning of Great Plains Energy, KCP&L and GMO (2014). He served as Vice Preside~t - Investor Relations and Strategic Planning and Treasurer of Great Plains Energy, KCP&L and GMO (2013). He served as Vice President - Investor Relations and Treasurer of Great Plains Energy, KCP&L and GMO (2011-2013). He was Vice President - Strategy and Risk Management ofKCP&L and GMO (2011) and Vice President - Energy Solutions (2006-2011) ofKCP&L and GMO.
(d) Mr. Busser was appointed Vice President - Risk Management and Controller of Great Plains Energy, KCP&L and GMO in
. 2016. He previously served as Vice President - Business Planning and Controller of Great Plains Energy, KCP&L and GMO (2014-2016). He. served as Vice President -Treasurer of El Paso Electric Company (2011-2014). Prior to that, he served as Vice President -Treasurer.and Chief Risk Officer (2006-2011) and Vice President - Regulatory Affairs and Treasurer (2004-2006) of El Paso Electric Company.
(e) Mr. Caisley was appointed Vice President " Marketing and Public Affairs of Great Plains Energy, KCP &L and GMO in 2011. He was Senior Director of Public Affairs (2008-2011) and Director of Governmental Affairs of KCP&L (2,007-2008).
(f)
Ms: Fairchild was appointed Vice President, Chief Compliance Officer and Corporate Secretary of Great Plains Energy, KCP&L and GMO in 2010. She was Senior Director oflnvestor Relations and Assistant Secretary (2010) and Director of Investor Relations (2008-2010) of Great Plains Energy, KCP&L and GMO.
(g) Ms'. Humphrey was appointed Senior Vice President - Corporate Services and General Counsel of Great Plains Energy, KCP&L and GMO in 2016. She previously served as General Counsel (2010-2016) and Senior Vice President - Human Resources of Great Plains Energy, KCP&L and GMO (2012-2016). She served as Vice President - Human Resources of Great Plains Energy; KCP&L and GMO (2010-2012). She was Senior Director of Human Resources arid Interim General Counsel of Great Plains Energy, KCP&L and GMO (2010) and Managing Attorney of KCP &L (2007-2010).
,(hl Mr. Ives was appointed Vice President - Regulatory Affairs ofKCP&L and OMO in 2013. He previously served as Se~1ior Director - Regulatory Affairs ofKCP&L and GMO (2011-2013). He was Assistant Controller of Great Plains Energy, KCP&L and GMO (2008 - 2011).
(i)
Ms. Wright was appointed Vice President - Corporate Planning, Investor Relations and Treasurer of Great Plains Energy, KCP&L and GMO in 2016. She previously served as Vice President- Investor Relations and Treasurer of Great Plains Energy, KCP&L and GMO (2014-2016). She serVed as Vice President - Business Planning and Controller of Great Plains Energy, KCP&L and GMO (2009-2014). She was Controller of Great Plains Energy and KCP&L (2002-2008) and GMO (2008). ' '
Available Information Great Plains Energy's website is www.greatplainsenergy.com and KCP&L's website is www.kcpl.coin. Information' contained on these websites is not incorporated herein. The Companies make available, free of charge, on or through their websites, their annual reports on F omi 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 of 1934, as amended, 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.
The public may read and copy any materials that the Companies file with t~e 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.gov that contains reports, proxy statements and other information regarding the Companies.
Investors should note that the Companies announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Companies may use the Investor Relations section of Great Plains Energy's website (www.greatplainsenergy.com) to communicate with investors about Great Plains Energy and KCP&L. It is possible that the financial and other information posted there could be deemed to be material information. The information on Great Plains Energy's website is not part of this document.
12
ITEM 1A. RISK FACTORS Actual results in future periods for Great Plains Energy and KCP&L could differ materially from historical results and the forward-looking statements contained in this report. 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 their control. Additional risks and uncertainties not presently known or that the Companies' management currently believes to be immaterial may also adversely affect the Companies. This information, as well as the other information !ncluded in this report and in the other documents filed with the SEC, should be carefully considered before making an investment in the securities of Great Plains Energy or KCP&L. Risk factors ofKCP&L are also risk factors* of Great Plains Energy. * .
Risks Relating to the Anticipated Acquisition of Westar:
The ability of Great Plains Energy and Westar to complete the merger is subject to various closing conditions, including the reJeipt of consents and approvals from governmental authorities, which may impose co~ditions
- that could adversely affect Great Plains Energy or cause the merger to be abandoned.
To complete the merger, each of Great Plains Energy and Westar must make certain filings with and obtain certain consents and approvals from various governmental and regulatory authorities .
. Great Plains Energy and Westar have not yet obtained all of the regulatory consents and approvals required to complete the merger. Governmental or regulatory agencies could seek to block or challenge the merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to appro~ing the merger. *
- Great Plains Energy and Westar will be unable to complete the merger until the necessary consents and approvals are received from FERC, the NRC, KCC, and the MPSC (collectively referred to as the required governmental approvals). The Merger Agreement may require Great Plains Energy and/or Westar to accept conditions from these regulators that could adversely impact the combined company. If the required governmental approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then neither Great Pfains Energy nor Westar will be obligate~ to complete the merger.
In addition, governmental authorities could seek to block or challenge the merger, including after closing, as they deem necessary or desirable in the public interest. In some jurisdictions, a private party could initiate an action under the antitrust laws challenging or seeking to enjoin the merger, before or after it is completed. Great Plains Energy or Westar may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.
- FERC Commissioner Norman Bay's resignation, effective February 3, 2017, left FERC with two sitting cominissioners and the inability to convene a quorum; Without a quorum, FERC cannot issue certain orders on contested cases, including Great Plains Energy's and Westar's merger application. If a replacement commissioner is not appointed and confirmed in a timely fashion, the closing of the merger could be delayed until such time that a replacement commissioner is approved by the Senate.
- The September 2016 special meetings at which the Great Plains Energy shareholders and the. Westar shareholders approved the transactions contemplated by the Merger Agreement have taken place before all required approvals have been obtained and, in certain cases, before the terms of any conditions to obtain such required approvals are known. As a result, GreatPlains*Energy and Westar may make decisions after the special meetings to waive a*
condition or approve certain actions required to obtain necessary approvals without seeking further shareholder approval. Such actions could have an adverse effect on the combined company.
In addition, the Merger Agreement contains other customary conditions to the closing of the merger, each of which
. must be satisfied or waived in order to complete the merger.
If Great Plains Energy and Westar are unable to complete the merger, Great Plains Energy would be subject to a number of risks, including the following:
13
Great Plains Energy would not realize the anticipated benefits of the merger, ihcludJng, among other things, ,
increased operating efficien,cies and future c;ost savings;
- '> - the attenti~n of managemeht of Great Plains Energy may have been diverted to tlie merger rather than to its*:_
-. __ own operations and the pursuit of other oppqrtunities that could have been beneficial to the. Company; the p~te~tial .lo~s _or'keY personnel during the pencie~cy of the merger ~s employees ~ay- experience _. -.
, : ,. uncertainty about their future roles with the combined company; and 1 - -
the tr~ding price of'Great Plains E~ergy common stock m~y decline to the .extent that the current ~~~ket --
prices reflect a market assumption that the merger will be completed. . - -* -
_Great Plains Energy will be required to pay Westar a termination fee of $3 80 million if th~ Merge~ Agreeme~t is termina_ted,:<l;ue to a. faUure ~o receive the ,required gov:ernmental approvals ()r _a failure to receive them on terpJ.~ l:UJ-d..
conditions t)lat would nqt result in a material adyerse e:ffect on Great Plains Energy and its subsidiaries, after giving __
effect to the merger. - ::- __
We can provide no assurance that the ~arlous closing conditions will be satisfied_ and that the_ required governlliental -
approvals will be obtained, or that any required conditions will n:ot materially adversely affect the combined company following the merger. In addition, we can pr()v:ide*no assurance that thes.e_ conditions will not re~ult in the_ .
aban,donp;ient ,gr delay of tb,e merger. T)le. occni,rrence of any of these ev:ents indiv:idually or in _co111binatio_i1 could-_ : ..
have a m,aterial adverse effect on Grea~ Plains Energy's results of operations and tl:J,e trading price of Great Plains :
Energy.c_ompioµ 1 ~tock.,_ . . , . _ . __ - ,.
The M~rger Agre~mef!t containsprovisions tha,t limit Great Plains En~rgy's or Westar's ability.to pursue.. _
alternatives_ to _the me_rger, could discourage a potential competing acquirer of either (]reat Plains Energy or. _..-*
Westar from making a fa_vorable a/ternative transaction prfJposql and, in. cer(ain circumstances, co_uld require Westar or Great Plains Energy to pay a termination fee to the .o(her party. - * ,. ,
Under the Merger Agreement, Westar and Great Plains Energy e~~h are restrict~d from e~tering into alternative merger oracql1isition transactio11s. Unless and,until the Merger Agreement is terminated, subject to specifieq , - _
exceptiqp.s,1 -each parcy is restricted from soliciting, initiating or knowingly encouraging, induci:ng or facilitating, or -
participating- in any d~scussions or negotiations with ap.y persqn regarding, or q>0perating ,in anyway ,with; any '
person with respect to,_ any altern~tiye prcipo_sal_ or arty inquiry _or proposal that would reason<).bly _be .exp_ected to lead, to an alternative proposal. Under certain circumstances either Westar or Great Plains Energy may be required t6 PaY a termination fee to the other if they were to enter into an alternative transaction within twelve months of a termination of the Merger Agreenient. These provisions could discourage~ third.party that may have an interest-in
- acquitjng all or a significant pa1t 9f Westar or_ Great _Plains_ Energy fro111_.considering, or proposing that acqµi~ition, : __
including under circumstances ~n which the Merger Agree:tp.ent would be terminated on a separate basis, even_ if -
sud'! third party we_re prepared.to pay con~;idera~io11 with a higlwr per share cash_ or :market va,lue than the_m,arket. ,_
value proposed to be received or realized in the merger. As a rerult of these restrictions, neither Westar nor Great* _. _
Plai11s Energy may be able to enter into an agreement with.respect to a more favorable alternative transaction wit}J.uµt iiwurri;ng potentially significant liability to the other. ' *
- ** ; * ' ' ** * ; * * " Ot ~ L, ' '
- . ,., '
- Great Pl~lns E_nergy and Westar will b~ subject tO, various uncert(!inties while the merger -is pending that mµy- . ; _
cause disruption a11d, ni~Y. make _it more,_difficu_lt to maintain r,elatiotl!ihips, wi,th,emplQye~s, suppf~erf$, Q.r , .:'. , "
customer!!. --
Uncertainty about the effect of the merger,o:µ employees, suppliers aiiµ cust_omers may have an adverse effe~t c;m Great Plains Energy and Westar. Although Great Plains Energy and Westar intend to take steps designed to reduce any adv_erse* e:lfec;t~, _th~se _uncertainties ~ay impair _the abil.ity of Great Plains Energy or Westar to attract, retain and ;
motivate key personnel until the merger is completed and for.a period of time thereafter, and could cause customers, suppliers and others that deal with Great Plains Energy or Westar to seek to change or terminate existing business
- relationships with Great P,lains Energy pr Westar or not enter.into new relationships or transactio_ns. -
. \.:*: .,**..
14
Employee retention and recruitment may be particularly challenging prior to the completion of the merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite Great Plains Energy's and Westar's retention and recruiting efforts, key employees depart or fail to continue employment with either c.ompany because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, Great Plains Energy's and/or Westar's financial results could be adversely affected. Furtherinore, the combined company's operational and financial performance following the merger could be adversely affected if it is unable to retain key employees and skilled workers of Great Plains Energy and Westar. The loss of the seltvices of key employees and skilled workers and their experience and .
knowledge regarding Great Plains Energy's and Westar's businesses could adversely affect the combined company's future operating results and the successful ongoing operation of its businesses.
Failure to successfully combine the businesses of Great Plains Energy and Westar in the expected time frame may adversely affect the future results of the combined company, and, consequently, the value of Great Plains Energy common stock. 1 The success of the merger will depend, in part; on the ability of Great Plains Energy to realize the anticipated benefits and efficiencies from combining the businesses of Great Plains Energy and Westar. To realize these anticipated benefits, the businesses must be successfully combined. If the combined company is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the a:n.ticipated benefits of the transactions may not be realized fully or at"all. In addition, the actual integration may result in additional and unforeseen expenses,' which could reduce the anticipated benefits of the merger. These integration difficulties could result in a decline in the market value of Great Plains Energy common stock.
Failure to complete the merger, or significant delays in completing.the merger, could negatively affect the trading prices of Great Plains Energy common stock and the future bu~iness andfinandal results of Great Plains Energy.
Completion of the merger is not assured and is subject to risks, including the risk that approval of the merger by governmental agencies is not obtained or that other closing conditions are not satisfied. If the merger is not completed, or ifthere are significant delays in completing the merger, it could negatively affect the trading price of Great Plains Energy common stock and the future business and financial .results of Great Plains Energy. Great
- Plains Energy also will be subject to several risks, including the following:
Great Plains Energy may be liable for damages to Westar under the terms and conditions of the Merger Agreement; negative reactions from the financial markets, including declines in the price of Great Plains Energy common stock due to the fact that curre~t prices may reflect a market assumption that the merger will be completed; having to pay certain significant costs relating to the merger, including, in certain circumstances, a
. termination fee; and
- the attention of Great Plains Energy will have been diverted to the merger rather than Great Plains Energy's own operations and pursuit of other opportunities that could have been beneficial to Great Plains Energy.
Each of Great Plains Energy and Westar will .incur significant transaction* and merger-related costs in connection with the merger.
Great Plains Energy and Westar have incurred, and expect to continue to incur, costs associated with combining the operations of the two companies, as well as transaction fees and other costs related to the merger. Additional, unanticipated costs. may be incurred in the integration of the businesses of Great Plains Energy and Westar.
Although Great Plains Energy and Westar expect that the elimination of duplicative costs, as well as the realization
- of other efficiencies related to the integration of the bu.sinesses, may offset incremental transaction, merger-related and restructuring costs over time, any net benefit may not be achieved in the near term, or at all.
15
Great Plains Energy may be unable to obtain the anticipated combination offinancing*or the necessary amount offinancing to pay the cash portion of the merger consideration.
Great Plains Energy intends to finance the cash portion of the merger consideration with a combination of cash on hand and the proceeds from the issuance of a combination of common stock, mandatory convertible preferred stock and debt securities. In ,October 2016, Great Plains Energy completed registered public offerings of 60.5 million shares of common stock for tot;:tl net proceeds of $1.55 billion and 17 .3 million depositary shares each representing a 1/20th interest in a share of Great Plains Energy's 7.00% Series B Mandatory Convertible Preferred Stock (Series B Preferred Stock) for total net proceeds of $836.2 million.
To the extent the proceeds from Great Plains Energy's remaining expected securities issuances are not available on or before the closing date of the merger, or are in insufficient amounts, Great Plains Energy may use borrowings under its bridge term loan facility to fund the remaining portion of the cash consideration for the merger. :However, the availability of funds under the bridge term loan facility is subject to certain conditions including, among others, the absence of a material adverse'effect with respect to Westar and its subsidiaries, taken as a whole, the accuracy of certain representations and warranties and the absence of certain defaults with respect to indebtedness of Great Plains Energy and its subsidiaries. .
- If Great Plains Energy is required tO obtain more debt financing than anticipated, whether through the issuance of debt securities or borrowings under the bridge term loan facility, the, required regulatory approvals to complete the merger may be more difficult to obtain and the combined company's credit ratings and ability to service its debt*
could be adversely affected.
Current Great Plains Energy shareholders will have a reduced own(!rship and voting interest after the merger and will exercise less if!fluence over management ofthe combined company.
Great Plains Energy has already issued approximately 60.5 million shares of common stock in order to raise proceeds to fund a portion of the cash consideration ,for the merger. Furthermore, Great Plains Energy issued in October 2016 and also expects to issue at the time of the merger, shares of mandatorily convertible preferred stock, which shall ultimately convert into common stock. In connection with the completion of the merger, Great Plains Energy will also issue up to approximately 45 million shares of Great Plains Energy common stock to Westar shareholders in connection with the transactions contemplated by the merger agreement.
Great Plains Energy shareholders currently have the right to vote for the Company's board of directors and on other
- matters affecting Great Plains Energy. When the* merger occurs, each Westar shareholder that receives shares of Great Plains Energy common stock will become a shareholder of Great Plains Energy with a percentage ownership of the combined company that is significantly smaller than the shareholder's percentage ownership in Westar.
Correspondingly, each Great Plains Energy shareholder will remain a shareholder of Great Plains Energy with a percentage ownership of the combined company that is smaller than the shareholder's percentage ownership of Great Plains Energy prior to the merger.
As a result of these securities issuances and reduced ownership percentages, current Great Plains Energy shareholders will have less influence on the management and policies of the combined company than they now have I . .
with respect to Great Plains Energy.
The market price of Great Plains Energy common stock after the merger may be affected by factors different from those affecting the shares of Great Plains Energy or Westar currently.
Upon completion of the merger, the businesses of the combined company will differ from those of Great Plains, Energy and Westar prior to the merger in important respects and, accordingly, the results of operations of the combined company and the market price of Great Plains Energy's shares of common stock following the merger may be affected by factors different from those currently affecting the independent res~lts of operations of Great Plains Energy and Westar.
- 16
There are risks associated with the mandatory convertible preferred stock Great Plains Ene.rgy expects to issue.
- j pursuant to its stock purchase agreement with OMERS to finance a portion of the merget: consideration; In connection with the Merger Agreement, Great Plains Ene;rgy entered into a stock purchase agreement with QCM Credit Portfolio LP (OMERS) pursuant to which Great Plains Energy will issue and sell to OMERS $750 million of.
7.25% Mandatory Convertible Preferred Stock, Ser.ies A (Series A Preferred Stock) upon the consummation of the merger.. Upon entering into the stock purchase agreement, Great Plains Energy paid OMERS $15 million, which is not. refundable in the event .the II}erger is not consummated. The tenns of the Series A Preferred Stock will provide that if Great Plains Energy misses .two quarterly ,dividend payments, Great Plaii;ts Energy would be required to.
appoint two representatives designate\i by QMERS to the Great Plains En~rgy Board. In addition, Ql\1ERS' non~ ..
U.S. based. ownership could.Po.teµ~ially .complicate:obtain.ing the reqtiired regulatory approvals .for the merger.
The combined company's indebtedness following the merger will be greater than Great Plains Energy's existing indebtedness. As a result, it ~ay. be. more difficu(t for the combine,fco,mpqny to.pay or refina,nce its debts or take.
other actions, and the combined company may need to divert its cash flow from operations to debt service payments. ,. . .
In connection with the merger, Gr~at Pl:;til).s Energy will incur additionaLpebt to pay the cashportion ofthe merger .
consideration and transaction expenses and the if1d.e.bteq~ess 9fthe cgmbined companywill include Westar's outstanding debt. . The combined company's debt s_ervic~ 9bligations w1th respect to this increal>ed indebte\}ness*
could have an adverse impact on .its earnings and ca,sh :(low~, wh,i~h a~er the _merger would. include the earning~ an,d cash flows of Westar, for as long as the indebtedness is outstanding. . .. ,
Tl::le combined company's,increased mdebtedness.c;;ould ?lso have. important.consequences to holders of Great Platns Energy securities. For example, it could: . "** ::: , .. "* : ,, __._, ,, , . , :. ,. ., . . . ..: ,. ::.. ,
make it more .difficult for. thy co.mqined gompany to pay or ~e:finat1se. its.debts as they become _due. during adverse economic and industry conditions because any decrease in r_evenues could Cal,lSe the combined company to not have sufficient. cash flqws. from operat~ons to make it~ scheduled debt payments; . ,, *;*
. - 1;* "
limit the comb~ned cmnpal).y's flqibilitY, tc;:> pursue other str~Jygic .opporhu1;ities or react to chap.ges)11 'f*'
business and the industcy in which it operates and, consequently, place the combined company at a competitive disadvantage to i~s competitors*with less.debt;... . .. .: '.. . .;. . ... ,... ,.,_ . , ~
require a substantial porti~n ofthe combined co~pany's. q1sh flows from ()perations to .be_ used fo~ .debt ...
\I.* se[vice payinerits, th,ereby reducing.the availability ofits cash flow to fiirid w~rklng c~phai, capital , .'
expenditllres, acquis,itions, dividend payments and other general corporate purposes; . ,\_,,,*. ,,{.
re_sult in a downgrade in the rating of the combined company:'s indebtedness, which could limit its ability: to borrow additional, funds or focrease the .interest rates ~pplicable to its indebtedness (after the ,annolincement of the merger, Moody's Investors Service placed its long-tenn ra~ings of Great_ Plains Energy on r.eview for downgrade and Standard & Poor's Ratings Services revised the o~tlook of Great Pl~1ns Energy, KCP&L and GMO from stab.le to ne&ative);
- result in higher interest expense in the event of increases in interest rates since some of Great Plains Energy's borrowings are, and will continue to be, at variable.rates of interest; or require that additional terms, conditions or covenants be placed on Great Plains.Energy.
Based upon current levels 9f operations, Great Plains Energy expects to be able to generate suffi'cient cash on a consolidated basis to make all* of the principal and interest payments when such payments are due under Great Plains Energy's and its current subsidi;iries'. existing creditfaeilities,.indentµres and other instruments governing their outstanding indebtedness, and under the indebtedness 9fWestar and its subsid~a~ies that may remai.n outstanding after the merger; but there can be no assurance that the combined company will .be able to repay or refinance such borrowings and obligations.
17
Great Plains Energy is committed to maintaining its credit ratings. In order to maintain these credit ratings, Great Plains Energy may consider it appropriate to reduce the amount of indebtedness outstanding following the merger.
This may be accomplished in several ways, including iSsuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that current Great Plains Energy shareholders and former Westar shareholders hold in the combined company and might reduce the reported earnings per share. Any potential issuances could be adversely impacted by movements in the overall equity* markets or the utility* sector 6fthe.
market and ultimately impact any offering price. The specific measures that Great Plains Energy may ultimately decide to use tci maintain or improve its credit ratings and their timing will depend* upon a number of factors, *'" .'
including market conditions and forecasts at the time those decisions are made .
The combined company will record goodwill that could become impaired and adversely affect the combined company's operating results.
- The merger will be accounted for as an acquisition by Great Plains Energy in accordance with Generally Accepted Accounting Principles (GAAP). Under the acquisition method of accounting, the assets and liabilities of Westar will be recorded, as of completion, at their respective fair values and added to those of Great Plains Energy. The reported financial condition arid results of operations of Great Plains Energy issued after completion of the merger will reflect Westar*balances and results after completion of the merger, but will not be restated retroactively to reflect the historical financial position or results of operations of Westar for periods prior to the merger.
- Under the acquisition method of accounting, the total purchase price will be allocated to Westar's tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the merger. The fair value of Westar's tangible and intangible assets and liabilities subject to the rate setting practices of their regulators approximate their carrying values. The excess of the purchase price over those fair values will be recorded as goodwill. Great Plains Energy expects that the merger will result in the creation of goodwill based upon the application of the acquisition method of accounting. To the extent.the value of goodwill or'intangibles becomes impaired, the combined company may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on the combined company's operating results.
- '. i The anticipated benefits of combining Great Plains Energy and Westar may not be realized.
Great Plains Energy and Westar entered into the Merger Agreement with the expectation that the merger would result in various benefits, including, among other things, increased operating efficiencies. Although Great Plains Energy and Westar expect to achieve the anticipated benefits of the merger, achieving them is subject to a number of uncertainties, including:
- whether United States federal and state pubiic utility, antitrust and other regulatory authorities whose approval is required to complete the merger impose conditions on the merger, *which may have a~ adverse effect on the combined company, including its ability to achieve the anticipated benefits of the merger; the ability of the two companies to combine certain of their operations or take advantage of expected growth opportunities; general market and economic conditions; general competitive factors in the i;narketplace; and
- higher than expected costs required to achieve the anticipated benefits of the merger.
No assurance can be given that these benefits will be achieved or, if achieved, the tiniing of their achievement.
- Failure to achieve these anticipated benefits could result in increased costs and decreases in the amount of expected revenues or net income of the combined company.
18
The merger may not be accretive to earnings and may cause dilution to Great Plains Energy's earnings per
- share, which may negatively affect the inarket price of Great Plains Energy common stock. .*
Great Plains Energy currently anticipates that the merger will be neutral to Great Plains Energy's forecasted earnings per share on a stand-alone basis in the first full calendar year after closing increasing to approximately a 10 percent accretion in the third full calendar year after closing. This expectation is base<;! on preliminary estimates, which may materially change. Great Plains Energy may encounter additional transaction and integration-related costs, niay fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates or its ability to realize operational 'efficiencies. Any _of these factors could cause a decrease in Great Plains Energy's earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Great Plains Energy's common stock.
The merger will combine tWo companies that are currently affected by developments in the electric utility industry, includi;,g changes in regulation and increased competition. A failure to adapt to the changing regulatory environment after the merger could adversely affect the stability ofthe combined company's earnings and could resitlt in the erosion *of its market positions, revenues and profits. .
Because Great Plains Energy, Westar and their respective subsidiaries are regulated in the U.S. at the federal level 1
and in several states, the two companies have been and will continue to be affected by legislative and regulatory developments. After the merger, the combined c*o:mpany ancilorits subsidiaries will be subject in the U.S. to extensive federal regulation as well as to state regulation in Missouri and Kansas. Each of these jurisdictions has
- implemented, is in the process of implementing or possibly will implement changes to the regulatory and legislative framework applicable. to the electric utility industry. These changes could have a material adverse effect on the
.combined company. * ** * --
- The costs and burdens associated with complying with these regulatory jurisdictions may have a material adverse effect on the combined company. Moreover, potential legislative changes, regulatory changes or otherwise may .
create greater risks to the stability ofutility*earnings
. generally. If the combined company is not responsive to these .
changes, it could suffer erosion in market position, revenues and profits as competitors gain access to the service territories of its utility* subsidiarie'S.
- The marketva(ue ofGreat Plains Energy common stock could decline if large amounts of it~ com~on stock are sold in anticipation of or following the merger. . *
- Following the merger, shareholders of Great Plains Energy and former shareholders of Westar will own interests in a combined company operating an expanded business wjth more assets and a different mix of liabilities. .Current shareholders of Great Plai~s Energy a~d Westar may not'wish to continue to invest in the.combined company, or may wish to reduce their investment in the combined company, in orderto comply with institutional investing guidelines; to increase diversification or to track any rebalaridng of stock indices in which Great Plains Energy or Westar common stock is or was included. If, before or following the merger, large amounts of Great Plains Energy common st~ck are sold, the price ofits common stock could decline. . . . . .. .
Utility Regulatory Risks:
Complex utilify regulation could adversely affect the Companies' results of operations, finandal position and cash flows.
The Companies are subjectto, or affected by, extensive federal and state utility regrtfation, ii:icluding regulation by the MPSC, KCC, FERC, NRC, North American Electric Reliability Corporation (NERC) and SPP. The Companies must address in their business planning and management of _operations the effects of existing and propo~ed laws and regulations and potential changes in the regulatory framework, including initiatives by federal and state legislatures, RTOs, utility regulators and taxing authorities. Failure of the Companies to obtain adequate rates or regulatory approvals in a _timely manner, new or changed laws, regulations, standards, interpretations or other legal requirements; deterioration of the Conipariies' reiationship with regtilators and l.ncreased compliance costs and potential non-compliance consequences may materially affectthe Companies' results-of operations, financial position and cash :f)ows. Additionally, regulators may impose burdensome restrictions and conditions on the 19
Companies' transactions and ventures, rendering them less attractive from a financial or operational perspective.
Certain of these risks are addressed in greater detail below. .
- The outcome of retail rate proceedings could have a material impact on the business and is largely outside the Companies' control. . .
The rates that KCP&L and GMO are allowed to charge their customers significantly influence the Companies'. results of operations, financial position and cash flows. These rates are subject to the determination, in large part, of governmental entities outside of the Companies' control, including the MPSC, KCC and FERC.
Th~ utility rate-setting principle generally applicable to KCP&L and GMO is that rates should provide a reasonable opportunity to recover expenses and investments prudently incurred to provide utility service plus a reasonable return on such investments. Various expenses incurred by KCP&L and GMO have been excluded from rates by the MPSC and KCC in past rate cases as not being prudently incurred. or not providing utility customer benefit, and there is a risk that certain expenses incurred in the future may not be recovered in rates. Third-parties often intervene. in the utilities' rate cases and argue that certain costs have not been prude:µtly incurred or are otherwise not recoverable in rates. The MPSC and KCC also have in the past-and may in the future exclude from rates all or a portion of investments in various facilities a~ not being prudently incurred or ncit being u.seful ~n providing utility service.
\
As. discussed in the "Environmental Risks" and "Financial Risks" sections below, the Companies' *c~pital expenditures are expected to be substantial over the next several years and there is a risk that -a portion of the capital costs could be excluded from rates in future rate cases.
The Companies are also exposed to cost-recovery shortfalls due to the inherent "regulatory lag" in the rate-setting process, especially during ,periods of significant cost inflation or declining retail usage, as KCP &L's and GMO's utility rates are generally based on historical information and are not subject to adjustment between rate cases, other than *principally for fuel, purchased power, transmission and property taxes for KCP&L in ~ansas; fuel, purchased power, certain transmission costs and demand-side investments for KCP&L in Missouri; and fuel, purchased power, certain transmission costs, demand-side investments and renewable energy (solar rebates) for GMO. These and other factors may result in under-recovery of costs,
. failure to .earn the authorized return on investment, or both. . . * * * .
Failure to timely recover the fulf Investment costs of capital projects, the impact of renewable energy and energy efficiency programs, other utility costs and expenses due to regulatory disallowances, regillatory lag or other factors could lead to lowered credit ratings, reduced access to capital markets, incre~sed financing costs, lower flexibility due to constrained financial resources and increased collateral security requirements,
. or reductions or delays in planned capitaf expenditures. In response to competltive, economic, political,.
legislative, public perception (inciuding, but not limited to, the Companies' environmental reputation) and regulatory pressures, the Companies may be subject to rate moratoriums, rate refunds,. limits on rate increases, lower allowed returns on investments or rate reductions, in~luding phase-in plans design~d to spread the impact of rate increas~s over an extended period of time for the benefit of customers.
Regulatory requirements regarding utility operations may increas.e costs and may expose the Companies to compliance penalties or adverse.rate consequences.
The FERC, NERC and SPP have implemented 'and enforce an extensive set of transmission system reliability, cybersecurity and critical infrastructure protection standards that apply to public utilities, including KCP&L and GMO. 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. In addition, the Companies .are also subject to'health, safety and other requirements enacted by the Occupational Safety and Health Administration, the Department of Transportation, the Depart~ent of Labor and other federal and state. agencies. As discussed more fully under "Operational Risks," the NRC extensively regulates nuclear power plants, including Wolf Creek. The costs of .existing, new or modified regulations, standards and other requirements could have an adverse 20
effect on the Companies' results of operations, financial position and cash flows as a result of increased operations or maintenance and capital expenditures for new facilities or to repair or improve existing facilities. In addition, failure to meet quality of service, reliability, cybersecurity, critical infra~tructure protection, operational or other standards and requirements could expose the Companies to penalties, additional compliance cpsts, or adverse rate consequences.
Tax Reform Risk:
Changes in federal income tax policy ,could negatively impact the Companies.
The Companies are impacted by the U.S. federal income tax policy, including corporate income tax laws. Both the new federal administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes in the U.S. corporate income tax laws. These propqsed changes include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital expenditures, and the elimination of the interest expense deduction. The Companies are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on the Companies.
However, it is possible that changes in the U.S. federal income tax laws could have a material adverse effect on the Companies', results of operations, financial position and cash flows.
Environmental Risks:
The Companies are subject to current and potential environmental requirements and the incurrence of enyironmental liabilities, any or all of which may _adversely affect their business _and, finan~ial results.
The Companies are subject to extensive federal, state and local environmental laws, regulations and permit requirements relating _to air m;id water quality, waste management ar;id disposal, natural resources and health and safety. In addition to imposing continuing .compliance obligations and remediation costs for historical and pre-existing conditions, these laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines,- injunctive relief and other sanctions. There is also a risk that new environmental laws and regulations, new administrative or judicial interpretations of environmental laws and regulations, or the requirements in new or renewed environmental permits could adversely affect the Companies' operations. In addition, there is also .a risk of lawsuits brought by third parties alleging violations of environmental commitments or requirements, claiming creation of a public nuisance or other matters, and seeking injunctions or monetary damages or other damage,s. Certain federal courts have held that state and local governments and private parties have standing to bring climate change tort suits seeking company-specific emission reductions and damages.
Enviromp.ental permits are subject to periodic renewal, which may result in more stringent permit conditions and limits. New facilities, or modifications of existing facilities, may require new environmental permits or amendments to existing permits. Delays in the environmental permitting process, public opposition and challenges, denials of permit applications, limits or conditions imposed inpermits and the associated uncertainty may materially adversely affect the cost and timing of projects, and thus materially adversely affect the Companies' results of operations, financial position and cash flows.
KCP&L and GMO periodically seek recovery of capital costs and expenses for environmental compliance and remediation through'rate increases; however, there can be no assurance that recovery of these costs would be granted. KCP&L and GMO may be subject to material adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies' environmental reputation.
The costs of compliance or noncompliance with environmental requirements, remediation costs, adverse outcomes oflawsuits, or,failure to timely recover environmental costs could have a material adverse effect on the Companies' results of operations, financial position and cash flows. <;ertain of these matters are discussed in more detail below. See Note 15 to the consolidated financial statements for additional information regarding certain significant environmental matters and Great P!ains Energy's and KCP&L's current estimates of capital expenditures to comply with environmental regulations.
21
Air and Climate Change The Companies' current generation capacity is primarily coal-fired, and is estimated to produce about one ton of carbon dioxide (C02) per MWh, or approximately 19 million tons and 15 million tons of C02 per year for Great Plains Energy and KCP&L, respectively. Management believes it is possible that additional federal cir relevant state or local laws or regulations could be enacted to address global climate change. At the international level, in December 2015 the Paris Agreement was adopted by nearly 200 countries and
- became effective in November 2016 as the threshold of at least 55 countries representing at least 55% of global greenhouse gas emissions have joined jt through ratification. The Paris Agreement does not result in any new, legally binding obligations on the United States to meet a particular greenhouse gas emissions target, but establishes a framework for international cooperation. on climate change. Other international agreements legally binding on the United States may be reached in the future. Such new laws, regulations or treaties could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as C02 , which are created in the combustion of fossil fuels. These requirements could include, among other things, taxes or fees on fossil fuels or emissions, cap and trade programs, emission limits and clean or renewable energy standards.
The Environmental Protection Agency (EPA) has enacted various regulations regarding the reporting and permitting of greenhouse gases and has proposed other regulations under the existing Clean Air Act. The EPA has established thresholds for greenhouse gas emissions, defining when Clean Air Act permits under the New Source Performance Standards, New Source Reyiew and Title V operating permits programs would be required for new or existing industrial facilities and when the installation of best available control technology would be required. In August 2015, the EPA finalized its Clean Power Plan which sets C02 emission performance rates for existing affected fossil fuel-fired electric generating units. Specifically, the EPA translated those performance rates into a state goal measured in mass and rate based on each state's generation mix. The states have the ability to develop their own plans for affected units to achieve either the performance rates directly or the state goals, with guidelines for the development, submittal and implementation of those plans. In February 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan putting the rule on hold pending review in the United States Court of Appeals for the District of
- Columbia Circuit and any subsequent review by the U.S. Supreme Court if such review is sought.
- Compliance with the Clean Power Plan has the potential of having significant financial and operational
- impacts on Great Plains Energy and KCP&L; however, the ultimate financial and operational consequences*
to Great Plains Energy and KCP&L cannot be determined until the outcome of pending litigation is known and/or the state plans to implement the Clean Power Plan are known. Additional federal and/or state legislation or regulation respecting greenhouse gas emissions may be proposed or e11acted in the future. Requirements to reduce greenhouse gas emissions may cause the Companies to incur significant costs relating to their ongoing operations (such as for additional environmental control equipment, retiring and replacing existing generation, re-powering existing plants to utilize alternative fuel or selecting more costly generation alternatives), to procure emission allowance credits, or due to the !mposition of taxes, fees or other governmental charges as a result of such emissions.
- Water The Clean Water Act and associated regulations enacted by the EPA form a comprehensive program to restore and preserve water quality. All of the Companies' generating facilities, and certain of their other facilities, are subject to the Clean Water Act.
In May 2014, the EPA finalized regulations regarding protection of aquatic life from being'killed or injured by cooling water intake structures. KCP&L's generation facilities with cooling water intake structures are .
subject to the best technology available standards based on studies completed to comply with such standards. The rule provides flexibility to work with the states to develop the best technology available to minimize aquatic species impacted by being pinned against intake screens or drawn into cooling water systems.
KCP&L holds a permit from the Missouri Department of Natural Resources (MDNR) covering water
.. discharge from its Hawthorn Station. The permit authorizes KCP&L to, among other things, withdraw 22
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
- . letterregarding 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 pennit. Future water permit renewals at KCP&L's Iatan Station and at GMO's Sibley and Lake Road Stations could also be impacted by the .
allowable amount of heat that can be contained in the returned water. Great Plains Energy and KCP&L cannot pred~ct the outcome of these matters; however, while less significant outcomes are possible, these matters may require a reduction in generation, installation of cooling towers or other technology to cool the water, or both, any of whicP. could have. a significant impact on Great Plains Energy's and KCP&L's results of operations, financial position and ca.sh flows.
- In September 2015, the EPA finalized a revision of the technology-based effluent limitations guidelines and*
standards regulation to make the existing controls on discharges from steam electric power plants more stringent. The final' rule sets the first federal limits on the levels of toxic metals in wastewater that can be
. discharged from power plants. The new requirements for. existing power plants would be phased in between 2018 and 2023.
Further, the possible effects ()f climate change, including potentially increased temperatures and reduced
.precipitation, could niake.it more difficult and costly to comply with the current and final permit requirements.
Solid Waste.
Solid and hazardous waste generatlon, storage, transportation, treatment and disposal are regulated at the federal and state levels uiider*various laws and regulations. In April 2015, the EPA published final .
regulations to regulate coal combustion residuals (CCRs) under the Resource Conservation and Recovery Act (RCRA) Subtitle.D to address the risks from the disposal of CCRs generated from the combustion of coal at electric generating facilities. The Companies principally use coal in generating electricity and dispose of CCRs in both on-site facilities and facilities owned by third parties. Current arid future EPA regulations. regarding the. handling, disposal and remediation of CCRs could have a material adverse effect on the Companies' results qf operations,, financial position and cash flows.
RemediatiolJ Under current law, the Companies are also generally responsible for any liabilities associated with the environmental condition of their properties and other properties at which the Companies arranged for the disposal or treatment of hazardous substances, including properties that they have previously owned or operated, such as manufactured gas plants (MGP), regardless of whether they were responsible for the contamination or whether the liabilities arose before, during or after the time they owned or operated the properties or ammged for the disposal or treatment of hazardous substances.
Due to all of the above, the CotP.panies' projected capital and other expenditures for environmental compliance are subject to signifi~ant uncertainties, including the timing of implementation of any new or modified environmental requirements, the limits imposed by. such requirements and the types and costs of the compliance alternatives selected by the Companies. As a result, costs to comply with environmental requirements cannot be estimated with certainty, and actual costs could be significantly higher than projections. New environmental laws and regulations affecting the operations of the Companies may be adopted, and new interpretations of existing laws and regulations could be ;;tdopted or become applicable to the Companies or their facilities, any of which may materially adversely affect the Companies' business, adversely affect the Companies' ability to continue operating its power plants as currently done and sul;>stantially increase environmental expenditures or liabilities in the future.
23
Financial Risks:
Financial market disruptions and declines in credit ratings may increase financing costs and/or limit access to the credit markets, which may adversely affect liquidity and results.
The Companies' capital requirements are expected to be substantial over the next several years. The Companies rely on access to short-term money markets, revolving credit facilities provided by financial institutions and long-term capital markets as significant sources of liquidity for capital requirements not satisfied by cash flows from operations.' The Companies also rely on bank-provided credit facilities for credit support; such as letters of credit, to support operations. The amount of credit support required for operations varies and is impacted by a.number of factors.
Great Plains Energy, KCP&L, GMO and certain of their securities are rated by Moody's Investors Service and Standard & Poor's. Following the announcement of the anticipated acquisition of Westar, Moody's Investors Service placed its long~term ratings on Great Plains Energy on review for downgrade a:nd Standard & Poor's Ratings Services revised the outlook on Great Plains Energy, KCP&L and GMO from stable to negative. These ratings impact the Companies' cost of funds and Great Plains Energy's ability to provide creditBi.ipport for its subsidiaries. The interest rates on borrowings under the Companies' revolving credit agreements and *on a portion of Great Plains Energy's debt are subject tQ. increase as their respective credit ratings decrease. The amount of collateral or other credit support required under power supply and certain other agreements is also dependent on credit ratings.
Conditions in the United States capital and credit ~arkets may deteriorate inthe future for a variety ofreasons, including, among others: .instability in global markets, political uncertainty in the United States or abroad, fluctuations in the price of oil, geopolitical instability or other unforeseen events both in the United States and around the,world. Adverse market conditions or decreases in Great Plains Energy's, KCP&L's or GMO's credit ratings could have material adverse effects on the Companies. These effeets could include, among others: reduced access to capital and increased cost of funds;:dilution resulting from equity issuances at reduced prices; changes in the type and/or increases in the amount of collateral or other credit support obligations .required to be posted with contractual counterparties; increased nuclear decommissioning trust and pension and other post-retirement benefit plan funding requirements; rate case disallowance of KCP&L's or GM O's costs of capital; reductions in or delays of capital expenditures; or reductions in Great Plains Energy's abilitY to provide credit support for* subsidiaries. Any of these results could adversely affect the Companies' results of operations, financial position and cash flows. In addition, market disruption and volatility could have an adverse impact on the Companies' lenders, suppliers and other counterparties or customers, causing them to fail to meet their obligations.
Great Plains Energy has guaranteed some of GMO's long-term and short-term debt and payments urider these guarantees may adversely affect Great .Plains Energy's liquidity.
Great Plains Energy has issued guarantees covering $96.6 million of GM O's long-terni debt. Great Plains Energy also guarantees GM O's commercial paper program. At December 31, 2016, GMO had $201.9 million of commercial paper outstanding. The guarantees obligate Great Plains Energy to pay amounts owed by GMO directly to the holders of the guaranteed debt in the event GMO defaults on its payment obligations. Great P,lains Energy may also guarantee debt that GMO may issue in the future. Any guarantee payments could adversely affect Great Plains Energy's liquidity. '*
The inability of Great Plains Energy's subsidiaries to provide sufficient dividends to Great Plains Energy, or the inability otherwise of Great Plains Energy to pay dividends to its shareholders and meet its financial obligations would have an adverse effect.
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 other financial obligations is dividends paid to it by its subsidiaries, particularly KCP&L and GMO. The ability of Great Plains Energy's subsidiari~s 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 regulatory factors, financial covenants, general business conditions and other matters.
24
In addition, Great Plains Energy, KCP&L and GMO are subject to certain corporate and regulatory restrictions and financial covenants that could affect their ability to pay dividends. Great Plains Energy's articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization.
In addition, 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 are in arrears for six or more quarters, whether or not consecutive, the preferred shareholders will be entitled to name two directors to the Great Plains Energy Board of Directors. Furthermore, pursuant to settlement agreements with certain interveriors in Missouri that are pending MPSC approval with respect to the merger, Great Plains Energy agreed that in the event that KCP&L's or GMO's credit ratings are downgraded below investment grade as a result of the merger, then. KCP&L and GMO would be restricted from paying a dividend to Great Plains Energy unless approved by the MPSC or until their credit ratings are restored to investment grade. Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at leas.t 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out ofretained earnings. The revolving credit agreements of Great Plains Energy, KCP&L and GMO and the note purchase agreement for GMO's Series A, Band C Senior Notes contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 fo 1.00, except as the ratio relates to Great Plains Energy, which was amended in June 2016. See Note 11 to the consolidated financialstatements for additional infonnation. Great Plains Energy's Board of Directors regularly evaluates the common stock dividend policy and determines an appropriate dividend each quarter, after taking into account such factors as, among other things, earnings, financial condition and cash flows from KCP&L and GMO, as well as general economic conditions. While the corporate and regulatory restrictions *and financial covenants discussed above are not expected to affect the Companies' ability to
- pay dividends. at the current level in the foreseeable future, Great Plains Energy cannot assure common shareholders that the dividend will be paid in the future or that, if paid, dividends will be at the same amount or with the same*
frequency as in the past.
Market performance, increased* retirements and retirement plan regulations could significantly impact retirement plan funding requirements and associated cash needs and expenses.
Substantially all of the Companies' and WCNOC's employees participate in defined benefit retirement and other post-retirement plans. Former employees also have accrued benefits in defined benefit retirement and other post-
- retirement plans. The costs ofth~*se plans depend on a number of factors, including the rates ofreturn on plan assets, the level and nature of the provided benefits, discount rates, the interest rates used to measure required .
- minimum funding levers, changes in benefit design, changes in laws or regulations, and the Companies' required or*
voluntary contributions to the plans. The Companies currently have substantial unfunded liabilities under these plans. Also, ifthe rate ofretirements exceeds planned levels, or if these plans experience adverse market returns o~
investments, or if interest rates materially fall, the Companies' contributions to the plans could rise substantially over historical levels. In addition, changes in accounting rules and assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, could have a significant impact *on the Companies' results of operations, financial position and cash flows.
The use of deriVative contracts in the normal course of business could result in losses that could negatively impact the Companies' results of operations, financial position and cash flows.
The Companies use derivative instruments, such as swaps, options, futures and forwards, to manage commodity aii.d financial risks. 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 the 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.
- As a service provider to GMO, KCP&L may have exposure to GMO's financial performance and operations.
GMO has no employees of its own. KCP&L employees operate and manage GMO's properties, and KCP&L charges GMO for the cost of these services. These arrangements may pose risks to KCP&L, including possible 25
claims arising from actions ofKCP&L employees in operating GMO's properties and providing other services to GMO. KCP&L's claims for reimbursement for services provided to GMO are unsecured and rank equally with other unsecured obligations of GMO. KCP&L's ability to be reimbursed for the costs incurred for the benefit of GMO depends on the financial ability of GMO to make such payments.
Customer and Weather-Related Risks:
The results_ of operations, financial position and cash flows of the Compa~ies can be materially affected by,;
changes in customer electricity consumption.
Changes in customer electricity consumption due to sustained financial market disruptions, downturns or sluggishness in the economy, technological advances, energy efficiency or other factors may adversely affect.the Companies'-results of operations, financial positiop and cash flows.
Technological advances, energy efficiency, or other energy conservation measures could reduce customer electricity consumption. KCP&L and GMO generate electricity at_central station power plants to achieve economies of scale and produce electricity at a competitive cost. There are distributed generation technologies that produce electricity, including microturbines, wind turbines, fuel cells and solar cells, that have recently become n:iore cost c9mpetitive.
If this trend continues, the Companies customer electricity consumption could be reduced. Changes in technology could also alter the channels through which the Companies' customers purchase or use electrici,ty, which could reduce the Companies customer electricity consumption. -
Weather is a major driver of the Companies' results of operations, financial position and cash flow.
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Great Plains Energy and KCP&L are significantly impacted by seasonality, with approximately orie-third of their retail electric revenues recorded in the third quarter. Unusually mild winter or summer weather can adversely affect sales. In addition, severe weather, including but n~t limited to tomados, snow, rain, flooding and ice storms can be destructive causing outages and property damage that can potentially result in additional expenses, lower revenues and additional capital restoration costs. KCP&L's and GM O's rates may not always be adjusted timely and adequately to reflect these increased costs. Some of the Companies' generating stations utilize water ,
from the Missouri River for cooling purposes. Low water and flow levels can increase maintenance costs at these stations and, if these levels were to get low enough, could require modifications to plant operations. The possible effects of climate change (such as increased temperatures, in~reased occurrence of severe weather or reduced precipitation, among other possible results) could potentially increase the volatility of ciemand anq prices for e~ergy commodities, increase the frequency and impact of severe weather, increase the frequency of flood~ng oi,- deer.ease water and flow levels. To the extent the frequency of extreme weather events increases, this could increase the Companies' cost in providing service. -
Operational Risks:
Operational risks may adversely affect the Companies' results of operations, financial position and casn flows.
The operation of the Companies' electric generation, transmission, distribution and information systems involv,es many risks, including breakdown or failure of equipment, aging infrastructure, processes and personnd ,
performance; problems that delay or increase the cost of returning facilities to servic~ after outag.es; limitations tpi;tt may be imposed by equipment conditions or environmental, safety or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; labor disputes; difficulties with th-e implementation or continued -
operation of information systems; transmission scheduling con~traints; and catastrophic events such as fires, floods, droughts, explosions, terrorism, cyber threats, severe weather or other similar occurrences. Fµqhermore, to the ..
extent that a cyber attack was successful, customer and employee information may be stolen, equipment may be destroyed or damaged and operations may be disrupted. Any such equipment or system outage or constraint can, among other things:
in the case of generation equipment, affect operating costs, increase capital requirements and costs, increase purchased power volumes a_nd costs and reduce wholesale sales opportunities; 26
-1 in the case of transmission equipment, affect operating costs, increase capital requirements and costs, require changes in the source of generation'and affect wholesale sales opportunities and.the ability to meet regulatory reliability and security requirements; in the case of distribution systems, affect revenues and operating costs, increase capital requirements and costs, and affect the ability to meet regulatory service metrics and customer expectati~ns; and
- I in the case of information systems, affect the control and operations of generation, transmission, distribution, customer information and other business operations and processes, increase operating costs, increase capital requirements and costs, and affect the ability to meet regulatory reliability and security
- 11 requirements and customer expectations.
With the exception of Hawthorn No. 5, which was substantially rebuilt in 2001, and Iatan No. 2, which was II completed in 2010, all ofKCP&L's and GMO'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, reduced generation output and higher maintenance expense. Training, preventive maintenance and other programs have I been implemented, but there is no assurance that these programs will prevent or minimize future breakdowns or failures of the Companies' generation facilities or increased maintenance expense. Furthermore, aging transmission and distribution facilities are more prone to failure than*new facilities, which results in higher maintenance expense and the need to replace these facilities with new infrastructure. The higher maintenance costs and capital expenditures for new replacement infrastructure could cause additional rate volatility for the Companies' customers, resistance by the Companies' regulators to allow customer rate increases and/ofregula:tory lag.
The Companies currently have general liability and property insurance in place. to cover their facilities in amounts.
that management considers appropriate. These policies, however, do not cover the Companies' transmission or distribution systems, and the cost of repairing damage to these systems may adversely affect the Companies' results of operations, financial position and cash flows. 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 reasonable costs. or on commercially reasonable terins, and the insurance proceeds received for any loss of, or any damage to, any of the Companies' facilities may not be sufficient to restore the loss or damage.
These and other operating events may reduce the Companies' revenues, increase their costs, or both, and*may*
- materially affect their results of operations, financial position and cash flows.
Cyber attacks and other disruptions to facilities could interfere with ,operations, expose the Companies, customers or employees to a risk of loss and could cause reputational and financial harm.
Electric utilities and other operators of critical energy infrastructure, like KCP&L and GMO, may face a heightened risk of cyber attack. The Companies' facilities could be direct targets or indirect casualties of any such cyber . * .
attacks. The Companies' business relies on information technology for the generation, transmission and distribution of electricity, their primary business, as well as in secondary operational functions, including supply chain, and invoicing and collecting payments from customers. In the ordinary course of business, the Companies collect, store and transmit sensitive data including operating information, proprietary business information belonging to the Companies and third parties and personal information belonging to customers and employees. To the extent that a cyber attack was successful, customer and employee information may be stolen, equipment may be destroy.ed or damaged and operations of the generation fleet and/or reliability of the transmission and distribution system may qe disrupted. In such ail event, the Companies may experience substantial loss ofrevenues, material response costs and other financial loss, including the increased cost of insurance coverage. The Companies could also be subject to litigation, increased regulation and reputational damage. Any of the foregoing could have a material adverse impact on the Companies' results of operations, financial position and cash flows.
The Companies are subject to information security risks and risks of unauthorized access to their systems.
In the course of their businesses, the Companies handle a range of system security and sensitive customer information. KCP&L and OMO are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of the utilities' information systems such as theft or the inappropriate release of certain types of information, including confidential customer information or 27
system operating information, could have a material adverse impact on the results of operations, financial position and cash flows of the .companies.
KCP&L and GMO operate in a highly regulated industry that requires the continued operation of sophisticated inforination techllology systems and network infrastructures. Despite implementation of sec.urity measures, the technology systems are vulnerable to disability, failures, employee error or malfeasance, or unauthorized access.
Such failures or breaches of the systems could impact the reliability of generation, transmission and distribution systems, res~lt in legal claims and proceedings, damage the Companies' reputation and also* subje~t the Companies to financial.harm. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on the Companies' results of operations, financial position and cash flows.
The cost and schedule of capital projects may materially.change and expected performance may not be
~~~ .
Great Plains Energy's and KCP&L's businesses are.capital intensive. The Companies currently have significant .
capital projects pending and may also have significant capital projects in the future. The risks of any capital project include: that actual costs may exceed.estimated c.osts due to inflation or other factors; risks associated wi.th the incurrence of additional debt or the issuance of additional equity to fund such projects; delays that may occur in obtaining permits and materials; the failure of suppliers and, contractors to perform as required under their contracts; inadequate availability or increased cost of equipment, materials or qualified craft labor; delays related to inelement weather; the scope, cost and.timing of projects may change due. to new or changed environmental requirements, health and safety laws or other factors; arid other events beyond the Companies' control may occur that may materially affect the* schedule, cost and performance *of these projects,
- These and other risks could materially increase the estimated costs of capital projects, delay the in-service dates of .
projects, adversely affect the performance of the projects, and/or require the Companies to purchase additional electricity to supply their respective retail customers until the projects are completed. Thus, these risks may significantly affect.the Companies' results of operations, financial position and cash flows.
Failure of one or more generation plant co-owners to pay their share of construction or op,erations and maintenance costs could increase the Companies' costs and capital requirements.
KCP&L owns 47% of Wolf Creek, 50% of La Cygne Station, 70% of Iatan No. 1 and 55% of Iatan No. 2. GMO owns 18% of both Iatan units and 8% of Jeffrey Energy Center. The remaining portions of these facilities are .
.owned by other utilities that are contractually obligated to pay their proportionate share qf capital and other costs.
While the ownership agreements provide that a defaulting co-owner's share of the electridty generflted 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. Occurrence of these or other events could materi~lly increase the Companies' .costs and capital requirements.
KCP&L is expQsed to risks associated with the ownership and operation of a nuclear* generating unit, which could result in an adverse effect on the Companies' business and financial results.
KC~&L own§ 47% ofWolfCreek. The NRC has broad.a:uthority 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 impo;:;e fines, shut down the facilities, or both, depending upon its assessment of the severity of the situation, until co111pliance is achieved. Additionally, the non-compliance of other n:uclear facility operators with applicable regulations or the occurrence of a serious nuclear incident anywhere in_ the world could result in increased regulation of the nuclear industry as a whole. Any revised safety requirements promulgated by the NRC could result in substantial capital expenditures at Wolf Creek.
Wolf Creek has the,lowest fuel cost.per MWh of any of KCP&:i,'s generating units. An.e:x.tended outage of Wolf Creek, whether resulting from NRC action; an incident at the plant or otherwise, could have a material adverse effect on KCP&L's results of operations, financial position and cash flows in the event KCP&L incurs higher replacement power and other costs that are not.recovered through rates or insurance. If a long-term outage 28
occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base. Wolf Creek was constructed pri<?r to 1986 and the age of Wolf Creek increases the risk of unplanned outages and results in higher maintenance costs.
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 based on estimated decommissioning costs 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 projected level or actual decommissioning costs are higher than estimated, KCP&L could be responsible for the balartc.e of funds required and may not be allowed to recover the balance through rates.
KCP&L is also exposed to other risks associated with the ownership and operation of a nuclear generating unit, including, but no,tlimited to, (i) potential liability associated with the potential harmful effects on the environment and human health resulting from the operation of a nuclear generating unit, (ii) the storage, handling, disposal and potential release (by accident, through third-party actions or otherwise) of radioactive materials and (iii) uncertainties with respect to contingencies and assessments if insurance coverage is inadequate. Under the structure for insurance among owners of nuclear generating units, KCP &L is also liable for potential retrospective premium assessments (subject to a cap) per incident at any commercial reactor in the country and losses in excess of insurance coverage.
The structure of the regional power market in which the Companies operate could have an adverse effect on the Companies' results of operations, financial position and cash flows.
In March 2014, the SPP launched its Integrated Marketplace. Similar to other RTO or ISO markets, this
- marketpiace determines which generating units among market participants sho~ld run, within the operating constraints of a unit, at any given time for maximum cost-effectiveness. In the event that KCP&L's and GMO's generating units are not among the lowest cost generating units operating within the market, i<.CP&L and GMO could experience decreased_ levels of wholesale electricity sales.
A market for Transmission Congestion Rights (TCR) is also included as part of the Integrated Marketplace. TCRs are financial instruments used to hedge transmission congestion charges. Both KCP&L and GMO acquire TCRs for the purpose of hedging against transmission congestion charges. There is a risk that KCP&L and GMO could incorrectly model the amount ofTCRs needed, or that the TCRs acquired could be ineffective in hedging against transmission congestion charges.which could lead to increased purchased power.costs.
The rules governing the various regional power markets may change from time to time andsuch changes could impact the Companies' costs and revenues. Because the manner in which RTO's or ISO's will evolve is unclear, the Companies are unable to assess fully the impact of these changes.
Litigation Risks:
The outcome of legal proceedings cannot be predicted. An adverse finding could have a material adverse effect on the Companies' results of operations, financial position and cash flows.
The Companies 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 be reasonably estimated. The liability that the Companies may ultimately incur with respect to any of these cases in the event of a negative outcome may be in excess of amounts currently reserved and insured against with respect to such matters.
ITEM lB. UNRESOLVED STAFF COMMENTS None.
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ITEM 2. PROPERTIES Electric Utility Generation Resources
' ~ .. Year Estimated 2017 Primary Unit Location Completed MW Capacity Fuel (a)
Base Load Iatan No. 2 Missouri 2010 482 Coal (a) .
Wolf Creek Kansas '1985 549 Nuclear
(a)
Iatan No. 1 Missouri 1980 490 Coa.l (a)
La Cygne Nos. 1 and 2 Kansas 1973, 1977 699 Coal
- Hawthorn No. 5 (b) Missouri 1969 :564 Coal i Montrose Nos. 2 and 3 * 'Missouri *1960, 1964 - 334 Coal P~akLoad
- WestGardnerNos. l,'2, 3 and4 Kansas : :2003 ' ' 314 Natural Gas
- 1*
-Os~w~tomie '" 'Kansas 2003 '76 Natural Gas Hawthorn Nos. 6 and 9 Missouri 2000 235 Natiii:al Gas Hawthorn No. 8 Missquri : _',f'i'
- '2.ooo 1
~ , 79. Natural Gas Hawthorn No. 7 Missouri 2000 78 Natural Gas Northeast Black Start Unit Missouri 1985 2 Oil Northeast Nos. *17arid18 - -'"'"Missouri 1977,, '105 Oil
..; 95:
Northeast Nos. 13 and 14 ' " Missouri'* - ' :1976' Oil
'North~ast NOS. 15 and i 6 Missouri - ' 1975 106 Oil Northeast Nos. 11 and 12 ii Missouri 1972 93 Oil Wind _Speai;ville 2 Wind Energy Facility (c) -.- Kansas 2010 I~: 48 Wind Spearville 1 Wind Energy Facility (d) Kansas - 2006 101 W~nd Total KCP&L 4,450 (a)
Base Load ' *Iatan No. 2 " Missouri i -2010 -159 Coal i (a)
Iatan No. 1 l
Missouri : 1980 i26 Coal i *' (a)
- Jeffrey Energy Center Nos: 1, 2 anci'3
- Kansas 1978-, 1980, 1983 172 Coal Sibley Nos. I, 2 and 3 Missouri 1960,1962, 1969 448 Coal Peak Load Lake Road Nos. 2 and 4 Missouri 1957, 1967 115 NatUral Gas South Harper Nos. 1, 2 and 3 , . Missouri 2005 303 Natural Gas Crossroads Energy Center Mississippi '2002' 292 -Natural Gas Ralph Green No. 3 Missouri' 1981 '. 71 Natural Gas Greenwood Nos. 1, 2, 3 and 4 Missouri 1975-1979 242 Natural Gas/Oil Lake Road No. 5 Missouri 1974 62 Natural Gas/Oil Lake Road Nos. 1and3 Missouri 1951, 1962 24 Natural Gas/Oil 1
Lake Road Nos. 6 and 7 Missouri 1989, 1990 42 (:)il Nevada-* Missouri 1974 18 Oil
- .t:,-
Total GMO 2,074 Total Great Plains Energy 6,524 (a) Share of a jointly owned unit.
(b) In 2001, a new boiler, air quality control equipment and an uprated turbine 'was placed in service at the Hawthorn Generating Station.
(c) Accredited capacity is 14 MW pursuant to SPP reliability standards.
(d) Accredited capacity is 29 MW pursuant to SPP reliability standards.
KCP&L owns 50% of La Cygne Nos. 1and2, 70% oflatan No. 1, 55% oflatan No. 2 and 47% of Wolf Creek GMO owns 1.8% of each oflatan Nos. 1 and 2 and 8% of Jeffrey Energy Center Nos. 1, 2 and 3.
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Electric Utility Transmission and Distribution Resources Electric utility's electric transmission system interconnects with systems of other utilities for reliability and to permit wholesale transactions with other electricity suppliers. Electric utility has, approximately 3,600 circuit miles of transmission lines, 15,600 circuit miles of overhead distribution lines and 7,100 circuit miles of underground distribution lines in Missouri and Kansas. *Electric utility has all material franchise rights necessary to sell electricity within its retail service territory. Electric utility's transmission and distribution systems are continuously
- monitored for adequacy to meet customer needs. Management believes the current systems are adequate to serve customers.
Electric Utility General
. Electric utility's generating plants are located on property owned (or co-owned) by KCP&L or GMO, except the Spearville Wind Energy Facilities which are located on easements, arid the Crossroads Energy Center and the South Harper Facility which are contractually controlled. Electric utility's service centers, electric substations and a
- portion of its transmission'and distribution systems are located on property owned or leased by electric utility.*
Electric utility's transmission and distribution systems are for the most part located above or underneath highways, streets, other public places or property owned by others. Electric utility believes that it has satisfactory rights to use those places or properties in the form of permits, grants, easements, licenses or franchise rights; however, it has not necessarily undertaken efforts to examine the underlying title to the land upon which the rights rest. Great Plains Energy's and KCP&L's headquarters are located in leased office space.
- Substantially all of the fixed property and franchises of KCP &L, which consist principally of electri~ 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, as supplemented.. Mortgage bonds totaling $510.5 million were outstanding at December 31, 2016.
- A portion of the fixed property and. franchises of GMO are subject to a. General Mortgage Indenture and Deed of Trust dated as of April 1, 1946, as supplemented. Mortgage bonds totaling $5. 7 million were outstanding at December 31, 2016. ,
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, 15 and 16 to the consolidated financial statements. Such information is incorporated herein by reference.
ITEM 4. MINE SAFETY DISCLOSURES Not applicable.
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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's common stock is listed on the New York Stock Exchange under the symbol "GXP". At February 21, 2017, Great Plains Energy's common stock was held by 14,886 shareholders ofrecord. Infonnatfon relating to market prices and cash dividends on Great Plains Energy's common stock is set forth in the following table.
Common Stock Price Range <*> Common Stock 2016 ' 2015 Dividends Declared Quarter High Low High Low 2017 2016 2015 First $ 32.26 $ 26.34 $ 30.06 $ 25.80 $ 0.275 (b) $ 0.2625 $ 0.245 Second 32.68 28:35 27.52 24.16 0.2625 0.245 Third 31.22 26.53 27.35 24.21 0.2625 0.245 Fourth 28:60 26.20 28.02 25.74 0.275 0.2625 (a) Based on closing stock prices.
(b) Declared February 14, 2017, and payable March 20, 2017, to shareholders of record as* of February 27, 2017.
Dividend Restrictions For information regarding dividend restrictions, see Note 13 to the consolidated financial statements.
Purchases of Equity Securities Great Plains Energy had no purchases of its equity securities during the three months ended December 31, 2016.
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:
Dividend Restrictions For information regarding dividend restrictions, see Note 13 to the consolidated financial statements.
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ITEM 6. SELECTED FINANCIAL DATA Year Ended December 31 2016 2015 2014(a) 2013(a) 2012(a)
Great Plafos Energy (dollars iri. millions except per share amo~nts)
Operating revenues $ 2,676 $ . 2,502 $ 2,568 $ 2,446 $ 2,:310 Net income $ 290 $ 213 $ 243 $ 250 $ 200 Basic earnings per common share $ 1.61 $ 1.37 $ 1.57 $ *1.62 $ 1.36 Diluted earnings per common share $ 1.61 $ 1.37 $ 1.57 $ 1.62 $ 1.35 Total assets at year end (al. $ 13,570 $ 10,739 $ 10,453 $ 9,770 $ 9,626 Total redeemable preferred stock, mandatorily redeemable preferred securities and long-term debt (including current maturities) <*l $ 3,747 $ 3,746 $ 3,481 $ 3,492 $ 2,999 Cash dividends per common share $ 1.0625 $ 0.9975 $ 0.935 $ 0.8825 $ 0.855 SEC ratio of earnings to combined fixed charges and preferred dividend. requirements 2.54 2.58 2.72 2.75 2.31 KCP&L Operating revenues $ 1,875 $ 1,714 $ 1,731 $ 1,671 $ 1,580 Net income $ 225 $ 153 $ 162 $ 169 $ 142 Total assets at year end (a) $ 8,058 $ 7,815 $ 7,495 $ 6,821 $ 6,689 Total redeemable preferred stock, mandatorily redeemable preferred securities and long-
. term debt (including current maturities) *(a) $ 2,565 $ 2,563 $ 2,297 $. 2,294 $ 1,887 SEO ratio of earnings to fixed charges 3.30 2.57 2.69 2.76 2.58
<*l Adjusted for adoption of Ac~ounting St~ndards Update (ASU) No. 2.015-03, Simplifying the Presentation ofDebt Issuance Costs.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GREAT PLAINS ENERGY INCORPORATED EXECUTIVE
SUMMARY
Description of Business Great Plains Energy is a public utility holding coµipan~ and does not own or operate any significant assets other than the stock of its subsidiaries and cash and cash equivalents and a time deposit to.be used to fund a portion of the cash consideration for the anticipated acquisition of Westar. *
- Great Plains Energy's sole reportable business segment is electric utility. Electric utility consists ofKCP&L, a regulated utility, GMO's regulated utility oper~tions and GMO Receivables Company. Electric utility has approximately 6,500 MWs of owned generating capacity and engages in the generation, transmission, distribution and sale of electricity to approximately 855,700 customers in the states of Missouri and Kansas. Electric utility's retail electricity rates are comparable to the national average of investor-owned utilities.
Great Plains Energy's corporate and other activities not included in the sole reportable business segment includes GMO activity. other than its regulated utility operations, GPETHC and unallocated corporate charges including certain costs to achieve the anticipated acquisition of Westar.
Anticipated Acquisition of Westar Ebergy, Inc .
. On May 29, 2016, Great Plains Energy entered into a Merger Agreement by and among Great Plains Energy, Westar, and, from and after its accession to the Merger Agreement, Merger Sub. Pursuant to the Merger 33
Agreement, subject to the satisfaction or waiver of certain conditions, Merger Sub will merge with and into Westar, with Westar continuing as the surviving corporation. Upon closing, pursuant to the Merger Agreement, Great Plains Energy will acquire Westar for (i) $51.00 in cash and (ii) a number, rounded to the nearest Vl 0,000 of a share, of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average price per share of Great Plains Energy common stock during a 20 consecutive full trading day period ending on (and including) the third trading day immediately prior to the closing date of the merger, for each share of Westar corrnnDn stock issued and outstanding innnediately prior to the effective time of the merger, with Westar becoming a wholly owned subsidiary of Great Plains Energy" Great Plains Energy's anticipated acquisition of Westar was unanimously approved by the Great Plains Energy Board and the Westar Board, has received the required approvals of each of Great Plains Energy's and Westar's shareholders and The Federal Communications Commission (FCC), and has received early termination of the waiting period under the HSRAct with respect to ant1trust review. The anticipated acquisition remains subject to regulatory approvals from KCC, the MPSC, NRC and FERC; as well as other customary CQnditions.
On October 3, 2016, Great Plains Energy completed registered public offerings of 60.5 million shares of common stock for total net proceeds of $1.55 billion and 17.3 million depositary shares each representing a l/20th interest in a share of Great Plains Energy's Series B Preferred Stock for total net proceeds of $836.2 million. The proceeds from these offerings will be used to fund a portion of the cash consideration for the anticipated acquisition.
See Note 2 to the consolidated financial statements for more information regarding the acquisition.
Earnings Overview Great Plains Energy's 2016 earnings available for common shareholders increased to $273.5 million or $1.61 per share from $211.4 million or $1.3 7 per share in 2015 driven primarily by new retail rates and cost recovery mechanisms; warmer weather; a performance .incentive for energy efficiency programs under the Missouri Energy Efficiency fovestment Act (MEEIA) and a decrease in interest charges; partially offset by a decrease in weather-normalized retail demand; costs to achieve the anticipated acquisition of Westar; an increase in utility operating and maintenance expense; depreciation and amortization expense .and general taxes; higher income fax expense; and increased preferred stock dividend requirements. **
In addition, a higher number of aver;:tge shares outstanding due to Great Plains Energy's registered public offering of60.5 million shares ofcommon stock in October 2016 diluted 2016 earnings per share by $0.15.
For additional information regarding the change in earnings, refer to the Great Plains Energy Results of Operations and the Electric Utility Results of Operations sections within this Management's Discussion and Analysis of Financial Condition artd Results of Operations (MD&A).
Adjusted Earnings (Non-GAAP) and Adjusted Earn.ngs Per Share (Non-GAAP)
Great Plains Energy's adjusted earnings (non-GAAP) and adjusted earnings per share (non-GAAP),for 2016 were
$286.0. million and $1.85, respectively. For 2015 and 2014, adjusted earnings (non-GAAP) and adjusted earnings per share (non-GAAP) were the same as GAAP earn!ngs and GAAP earnings per share at $211.4 million and
$1.37 and $241.2 million and $1.57, respectively. In addition to earnings available for common shareholders anq diluted earnin'gs p~r common share, Great Plains Energy's management uses adjusted earnings (non-GAAP) and adjusted earnings per share (non-GAAP) to evaluate earnings and earnings per share without the impact of the anticipated acquisition of Westar. Adjusted earnings (non-GAAP) and adjusted earnings per share (non-GAAP) excludes certain costs, expenses, gains, losses and the per share dilutive effect of equity issuances resulting from the anticipated acquisition. This information is intended to enhance an investor's overall understanding of results.
Adjusted earnings (non-GAAP) and adjusted earnings per share (non-GAAP) are used internally to. measure performance against budget and in reports for management and the Gre_at Plains Energy Board. Adjusted earnings (non-GAAP) and adjusted earnings per share (non-GAAP) are financial measures that are not calculated in accordance with GAAP and may not be comparable to other companies' presentations or more useful than the GAAP information provided elsewhere in this rep01t.
34
The following table provides a reconciliation between earnings available for common shareholders and diluted earnings per common share as detennined in accordance with GAAP and adjusted earnings (non-GAAP) and adjusted earnings per share (non-GAAP):
2016 Earnings per diluted Reconciliation of GAAP to Non-GAAP share (millions, except per share amounts)
Earnings available for common shareholders $ 273.5 $ 1.61 Costs to achieve the anticipated acquisition of Westar:
Operating expense, pre-tax (a) 34.2 0.22*
Financing, pre~tax Cb) 35.9 0.24 Mark-to-market impacts of interest rate swaps, pre-tax (c) (79.3) (0.51)
Interest income, pre-tax (d) (3.2) (0.02)
. Income tax expense Ce) 9.5 0.06 Preferred stock (!) 15.4 0.10 Dilutive.impact of October 2016 share iss~ance (g) NIA 0.15 Adjusted earnings (non-GAAP) $ 286.0 $ 1.85 Average Shares Outstanding Shares used in calculating diluted earnings per c~mmon share 169.8 Adjustment for October 2016 share issuance (g) (14.9)'
Shares used in calculating adjusted earnings per share (non-GAAP) 154.9 (a) Reflects legal, advisory and consulting fees* and certain severance.expenses and are included in Costs to achieve the anticipated .
. acquisition of Westar on the consolidated statements of comprehensive income. . *
.(bi Reflects fees incurred to finance the anticipated 'acquisition ofW~star, including. fees for a bridge term loan facility, and ai~ included in Interest charges on the consolidated statements of comprehensive inconie.
(c) Reflects the mark-to-market gain on interest rate swaps entered into in conriection with financing the anticipated acquisition of Westar and is included in Interest charges on the consolidated statements of comprehensive income.
(dJ Reflects interest income earned on the proceeds from Great Plains Energy's October 2016 equity offerings and is included in Non-operating income on the consolidated statements of comprehensive income. * * *
<*J Reflects an income tax effect calculated at a 38.9% statutory rate, with the exception of certain non-deductible )egal and financing fees.
<fl Reflects reductions to earnings available for common shareholders related to prefe~ed stock dividend requirements for Great Plains Energy's Series B Preferred Stock issued in October 2016 and the redemption of cumulative preferred stock in August 2016, including the redemption premium, and are included in Preferred stock dividend requirements and redemption premium on the consolidated statements of comprehensive income.
(gJ-R.efleets the average share impact of Great Plains Energy's issuance of 60.5 million shares of common stock in October 2016.
Regulatory Proceedings See Note 6 to the consolidated financial statements for information regarding regulatory proceedings.
Impact of Recently Issued Accounting Standards See Note 1 to the consolidated financial statements for information regarding the impact of recently issued accounting standards.
Wolf Creek Refueling Outage Wolf Creek's latest refueling outage began on September 10, 2016 and ended on November 21, 2016. Wolf Creek's next refueling outage is planned to begin in the first quarter of2018.
ENVIRONMENTAL MATTERS See Note 15 to the consolidated financial statements for information regarding environmental matters.
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RELATED PARTY TRANSACTIONS See Note 18 to the consolidated financial statements for information regarding related party transactions.
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 Great Plains Energy's results of operations and financial position. Management has identified the following accounting policies as critical to the understanding of Great Plains Energy'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 Great Plains Energy Board of Directors.
Pensions Great Plains Energy incurs 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.
- Pension costs are impacted by actual employee demographics (including age, life expectancies, compensation levels and employment periods), earnings on plan assets*, the level of contributions made to the plan, and plaii .
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. *
- The assumed rate ofreturn on plan assets was developed based on.the weighted-average oflong-term returns forecast for the expected portfolio mix of investments held by the plan. The assumed discount rate was selected based on the prevailing market rate of fixed income debt instruments with maturities matChing the expected timing of the benefit obligation. These assumptions, updated annually at the measurement date, are based on management's best estimates and judgment; however, material changes may occur if these assumptions differ from actual events. See Note 9 to the consolidated financial statements for information regarding the assumptions used to determine benefit obligations and net costs.
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 of the change based on a change in that assumption only.
Impact on Impact on Projected 2016 Change in Benefit Pension Actuarial assumption Assumption
- Obligation Expense (millions)
Discount rate 0.5% increase $ (86.1) $ (5.9)
Rate ofreturn on plan assets 0.5% increase (3.4)
Discount rate 0.5% decrease 96.9 6.1 Rate ofretum on plan assets 0.5% decrease 3.4 Pension expense for KCP&L and GMO is recorded in accordance with rate orders from the MPSC and KCC. The orders allow the difference between pension costs under GAAP and pension costs for ratemaking to be recorded as a regulatory asset or liability with future ratemaking recovery or refunds, as appropriate. .
In 2016, Great Plains Energy's pension expense was $98.2 million under GAAP and $93.3 million for ratemaking.
The impact on 2016 pension expense in the table above reflects the impact on GAAP pension costs. Under the 36
Companies' rate agreements, any increase or decrease in GAAP pension expense would be deferred in a regulatory asset or liability for future ratemaking treatment. S,ee Note 9 to the consolidated financial statements for additional information regarding the accounting for pensions.
_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 the inherent uncertainty of market conditions.
Regulatory Assets and Liabilities The Company has recorded assets and liabilities on its consolidated balance sheets resulting from the effeets 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 future reductions in revenues or refunds to customers.
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 in electric utility's rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to electric utility; and changes in laws and regulations: If recovery or refund ofregulatory 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. Electric utility's continued ability to meet the criteria for recording regulatory assets and liabilities may be affected in the future by restructuring and deregulation in the
- electric industry or changes in accounting rules. In the event that the criteria no longer applied to all or a portion of electric utility's operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism were provided. Additionally, these factors could result in an impairment on utility plant assets. See Note 6 to the consolidated financial statements for additional information.
Impairments of Assets, Intangible Assets and Goodwill Long-lived assets and intangible assets subject to amortization are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under GAAP.
Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists. The goodwill impairment test is a two step process. See Note 1 to the cqnsolidated financial statements for additional information regarding the Company's plans to adopt Accounting Standards Update (ASU) No. 2017-04 for its :2017 goodwill impairment test. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill, to identify potential_ impairment. If the carrying amount exceeds the fair value of the (eporting unit, the second step of the test is performed, consisting of assignment of the reporting unit's fair value to *its assets and liabilities to determine an implied fair value of goodwill, which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements. Great Plains Energy's regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics.
The annual impairment test for the $169.0 million of GMO acquisition goodwill was conducted on September 1, 2016. Fair value of the reporting unit substantially exceeded the carrying amount, including goodwill; therefore, there was no impairment of goodwill.
The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, earnings before interest, income taxes, depreciation and amortization (EBITDA), net utility asset values and market prices of stock of peer companies. The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit, which involves a significant amount of management
- judgment.
37
The discounted cash flow analysis is most significantly impacted by two assumptions: estimated future cash flows and the discount rate applied to those cash flows. Management d~termined the appropriate discount rate to be based on the reporting unit's weighted average cost of capital (WACC). The WACC takes into account both the return on equity authorized by the MPSC and KCC and after-tax cost of debt. Estimated future cash flows are based on Great Plains Energy's internal business plan, which assumes the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of return* on equity, anticipated earnings/returns related to future capital investments, continued recovery of cost of service and the renewal of certain contracts. Management also makes assumptions regarding the ~n rate of operations, maintenance and general and administrative costs based on the expected outcome of the aforementioned events. Should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, revisions to current cash flow assumptions could cause the fair value of Great Plains Energy's reporting unit under the income approach to be significantly different in future periods and could result in a future impairment charge to goodwill.
The market approach analysis is most significantly impacted by management's selection of relevant peer companies as well as the determination of an appropriate control premium to be added to the calculated invested capital of the reporting unit, as control premiums associated with a controlling interest are not reflected ill the quoted market price of a single share of stock. Management determined an appropriate control premium by using an average of control premiums for recent acquisitions in the industry. Changes in results of peer companies, selection of different peer companies and future acquisitions with significantly different control premiums could result in a significantly different fair value of Great Plains Energy's reporting unit.
Income Taxes Income taxes are accounted for using the asset/liability approach. Deferred tax assets and liabilities are determined based on the temporary differences between_ the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates in effect for the year in which the differences are expected to reverse. Deferred investment tax credits are amortized ratably over the life of the related property. Deferred tax assets ar'e also recorded for net operating losses, capital losses and tax credit carryforwards. The Company is required to estimate
- the amount of taxes payable or refundable for the current year and the deferred tax liabilities and assets for_ future tax consequences of events reflected in the Company's consolidated financial statements or tax returns. Actual results could differ from these estimates for a vi;iriety ofreasons including changes in income tax laws, enacted tax rates and results of audits by taxing authorities_. This process also requires management to make assessments regarding the timing and probability of the ultimate tax impact from which actual results may differ. The Company records valuation allowances on deferred tax assets if it is determined that it 'is more likely than not that the asset will not be realized. See Note 22 to the consolidated financial statements for additional information.
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GREAT PLAINS ENERGY RESULTS OF OPERATIONS The following table summarizes Great Plains Energy's comparative results of operations.
2016 2015 2014 (millions)
Operating revenues $ 2,676.0 $ 2,502.2 $ 2,568.2 Fuel and purchased power (590.1) (608.7) (742.5)
Transmission (84.8) (89.1) (74.7)
Other operating expenses (1,003.2) (943.9) (910.5)
Costs to achieve the anticipated acquisition of Westar (34.2)
Depreciation and amortization (344.8) (330.4) (306.0)
Operating income 618.9 530.l 534.5 Non-op~rating income and expenses 2.8 3.7 12.5 Interest charges (161.5) (199.3) (188.5)
Income tax expense (172.2) (122.7) (115.7)
Income from equity investments 2.0 1.2 Net income 290.0 213.0 242.8 Preferred dividends and redemption premium (16.5) (1.6) (1.6)
Earnings available for common shareholders $ 273.5 $ 211.4 $ 241.2 Reconciliation of gross margin to operating revenue:
Operating revenues $ 2,676.0 $ 2,502.2 $ 2,568.2 Fuel and purchased power (590.1) (608.7) (742.5)
Transmission (84.8) (89.1) (74.7)
Gross margin (al $ 2,001.1 $ 1,804.4 $ 1,751.0 (a) Gross margin is a non-GAAP financial measure. See explanation of gross margin below.
2016 Compared to 2015 Electric Utility Segment Electric utility's net income increased $68.3 million in 2016 compared to 2015 primarily due to:
a $196. 7 million increase in gross margin driven by new retail rates and cost recovery mechanisms, warmer weather and an increase in the recovery of program costs and throughput disincentive as well as a performance incentive for energy efficiency programs under MEEIA, partially offset by a decrease in weather-normalized retail demand; a $50.0 million increase in other operating expenses driven by an increase in pension expense, an increase in program costs for energy efficiency programs under MEEIA, an increase in plant operating and maintenance expenses, an increase in injuries and damages expense and an increase in general taxes driven by higher property taxes and higher gross receipts ~axes due to an increase in retail revenues;
$1 S.9 million of operating expenses for costs to achieve the anticipated acquisition of Westar; a $14.4 million increase in depreciation and am9rtization expense driven by capital additions; a $5 .2 million increase in. interest charges primarily due to an increase in interest expense in 2016 related to KCP&L's issuance of $350 million of 3.65% Senior Notes in August 2015; partially offset by a decrease in interest expense due to KCP&L's purchase in lieu ofredemption of its $50.0 million and $21.9 million Environmental Improvement Revenue Refunding (BIRR) Series 2005 bonds in September 2015; and a $43.5 million increase in income tax expense driven by an increase in pre-tax income.
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Corporate and Other Activities Great Plains Energy's corporate and other activities loss increased $6.2 million in 2016 compared to 2015 primarily due to:
$7Smillion of other operating expenses for the settlement oflitigation at MPS Merchant in 2016; *
$18.3 million of operating expenses for costs to achieve the anticipated acquisition of Westar;
$35.9 million of interest charges for fees incurred for a bridge term loan facility entered into in connection with the anticipated acquisition of Westar; a $79.3 million mark-to-market gain on interest rate swaps entered into in June 2016 to hedge against interest rate fluctuations on future issuances oflong-term debt expected to be issued to finance a portion of the cash consideration for the anticipated acquisition of Westar;
$3.2 million of interest income earned on the proceeds from Great Plains Energy's October 2016 common stock and depositary share offerings;
$12.7 million of income tax expense related to these items; and
$15.4 million ofreductions to earnings available for common shareholders consisting of $14.8 million of dividends on Great Plains Energy's Series B Preferred Stock issued in October 2016 and $0.6 million related to th~ redemption of Great Plains Energy's cumulative preferred stock in August 2016.
2015 Compared to 2014 Electric Utility Segment Electric utility's net income decreased $19.7 million in 2015 compared to 2014 primarily due to:
a $53.4 million increase in gross margin driven by new retail rates, an increase in recovery of program costs for energy efficiency programs under MEEIA, an increase in recovery of renewable energy costs under the Renewable Energy Standard Rate Adjustment Mechanism ,(RESRAM), an increase in weather-noni:lalized
- retail demand and an increase in other margin items, partially offset by lower wholesale margins, higher transmission expense and weather; a $33.8 million increase in other operating expenses primarily driven by an increase in program costs for energy efficiency programs under MEEIA, an increase in amortization of deferred renewable energy costs under RESRAM and an increase in general .taxes driven by higher property taxes, partially offset by a
. decrease in Wolf Creek ~perating and maint~nanc'e exp~nse~; . . - , . .. . . . . , ,.
a $24.4 million increase in depreciation and amortization expense due to capital additions; an $11.8 million decrease in non-operating income and expenses driven by a $13 .2 million decrease in the equity component of Allowance for Funds U sedDuring Construction (AFUDC) primarily due to a lower average construction work in progress in 2015 due to environmental upgrades at KC'.P&L's La Cygne Station being placed into service; a $7.9 million increase in interest charges primahiy duet~ a $7.2 million decrease in the.debt component of AFUDC; and*
a $4.8 million decrease in income tax expense primarily driven by decreased pre-tax income.
Corporate and Other Activities Great Plains Energy's corporate and other activities loss increased $10.1 million in 2015 compared to 20.14 primarily due to the release of uncertain tax positions related to former *GMO non-regulated operations in the third quarter of 2014 which resulted in:
- . $2.1 million lower after-tax,interest expense in 2014; and
- $6.1 million of income tax benefits in 2014.
40
Gross Margin Gross margin is a financial measure that is not calculated in accordance with GAAP. Gross margin, as used by Great Plains Energy and KCP&L, is defined as opei:ating revenues less fuel and purchased power and transmission.
Expenses for fuel and purchased power and ce1iain transmission costs, offset by wholesale sales margin, are subject to recovery through cost adjustment mechanisms, except for KCP&L's Missouri retail operations prior to September 29, 2015, when a cost adjustment mec4anism was approved. As a result, operating revenues increase or decrease in relation to a significmit portion of these expenses. Management believes that gross margin provides* a meaningful basis for evaluating electric utility's operations across periods because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Great Plains Energy Board. The Companies' definition of gross margin may differ from.similar terms used by other companies.
ELECTRIC UTILITY RESULTS OF OPERATIONS The following table summarizes the electric utility segment results of operations.
2016 2015 2014 (millions)
Operating revenues $ 2,676.0 $ 2,502.2 $ 2,568.2 Fuel and purchased power (590.1) (608. 7) (742.5)
Transmission (84.8) (89.1) (74.7)
Other operating expenses (990.2) (940.2) (906.4)
I Costs to achieve the anticipated acquisition of Westar (15.9)
Depreciation and amortization (344.8) (330.4) (306.0)
Operating income 650.2 533.8 538.6 Non-operating income and expenses 2.3 1.7 13.5 Interest charges (196.1) (190.9) (183.0)
Income tax expense (164.3) (120.8) (125.6)
Net income $ 292.1 $ 223.8 $ 243.5 Reconciliation of gross margin to operating revenue:
Operating revenues $ 2,676.0 $ 2,502.2 $ 2,568.2 Fuel and purchased power (590.1) (608.7) (742.5)
Transmission (84.8) (89.1) (74.7)
Gross margin (a) $ 2,001.1 $ 1,804.4 $ 1,751.0
<*l Gross margin is a non-GAAP financial me*asure. See explanation of gross margin under Great Plains Energy's Results of Operations.
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Electric Utility Gross Margin and MWh Sales The following .tables summarize electric utility's gross margin and MWhs sold.
Gross Margin <*> 2016 Change(c> 2015 Change(c) 2014 Retail revenues (millions)
Residential $ 1,092.5' 9 $ 1,006.2 (2) $ 1,025.5 Commercial 1,066.0 6 1,001.0 1 995.2 Industrial 229.6 3 222.3 (1) 225.3 Other retail revenues 20.9 3 20.4 20.3 Provision for rate refund (9.6) NIM Energy efficiency (MEEIA)(b) 80.0 55 51.5 81 28.5 Total retail 2,479.4 8 2,301.4 2,294.8 Wholesale revenues 142.0 (3) 147.1 (34) 222.6 Other revenues 54.6 2 53.7 6 50.8 Operating revenues 2,676.0 7 2,502.2 (3) 2,568.2 Fuel and purchased power (59o.ir (3) (608.7) ' (18) (742.5)
Transmission (84.8) (5) (89.1) 19 (74.7)
Gross margin $ 2,001.1 11 $ 1;804.4 ~ $ 1,751.0 (a) Gross margin is a non-GAAP financial measure. See explanation of gross margin urider Great Plains Energy's Results of Operations.
(b) Consists ofrecovery of program costs of $49.3 million, $42.9 million and $20.7 million for 2016, 2015 and 2014, respectively, that have a direct offset in utility operating and maintenance expenses, recovery of throughput disincentive of$15.l million, $8.6 million and $7.8 million for 2016, 2015 and 2014, respectively, and a performance incentive of$15.6 million for 2016.
(c) NIM - n~t meaningful .
O/o O/o MWh Sales 2016 Change 2015 Change 2014 Retail MWh sales (thousands)
Residential 8,774 2 8,585 (4) 8,971 Commercial 10,796 10,777 (1) 10,827 Industrial 3,149 (1) 3,191 3,200 Other retail MWh sales 115 (1) 116 (1) 117 Total retail 22,834 1 22,669 (2) 23,115 Wholesale MWh sales 7,063 9 6,512 (14) 7,587 Total MWh sales . 29 897* 3 29,181 (5) 30,702 Electric utility's residential customers' usage is significantly affected by weather. Bulk power sales, the major component of wholesale sales, vary with system requirements, generating unit availability, transmission availability, fuel costs, and requirements of other electric systems. Electric utility's revenues contain certain recovery
- mechanisms as follows:
KCP&L's Kansas retail rates contain an Energy Cost Adjustment (ECA) tariff. The ECA tariff reflects the projected annual amounts of fuel, purchased power, emission allowances and asset-based off-system sales margin. 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) is recorded either as a-reduction offuel and purchased power expense (for under-recoveries) or a reduction of retail revenues (for over-recoveries) 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.
KCP&L's Kansas retail rates contain a Transmission Delivery Charge (TDC) rider. The TDC tariff reflects a mixture of historiCal and projected costs related to transmission service, certain RTO fees, transmission rate base, and transmission operating and ml:).intenance expense. These costs are subject to an annu,al true-up with a twelve month recovery period. The TDC true-up is recorded either as a reduction of transmission expense (for under-recoveries) or a reduction of retail revenues (for over-recoveries) and deferred as a 42
regulatory asset or liability to be recovered from or refunded to KCP&L's Kansas electric retail customers.
The TDC became effective in conjunction with new retail rates on October 1, 2015.
KCP&L's Missouri retail rates contain a Fuel Adjustment Clause (FAC) tariff under which 95% of the difference between actual fuel cost, purchased power costs, certain transmission costs and off-system sales margin and the amount provided in base rates for these costs is passed along to KCP&L's customers. The FAC cycle consists of a:n accumulation period of six months beginning in January and July with FAC rate approval requested every six months for a twelve month recovery period. The FAC is recorded either as a reduction of fuel and purchased power expense (for under-recoveries) or a reduction ofretail revenues (for over-recoveries) and deferred as a regulatory asset or liability to be recovered from or refunded to KCP&L's electric retail customers. The FAC became effective in conjunction with new retail rates on September 29, 2015.
GMO's electric retail rates contain a F4-C tariff under which 95% of the difference between actual fuel cost, purchased power costs, certain transmission costs and off-system sales margin and the amount provided in base rates for these costs is passed along to GMO's customers. The FAC cycle consists of an accumulation period of six months beginning in June and December with FAC rate approval requested every six months for a twelve month recovery period. The FAC is recorded either as a reduction of fuel and purchased power expense (for under-recoveries) or a reduction ofretail revenues (for over..:recoveries) and deferred as a regulatory asset or liability to be recovered from or refund~d to GMO's electric retail customers.
GMO's steam rates contain a Quarterly Cost Adjustment (QCA) under which 85% of the difference between actual fuel costs and base fuel costs is passed along to GMO's steam customers. The QCA is recorded either as a reduction of fuel and purchased power expense (for under-recoveries) or a reduction ofretail revenues (for over-recoveries) ;md deferred as a regulatory asset or liability to be recovered from or refunded to GMO's stearn customers.
Both KCP&L and GMO offer energy efficiency and demand side management programs to their Missouri retail customers under MEEIA and recover program costs, throughput disincentive and as applicable, certain performance incentives in retail rates. KCP&L and GMO recover these items through a rider mechanism. For program costs, the difference between the amount collected and actual program costs is recorded either as a reduction to utility operating and maintenance expense (for under-recoveries) or a reduction to retail revenues (for over-recoveries) and is deferred as a regulatory asset or liability to be recovered from or refunded to customers. For throughput disincentive, the difference between the amount collected and the actual throughput disincentive is recorded as an increase to or reduction of retail revenues and i~ deferred as a regulatory asset or liability to be recovered from or refunded to customers. The performance incentive is recorded as an increase to retail revenues and a receivable to be recovered from customers.
Electric utility's gross margin increased $196.7 million in 2016 compared to 2015 primarily driven by:
an estimated $111 million increase due to new retail rates and an estimated $3 7 million increase due to new cost recovery mechanisms for KCP&L in Missouri effective September 29, 2015, and in Kansas effective October 1, 2015; an estimated $3 8 million increase due to warmer weather with a 16% increase in cooling degree days in 2016; a $6.4 million increase for recovery of program costs for energy efficiency programs under MEEIA, which have a direct offset in utility operating and maintenance expense; a $6.5 million increase in MEEIA throughput disincentive; a $15 .6 million MEEIA performance incentive recognized in 2016 related to the achievement of certain energy savings levels in the first cycle ofKCP&L's and GMO's MEEIA programs; and an estimated $9 million decrease due to a decrease in weather-normalized retail demand.
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Electric utility's gross margin increased $53.4 million in 2015 compared to 2014 primarily driven by:
an estimated $36 million increase due to new retail rates for KCP&L in Missouri effective September 29,
- 2015, and in Kansas effective July 25, 2014 and October 1, 2015; a $22.2 million increase for recovery of program costs for energy efficiency programs under MEEIA, which have a direct offset in utilitY operating and maintenance expense, primarily due to the implementation of KCP&L's MEEIA programs in August 2014; a $7.2 million increase for recovery ofrenewable energy costs under RESRAM, which have a direct offset in utility operating and maintenance expense; an estimated $6 million increase from weather-nonnalized retail demand; an estimated $20 million increase in other margin items including a change in customer mix, lower fuel and purchased power expenses that are not included in fuel recovery mechanisms and an increase in transmission costs recovered through the transmission delivery charge rider that began in the fourth quarter of 2015; an estimated $19 million decrease due to lower wholesale margins partially offset by an estimated $14 million due to lower fuel and purchased po,wer expense at KCP&L in Missouri, where there was no fuel ,
recovery mechanism prior to September 29, 2015; an estimated $9 million decrease due to higher transmission expense; and an estimated $24 million decrease due to weather driven by a 19% decrease in heating degree days in 2015 and a 15% decrease in cooling degree days in the second quarter of 2015 partially offset by an 18% increase in cooling degree days in the third quarter of 2015.
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.
O/o %
2016 Change 2015 Change 2014 CDD 1,585 16 1,370 8 1,266 HDD 4,296 (6) 4,578 (19) 5,666 Electric Utility Other Operating Expenses (including utility operating and maintenance expenses, general taxes and other)
Electric utility's other operating expenses increased $50,.0 million in 2016 compared to 2015 primarily driven by:
a $4.8 million increase in pension expense corresponding to the resetting of pension expense trackers with the effective date of new retail rates; a $6.4 million increase in program costs for energy efficiency programs under MEEIA, which have a direct offset in revenue; a $4.9 million increase in plant operating and maintenance expense; a $7 .9 million increase in injuries and damages expense primarily due to an increase in estimated losses from an unfavorable judgment in ongoing litigation; and a $13. 7 million increase in general. taxes driven by higher property taxes and higher gross receipts taxes due to an increase in retail revenues.
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Electric utility's other operating expenses increased $33.8 million 'in 2015 compared to 2014 primarily driven by:
a $22.2 million increase in program costs for energy efficiency programs under MEEIA, which have a direct offset in revenue, primarily due to the implementation ofKCP&L's MEEIAprograms in August
. 2014; a $7.2 million increase in amortization of deferred renewable energy costs under RESRAM, which have a direct offset in revenue; an $8. 7 million increase in general taxes driven by higher property taxes; and a $10.0 million d~crease in Wolf Creek operating and maintenance expenses primarily due to decreased refueling outage amortization of $3 .6 million and $8. 7 million from a planned mid-cycle maintenance outage in 2014.
Electric Utility Costs to Achieve the Anticipat~d Acquisition of Westar Electric utility's costs to achieve the anticipated acquisition of Westar of$15.9 million in 2016 reflects consulting fees, certain severance expenses and other transition costs related to the anticipated acquisition of Westar.
Electric Utility Depreciation and Amorti.Zation Electric utility's depreciation and amortization expense increased $14.4 million and $24.4 million in 2016 compared to 2015 and 2015 compared to 2014, respectively, due to capital additions.
Electric Utility Non-Operating Income and Expenses Electric utility's non-operating income and expenses decreased $11.8 million in 2015 compared to 2014 primarily due to a $13.2 million decrease in the equity component of AFUDCprimarily due to a lower average construction work in progress in 2015 due to environmental. upgrades at KCP&L's La Cygne Station being placed into service.
Electric Utility Interest Charges Electric utility's interest charges increased $5.2 million in 2016 compared to 2015 primarily due to a $7.9 million increase in interest expense related to KCP&L's issuance of $350 million of 3 .65% Senior Notes in August 2015; partially offset by a $2.2 million decrease in interest expense due to KCP&L's purchase in lieu ofredemption of its
$50.0 million and $21.9 million EIRR Series 2005 bonds in September 2015.
Electric utility's interest charges increased $7.9 million in 2015 compared to 2014 pr!marily due to a $7.2 million decrease in in the equity component of AFUDC primarily due to a lower average construction work in progress in 2015 due to environmental upgrades at KCP&L's La Cygne Station being placed into service.
Electric Utility Income Tax Expense Electric utility's income tax expense increased $43.5 million in 2016 compared to 2015 due to increased pre-tax income. Electric utility's income tax expense decreased $4.8 million in 2015 compared to 2014 primarily due to decreased pre-tax income.
GREAT PLAINS ENERGY SIGNIFICANT BALANCE SHEET CHANGES (December 31, 2016 compared to December 31, 2015)
Great Plains Energy's cash and cash equivalents increased $1,281.8 million due to*a portion of the
. proceeds from Great Plains Energy's October 2016 common stock and depositary share offerings.
- Great Plains Energy's time deposit increased $1,000.0 million due to an investment made with a portion of the proceeds from Great Plains Energy's October 2016 common stock and depositary share offerings.
Great Plains Energy's derivative instruments - current assets increased $80.7 million due to a $79.3 million mark-to-market gain on interest rate swaps entered into in June 2016 to hedge against interest rate fluctuations on future is_suances oflong-term debt expected to be issued to finance a portion of the cash consideration for the anticipated acquisition of Westar.
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Great Plains Energy's commercial paper increased $110.8 million due to an increase in commercial paper of $158.2 million at GMO due to borrowings for capital expenditures and general corporate purposes partially offset by the repayment of $47.4 million of commercial paper at KCP&L with funds from
- operations.
Great Plains Energy's current maturities oflong-term debt increased $381.0 million and long.:.term debt decreased $379.9 million due to the reclassification ofKCP&L's $250.0 million of 5.85% Senior Notes and $31.0 million of 1.25% BIRR Series 1992 bonds and Great Plains Energy's $100.0 million of 6.875%
Senior Notes from long-tenn to current.
Great Plains Energy's deferred income taxes increased $170.9 million primarily due to an increase in temporary differences and changes in the projected utilization of net operating loss carryforwards, primarily driven by bonus depreciation.
Great Plains Energy's asset retirement obligations increased $40.1 million primarily due to an increase in cost estimates for the closure of ponds and landfills containing coal combustion residuals (CCRs) at*
KCP&L electric generating facilities.
- Great Plains Energy's common stock increased $1,570.3 million I primarily due to $1.55 billion in net proceeds from Great Plains Energy's public offering of 60.5 million shares of common stock in October 2016.
Great Plains Energy's cumulative preferred stock $100 par value decreased $39.0 million due to the redemption of its 390,000 shares of outstanding cumulative preferred stock in August 2016.
Great Plains Energy's preference stock without par value increased $836.2 million due to the'issuance of Series B Preferred Stock in conjunction with Great Plains Energy's October 2016 depositary share offering. See Note 14 to the consolidated financial statements for additional information.
CAPITAL REQUIREMENTS AND LIQUIDITY Great Plains Energy operates through its subsidiaries and has no material assets other than the ~tock of its subsidiaries and cash and cash equivalents and a time deposit to be used to fund a portion o(the cash consideration for the anticipated acquisition of Westar. 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, proceeds from the issuance of its securities and borrowing under its revolving credit facility.
Great Plains Energy's capital requirements are principally comprised of debt maturities and electric utility's construction and other capital expenditures. These items as well as additional cash and capital requirements, including the anticipated acquisition of Westar, are discussed below. 1, Great Plains Energy's liquid* resources at December 31, 2016, consisted of $1.3 billion of cash and cash equivalents on hand, a $1.0 billion time deposit that matures in the first quarter of 2017 and $912.1 million of available borrowing capacity from unused bank lines of credit and receivable sale agreements. The available borrowing capacity consisted of $199 .0 million from Great Plains Energy's revolving credit facility, $464.3 million from KCP&L's credit facilities and $248.8 million from GMO's credit facilities. See Notes 4 and 11 to the consolidate~
financial statements for inore information regarding the receivable sale agreements and revolving credit facilities, respectively. Generally; Great Plains Energy uses these liquid resources to meet its day-to-day ca('lh flow requirements, and from time to time issues equity and/or long-term debt to repay short-term debt or increase cash balances. However, the $1.3 billion of cash and cash equivalents on hand and the $1.0 billion time deposit at December 31, 2016; are primarily the result of Great Plains Energy's equity issuances in October 2016, the proceeds of which are to be used to fund a portion of the cash consideration for the anticipated acquisition of Westar.
Great Plains Energy intends to meet day-to-day cash flow requirements including interest payments, retirement of maturing debt, construction requirements, dividends and pension benefit plan funding requirements with a combination of internally generated funds and proceeds from short'-term debt. From time to time, Great Plains Energy issues equity and/or long-ten:n debt to repay short-term debt or increase cash balances. Great Plains 46
Energy's intention to meet a portion of these requirements with internally generated funds may be impacted by the effect of inflation on operating expenses, th~ level ofMWh sales; regulatory actions, compliance with environmental regulations and the availability of generating units. In addition, Great Plains Energy may issue equity, equity-linked securities and/or debt to finance growth~
For a description of Great Plai.ns Energy's financing activities and the remaining portion of its proposed financing plan with respect to the anticipated acquisition of Westar, see Note 2 to the consolidated financial statements.
Great Plains Energy also has a 364-day $5.1 billion senior unsecured bridge term loan facility to support the antiCipated acquisition of Westar and provide flexibility for timing oflong-term financing. See Note 11 to the consolidated financial statements for additional infonnation.
Cash Fl.ows from Operating Activities Great Plains Energy generated positive cash flows from operating activities for the periods presented. The $30.9 million increase in cash flows from operating activities for Great Plains Energy in 2016 compared tq 2015 was.
primarily driven by new retail rates for KCP&L and warmer weather. Other changes in working capital are detailed
. in Note 3 to the consolidated financial statements. The individual components of working capital vary with normal business cycles and operations.
The $54.9 million increase in cash :(lows from operating activities for Great Plains Energy in 2015 compared to 2014 was primarily due to a $34.2 million increase driven by a decrease in solar rebates paid to customers and an increase in the recovery of costs subject to fuel recovery mechanisms of $76.0 million, partially offset by a decrease
- in net income of $29. 8 million and a decrease driven by deferred refueling outage costs of $23. 7 million.
Cash Flows from Investing Activities Great Plains Energy'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 proceeds from the sale of
.Properties and insurance recoveries.
In 2016, Great Plains Energy purchased a time deposit of $1.0 billion with a portion of the proceeds from Great Plains Energy's October 2016 common stock and depositary share offerings.
Great Plains Energy's utility capital expenditures decreased $67.7 million in 2016 compared to 2015 primarily due.
to a decrease in cash utility capital expenditures related-to infrastructure and system improvements.
Great Plains Energy's utility capital expenditures decreased$96.6 million in 2015 compared to 2014 primarily due to a decrease in cash utility capital expenditures related to environmental upgrades at KCP&L's La Cygne Stat.ion.
In January 2014, KCP&L and GMO completed the sale of two SPP-approved regional transmission projects, at
Cash Flows from Financing Activities great Plains Ene~gy's cash flows from financing ,i:tctivities in ,2016 reflect gross proceeds of $1.6 billion from the issuance of 60.5 million shares of common stock at a public offering price of $26.45 per share and gross proceeds of $862.5 million from the issuance of 17 .3 million depositary shares each representing a I /20th interest in a share of Great Plains Energy's Series B Preferred Stock at $50 per depositary share. Great Plains Energy paid $40.1 million for the redemption of its 390,000 shares of cumulative preferred stock and $143.6 million in issuance fees related to common stock and depositary share issuances, establishing Great Plains Energy's bridge term loan facility and a payment to OMERS pursuant to a stock purchase agreement. .
Great Plains Energy's cash flows from financing activities in 2015 reflect KCP &L's issuance, at a discount, of
$350.0 million of 3.65% Senior Notes that mature in 2025, with the proceeds used to purchase in lieu ofredemption
$71.9 million ofEIRR bonds and repay short-term borrowings.
47
G~eat Plains Energy's cash flows from financing activities in 2014 reflect increased short-term borrowings at KCP&L primarily driven by capital expenditures and pension funding contributions.
Impact of Credit Ratings on Liquidity The ratings of Great Plains Energy's, KCP&L's and GMO's securities by the credit rating agencies impact their liquidity, inciuding the cost of borrowings under their revolving credit agrceements and in the capital markets. After the announcement of the anticipated acquisition of Westar, Moody's Investors Service placed its long-term ratings
- of Great Plains Energy ~n review for downgrade and Standard & Poors' Ratings Services revised its outlook of Great Plains Energy, KCP&L and GMO from stable to negative. The Companies view maintenance of strong credit ratings as extremely important to their access to and cost of debt financing and to that end maintain an active and ongoing dialogue with the agencies with respect to results of operations, financial position and future prospects.
While a decrease in these credit ratings would not cause any acceleration of Great Plains Energy's, KCP&L's or GMO's debt, it could increase interest charges under Great Plains Energy's 6.875% Senior Notes due 2017 or Great Plains Energy's, KCP&L's and GMO's revolving credit agreements. A decrease in credit ratings could also have, among other things, an adverse impact, which could be material, on Great Plains Energy's, KCP&L's and GMO's access to capital, the cost of funds, the ability to recover actual interest costs in state regulatory proceedings, the type and amounts of collateral required under supply agreements and Great Plains Energy's ability to provide credit support for its subsidiaries ..
As of February 23, 2017, the major credit rating agencies rated Great Plains Energy's, KCP&L's and GM O's securities as detailed in the following table.
Moody's* Standard Investors Service & Poor's Great Plains Energy
- Review for Outlook downgrade Negative.
Corporate Credit Rating BBB+
Preferred Stock Bal BBB-Senior Unsecured Debt Baa2 BBB KCP&L Outlook Stable Negative Senior Secured Debt A2 . A Senior Unsecured Debt Baal BBB+
Commercial Paper P-2 A-2 GMO Outlook Stable Negative Senior Unsecured Debt Baa2 BBB+
Commercial Paper P-2 A-2 A securities rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.
- Financing Authorization Under stipulations with MPSC and KCC, Great Plains Energy.and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). KCP&L's long-term financing activities are subject to the authorization of the MPSC. On June 30,2016, KCP&L's MPSC authorization to issue long-term debt expired.
KCP&L will seek new authorization if and when it is deemed necessary.
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KCP&L's and GMO's. short-term financing activities are subject to the authorization ofFERC. In November 2016, FERC authorized KCP &L to have outstanding at any one time up to a total of $1. 0 billion in short-term debt .
instruments through December 2018. At December 31, 2016, there was $867.1 million available under this authorization., In February 2016, FERC aufhorized GMO to have outstanding at any one time up to a total of
$750.0 million in short-tenn debt instruments through March 2018. At December 31, 2016, there was $548.1 million available under this authorization:
- KCP&L and GMO are also authorized by FERC to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. At December 31, 2016, there were no outstanding payables under the money pooL Significant Financing Activities Great Plains Energy Great Plains Energy has an effective shelr'registration statement for the sale of unlimited amounts of securities with the SEC that became effective in March 2015 and expires in March 2018. In September 2016, Great Plains Ene~gy filed a post-effective amendment to its shelf registration statement to register depositary shares and preference stock among the types of securities that Great Plains Energy may offer and sell.
In October 2016, Great Plains Energy completed a registered public offering of 60.5 million shm::es of common stock, without par value, at a public offering price of $26.45 per share, for total gross proceeds of approximately
$1.6 billion (net proceeds of approximately $1.55 billion after issuance costs). Great Plains Energy plans to use proceeds from the offering to fund a portion of the cash consideration forthe anticipated acquisition of Westar.
In October 2016, Great Plains Energy also completed a registered public offering of 17.3 million depositary shares, each representing a l/20th interest in a share of Great Plains Energy's Series B Preferred Stock, without par value, at a public offering price of $50 per depositary share for total gross proceeds of $862.5 million (net proceeds of approximately $836.2 million after issuance costs). Great Plains Energy plans to use proceeds from the offering to*
fund a portion of the cash consideration for the anticipated acquisition of Westar.
KCP&L KCP &L has an effective shelfregistration statement providing for the sale of unlimited amounts of notes and general mortgage bonds with the SEC that was filed and became effective in March 2015 and expires in March 2018. '
In August 2015, KCP&L issued, at a discount, $350.0 million of3.65% unsecured Senior Notes, maturing in 2025.
Debt Agreements
- See Note 11 to the consolidated financial statements for information regarding revolving credit facilities and term loan facility related to the anticipated acquisition of Westar.
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Projected Utility Capital Expenditures Great Plains Energy's cash utility capital expenditures, excluding AFUDC to finance construction, were $609 .4 million, $677.l million and $773.7 million in 2016, 2015 and 2014, respectively. Utility capital expenditures represent a significant portion of Great Plains Energy's capital requirements. Utility capital expenditures projected for the next four years include improvements to generating, distribution aud transmission ;facilities, software upgrades and expenditures for environmental projects at coaHired power plants. Great Plains Energy intends to meet these capital requirements with a combination of internally generated funds and proceeds from short-term and long-term debt.
Utility capital expenditures projected for the next four years, excluding AFUDC, are detailed in the following table.
This utility capital expenditure plan is subject to continual review and change.
2017 2018 2019 2020 (millions)
Generating facilities $ 180.5 $ 204.3 $ 178.0 $ 192.7 Distribution and transmission facilities 216.5 . 192.3 216.7 I 203.5.
General facilities 106.2 98.5 56.7 69.4 Nuclear fuel 44.5 25.2 22,9 50.0 Environmental 43.4 I 36.6 11.5 14.0 Total utility capital expenditures $ 591.1 $ 556.9 $ 485.8 $ 529.6 Pensions The Company incurs significant costs in providing defined benefit plans for substantially all active and inactive employees ofKCP&L and GMO and its 47% ownership share ofWCNOC's defined benefit plans. Funding of the plans follows legal and regulatory requirements with funding equaling or exceeding the minimum requirements of the Employee Retirement Income Security Act of 1974, as amended (ERlSA).
In 2016 and 2015, the Company contributed $69.8 million and $76.9 million to the pension plans, resp*ectively, and expects to contribute $79.6 million in 2017 to satisfy ERlSA funding requirements and the MPSC and KCC rate orders, tlie majority of which is expected to be, paid by KCP&L: Additional contributions to the plan~ are expected beyond 2017 in amounts at least sufficient to meet the greater ofERlSA or regulatory funding requirements; however, these amounts have not yet been determined. .
- Additionally, the Company provides post~retirement health and life insurance benefits for certain retired employees and expects to make benefit contributions of $4.6 million under the provisions of these plan~ in 2017' the majority of which is expected to be paid by KCP&L.
Management believes the Company has adequate access to capital resources through.cash flows from operations or through existing lines of credit to support thes.e funding requirements.
50
Supplemental Capital Requirements and Liquidity Information The information in the following table is provided to summarize Great Plains Energy's cash obligations and commercial commitments.
Payment due by period 2017 2018 2019 2020 2021 After 2021 Total Long-term debt (millions)
Principal $ . 382.l $ 351.l $ 401.l $ 1.1 $ 432.0 $ 2,197.1 $ 3,764.5 Interest 182.5 156.8 131.3 116.9 108.3 945.9 1,641.7 Lease commitments Operating leases 12.9 11.0 . 9.3 9.7 9.7 110.5 163.1 Capital leases 0.4 0.4 0.4 0.4 0.4 3.1 5.1 Pension and other. post-retirement plans 84.2 84.2 84.2 84.2 84.2 (a) 421.0 Purchase commitments Fuel 259.0 145.8 62.2 53.8 11.2 100.8 632.8 Power 47.3 47.3 47.3 47.3 47.4 462.2 698.8 Other 50.1 32.0 33.3 5.9 6.5 38.7 166.5 Total contractual commitments (a) $ 1,018.5 $ 828.6 $ 769.1 $ 319.3 $ 699.7 $ 3,858.3 $ 7,493.5 (al The Company expects to make contributions to the pension and other post-retirement plans beyond 2021 but the amounts are not yet determined. Amounts for years after 2017 are estimates based on information available in detetmining the amount for 2017. Actual amounts for years after 2017 could be significantly different than the estimated amounts in the table above.
Long-term debt includes current maturities. Long-term debt principal excludes $17.2 million of net discounts on senior notes and debt issuance costs. Variable rate interest obligations are based on rates as of December 31, 2016.
Lease commitments end in 2048. Operating lease commitments include railcars to serve jointly-owned generating units where KCP&L is the managing partner. Of the amounts included in the table above, KCP&L will be reimbursed bY. the other owners for approximately $1.5 million in 2017, $1.2 million in 2018 and approximately
$0.4 million per year from 2019 to 2025, for a total of $5.5 million.
The Company expects to contribute $84.2 million to the pension and other post-retirement plans in 2017, of which the majority is expected to be paid by KCP&L Additional contributions to the plans are expected beyond 2021 in amounts at least sufficient to meet the greater of ERISA or regulatory funding requirements; however, these amounts have not yet been determined. Amounts f<;>r years after 201 7 are estimates based on information available in determining the amount for 201 7. Actual amounts for years after 2017 could be significantly different than the estimated amounts in the table above.
Fuel commitments consist of commitnie.nts for nuclear fuel, coal and coal transportation costs. Power commitments consist of commitments for renewable energy under power purchase agreements. Other represents individual commitments entered into in the ordinary course of business.
Great Plains Energy has other insignificant long-term liabilities recorded on its consolidated balance sheet at
- December 31, 2016, which do not have a definitive cash payout date and are not included in the table above.
Off-Balance Sheet Arrangements ,
I In the ordinary 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 letters of credit. 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 subsidiary's intended business purp~ses. The majority of these agreements guarantee the Company's own future performance, so a liability for the fair value of the obligation is not I
recorded.
51
At December 31, 2016, Great Plains Energy has provided $135 .3 milli~n o~ credit support for GMO as follows:
Great Plains Energy direct guarantees to GMO counterparties totaling $38.7 million, which expire in 2017 and' 2018 and Great Plains Energy guarantees of GMO long-term debt totaling $96.6 million, which includes debt with maturity dates ranging from 2017 to 2023.
Great Plains Energy has also guaranteed GM O's commercial paper program. At December 31, 2016, GMO had
$201.9 million commercial paper outstanding. None of the guaranteed obligations are subject to default or prepayment if GM O's credit ratings were downgraded.
At December 31, 2016, KCP&L had issued letters of credit totaling $8.8 million as credit support to certain counterparties that expire in 2017. KCP&L has issued $148.1 million ofletters of credit as credit support for its variable rate BIRR Bond Series 2007 A and B that expire in 2018.
At December 31, 2016, GMO had issued letters of credit totaling $1.9 million as credit support to certain counterparties that expire in 2017.
KAN.SAS CITY POWER & LIGHT COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS The following table summarizes KCP&L's consolidated comparative results of operations, 2016 2015 (millions)
Operating revenues $ 1,875.4 $ 1,713.8 Fuel and purchased power (372.7) (397.1)
Transmission ' (56.4) (58.4)
Other operating expenses (705.8) (658.6)
Costs to achieve t~e anticipated acquisition of Westar (10.9)
Depreciation and amortization (247.5) .(235.7)
Operating income 482.1 364.0 Non-operating income and expenses 4.2 1.2 Interest charges (139.4) (135.6)
Income tax expense (121.9) (76.8)
. Net income . $ 225.0 $ 152.8' Reconciliation of gross margin to operating revenue:
Operating revenues $ 1,875.4 $ 1,713.8 Fuel and purchased power (372.7) (397.1)
Transmission (56.4) (58.4)
Gross margin (a) $ 1,446.3 $ 1,258.3.
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results of Ope~ations.
< ) * * ~
52
KCP&L Gross Margin and MWh Sales The following table summarizes KCP&L's gross margin and MWhs sold.
Revenues and Costs* O/o MWhs Sold %
2016 2015 ChangeCc) 2016 2015 Change Retail revenues (millions) (thousands)
Residential $ 713.0 $, 639.9 11 5,330 5,213 2 Commercial 798.5 738.7 8 7,553 7,569 Industrial 147.4 137.8 7 1,839 1,833 Other retail revenues 13.1 12.5 6 83 83 Provision for rate refund 0.8 NIM NIA NIA NIA Energy efficiency (MEEIA)(a) 50.9 27.5 85 NIA NIA NIA Total retail 1,723.7 1,556.4 11 14,805 14,698 1 Wholesale revenues 128.9 134.1 (4) 6,629 6,099 9 Other revenues 22.8 . 23.3 (2) NIA NIA NIA Operating revenues 1,875.4 1,713.8 9 21,434 20,797 3 Fuel and purchased power (372.7) (397.1) . (6)
Transmission (56.4) (58.4) (3)'
Gross margin (b) $1,446.3 $ 1,258.3 15 (a) Consists ofrecovery of program costs of$31.0 million and $20.5 million for 2016 and 2015, respectively, that have a direct offset in operating and maintenance expenses, recovery of throughput disincentive of$9.5 million and $7.0 million for 2016 and 2015, respectively; and a performance incentive of $10.4 million for 2016.
(b) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains Energy's Results of Operations.
(c) NIM - not meaningful KCP&L's gross margin increased $188.0 million in 2016 compared to 2015 primarily driven by:
.* an estimated $111 million increase due to new retail rates and an estimated $3 7 million increase due to new cost recovery mechanisms for KCP&L in Missouri effective September 29, 2015, and in Kansas effective October 1, 2015;
- an estimated $25 million increase due to warmer weather with a 16% increase in cooling degree days in 2016;
- a $10.5 million increase for recovery of p~ogram costs for energy efficiency programs under MEEIA,
- which have a direct offset in operating and maintenance expense; a $2.5 million increase in MEEIA throughput disincentive; a $10 .4 million MEEIA performance incentive recognized in 2016 related to the achievement of certain energy savings level~ in the first cycle ofKCP&L's MEEIAprograms; and an estimated $6 million decrease due to a decrease 1n weather~normalized retail demand.
KCP&L Other Operating Expenses (including operating and maintenance expenses, general taxes and other)
KCP&L's other operating expenses increased $47.2 million in 2016 compared to 2015 primarily driven by:
a $5.6 million increase in pension expense corresponding to the resetting of pension expense trackers with the effective date of new retail rates; *
.a $10.5 million increase in program costs for energy efficiency programs ~nder MEEIA, which have~
direct offset in revenue; a $2.3 million increase in plant operating and maintenance expense; a $7A million increase in injuries and damages expense primarily due to an increase in estimated losses from an unfavorable judgment in ongoing litigation; and 53
a $14.0 million increase in general taxes.driven by higher property taxes and higher gross receipts taxes due to an increase in retail revenues.
KCP&L Costs to Achieve the Anticipated Acquisition of Westar KCP&L's costs to achieve the anticipated acquisition of Westar of $l0.9 million in 2016 reflects consulting fees, certain severance expenses and other transition costs related to the anticipated acquisition of Westar.
KCP&L Depreciation and Amortization KCP&L's depreciation and amortization expense increased $11.8 million in 2016 compared to 2015 due to capital additions.
KCP&L Interest Charges KCP&L's interest charges increased $3.8 million in 2016 compared to 2015 primarily due to a $7.9 million increase in interest expense related to KCP&L's issuance of $350 million of 3.65% Senior Notes in August 2015; partially offset by a $2.2 million decrease in interest expense due to KCP&L's purchase in lieu ofredemption of its $50.0 million and $21.9 million BIRR Series 2005 bonds in September 2015.
KCP&L Income Tax Expense KCP&L's income tax expense increased $45.1 million in 2016 compared fo 2015 due to increased pre-tax income; 54
ITEM _7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK In the ordinary course of business, Great Plains Energy and KCP&L face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operational and credit risks and are not represented in the following analysis. See Item lA Risk Factors and Item 7 MD&A for further discussion of risk factors.
Great Plains Energy and 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 ,that the volatility of the markets may have on its operating results. During the ordinary course of business, under the direction and control of an internal commodity risk committee, Great Plains Energy's
~i1d 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 are 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 their results of operations or financial position, due to many factors, including unexpectedly large or rapid movenients 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.
- Hedging Strategies Derivative instruments are utilized to execute risk management and hedging strategies. 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.
Interest Rate Risk Great Plains Energy and 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. At December 31, 2016, 4% and 6%, respectively, of Great Plains Energy's and KCP&L's long-term debt was variable rate debt. Interest rates impact the fair value of long-term debt. A change in interest rates would impact Great Plains Energy and KCP&L to the extentthey redeemed any of their outstanding long-term debt. Great Plains Energy's and KCP&L's book values of long~term .debt were below fair value by 5% at December 31, 2016.
Great Plains Energy atid KCP&L had $334.8 million and $132.9 million, respectively, of commercial paper
- outstanding at December 31, 2016. The principal amount of the commercial paper, which will vary during the year, drives Great Plains Energy's and KCP&L's commercial paper interest expense. Assuming $334.8 million and
$132.9 million of commercial paper was outstanding for all of2017 for Great Plains Energy and KCP&L, respectively, a hypothetical 10% increase in commercial paper rates would result in an increase in interest expense of $0.3 million for Great Plains Energy and $0.1 million for KCP&L in 2017. Assuming $334.8 million and $132.9 million of commercial paper was outstanding for all of 201 7 for Great Plains En,ergy and KCP &L, respectively, a hypothetical 100 basis point increase in commercial paper rates would result in an increase in interest expense of
$3 .3 million for Great Plains Energy and $1.3 million for KCP &L in 2017.
At December 31, 2016, Great Plains Energy had $4.4 billion of notional amounts of fixed~to-floating interest rate swaps to hedge against interest rate fluctuations on future issuances of long-term debt expected to be issued to finance a portion of the cash consideration for the anticipated acquisition of Westar. Settlement of these swaps is contingent on the consummation of the anticipated acquisition of Westar. Assuming settlement of the swaps, a hypothetical 10% decrease in the interest rates underlying the swaps would have resulted in .an approximately $51 miJlion increase in interest expense associated with settlement of the swaps as ofDecember 31, 2016.
55
Commodity Risk Great Plains Energy and KCP&L engage in the wholesale and retail marketing of electricity and are exposed to risk associated with the price of electricity. Exposure to these risks is affected by a number,of factors including the quantity and availability of fuel used for generation and the quantity of electricity cusfomers consume. Customers' electricity usage could also vary from year to year based on the weather or other factors. Quantities of fossil fuel used for generation vaty from year to year based on the availability, price and deliverability of a given fuel type as well as planned and unplanned outages at facilities that use fossil fuels.
KCP&L's wholesale operations include the physical delivery and marketillg of power obtained through its generation capacity. KCP&L is required to maintain a capacity margin of at least 12%. This net positive supply of capacity and energy is maintained through KCP&L's generation assets and capacity and power purchase agreements to protect KCP&L 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.
KCP&L's sales include the sale of electricity to its retail customers and bulk power sales of electricity in the wholesale market. KCP&L is a member of SPP Consolidated Balancing Authority (CBA) and Integrated Marketplace (IM), which are largely responsible for the dispatch of member generating facilities and the resulting supply of energy to fulfill member load obligations. KCP&L's Kansas ECA allows for therecovery of increased fuel and purchased power costs from Kansas retail customers. KCP&L's Missouri FAC allows for KCP&L Missouri retail electric rates to be adjusted based on 95% of the difference between actual fuel and purchased power costs and the amount of fuel and purchased power costs provided in base rates. Most of the change in market prices for fuel and purchased power is recovered through the ECAor FAC, which mitigates KCP&L's commodity price exposure.
GMO is also a member of SPP's CBA and IM. GMO has an FAC that allows GMO to adjust retail electric rates based on 95% of the difference between actual fuel and purchased power costs and the amount of fuel and purchased power costs provided in base rates. Most of the change in market prices for fuel and purchased power is recovered through the FAC, which mitigates GMO's commodity price exposure.
Credit Risk - MPS Merchant MPS Merchant is exposed to credit risk. Credit risk is measured by the loss that would be recorded if counterparties failed to perform pursuant to the terms of the contractual obligations less the value of any collateral held. MPS Merchant's counterparties are not externally rated. Credit exposure to counterparties at December 31, 2016, was
$8.7 million.
Investment Risk KCP&L maintains trust funds, as required by the NRC, to fund its share of deco:inrrlissioning the Wolf Creek nuclear power plant. As of December 31, 2016, 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. The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs; however, the equity securities in the trusts are exposed to price fluctuations in equity markets arid 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 $6.5 million reduction in the value of the decommissioning trust funds at December 31, 2016. A hypothetical 10% decrease in equity prices would have resulted in a $15.2 million reduction in the fair value of the equity securities at December 31, 2016. KCP&L's exposure to investment risk associated with the decommissioning trust funds is in large part m~tigated due to the fact that KCP&L is currently allowed to recover its decommissiol:ling costs in its rates. If the actual return on trust assets is below the anticipated level, KCP&L could be responsible for the balance of funds required to decommission Wolf Creek; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommi.ssioning costs over the remaining life of the unit.
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Report oflndependent Registered Public Accounting Firm Great Plains Energy Incorporated 58 Kansas City Power & Light Company 59 Great Plains Energy Incorporated Consolidated Statements of Comprehensive Income 60 Consolidated Balance Sheets 61 Consolidated Statements of Cash Flows 63 Consolidated Statements of Shareholders' Equity 64 Kapsas City Power & Light Company Consolidated Statements of Comprehensive Income 65 Consolidated Balance Sheets 66 Consolidated Stateillents of Cash Flows 68 Consolidated Statements of Common Shareholder's Equity 69 Combined Notes to Consolidated Financial Statements. for Great Plains Energy Incorporated and Kansas City Power & Light Company Note 1: Summary of Significant Accounting Policies 70.
Note 2: Anticipated Acquisition of Westar Energy, Inc. 76 Note 3: Supplemental Cash Flow Information 78 Note 4: Receivables 79 Note 5: Nuclear Plant 80 Note 6: Regulatory Matters 83 Note 7: Goodwill and Intangible Assets 86 Note 8: Asset Retirement Obligations 87 Note 9: Pension Plans and Other Employee Benefits 87 Note 10: Equity Compensation 94 Note 11: Short-Term Borrowings and Short-Terin Bailk Lines of Credit 96 Note 12: Long-Term Debt 98 Note 13: Common Stock 100 Note 14: Preferred Stock 101 Note 15: Commitments and Contingencies 102 Note 16: Legal Proceedings 106 Note 17: Guarant~es 107 Note 18: Related Party Transactions and Relationships 108 Note 19:
- Derivative Instruments 108 Note 20: Fair Value Measurements 111 Note 21 : Accumulated Other Comprehensive Income (Loss) 115 N9te 22: Taxes 117 Note 23: Segments arid Related Information 120 Note 24: Jointly-Owned Electric Utility Plants .121 Note 25: Quarterly Operating Results (Unaudited) 122 57 l
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, 2016 and 2015, arid the related consolidated statements of comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2016. 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 managenient.
Our responsibility is to express an opinion on the financial statemerits and financial statement ~chedules .based OIJ. .
our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those sta~dards require that we plan and perform the audit to obtain reasonable assurance abo)lt whether the financial statements ate 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.*
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Great Plains Energy Incorporated and subsidiaries as of December 3.1, 2016 and 2015, and the results of their
- operations and their cash flows for each of the three years in the period ended December.31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such finaneial statement schedules, when considered in relatio,n to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2016, based on the criteria.
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2017, expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 23, 2017 58
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholder of Kansas City Power & Light Company Kansas City, Missouri We have audited the accompanying consolidated balance sheets ofKansas City Power & Light Company and subsidiaries (the "Company") as of December 31, 2016 and 2015, and the related consolidated statements of comprehensive income, common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our
. resporisibility is to express an opinion on the financial statements and financial* statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Kansas City Power & Light Company and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2016, based on the criteria 1*
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring .
Organizations of the Treadway Commission and our report dated February 23, 2017, expressed an unqualified*
opinion on the Company's internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 23, 2017 59
GREAT PLAINS ENERGY INCORPORATED Consolidated Statements of Comprehensive Income Year Ended December 31 2016 2015 2014 Operating Revenues (millions, except per share amounts)
Electric revenues $ 2,676.0 $ 2,502.2 $ 2,568.2 Operating Expenses Fuel and purchased power 590.1 608.7 742.5 Transmission ~4.8 . 89.1 74_7, Utility operating and maintenance expenses 759.5 724.8 701.9 Costs to achieve the anticipated acquisition of Westar Energy, Inc. 34.2 Depreciation and amortization 344.8 330.4 306.0 General taxes 226.7 213.2 204.6 Other 17.0 5.9 4.0 Total 2,057.1 . 1,972.1 2,033.7 Operating income 618.9 530.1 534.5 Non-operating income 17.1 ... . 11.7,. 25.0 Non-operating expenses (14.3) (8.0) . (12.5)
Interest charges . (l61.5) (199.3) (188.5)
Income before income tax expense and income from equity investments 460.2 334.5 358.5 Income tax expep.se (172.2) 'Cl.22.7). 015.7)
Income from equity investments, net of income taxes 2.0 1.2 Net income 290.0 213.0 242.8 Preferred stock dividend requirements and redemption premium 16.5 1.6 1.6 Earnings available for common shareholders $ 273.5 $ 211.4 $ 241.2 Average number of basic common shares -0utstanding 169.4 154.2 153.9 Average number of diluted common shares outstanding 169.8 154.8 154.1 Basic and diluted earnings per common share $ 1.61 $ 1.37 $ 1.57 Comprehensive Income Net income $ 290.0 $ 213.0 $ 242.8 Other comprehensive income Derivative hedging activity Reclassification to expenses, net of tax 5.6 5.7 8.0 Derivative hedging activity, net of tax 5.6 5.7 8.0 Defined benefit pension plans Net gain (loss) arising during period (1.1) 1.0 (3.0)
Income tax (expense) benefit 0.4 (0.4) 1.2 Net gain (loss) arising during period, net of tax (0.7) 0.6 (1.8)
Amortization of net losses included in net periodic benefit costs, net of tax 0.5 0.4 0.4 Change in unrecognized pension expense, net of tax (0.2) 1.0 (1.4)
Total other comprehensive income 5.4 6.7 6.6 Comprehensive income $ 295.4 $ 219.7 $ 249.4 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
60
GREAT PLAINS ENERGY INCORPORATED Consolidated Balance Sheets December31 2016 2015 ASSETS (millions, except share amounts)
Current Assets Cash and cash equivalents $ 1,293.1 $ 11.3 Tinie deposit 1,000.0 Receivables, net 166.0 147.7 Accounts receivable pledged as collateral 172.4 175.0 Fuel inventories, at average cost 108.8 118.4 Materials and supplies, at averagi;: cost 162.2 155.7 Deferred refueling outage costs 22.3 19.2 Refundable' income taxes 3.8 Derivative instruments 81.5 0.8 Prepaid expenses and other assets 53.2 32.3 Total 3,059.5 664.2 Utility Plant, at Original Cost Electric 13,597.7 13,189.9 Less - accumulated depreciation 5,106.9 4,943.7 Net utility plant in service 8,490.8 8,246.2 Construction work in progress 403.9 347.9
- Nuclear fuel, net of amortization of $172. i *and $192.5 62.0 68.3 Total 8,956.7 8,662.4 Investments and Other Assets Nuclear decommissioning trust fund 222.9 200.7 Regulatory assets 1,048.0 979.1 Goodwill 169.0 169.0 Other 113.9 63.2
. Total 1,553.8 1,412.0 Total $ 13,570.0 $ 10,738.6 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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GREAT PLAINS ENERGY INCORPORATED Consolidated Balance Sheets
- December31 2016 2015 LIABILITIES AND CAPITALIZATION (millions, except share amounts)
Current Liabilities Notes payable $ $ 10.0 Collateraliz.ed note payable 172.4 175.0 Commercial paper 334.8 224.0
. Current maturities of long-term debt 382.1 1.1 Accounts payable 323.7 352.9 Accrued taxes 33.3 31.6 Accrued interest 50.8 44.7
- 1. Accrued compensation and l;>enefits 52.1 41.4 Pension and post-retirement liability 3.0 3.4 Other 32.6 31.6 Total 1,384.8 915.7 Deferred Credits and Other Liabilities Deferred income taxes 1,329.7 1,158.8 Deferred tax credits 126.2 125.l Asset retirement obligations 316.0 275.9 Pension and post-retirement liability 488.3 455.2 Regulatory liabilities 309.9 284.4 Other 87.9 82.9 Total 2,658.0 2,382.3 Capitalization Great Plains Energy shareholders' equity Common stock - 600,000,000 and 250,000,000 shares authorized without par value 215,479,105 and 154,504,900 shares issued, stated value
- 4,217.0 2,646.7 Cumulative preferred stock - 390,000 shares authorized, $100 par value 0 and 390,000 shares issued and outstanding 39.0 Preference stock - 11,000,000 shares authorized withqut paryalu~
7.00% Series B Mandatory Convertible Preferred Stock
$1,000 per share liquidation preference, 862;500 and 0 shares issued and outstanding 836.2 Retained earnings 1,119.2 1,024.4 Treasury stock - 128,087 and 101,229 shares, at cost (3.8) (2.6)
Accumulated other comprehensive loss (6.6) (12.0)
Total shareholders' equity_ 6,162.0 3,695.5 Long-term debt (Note 12) 3,365.2 3,745.1 Total 9,527.2 7,440.6 Commitments and Contingencies (Note 15)
Total $ 13,570.0 $ 10,738.6
- The_accompanying Notes to Consolidated Financial Statements are an integral part.ofth.ese statements.
62
GREAT PLAINS ENERGY INCORPORATED Consoiidated Statements of Cash Flows Year Ended December 31 2016 2015 2014.
Cash Flows from Operating Activities (millions)
Netincom~ $ 290.0 $ 213.0 $ 242.8 Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization 344.8 330.4 306.0 Amortization of:
Nuclear fuel 26.6 26.8 26.1 Other 77.5 47.7 46.1 Deferred income taxes, net 170.1 124.9 125.8 Investment tax credit amortization (1.4) (1.4) (1.4)
I~coine fro~ equity investments, nef of incom~ taxes (2.0) (1.2)
Fair value impacts of interest rate swaps (79.3)
Other operating activities (Note 3) (42.3) 12.9 (47.2)
Net.cash from operating activities 784.0 753.1 698.2 Cash Flows from Investing Activities Utility capital expenditures (609.4) (677.1) (773.7)
Allowance for borrowed funds used during construction (6.8) (5.8) (13.0)
Purchases of nuclear decommissioning trust investments (31.9) (50.9) (27.5)
Pro.ceeds from nuclear decommissioning trust investments 28.6 47.6 24.2 Purchase of time deposit (1,000.0)
Proceeds from sale of transmission assets 37.7 Other investing activities (64.0) (48.2) (27.5)
Net cash from investing activities (1,683.5) (734.4) (779.8)
Cash Flows from Financing Activities Issuance of common stock 1,603.7 3.0 4.8 Issuance of preference stock 862.5 Issuance oflong-term debt 348.8 Issuance of long-term debt from remarketing 146.5 Repayment oflong-term debt from remarketing (146.5)
Issuance fees (143.6) (3.0). (0.9)
' Repayment ofloq.g-term debt (1.1) (87.0) (13 .4)
Net change in short-term borrowings 100.8 (128.3) 245.1 Net change in collateralized short-term borrowings (2.6) 4.0 (4.0)
Dividends paid (194.0) (155.5) (145.6)
Redemption of cumulative preferred stock (40.1)
Purchase of treasury stock (5.0) (1.6) (2.5)
Other financing activities 0.7 (0.8) 0.5 Net cash from financing activities 2,181.3 (20.4) 84.0 Net Change in Cash and Cash Equivalents 1,281.8 (1.7) 2.4 Cash and Cash Equivalents at Beginning of Year 11.3 13.0 10.6 Cash and Cash Equivalents at End of Year $ 1,293.1 $ 11.3 $ 13.0 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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GREAT PLAINS ENERGY INCORPORATED Consolidated Statements of Shareholders' Equity Year Ended December 31 2016 2015 2014 Shares Amount Shares Amount Shares Amount Common Stock (millions, except share amounts)
Beginning balance 154,504,900 $ 2,646.7 154,254,037 $ 2,639.3 153,995,621 $ 2,631.1 Issuance of common stock 60,974,205 . 1,565.3 250,863 6.6 258,416 6.7 Equity compensation expense, net of forfeitures '
4.3 1.9 0.5 Unearned Compensation Issuance of restricted common stock (2.8) (2.4) (2.1)
Forfeiture of restricted common stock 0.5 Compensation expense recognized 2.7 1.8 2.0 Other 0.8 (1.0) 1.1 Ending balance 215,479,105 4,217.0 154,504,900 2,646.7 154,254,037 2,639.3 Cumulative Preferred Stock Beginning balance 390,000 39.0 390,000 39.0 390,000 39.0 Redemption of cumulative preferred stock (390,000) (39.0)
Ending balance 390,000 39.0 390,000 39.0 Preference Stock Beginning balance Issuance of Series B Mandatory Convertible Preferred Stock 862,500 836.2 Ending balance 862,500 836.2 Retained Earnings Beginning balance 1,024.4 967.8 871.4 Net income 290.0 213.0 242.8 Redemption premium on cumulative preferred stock (0.6)
Dividends:
Common stock ($1.0625, $0.9975 and $0.935 per share) (181.0) (153.9) (144.0)
Preferred stock - at required rates (13.0) (1.6) (1.6)
Performance shares (0.6) (0.9) (0.8)
Ending balance 1,119.2 1,024.4 967.8 Treasury Stock Beginning balance (101,229) (2.6) (91,281) . (2.3) (129,290) (2.8)
Treasury shares acquired (138,021) (4.1) (76,468) (2.0) (85,744) (2.2)
Treasury shares reissued 111,163 2.9 66,520 1.7 123,753 2.7 Ending balance (128,087) (3.8) (101,229) (2.6) (91,281) (2.3)
Accumulated Other Comprehensive.Income (Loss)
Beginning balance (12.0) (18.7) (25.3)
Derivative hedging activity, net of tax 5.6 5.7 8.0 Change in unrecognized pension expense, net of tax (0.2) 1.0 (1.4)
Ending balance (6.6) (12.0) (18.7)
Total Great Plains Energy Shareholders' Equity $ 6,162.0 $ 3,695.5 $ 3,625.1 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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KAl'IJSAS CITY POWER & LIGHT COMPANY
- Consolidated Statements of Comprehensive Income
- Year Ended December 31 . 2016 2015 2014 Operating Revenues (millions)
Electric revenues $ 1,875.4 $ 1,713.8 $ 1,730.8 Operating Expenses Fuel and purchased power 372.7 397.1 472.7 Transmission 56.4 58.4 47.2 Operating and maintenance expenses 525.8 494.2 489.l Costs to achieve the anticipated acquisition of Westar Energy, Inc. 10.9 Depreciation and amortization 247.5 235.7 213.9 General taxes 177.5 163.5 159.1 Other 2.5 0.9 (1.3)
Total 1,393.3 1,349.8 J,380.7 Operating income 482.1 364.0 350.1 Non-operating income 11.8 8.4' 20.4 Non-operating expenses (7.6) (7.2) (8.3)
Interest charges (139.4) (135.6) (124.1)
Income before income tax expense 346.9 229.6 238.l Income tax expense (121.9) (76.8) (75.7)
Net income $ ' 225.0 $ 152.8 $ 162.4 Comprehensive Income Net income $ 225.0 $. 152.8 $ 162.4 Other comprehensive income Derivative hedging activity Reclassification to expenses, net of tax 5.4 5.3 5.3 Derivative hedging activity, net of tax 5.4 5.3 5.3 Total other comprehensive income 5.4 5.3 5.3 Comprehensive income $ 230.4 $ 158.l $ 167.7
- The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements .are an integral part of these statements.
65
KANSAS CITY POWER & LIGHT .COMPANY Consolidated Balance Sheets December31 2016 2015 ASSETS (millions, except share amount.s)
Current Assets Cash and cash equivalents $ 4.5 $ 2.3 Receivables, net 139.1 129.2 Related party receivables 67.2 65.8 Accounts receivable pledged as collateral 110.0 110.0 Fuel inventories, at average cost 72.9 83.5 Materials and supplies, at average cost 118.9 114.6 Deferred refueling outage costs 22.3 19.2 Refundable income taxes 12.7 79.0 Prepaid expenses and other assets 27.9 27.6" Total 575.5 631.2 Utility Plant, at Original Cost Electric 9,925.1*. 9,640.4.
Less - accumulated depreciation 3,858.4 3,722.6 Net utility plant in service 6,066.7 5,917.8 Construction work in progress 300.4 '246.6 Nuclear fuel, net of amortization of $172.1 and $192.5 62.0 68.3 Toti!! 6,429.1 6,232.7 Investments and Other Assets Nuclear decommissioning trust fund 222.9 200.7 Regulatory assets 801.8 . 732.4 Other 29.1 17.6 Total 1,053.8 950.7 Total $ 8,058.4 $ 7,814.6 The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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KANSAS CITY POWER & LIGHT COMPANY Consolidated Balance Sheets December31 2016 2015 LIABILITIES AND CAPITALIZATION (millions, except share amounts)
Current Liabilities Collateralized note payable $ 110.0 $ 110.0 Commercial paper 132.9 180.3 Current maturities oflong-term debt 281.0 Accounts payable 231.6 258.8 Accrued taxes 27.0 25.6 Accrued interest i 32.4 32.4 Accrued compensation and benefits 52.1 41.4 Pension and post-retirement liability 1.6 2.0 Other 11.4 12.6 Total 880.0 663.l Deferred Credits and Other Liabilities Deferred income taxes 1,228.3 1,132.6 Deferred tax credits . 122.8 123.8 Asset retirement obligations 278.0 239.3 Pension and post-retirement liability 465.8 433.4 Regulatory liabilities 187.4 164.6 Other 70.6 61.6 Total 2,352.9 2,155.3 Capitalization Common shareholder's equity Common stock - 1,000 shares authorized without par value 1 share issued, stated value 1,563.1 1,563.l Retained earnings 982.6 879.6 Accumulated other comprehensive loss (4.2) (9.6)
Total 2,541.5 2,433.1 Long-term debt (Note 12) 2,284.0 2,563.l Total 4,825.5 4,996.2 Commitments and Contingencies (Note 15)
Total $ 8,058.4 $ 7,814.6 The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Cash Flows Year Ended December 31 2016 2015 2014 Cash Flows from Operating Activities (millions)
Net income $ 225.0 $ 152.8 $ 162.4 Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization 247.5 235.7 213.9 Amortization of:
Nuclear fuel 26.6 26.8 26.1 Other 33.9 29.1 29.3 Deferred income taxes, net 93.4 99.4 88.4 Investment tax credit amortization (1.0) (1.0) (1.0)
Other operating activities (Note 3) (2.1) (61.5) (64.7)
Net cash from operating activities 623.3 481.3 454.4 Cash Flows from Investing Activities Utility capital expenditures (418.8) ' (518.3) (635.9)
Allowance for borrowed funds used during construction (5.6) (3.9) (11.1)
Purchases of nuclear decommissioning trust investments (31.9) (50.9) (27.5)
Proceeds from nuclear decommissioning trust investments 28.6 47.6 24.2 Net money pool lending 4.7 Other investing activities (23.8) (25.5) (15.2)
Net cash from investing activities (451.5) (551.0) (660.8)
Cash Flows from Financing Activities Issuance of long-term debt 348.8 Issuance fees (0.2) (3.0) (0.4)
Issuance oflong-term debt from remarketing 146.5 Repayment of long-term debt from remarketing (146.5)
. Repayment of long-term debt (85.9)
Net change in short-term borrowings (47.4) (178.0) 265.1 Net money pool borrowings (12.6) 12.4 Dividends paid to Great Plains Energy (122.0) (72.0)
Net cash from financing activities (169.6) 69.3 205.l Net Change in Cash and Cash Equivalents 2.2 (0.4) (1.3) at Cash and Cash Equivalents Beginning of Year 2.3 2.7 4.0 Cash and Cash Equivalents at End of Year $ 4.5 $ 2.3 $ 2.7 The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Common Shareholder's Equity Year Ended December 31 2016 2015 2014 Shares Amount Shares
- Amount Shares Amount (millions, except share amounts)
Common Stock f $ _1,563.1 $ 1,563.1 $ 1,563.1 Retained Earnings
.Beginning balance **879;6. 726.8 '636.4 Net income 225.0 152.8 162.4 Dividends:
Common stock held by Great Plains Energy (122.0) (72.0)
Ending balance 982.6 879.6 . 726.8 Accumulated Other Com11rehensive Incom.e (Loss)*
Beginning. balance (9.6) (14.9) . (20.2)
Derivative hedging activity, net of tax 5.4 53 5.3 Ending )Jalance (4.2) (9.6) (14.9)
Total Common Shareholder's Equity $ .2,541.5 $ 2,433.1 . $ 2,275.0 The ~isclosures regardin.g KCl'.&L included in the accompanying Notes to Consolidated Financial Statements are an .integral part of these statements.
\..
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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 "Companies" 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 & Li~ht Company and its consolidated subsidiaries.
"Companies" refers to Great Plains Energy Incorporated and its consolidated subsidiaries and KCP&L and its consolidated subsidiaries.
- 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES Organization .
Great Plains Energy, a Missouri corporation incorporated in 2001, is a publi~ utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries and cash and cash equivalents and a time deposit to be used to fund a portion of the cash consideration for the anticipated acquisition of Westar Energy, Inc. (Westar). Great Plains Energy's whol~y owned direct subsidiaries with significant operations are as follows:
KCP&L is an integrated, regulated electric utility that provides electricity to customers primarily in the states of Missouri aI).d Kansas. KCP&L has one active wholly owned s11bsidiary, Kansas City Power &
Light Receivables Company (KCP&L Receivables Company).
KCP&L Greater Missouri Operations Company (GMO) is an integrated, regulated electric utility that provides electricity to custoniers in the state of Missouri. GMO also provides regulated steam service to certain customers in the St. Joseph, Missouri area. GMO has two active wholly owned subsidiaries, GMO Receivables Company and MPS Merchant Services, Inc. (MPS Merchant). MPS Merchant has certain long~term natural gas contracts remaining from its former non-regulated trading operations.
Great Plains Energy also wholly owns GPE Transmission Holding Company, LLC (GPETHC). GPETHC owns 13.5% ofTransource Energy, LLC (Transource) with the remaining 86.5% owned by AEP Transmission Holding .
Company, LLC (AEPTHC), a subsidiary of American Electric Power Company, Inc. GPETHC accounts for its investment in Transource under the equity method.
- Transource is focused on the development of competitive electric transmission projects.
Each of Great Plains Energy's and KCP&L's consolidated financial statements includes the accounts of their subsidiaries. Intercompanytransactions have been eltminated.
Great Plains Energy's sole reportable business segment is electi;ic utility. See Note 23 for additional information.
Use of Estimates The process of preparing financial statements in conformity wlth Generally Accepted Accounting Principles (GAAP) requires the use of estimates and assumptions that affect the reported amounts of certain types *of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.
Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less at acquisition.
Time Deposit Consists ofa non-negotiable fixed rate investment in a time deposit with an original maturity of greater than three months and is recorded on the balance sheet at cost. The time deposit matures in the first quarter of 2017 and the proceeds from this investment are expected to be used to fund a portion of the cash consideration for the anticipated acquisition of Westar. The Company estimates the fair value of the time deposit, which approximates its' carrying 70
value, using Level 2 inputs based on current interest rates for similar investments with comparable credit risk and
- time to maturity.
Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practicable to estimate that value.
Nuclear decommissioning trust fund - KCP&L's nuclear decommissioning trust fund assets are recorded at fair value based on quoted market prices of the investments held by the fund and/or valuation models.
Derivative instruments - The fair value of commodity derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlation among fuel prices, net of estimated credit risk. The fair value of interest rate derivative instruments is determined by calculating the net present value of expected payments and receipts under interest rate swaps using observable market inputs including interest rates and LIBOR swap rates. Management also discounts the value by a contingency factor that it believes is representative of what a market participant would use in valuing these instruments in order to account for the contingent nature of the settlement of these instmments.
Pension plans - For financial reporting purposes, the market value of plan assets is the fair value. For regulatory reporting purposes, a five-year smoothing of assets is used to determine fair value.
Derivative Instruments The Company records derivative instruments on the balance sheet at fair value in accordance with GAAP. Great Plains Energy and KCP&L enter into derivative contracts to manage exposure to commodity price and interest rate fluctuations. Derivative instruments are used solely for hedging purposes and are not issued or held for speculative reasons.
The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception. Great Plains Energy and KCP&L may elect the normal purchases and normal sales (NPNS) exception, which requires the effects of the derivative to be recorded when the underlying contract settles. Great Plains Energy and KCP&L account for derivative instruments that are not designated as NPNS as non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value.
See Note 19 for additional information regarding derivative financial instruments and hedging activities.
Great Plains Energy and KCP&L offset fair value amounts recognized for derivative instruments under master netting arrangements, which include rights to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable).
Utility Plant ,
Great Plains Energy's* and 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 ofKCP&L's 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. A portion ofGMO's utility plant is pledged as collateral for GMO's mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.
As prescribed by The Federal Energy Regulatory Commission (FERC), Allowance for Funds Used During Construction (AFUDC) is charged to the cost ofthe'plant during construction. AFUDC equity funds are included as a non-cash item in non-operating income and AFl.JDC borrowed funds are a reduction of interest charges. The rates used to compute gross AFUDC are compounded semi-annually. The rates used to compute gross AFUDC for 71
KCP&L averaged 5.7% in 2016, 3.0% in 2015 and 5.7% in 2014. The rates used to compute gross AFUDC for GMO averaged 1.6% in 2016, 4.2% in 2015 and 6.1%in2014.
Great Piains Energy's and KCP&L's balances of utility plant, at original cost, with a range of estimated us~ful lives*
are listed in the following tables.
Great Plains Energy December 31 2016 20151 Utility plant, at original cost * (millions)
Generation (20 - 60 years) $ 8,106.4 $ 7,923.8 Transmission (15 - 70 years)
- 8.86.3 848;8 Distribution (8 - 66 years) 3,629.1 3,498.6 General (5 - 50 years) '975.9 91.8.7 Total (a) $ 13,597.7* $ 13,189.9 (a) Includes $261.2 million and $214.0 million at December 31, 2016 and 2015, respectively, ofland and other assets that are not depreciated; KCP&L December 31 2016. , I 2015 Utility plant, at original cost (millions)
Generation (20 - 60 years) $ 6,350.7 $ 6,222.5 Transmission (15 - 70 years) 484.I 465.3 Distribution (8 - 55 years) 2,298.4 2,215.2' General (5 - 50 years) 791.9 737.4 Total (a) $ 9,925.I $ 9,640.4
<*l Includes $178.0 million and $136.5 million at December 31, 2016 and 2015, respectively, of land and other assets that are not depreciated.
Depreciation and Amortization Depreciation and amortization of 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%. Nucle~r fu~Us amortized to fuel expense ba,sed on .the quantity Qf heat produced during the generation of electricity.
Great Plains Energy's depreciation expense was $368.8 million, $299.4 million and $277.9 million for 2016, 2015 and 2014, respectively. KCP&L's depreciation expense was $215.4 million, $208.5 million and $189.7 million for 2016, 2015 and 2014, respectively.
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 Great Plains Energy's and KCP&L's balance sheets 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 8 for discussion of AROs including those associated with nuclear plant decommissioning costs.
Deferred Refueling O,utage 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, which is 72
approximately 18 months, until the next scheduled outage. Replacement power costs during an outage are expensed as incurred.
Regulatory Matters KCP&L.and GMO defer items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded ifKCP&L and GMO were not regulated .. See Note 6 for additional information concerning regulatory matters.
Revenue Recognition Great Plains Energy and KCP&L recognize revenues on sales of electricity when the service is provided. Revenues recorded include electric services provided but not yet billed by KCP&L and GMO. Unbilled revenues are recorded for kWh usage in the period following the customers' billing cycle to the end of the month. KCP&L's and GMO's estimate is based on net system.
kWh. usageI less actual billed kWhs. KCP&L's and GMO's estimated unbilled. kWhs are allocated and priced by regulatory jurisdiction across the rate classes based on actual billing rates.
KCP&L and GMO collect from customers gross receipts taxes levied by state and local governments. These taxes.
from KCP&L's Missouri customers are recorded gross in operating revenues and general taxes on Great Plains Energy's and KCP&L's statements of comprehensive income. KCP&L's gross receipts taxes collected from Missouri ~ustomers were $70.3 million, $62.0 million and $60.4 million in 2016, 2015 and 2014, respectively.
These taxes from KCP&L's Kansas customers and GMO's customers are recorded net in operating revenues on Great Plains Energy's and KCP&L's statements of comprehensive income.
Great Plains Energy and KCP&L collect sales taxes from customers and remit to state and local governments.
These taxes are presetlted on a net basis on Great Plains Energy's and KCP&L's statements of comprehensive income.
Great Plains Energy and KCP&L record sale and purchase activity on a net basis in wholesale revenue or purchased power when transacting with Regional Transmission Organization (RTO)/Independent System Operator (ISO) markets.
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 expensed to maintain the allowance at a level considered adequate to cover expected losses.
Receivables are charged off against the reserve when they are deemed uncollectible.
Property Gains and Losses Net gains and losses from the sale of assets and businesses and from asset impairments are recorded in operating expenses.
Asset Impairments Long-lived assets and finite-lived intangible assets subject to amortiz~tion are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. 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 th~ financial statements. The amount of impairment.
recognized is the excess of the carrying value of the asset over its fair value.
Goodwill and indefinite lived intangible assets are tested for impairment annually and when an event occurs indicating the possibility that an impairment exists. The annual test must be performed at the same time each year.
If the fair value of a reporting unit is less than its carrying value including goodwill, an impairment chargt:ffor 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 is compared with its carrying value.
73
Income Taxes Income taxes are accounted for using the asset/liability approach. Deferred tax assets and liabilities are determined based on the temp9rary differences between the financial reporting and tax bases of assets and liabilities, applying
- enacted statutory tax rates in effect for the year in which the _differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance when, in the opinion of Ill:anagement, it is more likely than not that some portion of the deferred tax assets will not be realized.
Great Plains Energy and KCP&L recognize tax benefits based on a "more-likely-than-not" recognition threshold. In addition, Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.
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. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss. KCP&L's income tax provision includes taxes allocated based on its separate company income or loss.
Great Plains Energy and KCP&L have 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 and GMO investment tax credits that have been deferred and amortized overthe remaining service lives of the related properties.
- 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.
Basic and Diluted Earnings per Common Share Calculation To determine basic earnings per common share (EPS), preferred stock dividend requirements and redemption premium are deducted from net income before dividing by the average number of common shares outstanding. To determine diluted EPS, preferred stock dividend requirements are added to earnings available for common shareholders for the periods in which the assumed conversion of Great Plains Energy's 7 .00% Series B Mandatory Convertible Preferred StOck (Series B Preferred Stock) has a dilutive effect before dividing by the diluted average number of common shares outstanding. The effect of dilutive securities assumes the issuance of common shares applicable to performance shares and restricted stock calculated using the treasury stock method and the number of common shares that would be issued under an assumed conversion of Series B Preferred Stock using the if-converted method. *
- The following table reconciles Great Plains Energy's basic and diluted EPS.
2016 2015 2014
- (millions, except per share amounts)
Income Net income $ 290.0 $ 213.b $ 242.8 Less: preferred stock dividend requirements and redemption premium 16.5 1.6 1.6 Earnings available for common shareholders $ 273.5 $ 211.4 $ 241.2 Common Shares Outstanding Average number of common shares outstanding 169.4 154.2 153.9 Add: effect of dilutive securities 0.4* 0.6 0.2 Diluted average number of common shares outstanding 169.8 154.8 154.1 Basic and Diluted EPS $ 1.61' $ 1.37 $ 1.57 74
Anti-dilutive shares excluded from the computation of diluted EPS are detailed in the following table.
2016 2015 2014 Assumed conversion of Series B Preferred Stock 7,805,460 Performance shares 482,987 Restricted stock shares 900 3,287 Dividends Declared \
In February 2017, Great Plains.Energy's Board of Directors (Board) declared a.quarterly dividend of $0.275 per share on Great Plains Energy's common stock. The common dividend is payable March 20, 2017, to shareholders '
ofrecord as of February 27, 2017 ..
The Board also dei;:lared ~ regu.lar qu~rterly dividend on Great Plains Energy's Series B Preferred Stock. The dividend will be payable March 15, 2017, to shareholders of record as of March 1, 2017.
In February 2017, KCP&L's Board of Directors declared a cash dividend payable to Great Plains Energy of $57 million payable on March 17, 2017.
New Accounting Standards In May 2014, the Financial Accounting Standards Board (FASB) issued Accounti.ng Standards Update (ASU) No.
2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to whi~h it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU No. 2014-09 one year, from January 1, 2017, to January 1, 2018. The Companies plan to adoptASU No. 2014-09 on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Companies have completed a review of the majority of their revenue arrangements and do not expect the standard to have a material impact on their consolidated financial statements. However, the Companies are still evaluating the impacts on revenue recognition of their remaining revenue arrangements and contracts where collectability is uncertain, as well as the accoun,ting for contri~utions in aid of construction. The Companies are in the process of determining their method of adoption, which depends in part on completing the evaluation of the remaining items noted above.
In February 2016, the FASB issued ASU No._2016-02, Leases, which requires an entity that is a lessee to record a-right-of-use asset and a lease liability for lease payments on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new guidance is effective for interim and annual periods beginning after December 15, 2018, and is required to be applied using a modified retrospective approach. The Companies are evaluating the effect thatASU No. 2016-02 will have on their consolidated financial statements and related disclosures and have not yet determined the effect of the standard on their ongoing financial reporting.
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation, which is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The new guidance is effective for interim and annual periods beginning after December 15, 2016, and early adoption is permitted. This guidance will be applied either prospectively; retrospectively or using :;t modified retrospective transition method, depending on the area covered in this update. The Companies adoptedASU No, 2016-09 effective January 1, 2017 and it will not have a significant impact on their ongoing financial reporting.
- In January 2017, the FASB issuedASU No. 2017-04, Simplifying the Test for Goodwill Impairment, which eliminates Step 2 of the goodwill impai~ent test. Step 2 measures a goodwill impairment loss by computing the implied fair value of a reporting unit's goodwill and comparing it with the carrying amount of that goodwill in the event that the reporting unit does not pass Step 1 of the goodwill impairment test. Under the amendments in this ASU, a goodwill impairment loss would be measured by the amount the carrying value of the reporting unit exceeds 75
its fair value as calculated in Step 1 of the goodwill impairment test. The new guidance is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted for tests performed after January 1, 2017;
- Great Plains Energy anticipates early adopting ASU No.
2017-04 for its 2017 goodwill impairment test and does not anticipate that it will have a significant impact on its ongoing financial reporting.
- 2. ANTICIPATED ACQUISITION OF WESTAR ENERGY, INC.
On May 29, 2016, Great Plains Energy entered into anAgreement and Plan of Merger (Merger Agreement) by an~
among Great Plains Energy, Westar, and, from and after its accession to the Merger Agreement, GP Star, Inc., a
- wholly owned subsidiary of Great Plains Energy in the State of Kansas (Merger Sub). Pursuant to the Merger Agreement, subject to the satisfaction or waiver of certain conditions, Merger Sub will merge with and into Westar, with Westar continuing as the surviving corporation. Upon closing, pursuant to the Merger Agreement, Great Plains 1
. Energy will acquire Westar' for (i) $51.00 in cash and (ii) a number, rounded to the nearest 1110,000 of a share, of shares of Great Plains Energy common stock, equal to the Exchange Ratio (as described below) for each share of Westar common stock issued and outstanding immediately prior to the effective time ofthe merger, with Westar.
becoming a wholly owned subsidiary of Great Plains Energy.
The Exchange Ratio is. calculated as follows:
If the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the twenty consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the merger (the GreatPlains Energy Averag~ Sto.ck Price) is:
(a) greater than $33.2283, the Exchange Ratio will be 0.2709; .
{b) greater than or equal to $28.5918 but less than or equal to $33.2283, the Exchange Ratio will be an amount equal to the quotient obtained by d,ividing (x) $9.00 by (y) the Great Plains Energy Average Stock Price; or (c) le~s than $28.5918, the Exchange Ratio will be 0.3148.
Financing Great Plains Energy plans to finance the cash portion of the merger consideration with equity and debt financing, including (i) $750 million of mandatory convertible preferred equity pursuant to*a stock purchase agreement with OCM Credit Portfolio LP (OMERS), (ii) approximately $2.35 billion of equity comprised of a combination of Great Plains Energy common stock and additional mandatory convertible preferred stock, which, as discussed below, was completed in October 2016, and (iii) approximately $4.4 billion in debt.
On May 29, 2016, in connection with the Merger Agreement, Great Plains Energy entered into a commitment letter for a 364-day senior unsecured bridge term loan facility in an aggregate principal amount of $8.017 billion (which
- has subsequently been reduced to $5.1 billion) to support the anticipated transaction and provide flexibility for the timing oflong-term financing. See Note 11 for additional information:
On May 29, 2016, Great Plains Energy entered into a stock purchase agreement with OMERS, pursuant to which Great Plains Energy will issue and sell to OMERS 750,000 shares of preferred stock of Great Plains Energy designated as 7.25% Mandatory Convertible Preferred Stock, Series A (Series A Preferred Stock), without par value, for an aggregate purchase price equal to $750 million at the closing of the merger. See Note 14 for additional information.
On October 3, 2016, Great Plains Energy completed a registered public offering of 60.5 million shares of common stock, without par value, at a public offering price of $26.45 per share, for total gross proceeds of approximately
$1.6 billion (net proceeds of approximately $1.55 billion after issuance costs). Concurrent with this .offering, Great Plains Energy also completed a registered public offering of 17.3 million depositary shares, each representing a 1/20th interest in a share of Great Plains Energy's Series B Preferred Stock, without par value, at a public offering 76
price of $50 per depositary share for total gross proceeds of $862:5 million (net proceeds of approximately $836.2 million after issuance costs). See Note 14 for additional information on the Series B Preferred Stock.
Regulatory and Shareholder.Approvals Great Plains Energy's anticipated acquisition of Westar was unanimously approved by the Great Plains Energy Board and Westar's Board of Directors (Westar Board). In September 2016, shareholders of Great Plains Energy and'Westar.approved all proposals necessary for Great Plains Energy's acquisition of Westar at each company's respective shareholder meeting. The anticipated acquisition remains subject to regulatory approvals from The State Corporation Commission of the State of Kansas (KCC), the Public Service Commission of the State of Missouri (MPSC), the Nuclear Regulatory Commission (NRC) and FERC; as well as other customary conditions.
KCC Approval In June 2016, Great Plains Energy, KCP&L and Westar filed a joint application with KCC for approval of the anticipated acquisition of Westar by Great Plains Energy. Under applicable Kansas regulations, KCC has 300 days .
following the filing to rule on the transaction. In December 2016, KCC staff filed its testimony and recommended that the KCC not approve the anticipated acquisition, citing concerns with the size of the acquisition premium, the amount of anticipated cost synergies and potential impacts to the quality of service provided t6 Kansas customers.
In January 2017, Great Plains Energy, KCP&L and Westar filed rebuttal testimony responding to KCC staff's concerns: An evidentiary hearing was held in the case from January 30, 2017 through February 7, 2017 and a final order on the joint application is expected by April 24, 2017.
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MPSC Approval On February 22, 2017, the MPSC issued an order directing Great Plains Energy to file an application with the MPSC for approval of the anticipated acquisition of Westar. The order requires Great Plains Energy to file the application within ten days from the date of the order. An evidentiary hearing in the case is expected to occur in early April 2017. While there is not a statutory deadline for an MPSC ruling on the merger application, the MPSC has indicated that they intend .to work towards a ruling on a timeline that is consistent with the joint application filed by Great Plains *Energy, KCP&L and Westar with KCC, where a final order is expected by April 24, 2017. .
Prior to receiving the MPSC order to file an application for approval of the anticipated acquisition of Westar, Great Plains Energy had reached separate stipulations and agreements with the MPSC staff and the Office of the Public Counsel (OPC) in which the MPSC staff and OPC agreed that they would not file complaints alleging that MPSC approval was necessary in order for Great Plains Energy to acquire Westar. The stipulations and agreements impose certain conditions on Great Plains Energy, KCP&L and GMO in the areas of financing, ratemaking, customer service, corporate social responsibi1ity and also, include other general provisions. The stipulation and agreement with the MPSC staff, among other things, provides that retaii rates for KCP&L Missouri and GMO customers will.
not increase as a result of the acquisition and that in the event KCP&L's or GMO's credit ratings are downgraded below investment grade as a result of the acquisitioµ, KCP&L and GMO will be restricted from paying a dividend to Great Plains Energy unless approved by the MPSC or until their credit ratings are restored to investment grade.
The stipulations and agreements must still be approved by the MPSC and it is expected that they will be considered as part of Great Plains Energy's application for approval of the anticipated acquisition of Westar.
Other Approvals In July 2016, Great Plains Energy and Westar filed applications with FERC and *NRC for approval qf the merger. In August 2016, the Securities and Exchange Commission (SEC) declared effective a registration statement including a joint proxy statement with Westar (the Proxy Statement Prospectus) used in connection with the Great Plains Energy and Westar special shareholder meetings that occurred in September 2016. In September 2016, shareholders of Great Plains Energy and Westar approved all proposals necessary for Great Plains Energy's acquisition of Westar at each company's respective shareholder meeting. In September 2016, Great Plains Energy and Westar filed their respective Pre-Merger Notification and Report forms with the *Federal Trade Commission .
(FTC) and the Department of Justice (DOJ) under the Hart-Scott-Rodino (HSR) Act. In October 2016, the FTC granted Great Plains Energy's request for early termination of the waiting period under the HSRAct with respect to the anticipated acquisition, and the DOJ also notified Great Plains Energy that it has closed its investigation of the 77
antitrust aspects of the anticipated acquisition. In January 2017, The Federal Communications Commission (FCC) consented to the Transfer of Control application filed by Great Plains Energy and Westar relating to the anticipated acquisition.
Termination Fees The Merger Agreement provides that in connection with the termination of the Merger Agreement under specified circumstances relating to a failure to obtain required regulatory approvals prior to May 31, 2017 (which date may be extended to November 30, 2017*under certain circumstances (the End Date)), a final and nonappealable order enjoining.the consummation of the merger in connection with regulatory approvals or failure by Great Plains .
. Energy to consummate the merger once all of the conditions have been satisfied, Great Plains Energy will be required to pay Westar a termination fee 'of $380 million. In addition, in the event that the Merger Agreement is terminated by (a) either party because the closing has not occurred by the End Date or (b) Westar, as a result of Great Plains Energy's uncured breach of the Merger Agree111ent, and prior to such termination, an acquisition proposal for Great Plains Energy is publicly disclosed or made to Great Plains Energy, if Great Plains Energy enters
- into an agreement or consummates a transaction with respect to an acquisition proposal, within twelve months following such termination, then Great Plains Energy may be required to pay Westar a termination fee of $180 million. Similarly, in the event that. the Merger Agreement is .terminated1 by (x) either party* because the closing has not occurred by the End Date or (y) Great Plains Energy, as a result ofWestar's uncured breach of the Merger Agreement, and prior to such termination, an acquisition proposal for Westar is publicly. disclosed or made to Westar, if Westar enters into an agreement or consummates a transaction with respect to an acquisition proposal within twelve months following. such termination, then Westar may be required to pay Great Plains Energy a termination fee of $280 miliion. '
- 3. SUPPLEMENTAL CASH FLOW INFORMATION Great Plains Energy Other Operating Activities Year Ended December 31 2016 2015 2014 Cash flows affected by changes in: (millions)
Receivables $ (18.3) $ 12.5 $ 3.0 Accounts receivable pledged as collateral 2.6 (4.0) 4.0 Fuel inventories 9.6 (28.3) (13.7)
Materials and supplies (6.5) (3.0) (0.4)
Accounts payable (25.4) (11.4) 15.2 Accrued taxes 8.1 1.1 8.3 Accrued interest 6.1 3.4 (4.1)
Deferred refueling outage costs* (3.1) (6.7) 17.0
- Pension and post-retirement benefit obligations 27.4 18.5 25.5 Allowance for equity funds used during construetion (6.6) (4.8) (18.0)
Fuel recovery mechanisms (46.9) 47.5 (28.5)
Solar rebates paid (4.5) (9.0) (43.2)
Other 15.2 (2.9) (12.3)
Total other operating activities $ (42.3) $ 12.9 $ (47.2)
Cash paid during the period:
Interest $ 191.2 $ 182.2 $ 174.8 Income taxes $ 0.1 $ 0.1 $
Non-cash investing activities:
Liabilities accrued for capital expenditures $ 32.4 $ 35.7 $ 57.4 78
KCP&L Other Operating Activities Year Ended December 31 2016 2015 2014 Cash flows affected by changes in: (millions)
Receivables $ (12.4) $ 2.6 ,$ (18.1)
Fuel inventories 10.6 (24.7) (8.5)
Materials and supplies (4.3) (4.5) (1.1)
Accounts payable (30.5) (18.0) 20.4 Accrued taxes 67.9 (19.0) (42.5)
Accrued interest 3.4 (0.1)
Deferred refueling outage costs (3.1) (6.7) 17.0
- Pension and post-retirement benefit obligations 28.6 18.4 26.9 Allowance for equity funds used during construction (6.6) (3.8) (16.0)
Fuel recovery mechanisms (53.7) 3.5 (2.2)
Solar rebates paid (3.1) (7.2) (17.3)
Other 4.5 (5.5) (23.2)
Total other operating activities $ (2.1) $ (61.5) $ (64.7)
Cash paid during the period:
Interest $ 127.0 $ 120.2 $ 112.1 Income taxes $ $ $ 30.2 Non-cash investing activities:
Liabilities accrued for capital expenditures $ 27.2 $ 23.9 $ 48.8
- 4. RECEIVABLES Great Plains Energy's and KCP&L's receivables are detailed in the following table.
December31 2016 2015 Great Plains Energy (millions)
Customer accounts receivable - billed $ 26.2 $ 3.4 Customer accounts receivable - unbilled 79.1 71.6 Allowance for doubtful ac*counts - customer accounts receivable (4.0) (3.8)
Other receivables 64.7 76.5 Total $ 166.0 $ 147.7 KCP&L Customer accounts receivable - billed $ 25.5 $ 2.8 Customer accounts receivable - unbilled 63.7 58.8 Allowance for doubtful accounts - customer accounts receivable (1.8) . (1.8)
Other receivables 51.7 69.4 Total $ 139.1 $ 129.2 Great Plains Energy's and KCP&L's other receivables at December 31, 2016 and 2015, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.
Sale of Accounts Receivable - KCP&L and GMO.
KCP&L and GMO sell all* of their retail electric accounts receivable to their wholly owned subsidiaries, KCP&L Receivables Company and GMO Receivables Company, respectively, which in turn sell an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor.
Each ofKCP&L Receivables Company's and GMO Receivables Company's sale of the undivided percentage ownership interest in accounts receivable to Victory Receivables Corporation is accounted for as a secured borrowing with accounts receivable pledged as collateral and a corresponding short-term collateralized note payable recognized on the balance sheets. At December 31, 2016 and 2015, Great Plains Energy's accounts receivable 79
pledged as collateral and the corresponding short-term collateralized note payable were $172.4 million and $175.0 million, respectively. At December 31, 2016 and 2015, KCP&L's accounts receivable pledged as collateral and the corresponding short-term collateralized note payable were $110.0 million. KCP&L's agreement expires in September 2017 and allows for $110 million in aggregate outstanding principal amount of borrowings at any time. GMO's agreement expires in September 2017 and allows for $65 million in aggregate outstanding principal of borrowings from mid-November through mid-June and then increases to $80 million from mid-June through mid-November.
- 5. NUCLEAR PLANT KCP&L owns 47% of Wolf Creek Generating Station (Wolf Creek), its only nuclear generating unit. Wolf Creek is located in Coffey County, Kansas, just northeast of Burlington, Kansas. Wolf Creek's operating license expires in 2045. Wolf Creek is regulated by the NRC with respect to licensing, operations and safety-related requirements .
Spent Nuclear Fuel and High-Level 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. Wolf Creek historically paid 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 of spent nuclear fuel. In May 2014, this fee was set to zero.
In 2010, the DOE filed a motion with tQ.e NRC to withdraw its then pending application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level-radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE's motion to withdraw its application. In 2011, the NRC announced that it was evenly divided on whether to take affirmative action to overturn or uphold the board's decision and ordered the licensing board, consistent with budgetary limitations, to close out its work on the DOE's application. In August 2013, a federal court of appeals ruled that the NRC must resume its review of the DOE's application to the extent of appropriated funds. With the available funds, the NRC was able to complete its technical review of the Yucca Mountain application but was not able to resume the licensing hearing.
Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. Management cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.
Low-Level Radioactive Waste Wolf Creek disposes of most of its low-level radioactive waste (Class A waste) at an existing third-party repository in Utah. Management expects that the site located in Utah will remain available to Wolf Creek for disposal of its Class A waste. Wolf Creek has contracted with a waste processor that will process, take title and dispose in another state most of the remainder of Wolf Creek's low-level radioactive waste (Classes Band C waste, which is higher in radioactivity but much lower in volume). Should on-site waste storage be needed in the future, Wolf Creek has current storage capacity on site for about four years' generation of Classes B and C waste and believes it will be able to expand that storage capacity as needed if it becomes necessary to do so.
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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 August 2014 and is the basis for the current cost of decommissioning estimates in the following table.
Funding levels included in KCP&L retail rates have not changed. *
- KCC MPSC (millions)
Current cost of decommissioning (in 2014 dollars)
Total Station $ 765.1 $ 765.1 KCP&L's 47% Share 359.6 359.6 Future cost of decommissioning (in 2045-2053 dollars) (a)
- Total Station $ 2,201.5 $ 2,253.1 KCP&L's 47% Share 1,034.7 1,059.0 Annual escalation factor 3.15% 3.22%
Annual return on trust assets (b) 6.29% 5.81%
(a) Total future cost over an eight year decommissioning period .
(b) The 6.29% and 5.81 % rate ofreturn for KCC and MPSC, respectively, is through 2025. Th~ rates then systematically decrease through 2053 to 0.72% and 2.22% for KCC and MPSC, respectively, based. on the assumption that the fund's investment mix will become increasingly conservative as the decommissioning period approaches.
- Nuclear Decommissioning Trust Fund In 2016 and 2015, KCP&L contributed approximately $3.3 million 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. The *funding level assumes a projected level of return on trust assets. If the actual return on trust assets is below the projected level or actual decommissioning .costs are higher.than estimated, KCP&L could be responsible for the balance of funds required; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommissioning costs over the remaining life of the unit.
The following table summarizes the change in Great.Plains Energy's and KCP&L's nuclear decommissioning trust fund.
2016 2015 Decommissioning Trust (millions)
Beginning balance January 1 $ 200.7 $ 199.0 Contributions 3.3 3.3 Earned income, net of fees 4.1 3.4 Net realized gains 0.3 0.7 Net unrealized gains (losses) 14.5 (5.7)
Ending balance December 31 $ 222.9 $ 200.7 81
The nuclear decommissioning trust is_ reported at fair value on the balance sheets and is invested in assets as detailed in the following table.
December31 2016 2015 Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair Basis Gains Losses Value Basis Gains Losses Value (millions)
Equity securities $ 93.3 $ 62.1 $ (1.5) $ 153.9 '$ 89.6 $ 47.9 $ (2.1) $ 135.4 Debt securities 63.4 2.3 (0.5) 65.2 59.6 2.6 - (0.5) 61.7 Other 3.8 3.8 3.6 3.6 Total $ .160.5 $ 64.4 $ (2.0) $ 222.9 $ 152.8 $ 50.5 ,$ (2.6) $ 200.7 The weighted average matllrity of debt securities held by the trust at December 31, 2016, was approximately 8 years. The costs of securities sold are determined on the basis of specific identification. The following table summarizes the realized gains and losses from the sale of securities in the nuclear decommissioning trust fund.
2016 2015 2014 (millions)
Realized gains $ 1.6 $ 5.3 $ 1.4 Realized losses (1.3) (4.6) (1.0)
Nuclear Insurance The owners of Wolf Creek (Owners) maintain nuclear insura~ce fo,r Wolf Creek for 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. The nuclear property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for acts of terrorism and related losses, including replacement power costs. There is no industr)r aggregate limit for liability claims related to terrorism, regardless of the number of acts of terrorism affecting Wolf Creek or any other nudear 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 related to nuclear acts of terrorism, including accidental outage power costs for nuclear acts of terrorism affecting *Wolf Creek or a'n.y other n"uclear energy facility property policy within twelve months. from the date of the first act. An industry aggregate limit of. $1.8 billion exists for property claims related to non-nuclear acts of terrorism. These limits plus any recoverable reinsurance are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. In addition, industry-wide retrospective assessmen_t programs (discussed below) can apply once these insurance programs have been exhausted.
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 effect on Great Plains Energy's and KCP&;L's results of operations, financial position and cash flows.
Nuclear Liability Insurance Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of2005, the Owners are required to insure against public liability Claims resulting from nuclear incidents to the full limit of public liability, which is currently $13.4 billion. This limit ofliability consists of the maximum available commercial insurance of $0.4 billion and the remaining $13.0 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 $127.3 million ($59.8 million, KCP&L's 47% share) per incident at any commercial reactor in the country, payable at no more than $19.0 million ($8.9 million, KCP&L's 47% share) per incident per year. This assessment is subject to an inflation adjustment based on the Consumer 82
Price Index and applicable premium taxes. In addition, the U.S. Congress. could impose additional revenue-raising measures to pay claims.
Nuclear Property Insurance The Owners carry decontamination liability, premature decommissioning liability and property damage insuranct:(
from NEIL for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site dee<ontamination in accordance with a plan ihandated by the NRC. KCP&L's share ofany 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.
Accide11tal 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.
Under all NEIL policies, the Owners are subject t6 retrosp~ctive 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 $3 7 .5 rµillion ($17 .6 million, KCP&L's 4.7% share) per policy year.
- 6. REGULATORY MATTERS KCP&L Kansas 2016 Abbreviated Rate Case Proceedings In November 2016, KCP&L filed an abbreviated application with the KCC to request a decrease to its retail revenues of $2.8 million, reflecting the true-up to actuals of construction and environmental upgrade .costs at the La Cygne station and Wolf Creek capital addition costs and the removal of certain regulatory asset and liability amortizations. The previously approved return on equity and rate-making ratio for KCP&L will not be addressed in this case. Testimony from KCC staff and other parties regarding the case is expected in April 2017, with an evidentiary hearing to occur in May 201 7. The decrease to retail revenues is anticipated to be effective in July 2017.
KCP&L Missouri 2016 Rate Case Proceedings In July 2016, KCP&L filed an application with the MPSC to request an increase to its retail revenues of$62.9 million, with a return on equity of 9.9% and a rate-making equity ratio of 49.88%. The request reflects increases in infrastructure investment costs, costs for regional transmission lines, property tax costs and costs to comply with environmental and cybersecurity mandates. KCP&L also requested an additional $27.2 million increase associated with rebasing fuel and purchased power expense. In November 2016, MPSC staff filed testimony regarding the case stating that they did not have sufficient information to support a change in rates but in the event that. new rates were approved, recommended a return on equity of 8.65%, which is on the upper end of their range of 7 .9% to 8.75%.
In February 2017, KCP&L, MPSC staff and other parties to the case filed a non-unanimous stipulation and agreement resolving certain issues in the case. The stipulation and agreement is pending MPSC approval. An evidentiary hearing also occurred in February 2017. An order on the remaining issues in the case is anticipated to be received to accommodate new rates to be effective in May 201 7.
GMO Missouri 2016 Rate Case Proceedings In February 2016, GMO filed an application with the MPSC to request an increase to its retail revenues of $59 .3 million, with a return on equity of 9.9% and a rate-making equity ratio of 54.83%. The request included recovery of increased transmission and property tax -expenses as well as costs for infrastructure and system improvements to continue to provide reliable electric service.
83
In September 2016, GMO, the MPSC staff and certain intervenors reached several non-unanimous stipulations and*
agreements resolving all issues in the case. In September 2016, the MPSC issued an order for GMO approving the non-unanimous stipulations and agreements and authorizing anincrease in annual revenues of $3.0 million and a return on equity of 9.5% to 9.75%. The rates established by the order took effect on February 22, 2017.
- Regulatory Assets and Liabilities
- Great Plains Energy and KCP&L have recorded assets and liabilities on their consolidated balance sheets resulting from the effects of the ratemaking process, which would not otherwise be recorded if the Companies were not regulated. Regulatory assets represent incurred costs that are probable of recovery from future revenues.
Regulatory liabilities represent future reductions in revenues or refunds to customers.
- 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 in KCP&L's and GMO's rate case filings;
- decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to the Companies; 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. The Companies' continued ability to meet the criteria for
- recording regulatory assets and liabilities may be affected in the future by restructuring and deregulation in the electric industry or changes in accounting rules. In the event that the criteria no longer applied to any or all of the Companies' operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism were provided. Additionally, these factors could result in an impairment on utility plant assets.
1.
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Great Plains Energy's and KCP&L's regulatory assets and liabilities are detailed in the following table.
December31 2016 2015 Great Great Plains Plains KCP&L GMO Energy KCP&L GMO Energy Regulatory Assets (millions).
Taxes recoverable through future rates $ 123.9 $ 24.8 $ ' 148.7 $ 125.0 $ 26.4 $ 151.4 (a) (a)
- Loss on reacquired debt 10.0 1.7 .11.7 11.3 2.2 13.5 Cost of removal 28.6 28.6 12.9 12.9 Asset retirement obligations 69.6 24.9 94.5 57.9 19.5 77.4 (b)
Pension and post-retirement costs 367.9 104.7 ' (b) 472.6 358.5 98.9 457.4 Deferred customer programs 45.9 (c) 27.4 (d) 73.3 50.3 20.8 71.1 (e)
Fuel recovery mechanism 69.9 69.9 16.3 0.1 16.4 Derivative instruments 0.5 6.3 '6.8 Iatan No. 1 and common facilities (f) (f) depreciation and carrying costs 13.6 5.0 18.6 14.1 5.2 19.3 Iatan No. 2 construction accounting (g) (g) costs 26.9 16.1 43.0 28.7 16.0 44.7 (e)
Kansas property tax surcharge 3.6 3.6 6.8 6.8 (e) (e)
Solar rebates 29.2 41.6 . 70.8 33.6 49.0 82.6 (e)
Transmission delivery charge 3.1 3.1 1.7 1.7 I* La Cygne deferred depreciation 2.8 (h) 2.8 2.9 2.9 (e)
Other 6.8 6.8 i 1.9 2.3 14.2 Total $. 801.~, : $ 246.2 '$ 1,048.0 $ 732.4 $ 246.7 $ 979.1 Regulatory Liabilities Emission allowances $ 62.1 ' $ $ 62.1 $ 66.l $ $ 66.1 Asset retirement obligations 99.7 99.7 86.5 86.5 (i)
Cost of removal 65.1 65.1 68.2 68.2 Fuel recoyery mechanism 11.6 11.6 5.0 5.0 Pension and post-retirement costs 15.3 7.4 22.7 4.8 3.7 8.5 Other 10.3 38.4 48.7 7.2 42.9 50.1 Total $ 187.4 $ **122.5 '$ ' 309.9 ' $ 164.6 $ '119.8 $ 284.4 .
(a) Amortized over the life of the related new debt issuances or the remaining.lives of the old debt issuances if no new debt was issued.
(bl' Represents unr~cognized gain~ and losses, prior service and transiti~n costs that will be recognized in future net periodic pension and post-retirement costs, pension settlements amortized over various periods and financial and regulatory accounting method differences that will be eliminated over the. life of the pension plan~. O(these amounts, $360.7 million and $65.1 million for KCP&L and GMO, respectively, are n,ot included in rate base and are amortized over various periods.
(c)
$13 .2 million not included in rate base and amortized over various p.eriods.
(d)
$15.4 million not included in rate base and amortized over various periods.
(e)
Not included in rate base and amortized over various periods .
(f)
. In?luded in rate hase and amortized through 2~38. .
(g)
Included in rate base and amortized through 2058.
(h)
Included in rate base and amortized through 2040. .
(i)
Estimated cumulative *net provision for future removal costs.
85
- 7. GOODWILL AND INTANGIBLE ASSETS Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exist.s. The annual impairment test for the $169.0 million of GMO acquisition
- goodwill was conducted on September 1, 2016. The goodwill impairment test is a two step process. See Note 1 for additional information regarding the Company's plans to adoptASU No. 2017-04 for its 2017 goodwill impairment test. The first step compares the fair value.of a reporting unit to its carrying amount, including goodwill, to identify potential impairment. If the carrying amount exceeds the fair value ofthe*reporting unit, the second step of the test is performed, consisting of assignment of the 'reporting unit's fair value to its assets and liabilities to determine an implied fair value of goodwill, which is compared to the carrying amount of goodwill to determine the impa~rment loss, if any, to be recognized in the financial statements. Great Plains Energy's regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics. The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a deterillination of reporting *unit invested capital using market multiples derived from the historical revenue, earnings before interest, income taxes, depreciation and amortization (EBITDA), net utility asset
. (
values and market prices of stock of peer companies. The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit. Fair value of the reporting unit exceeded the carrying amount, including goodwill; therefore, there was no impairment of goodwill.
Great Plains Energy's and KCP&L's intangible assets are included in electric utility plant on the consolidated balance sheets and are detailed'in the following table.
- December 31, 2016 December 31, 2015.
Gross Carrying Accumulated Gross Carrying Accumulated Amoun.t . Amortization . Amount Amortization Great Plains Energy (millions)
Computer software $ 355.2 $ (2i9~1) ' $ 333.0 $ (191.8)
Asset improvements 28.8 . (6.7) 28.3 (6.1)
KCP&L
- Computer software $ 338.3 $ "{263.1) $ 315.5 $ (177.7)
As.set improvements 13.6 (t8) 13..1 (1.5)..
Great Plains Energy's and KCP&L's amortization expense related to intangible assets is detailed in the following I * ' I *i ' '
- table. . . .* , . .
.\
2016 2015 (millions)
Great Plains Energy '. $ 29.1 $ 28.6 KCP&L -25.7 24.7 The following table provides the estimated amortization expense related to Great Plains .Energy's and KCP&L's intangible assets for 2017 through 2021 for the Intangible assets included in the consolidated balance sheets at
- December 31, 2016.
- 2017 2018 2019 2020 2021 (millions)
Great Plains Energy $ 26.1 $ 23.7 $ 21.5 $ 18.0 $ 14.3 KCP&L. 24.9 23.2 21.0 17.6 13.9 86
- 8. ASSET RETIREMENT OBLIGATIONS
.ARQs associated with tangible long-lived assets are legal obligations that exist 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 with a corresponding amount 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 to a regulatory asset and/or liability. Changes in the estimated fair values of the liabilities are recognized when known.
KCP&L has AROs related to decommissioning Wolf Creek, site remediation of its Spearville Wind Energy Facilities, asbestos abatement, removal of storage tanks and closure and post-closure of ponds and landfills containing coal combustion residuals (CCRs). GMO has AROs related to asbestos abatement, removal of storage tanks and closure and post-closure of ponds and landfills containing CCRs.
Additionally, certain wiring used in. Great Plains Energy's and KCP&L's generating stations include asbestos insulation, which would require special handling if disturbed. Due to the inability to reasonably estimate the quantities or the amount of disturbance. that will be necessary during dismantlement at the end of the life of a plant, the fair value of this ARO cannot be reasonably estimated at this time. Management will continue to monitor the obligation and will recognize a liability in the period in which sufficient information becomes available to reasonably estimate its fair value.*
On April 17, 2015, the Environmental Protection Agency (EPA) published new regulations to regulate the disposal
.of CCRs at electric generation facilities. The CCR rule represents legal obligations of Great Plains Energy and KCP&L as to the closure and post-closure of its ponds and landfills containing CCRs. In 2016, Great Plains Energy and KCP&L revised their AR.Os by $42.1 million and $40.1 million, respectively, due to an increase in cost estimates for the closure of ponds and landfills containing CCRs at KCP&L's electric generating facilities. As a result of the CCR rule being published, Great Plains Energy and KCP&L increased their AROs $69.5 million and
$51.3 million, respectively, in the second quarter of2015.
The following table summarizes the change in Great Plains Energy's and KCP&L's AROs.
Great Plains Energy KCP&L 2016 2015 2016 2015 (millions).
Beginning balance $ 275.9 $ 195.9 $ 239.3 $ 177.7 Additions 1.6 54.5 1.3 34.6 Revision in timing and/or estimates 42.1 20.5 40.1 22.2 Settlements (17A) (7.8) (15.0) (6.7)
- Accretion 13.8 12.8 12.3 11.5 Ending balance $ 316.0 $ 275.9 $ 278.0 $ 239.3 ARO settlement activity in 2016 and 2015 primarily consists ofthe remediation ofAROs for the closure of ponds and landfills containing CCRs at KCP&L and GMO. * '
- 9. PENSION PLANS AND OTHER EMPLOYEE BENEFITS Great Plains Energy maintains defined be11efit pension pla11s for the _majority of KCP&L's and GM O's active and inactive employees, including officers, and its 47% ownership share of Wolf Creek Nuclear Operating Corporation (WCNOC) defined benefit plans. For the majority of employees, pension benefits under these plans reflect the employees' compensation, years of service and age at retirement: Effective in 2014, Great Plains Energy's non~
union plan was closed to future employees. Great Plains Energy also provides certain post-retirement health care and life insurance benefits for substantially all retired employees ofKCP&L, GMO and its 47% ownership share of WCNOC.
87
KCP&L and GMO re~01:d pension and post-retirement expense.in accordance with rate orders from the MPSC and KCC that allow the difference between pension and post-retirement costs under GAAP and costs for ratemakirig to be recognized as a regulatory asset or liability. This difference between financial and regulatory accounting methods is due to timing and will' be eliminated over the life of the plans. * , ,
In 2014, Great Plains Energy incurred pension.settlement charges of $8:5 million as a result of accelerated pensl.on distributions.
- The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans' on an aggregate basis as well as the cqmponents of net 'periodic benefit, costs. For financial reporting purposes, the *market value of plan assets is the fair value. For regulatory reporting purposes, a five-year smoothing ofassets is used to determine fair value. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint owners of power plants.
Pension Benefits Other Benefits I
2016 2015 2016 *2015 Change in projected benefit obligation (PBO) (millions)
PBO at January 1 '$ 1,154.8 $ 1,186.8 $ 137.5 $ 165.2 Service cost 42.0 45.3 2.6 '3.3 Interest cost 52.9 50.3 6.1 6.8 Contribution by participants* 5:3, 6.9 Amendments - *(iO.l) , (7.1)
Actuarial (gain) loss 65.5 (59.4) 0.6 (23.6)
Bern'?fits paid (70.6) (68.2) (11.9) (14.0)
PBO atDecember 31 * $ 1,244.6_ $ 1,154.8 '$ 130.l $ 137.5 Change in plan assets Fair vafoe of plan assets at January 1 $ 723.9 $ 730.0 $ 114.3 $ 110.6 Actual return on plan assets 51.1 (16.3) 2.6 (0.1)
Contribut~ons by employer and participants ' 69.8' - 76:9 '10.2 L7.6 Benefits paid (68.0) (66.7) (11.5) (13.8)
Fair Yalue of plan assets at December 31 -- $: 776.8 $.. 723.9 $ 115.6 $. 114.3 Funded status at December 31 $ (467.8) $ (430.9) $ (14.5) $ (23.2)
Amounts recognized in the consolidated balance sheets Non-current asset $ $ $ 9.0 $ 4.5 Current pension and other post-retirement liability (2.2)' (2.6) (0.8) (0.8)
_Noncurrent pension liability and other pos~-retirement liability : (465.6) (428.3) (22.7) (26.9)
Net amount recognized before regulatory treatment .(467.8) (430.9) (14.5) (23.2)
Accumulated OCI or regulatory asset/liability 476.9 461.2 (23.6) (9.4)
Net amount recognized at December 31 $ 9J $ 30.3 $ (38.1) $ (32.6)
Amounts in.accumulated OCI or regulatory ass~t/liability'not yet, recognized as a component of net periodic benefit cost:
Actuarial (gain) loss $ 242.5 $ 230.7 $ (0.7) $ (3.3)
Prior service cost ~.2 3'.9 (8.0) 3.4' Other 231.2 '226.6 '(14.9) ' ', (9.5)
Net-amount recognized at December 31 $ 476.9 $' 461.2 $ (23.6) *$ ' (9.4) 88
Pension Benefits* Other Benefits 2016 2015 - 2014 2016' 2015 2014 Components of net periodic benefit costs (millions)
Service cost $ 42.0 ,$ 45.3 $ 36.7 $ 2.6 .$ 3.3 $ 3.7 Interest cost '52.9 50.3 50.1 6.1 6.8 7.9.
_Exp.ected return on plan assets (49.2) (5L7) (50.2) (3.1) (2.9) (2.6)
Prior service cost 0.7 0.8 0.9 1.2 3;1 3.1.
Recognized net actuarial (gain) loss 5:1.8 51.4 '50.0 (1.5) 0.2, (0.1)
Transition obligation*
- 0.2 0.2 Settlement charges 8.5 Net periodic benefit costs before.regulatory adjustment
- 98.. 2 96.l 96.0 5.3 10.7 ~
12.2 Regulatory adjustment (4.9) (9.8) (11.3) 6~0 4.4 4.3 Net periodic benefit costs 93.3 . 86.3 84.7 11.3 15.l 16.5.
Other changes in plan assets and benefit .
obligations recognized in OCI or ~
.. regulatory assets/liabilities Current year net (gain) loss 63.6 8.6 175.8 ' 1.1 ' (20.6) . (L8)
Amortization of gain (loss) '(51.8) (51.4) (50.0) 1.5 (0.2) 0.1.
Prior service cost (10.2) (7.0)
Amortization ofprior service cost (0.7) (0.8)' (0.9) '(1.2) (3.1) (3.1)
Amortization of.transition obligation (0.2)* ' (0.2)
Other regulatory activity 4,6 4.3 7.3 ' (5.4) (4.4) '(4.2)
Total recognized in OCi or regulatory asset/
liability 15.7 (39.3) 132.2 (14.2) - (35.5) ' (9.2)
,Total recognized in net periodic benefit costs and. OCI or regulatory asset/liability $ 109.0 $ 47.0 $ 216.9 ,$ (2.9) $ (20.4) $ 7.3 For financial reporting purposes, the estimated prior service cost and net loss for the defined benefit plans that will be amortized from accumulated other comprehensive income (OCI) or a regulatory asset into net periodic benefit*
cost in 2017 are $0.7 million and $49.7 million, respectively. For financial reporting purposes, net actuarial' gains and losses are recognized ori*a rolling.five-year average basis. Foneglilatory.reporting purposes, net actuarial gains and losses are amortized over ten years. The estimated net gain for the other post-retirement benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in 2017 is. $0.5 million ...
The accumulated benefit obligation (ABO) for all defined benefit pension plans was $1,090.2 million and $1,017.6 miJli~n at Oecember 31, 2016; and 2015, r~spectively. Pension and other post-retirement benefit plans with the PBO, ABO or accumulated other post-retirement benefit obligation (APBO) in excess of the fair value of plan assets*
at year-end are detailed in the following table.
2016 2015 ..
Pension plans witli th.e PBO in excess of plan assets (millions)
Projected benefit obligation $ 1,244.6 $ 1,154.8 Fair value of plan assets 776.8 723'.9, Pension plans with the ABO in excess of plan* assets Accumulated benefit obligation $ 1,090.2, $ 1,017.6 Fair value of plan ~ssets 776.8 ' 723.9 Other post-retirement benefit.plans with the APBO in excess of plan assets Accumulated other.post-retirement benefit obligation $ 61.7 $ 108.5 Fair value of plan assets I
- 38.3 80.8 89
The C:JMO Supplemental Executive Retirement Plan (SERP) is reflected as an unfunded ABO of $23.6 million.
Great Plains Energy has approxffi?.ately $15.8 million of assets in a non-qualified trust for this plan as of December 31, 2016, and expects to fund fu~re benefit payments* from these assets.
The expe~ted long~terin rate of return on plan ass~ts represents Great Plains Energy's estimate of the long-term
. return on plan assets and is based on.historical and projected rates ofretum for current and planned asset classes in :
the plans' investment portfolios. Assillned projected rates ofreturn for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes. Based on thetarget asset allocation for each asset class, the overall expected rate of return for the portfolios was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions. The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.
- Weighted-average assumptions used to determine the benefit Pension Benefits Other Benefits obligation at December 31 .2016 2015 2016 *2015 Discount rate 4.31% 4.54% 4.20% 4.47%
Rate of compensation increase 3.62% 3.62% . 3.50% 3.50%
Weighted-average assumptions used to determine net costs for Pension Benefits Other Benefits years ended December 31 2016 2015 2016 201~
Discount rate 4.54% 4.22% 4.47%. 4.14%-*.
Expected long-term return on plan assets 7.14% 7.14% 2.54%
- 2.81%
- Rate of compensation increase 3.62% 3:62% '3.50% *.3.50%
- after tax Great Plains Energy expects to contribute $79.6 million to the pension plans in 2017 to meet BRISA funding requirements and regulatory orders, the majority of which l.s expected to be paid by KCP&L Gre.at Plains Energy's fl1nding policy is to contrib11te. amounts suffic,ie11t to meet the E.NSA.fwJ:ding _req~ireine11ts and .MPSC and KCC ..
rate orders plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions.*. Great Plains Energy also expects to contribute $4.6 million to other post-retirement benefit plans in 2017, the majority of which is expected to be paid* by KCP&L. . .
The following benefit payments, which reflect expected future ,service, as appropriate, are. expected to be paid through 2026.
Pension Other Benefits Benefits (millions) 2017 $ 84.9 $ ' 8.9 2018 81.0 9.4,
~019 .. 84.l w.o 2020 85.9 ..1.0.3.
2021 87.7 '10.7 2022-2026 448.5 58'.T' 90
Pension plan assets are managed in accordance with prudent investor guidelines contained in the BRISA 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. The portfolios are invested, and periodically rebalanced, to achieve targeted allocations of approximately 34% U.S. large cap and small cap equity securities, 21 % international equity securities, 36% fixed income securities, 6% real estate, 1% commodities and 2% hedge funds. Fixed income securities include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S." go:vemment agency, state and local obligations, U.S. Treasury notes and money market funds.
The fair values of Great Plains Energy's pension plan assets at December 31, 2016 and 2015, by asset category are in the following tables.
Fair Value Measurements Using Quoted
- Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets December31 Assets Inputs Inputs measured Description 2016 (Level 1) * (Level 2) (Level 3) atNAV (millions)
Pension Plans Equity securities
. U.S. (a) $ 247.6 $ 213.0 $ $ $ 34.6 International (b) 163.7 120.4 43.3 Real estate (c) 42.7 12.4 30.3 Commodities (d) 14.1 14.1 Fixed income securities Fixed income funds (e) 65.1 20.9 44.2 U.S. Treasury 52.2 52.2 U.S. Agency, state and local obligations 17.9 17.9 U.S. corporate bonds (t) 120.2 120.2 Foreign corporate bonds 9.3 9.3 Hedge funds (g) 15.6 15.6 Cash equivalents 31.7 31.7 Other (3.3) (3.3)
Total $ 776.8 $ 450.6 $ 144.1 $ $ 182.1 91
Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant
- Identical Observable Unobservable Assets December 31 Assets Inputs Inputs measured Description 2015 (Level 1) (Level 2) (Level 3) at.NAV Pension Plans (millions)
Equity securities U.S. C*l $ 226.0 $ 195.5 $ $ $ 30.5 International (bl 147.4 109.7 37.7 Real estate (c) 45.9 12.2 33.7 Commodities (ct) 5.8 5.8 Fixed in.come securities Fixed income funds (e) 60.4 20.0 40.4 U.S. Treasury 48.8 48.8 U.S. Agency, state and local obligations 19.0 19.0 U.S. corporate bonds (f) 108.8 108.8 Foreign corporate bonds 10.2 10.2 Hedge funds (g) 23.7 23.7 Cash equivalents 26.0 26.0 Other 1.9 1.9 Total $ 723.9 $ 412.2 $ 139.9 $ $ 171.8 (a) At December 31, 2016 and 2015, this category is comprised o_f$128.8 million and $121.6 million, respectively, of traded mutual funds valued at daily listed prices and $84.2 million and $73.9 million, respectively, of traded common stocks and' exchange traded funds. At December 31, 2016 and 2015, this category also includes $34.6 million and $30.5 million, respectively, of institutional common/collective trust funds valued at net asset value (NAV) per share (or its equivalent) and is not categorized in the fair value hierarchy.
(bl At December 31, 2016 and 2015, this category is comprised of $92.8 million and $34.2 million, respectively, of traded mutual funds valued at daily listed prices and $27.6 million and $75.5 million, respectively, of traded American depository receipts, global depository receipts and ordinary shares. At December 31, 2016 and 2015, this category also includes $43.3 million and $37.7 million, respectively, of institutional common/collective trust funds valued at NAV per share (or its equivalent) and is not categorized in the fair value hierarchy.
(c) At December 31, 2016 and 2015, this c~tegory is comprised of $12.4 million and $12.2 million, respectively, of traded real estate investment trusts. At December 31, 2016 and 2015, this category also includes $30.3 million and $33.7 million, respectively, of institutional common/collective trust funds and a limited partnership valued at NAV per share (or its equivalent) and is not categorized in the fair value hierarchy.
(ct) Consists of institutional common/collective trust funds valued at NAV per share (or its equivalent) and is not categorized in the fair value hierarchy. * *
(e) At December 31, 2016 and 2015, this category is comprised of $20.9 million and $20.0 million, respectively, of traded mutual funds valued at daily listed prices. At December 31, 2016 and 2015, this category also includes $44.2 million and $40.4 million, respectively, of institutional common/collective trust funds valued at NAV per share (or its equivalent) and is not categorized in the fair value hierarchy.
(f) At December 31, 2016 and 2015, this category is comprised of $115.7 million and $103.0 million, respectively, of corporate bonds, $2.3 million and $2.9 million, respectively, of collateralized mortgage obligations and $2.2 million and $2.9 million, respectively, of other asset-backed securities.
(g) Consists of closely-held limited partnerships valued at NAV per share (or its.equivalent) and is not categorized in the fair value hierarchy.
Other post-retirement plan assets are also managed in accordance with prudent investor guidelines contained in the ERISArequirements. The investment strategy supports the objective of the funds, which is to preserve capital, maintain sufficient liquidity and earn a consistent rate ofreturn .. Other post-retirement plan assets are invested primarily in fixed income securities, which rri.ay include domestic and foreign corporate bonds, collateralized mortgage obligations and asset-backed securities, U.S. government agency, state and local obligations, U.S.
Treasury notes and money market funds, as well as domestic and international equity funds.
92
The fair values of Great Plains Energy's other post-retirement plan assets at December 31, 2016 and 2015, by asset category are in the following tables. '
Fair Value Measurements Using Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets December31 Assets Inputs Inputs measured Description 2016 (Level 1) (Level 2) (Level 3) atNAV Other Post-Retirement Benefit Plans (millions)
Equity securitie.s $ 4.1 $ 4.1 $ $ $
Fixed income securities Fixed income fund<*) 62.7 62.7 U.S. TreasUry 3.9 3.9 U.S. Agency, state and local obligations 4.3 4.3 U.S. corporate bonds(b) 17.8 *17.8 Foreign corporate bonds 1.6 1.6 Cash equivalents 19.5 19.5 Other 1.7 0.2 1.5 -
Total $ 115':6 $ 27.7 $ 25.2 $ $ 62.7 Fair Value Measurements Using Quoted
- Prices in
- Active Significant Markets for Other Significant Identical Observable Unobservable . Assets December3l Assets Inputs Inputs measured Description 2015 (Level 1) (Level 2) *(Level 3) atNAV Other Post-Retirement Benefit Plans (millions)
Equity securities $ 3.2 $ 3.2 ' $ $ $
Fixed income securities Fixed income fund<*) 68.9 0.1 68.8 U.S. TreasUry 3.9 3.9 U.S. Agency, state and local obligatioi;is 5.4 5.4 U.S. corporate bonds(b) 15.6 15.6 Foreign corporate bonds 1.6 1.6 Cash equivalents 14.0 14.0 Other 1.7 1.7 Total $ 114.3 $ 21.2 $ 24.3 $ $ 68.8
<*>At December 31, 2015, this*category is comprised of $0.1 million of traded mutual funds valued at daily listed prices. At December 31, 2016 and 2015, this category also includes $62.7 million and $68.8 million, respectively, of an institutional common/collective trust fund valued at NAV per share (or its equivalent) and is not categorized in the fair value hierarchy. .
(b) At December 31, 2016 and'2015, this category is comprised of $14.0 million and $12.6 million, respectively, ofcorporate bonds, $0.5 million and $0.6 million, respectively, of collateralized mortgage obligations and $3.3 million and $2.4 million, respectively, of other asset-backed securities.
- Assumed health care cost trend rates have a significa,nt effect on the amounts reported for the health care plans. The cost trend assumed for 2016 and 2017 was 6.8% and 6.5%, respectively, with the rate' declining through 2025 to the ultimate cost trend rate of 4.5%.
93
The effects of a one-percentage point-change in the assumed health care cost trend rates, holding all other assumptions constant, at December 31; 2016, are detailed in the following table.
Increase Decrease (millions)
Effect on total service and interest component $' 0.8 $ (0.7)
Effect on post-retirement benefit obligation 1.0 (0.8)
Employee Savings Plans Great Plains Energy has defined contribution savings plans (401(k)) that cover substantially all employees. Great Plains Energy matches employee contributions, subject to limits. The annual cost of the plans was approximately
$11.5 million in 2016, $10.6 million in 2015 and $9.7 million in 2014. KCP&L's annual cost of the plans was approximately $8.0 million in 2016,, $7.9 million in 2015 and $7.1 million in 2014.
- 10. 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, restricted stock units, bonus shares, stock options, stock appreciation rights, 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 8.0
_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 securities laws. Great Plains Energy has a policy of delivering newly issued shares, or shares surrendered by Long-Term Incentive Plan participants for the withholding of taxes .and held in treasury, or both, and does not expect to repurchase common shares during 2017 to satisfy performance share payments and
. director deferred share unit conversion. Forfeiture rates are based on historical forfeitures and future expectations and are reevaluated annually. ' .
The following table SQmmarizes Great Plains Energy's and KCP&L's equity compensation expense and the associated income tax benefit.
2016 2015 ~014 Great Pfains Energy (millions)
Equity compensation expense $ 5.0 $ 4.0 $ 9.9 Income tax benefit 1.6 1.4 3.6 KCP&L Equity compensation expense $ 3.2 $ 2.6 $ 6.9 Income tax benefit 1.0 0.9 2.4 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 the Board. The number of performance shares ultimately paid can vary from the number of shares initially granted depending on Great Plains Energy's performance over stated performance periods. Compensation expense for performance shares is calculated by recognizing the portion of the fair value for each reporting period for which the requisite service has been rendered. Dividends are accrued over the vesting period and paid in cash based on the .number of performance shares ultimately paid.
The fair value of performance share awards is estimated using the market value of the Company's stock at the.
valuation date and a Monte Carlo simulation technique that incorporates assumptions for inputs of expected volatilities, dividend yield and risk~free rates. Expected volatility is based on daily stock price change during a historical period commensurate with the remaining term.of the performance period of the grant. The risk-free rate is 94
ba~ed upon the rate at the time of the evaluation for zero-coupon government bonds with a maturity consistent with the remaining performance period of the grant. The dividend yield is based on the most recent dividends paid and the actual closing stock price on the valuation date. For shares granted in 2016, inputs for expected volatility, dividend yield and risk-free rates were 18%, 3.61%and0.94%, respectively.
Performance share acti\Tity 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 over a stated period of time.
Performance Grant Date Shares Fair Value*
Beginning balance January l , 2016 609,010 $ 25.60 Granted 225,204 31.41 Earned (306,953) 24.22 Forfeited (1,714) 27.61
,Performance adjustment 99,553 24.16 Enditig balance December 31, 2016 625,100 28.13
- weighted-average At December 31, 2016, the remaining weighted-average contractual term was 1.1 years. The weighted-average grant-date fair value of shares granted was $31.41, $24.03 and $28.78 in 2016, 2015 and 2014, respectively. At December 31, 2016, there was $6.4 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 performance shares earned and paid was $7.4
~illion, $0.5 million and $2.8 million in 2016, 2015 and 2014, respectively.
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 subject to the same restrictions. Compensation expense, calculated by multiplying shares by the grant-date fair value related to restricted stock, is recognized over the stated vestillg period: Restricted
- stock activity is summarized in the following table.
Nonvested Grant Date Restricted Stock Fair Value*
Beginning palance January 1, 2016 231,508 $ 24.78 Granted and issued 96,053 29.41 Vested (77,317) 22.69 Forfeited (572) 27.51 Ending balance December 31, 2016 249,672 27.20
- weighted-average At December 31, 2016, the remaining weighted-average contractual term was 1.2 years. The weighted-average grant-date fair value of shares granted was $29.41, $25.89 and $25.70 in 2016, 2015 and 2014, respectively. At December 31, 2016, there was $2.6 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. Total fair value of shares vested was $1.8 million, $2.2 million and
$1.9 million in 2016, 2015 and 2014, respectively.
Director Deferred Share Units Non-employee directors receive shares of Great Plains Energy's common stock as part of their annual retainer. Each*
director may elect to defer receipt of their shares by receiving Director Deferred Share Units that convert to shares of Great Plains Energy's common stock at the end of January in the year after departure from the Board or such 95
other time as elected by each director. Director Deferred Share Units have a value equal to the market value of Great Plains Energy's common stock on the grant date with accruing dividends.* Compensation expense', .calculated by multiplying the director deferred share units by the related grant-date fair value, is recognized at the grant date.
The total fair value of shares of Director Deferred Share Units issued was insignificant for 2016 anci 2015. Director Deferred Share Units activity ,is summarized in the following table.
Grant Date Share Units Fair Value*
Beginning balance January 1, 2016, 115,415 $ 22,95 Issued 23,172 28.99 Ending balance December 3,1, 2016 138,587 23,96
- weighted-average
- 11. SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT Great Plains Energy's $200 Million Revolving Credit Facility Great Plains Energy's $200 million revolving credit facility with a group of banks expires in October 2019, The facility's terms permit transfers of unused commitments between this facility and the KCP&L and GMO facilities discussed below, with the total amount of the facility not exceeding $400 million at any one time. A default by Great Plains Energy or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the tenns of this facility, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times.* At December 31, 2016, Great Plaii:J.s Energy was in compliance with this covenant. In June 2016, the facility was *amended, among other things, to increase the maximum consolidated indebtedness to consolidated capitalization ratio of 0.65 to 1.00 to a level such that, if Great Plains Energy would not be in compliance with the covenant as of the d~te of the closing of the anticipated.acquisition of Westar, the ratio would increase up to a maximum of 0.75 to 1.00 for one year. At becember 31, 2016, Great Plains Energy had no outstanding cash borrowings and had issued $1.0 million in letters of credit under the credit facility, At December 31, 2015, Great
- Plains Energy had $10.0 million of outstanding cash borrowings at a weighted-average interest rate of 1.94% and had issued $0.2 million letters of credit under the credit facility.
KCP&L's $600 Million Revolving Credit Facility and Commercial Paper
- KCP&L's $600 million revolving credit facility with a group of banks provides support for its issuance of commercial paper and other general corporate purposes and expires in October 2019. Great Plains Energy and KCP&L may transfer up to $20_0 million of unused commitments between Great Plains Energy's and KCP&L's facilities. A default by KCP&L on other indebtedness totaling more than $50~0 million is a default under the facility. Under the terms of this facility, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to 1.00 at all times. At December 31, 2016, KCP&L was in compliance with this covenant. At December 31, 2016, KCP&L had $132.9 million of commercial paper outstanding at a weighted-average interest rate of 0.98%, had issued letters' of credit
. totaling $2. 8 million and had no outstanding cash borrowings under the credit facility. At December 31, 2015, KCP&L had $180.3 million of commercial paper outstanding at a weighted-average interest rate of 0.70%, had issued letters of credit totaling $2.7 million and had no outstanding cash borrowings under the credit facility.
GMO's $450 Million Revolving Credit Facility and Commercial Paper GMO's $450 million revolving credit facility with a group of banks provides support for its issuance of commercial paper and other general corporate purposes and expires in October 2019. Great Plains Energy and GMO may transfer up to $200 million of unused commitments between Great Plains Energy's and GMO's facilities. A default by GMO or any of its significant subsidiaries on other indebtedness totaling more than $50.0 million is a default under the facility. Under the terms of this facility, GMO is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the facility, not greater than 0.65 to l ,00 at all times. At -
December 31, 2016, GMO was in compliance with this covenant. At December 31, 2016, GMO had $201.9 million of commercial paper outstanding at a weighted-average interest rate of 1.02%, had issued letters of credit totaling
' 96
$1.9 million and had no outstanding cash borrowings under the credit facility. At December 31, 2015, GMO had
$43. 7 million of commercial paper outstanding at a weighted-average interest rate of 0 .65%, had issued letters of credit totaling $2.5 million and had no outstanding cash borrowings under the credit facility.
Great Plains Energy's $5.1 Billion Term Loan Facility In connection with the Merger Agreement, Great Plains Energy entereq into a commitment letter for a 364-day senior unsecured bridge term loan facility, originally for an aggreg~te principal amount of $8;017 billion to support the anticipated transaction and provide flexibility for the tirriing of long-term financing. The aggregate principal amount of the facility has been reduced most recently in connection with the October 2016 Great Plains Energy common stock and depositary share offerings. As of December 31, 2016, the available aggregate principal amount of the facility was $5.1 billion. . * \
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- 12. LONG-TERM DEBT Great Plains Energy's and KCP&L's long-term debt is detailed in the following table.
December31 Year Due 2016 2015 KCP&L (millions)
General Mortgage Bonds 2.47% EIRR bonds(*) 2017-2035 $ 110.5 $* . 110.5 7.15% Series 2009A (8.59% rateibl 2019. 400.0 400.0 Senior Notes 5.85% ~eries (5.72% rate)(bl 2017 250.0 250.0 6.375% Series (7.49% rate)(bl 2018 350.0 350.0 3.15% Series 2023 300.0 300.0 3.65% Series 2025 350.0 350.0 6.05% Series (5.78% rate)(b! 2035 250.0 250.0 5.30% Series 2041 400.0 400.0 EIRRBonds 0.694% Series 2007 A and 2007B(c) 2035 146.5 146.5 2.875% Series 2008 2038 23.4 23.4 Current maturities (281.0)
Unamortized discount and debt issuance costs (15.4) (17.3)
Total KCP&L excludjng current mahirities(d) 2,284.0 2,563.1 Other Great Plains Energy GMO First Mortgage Bonds 9.44% Series 2017-2021 5.7 6.8 GMO Senior Notes 8.27% Series 2021 80.9 80.9 3.49% Series A 2025 125.0 125.0 4.06% Series B 2033 75.0 75.0 4.74% Series C 2043 150.0 150.0 GMO Medium Term Notes 7.33% Series 2023 3.0 3.0 7 .17% Series 2023 7.0 7.0 Great Plains Energy Senior Notes 6.875% Series (7.33% rate)(b) 2017 100.0 100.0 I 4.85% Series 2021 350.0 350.0 5.292% Series 2022 287.5 287.5 Current maturities (lOLl) . (1.1)
- Unamortized discount and premium, net and debt issuance costs '(1.8) (2.1)
Total Great Plains Energy excluding current maturities(d) $ 3,365.2, $ 3,745.1 (a)
Weighted-average interest rates at December 31, 2016 (b)
Rate after amortizing gains/losses recognized in other comprehensive income (OCI) on settlements of interest rate hedging instrµments (c)
Variable rate (d)
At December 31, 2016 and 2015, does not include $50.0 million and $21.9 million of secured Series 2005 Environmental Improvement Revenue Refunding (EIRR) bonds because the bonds were repurchased in September 2015 and are held by KCP&L 98
of Amortization Debt Expense Great Plains Energy's and KCP&L's amortization of debt expense is detailed in the following table.
2016 2015 2014 (millions)
KCP&L $ 3.2 $ 3.0 $ 3.0 Other Great Plains Energy 30.6 1.1 1.8 Total Great Plains Energy $ 33.8 $ 4.1 $ 4.8' In 2016, Other Great Plains Energy includes $29 .6 million of amortization of debt expense related to Great Plains Energy's $5.1 billion bridge term loan facility. Fees related to this facility are being amortized over the 364 day '
term o~ the facility.
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 (Indenture). The Indenture creates a mortgage lien on substantially all of KCP&L's utility plant. Mortgage bonds totaling $510.5 million were outstanding at December 31, 2016 and 2015, respectively.
KCP&L Municipal Bond Insurance Policies . . . .
KCP&L's secured Series 2005 BIRR bonds totaling $50.0 million and $21.9 million, respectively, are covered by a municipal bond insurance policy betWeen KCP&L ~nd Syncora Guarantee, Inc .. (Syncora). The insurance agreements between KCP&L and Syncora provide for reimbursement by KCP&L for any amounts that Syncora ..
pays under the municipal bond insurance policies. 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, 2016, KCP&L was in compliance w;ith this covenant. KCP&L is also restricted fr.om 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% ifthe long term rating for such bonds by Standard & Poor's or Moody's Investors Service would be at or below A- or A3, respectively.
The insurance agreement covering the unsecured Series 2005 EIRR bonds also required KCP&L to provide collateral to Syncora in the form of$50.0 million of Mortgage Bonds Series 2005 EIRR Insurer due 2035 for KCP&L's obligations under the insurance agreement as a result ofKCP&L issuing general mortgage bonds.in 2009
- (other than refunding of outstanding general mortgage bonds) that resulted in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. The bonds are not incremental debt for KCP&L but collateralize Syncora's claim on KCP&L if Syncora was required to meet its obligation under the insurance agreement. In the event of a defa~lt under the insurance agreements, Syncora may take any availahle legal or equitable action against KCP&L, including seeking specific performance of the covenants.
GMO First Mortgage Bonds GMO has issl,led mmigage bonds under the General Mortgage Indenture and Deed ofTrustdatedApril l, 1946, as supplemented. The Indenture creates a mortgage lien on a portion of GM O's utility plant. Mortgage bonds totaling
$5. 7 million and $6.8 million, respectively, were outstanding at December 31, 2016 and 2015 ..
GMO SeniQr ~otes Under the terms of the note purchase agreement for GMO's Series A, Band C Senior Notes, GMO is required to maintain _a consolidated indebtedness .to con,solidated capitalization ratio, as defined in the agreement, not greater than 0.65 to LOO at all times. In addition, GMO's priority debt, as defined in the agreement, cannot exceed 15% of consolidated tangible net worth, as defined in the agreemen,t. At December .31, 2016, GMO was. iii compliance with these covenants ..
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Scheduled Maturities Great Plains Energy's and KCP&L's long-term debt maturities for the next five years are detailed in the following table.
2017 2018 2019 2020 2021 (millions)
Great Plains Energy $ 382.l $ 351.l $ 401.l "$ 1.1 $ 432.0 KCP&L 281.0 350.0 400.0
- 13. COMMON STOCK Great Plains Energy has an effective shelf registration statement for the sale of unlimited amounts of securities with the SEC that became effective in March 2015 and expires in March 2018. In September 2016, Great Plains Energy filed a post-effective amendment to its shelf registration statement to register depositary shares and preference stock among the types of securities that Great Plains Energy may offer and sell.
In September 2016, Great Plains Energy shareholders approved an amendment to Great Plains Energy's articles of incorporation, increasing the authorized number of shares of common stock, without par value, to 600 million shares from 250 million shares.
In October 2016, Great Plains Energy completed a registered public offenng Of 60.5 million shares of common stock, without par value, at a public offering price of $26.45 per share, for total gross proceeds of approximately
$1.6 billion (net proceeds of approximately $1.55 billion after issuance costs). Great Plains Energy plans to use proceeds from the offering to_ finance a portion of the cash consideration for the anticipated acquisition of Westar.
Great Plains Energy has 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, 2016, 1.0 million shares remained available for future issuances.
Great Plains* Energy has shares of common stock registered with the-SEC for a defined contribution savings plan (401 (k)): Shares issued under the plan may be either newly issued shares or shares purchased in the open market.
At December 31, 2016, 0.7 million.shares remained available for future issuances.
Treasury shares are held for future distribution upon issuance of shares in conjunction with the Company's Long-Term Incentive Plan.
Great Plains Energy's articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization. In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay comillon stock dividends or purchase any common shares. If the unpaid preferred stock dividends are in arrears for six or more quarters, whether or not consecutive, the preferred shareholders will be entitled to name two directors to the Great Plains Energy Board.
Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). Under the Federal Power Act; KCP&L and GMO generally can pay dividends only out ofretained earnings. The revolving credit agreements ofGreat Plains* Energy, KCP&L and GMO and the note purchase agreement for GMO's Series A, B and C Senior Notes contain a cqvenant requiring the respective company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 fo 1.00 at all times, except as the ratio pertains to Great Plains Energy, which was amended in June 2016, as further described in Note 11.
As of December 31, 2016, all of Great Plains Energy's and KCP&L's retained earnings and net income were free of restrictions. As a result of the above restrictions, Great Plains Energy's subsidiaries had restricted net assets of 100
approximately $2.8 billion as of December 31, 2016. The restrictions are not expected to affect the Companies' ability to pay dividends at the current level in the foreseeable future.
- 14. PREFERRED STOCK At December 31, 2016, 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 Preference Stock without par value were authorized under Great Plains Energy's articles of incorporation.
- At December 31, 2016,*Great Plains Energy had 862,500 shares of Series B Preferred Stock.issued and .outstanding and had entered into a stock purchase agreement to issue 750,000 shares of Series A Preferred Stock at the closing of the anticipated acquisition with Westar. In August 2016, Great Plains Energy redeemed its 390,000 shares of outstanding Cumulative Preferred Stock, $100 par value .. See the discussion below for further information on these transactions and the pertinent rights and privileges of the Series A and Series B Preferred Stock.
Series A Mandatory Convertible Preferred Stock On May 29, 2016; Great Plains Energy entered into a stock purchase agreement with OMERS, pursuant to which Great Plains Energy will issue and sell to OMERS 750,000 shares of Series A Preferred Stock, for an aggregate purchase price equal to $750 million at the closing of the merger. The stock purchase agreement is subject to various closing conditions.
Each share of Series A Preferred Stock shall automatically convert three years after issuance into a number of shares of Great Plains Energy comillon stock equal to the Conversion Rate.
The Conversion Rate is calculated as follows:
If the average volume~weighted average price per share of Great Plains Energy common stock over 20 consecutive trading days commencing on the 22nd trading day prior to the date of conversion (Applicable Market Value) is:
(a) Equal to or greater than $34.38, the Conversion Rate shall be 29.0855; (b) Less than $34_.38 but greater than $28.65, the Conversion Rate shall be $1,000 divided by the Applicable Market Value; or (c) Les~ than or equal to $28.65, the Conver~ion Rate shall be 34.9026.
OMERS can voluntarily convert its Series A Preferred Stock into Great Plains Energy common stock at any' tim~ at the 29.0855 Conversion Rate, subject to obtaining all necessary governmental approvals.
- The Series A Preferred Stock is entitled to a 7 .25% annual dividend, payable in cash, Great Plains Energy common stock or a combination thereof. The Series A Preferred Stock has a liquidation preference of $1,000 per, share.
OMERS will be entitled to name two directors to the Great Plains Energy Board if dividends payable with respect to the Series A Preferred Stock are in arrears for two quarters and one obse:t,-ver on the Great Plains Energy Board if Great Plains Energy's credit rating is downgraded to below investment grade, so long as OMERS holds 50 percent of its, original investmen~ and subject to all necessary governmental approvals being obtained.
Series B Mandatory Convertible freferred Stock
- In October 2016, Great Plains Energy completed a registered public offering of 17.3 million depositary shares, each representing a 1/20th interest in ~ share of Great Plains Energy's Series B Preferred Stock, without par value, at a publi~ offering price of $50 per depositary share for total gross proceeds of $862.5 million (net proceeds of approximately $836.2 million after issuance costs). Great Plains Energy plans to use proceeds from the offering to fund a portion of the cash consideratiof .for the anticipated acquisition of Westar.
Each depositary share entitles the holder of such depositary share, through the bank depositary, to a 1/20th interest in the rights and preferences of the Series B Preferred Stock, includtng conversion, dividend, liquidation and voting rights, ~ubject to the terms of the deposit agreement.
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Unless previously converted or redeemed, on or around September 15, 2019, each outstanding share of Series B Preferred Stock will automatically convert into a number of shares of Great Plains Energy common stock equal to the Conversion Rate.
The Conversion Rate is calculated as follows:
If the volume-weighted average price per share, subject to certain anti-dilution adjustments, of Great Plains Energy common stock over 20 consecutive trading days commencing on the 22nd trading day prior to the date of conversion (Applicable Market Value) is:
(a) Equal to or greater than $31.74, the Conversion Rate shall be 31.5060;
. (b) Less than $31.74 but greater than $26.45, the Conversion Rate shall be $1,000 divided by the Applicable Market Value; or (c) Less than or equal to $26.45, the Conversion Rate shall be 37.8080.
At any time prior to September 15, 2019, a holder may elec;t to convert shares of the Series B Preferred Stock in whole or in part (but not less than one share of Series B Preferred Stock) into shares of Great Plains Energy common stock at the 31.5060 Conversion Rate.
Dividends on the Series B Preferred Stock will be payable on a cumulative basis when, as and if declared by Great Plains Energy's Board of Directors, and subject to Missouri law, at ari annu.al rate.of 7.00% on the liquidation preference of $1,000 per share of Series B Preferred Stock (or $50 per depositary share), payable in cash, Great Plains Energy common stock or a combination thereof.
Holders of the Series B Preferred Stock will be entitled to name two directors to the Great Plains Energy Board if dividends payable with respect to the Series B Preferred Stock are in arrears for six or more quarters, whether or not consecutive.
Cumulative Preferred Stock In August 2016, Great Plains Energy redeemed its 390,000 shares of outstanding Cumulative Preferred Stock, par value $100 per share, for a total redemption price of $40.1 million. Great Plains Energy redeemed all outstanding shares of its (i) 3.80% Preferred for $103.70 per share, plus accrued and unpaid dividends of$0.75 per share, for a total redemption price of $104.45 per share, (ii) 4.50% Preferred for $101.00 per share, plus accrued and unpaid dividends of $0.89 per share, for a total redemption price of $101.89 per share, (iii) 4.20%Preferred for $102.00 per share, plus accrued and unpaid dividends of $0.83. per share, for atotal redemption price of$102.83 per share and (iv) 4.35% Preferred for $101.00 per share, plus accrued and unpaid dividends of $0.86 per share, for a total redemption price of $101. 86 per share.
- 15. COMMITMENTS AND CONTINGENCIES Environmental Matters to Great Plains Energy and KCP.&L are subject extensive federat state and local environmental laws, regulatl.ons and permit requirements re~ating to air and water quality, waste management and disposal, natural resources and health and safety. In addition to imposing continuing compliance obligations and remediation costs, thes.e laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines, .
injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is .
expected to be material to Great Plains Energy and KCP&L. Failure to comply with environmental requirements or to timely recover environmental costs through rates could have a material effect.on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.
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Great Plains Energy's and KCP&L's current estimates of capital expenditures (exclusive of AFUDC and property taxes) over the next four years to comply with environmental regulations are in the following table. The total cost of compliance with any existing, proposed or future laws and regulations may be significantly different from these cost estimates provided.
2017 20i8 2019 2020 (millions)
Great Plains Energy $ 43.4 $ 36.6 $ 11.5 $ 14.0 KCP&L 34.9 16.5 7.6 13.0 The Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted. The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory factors and/or public perception of the Companies' environmental reputation.
The following discussion.groups environmental and certain associated matters into the broad categories of air and climate change, water, solid waste and remediation.
Clean Air Act and Climate Change Overview The Clean Air Act Amendments of 1990 (Clean Air Act) and associated regulations enacted by the Environmental Protection Agency (EPA) form a comprehensive program to preserve and enhance air quality. States are required to establish regulations and programs to address all requirements of the Clean Air Act and have the flexibility to enact more stringent requirements. All of Great Plains Energy's and KCP&L's generating facilities, and certain of their other facilities, are subject to the Clean Air Act.
- Climate Change The Companies' current generation capacity is primarily coal-fired and is estimated to produce about one ton of carbon dioxide (C02) per MWh, or approximately 19 million tons and 15 million tons per year for Great Plains Energy and KCP&L, respectively. The Companies are subject to existing greenhouse gas reporting regulations and certain greenhouse gas requirements. Federal or state legislation concerning the reduction of emissions of greenhouse gases, including C02 , could be enacted in the future. At the international level, in December 2015 the Paris Agreement was adopted by nearly 200 countries and became effective in November 2016 as the threshold of at least 55 countries representing at least 55% of global greenhouse gas emissions have joined it through ratification. The Paris Agreement does not result in any new, legally binding obligations on the United States to meet a particular greenhouse gas emissions target, but establishes a framework for international cooperation on climate change. Other international agreements legally binding on the United States may be reached in the future. Greenhouse gas legislation has the potential of having significant financial and operational impacts on Great Plains Energy and KCP&L; however, the ultimate financial and operational consequences to Great Plains Energy and KCP&L canriot be determined until such legislation is passed. In the absence of new Congressional mandates, the EPA is proceeding with the regulation of greenhouse gases under the existing Clean Air Act.
In August 2015, the EPA finalized C02 emission standards for new, modified and reconstructed affected fossil-fuel-fired ele_ctric utility generating units. The standards would not apply to Great Plains Energy's and KCP&L's existing units unless the units were modified or reconstructed il;l. the future.
In August
. 2015, the EPA fihalized its Clean Power Plan which sets C02 emission performance rates for
/,
existing affected fossil fuel-fired electric generatjng units. Specifically, the EPA translated those performance rates into a state goal measured in mass and rate based on each state's generation mix. The states have the ability to develop their own plans for affected units to achieve either the performance rates directly or the state goals, with guidelines for the development, submittal and implementation of those 103
plans. Nationwide, by 2030, the EPA projects the Clean Power Plan would achieve C02 emission reductions from the power sector of approximately 32% from C0 2 emission levels in 2005.
The EPA has finalized an interim C02 goal rate reduction in Kansas and Missouri (average of 2022-2029) of 34% arid 26%, respectively, and 2030 targets in Kansas and Missouri of 44% and 37%, respectively. The baseline for these reductions is 2012 C02 emissions adjusted by the EPA. The EPA has also finalized mass based C02 reduction goals .
.States are required to submit plans to implement the Clean Power Plan. An EPA plan with either a rate- .
based or mass-based trading program has yet to be finalized and can be enforced in states that fail to submit approved plans.
In February 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan putting the rule on hold pending review in the United States Court of Appeals for the District of Columbia Circuit and any subsequent review by the U.S. Supreme Court if such review is sought. Compliance with the Clean.Power Plan has the potential of having significant financial and operational impacts on Great Plains Energy and KCP&L; however, the ultimate financial and operational consequences to Great Plains Energy and KCP&L cannot be determined until the outcome of pending litigation is known and/or the state plans to implement the Clean Power Plan are known.
Clean Water Act The Clean Water Act and associat~d regulations enacted by the EPA form a comprehensive program to restore and preserve water quality. Like the Clean Air Act, states are required to establish regulations and programs to address all requirements of the Clean Water Act, and have the flexibility to enact more stringent requirements. All of Great Plains Energy's and KCP&L's generating facilities, and certain of their other facilities, are subject to the Clean Water Act.
fo May 2014, the EPA finalized regulations pursuant to Section 316(b) of the Clean Water Act regarding cooling water intake structures pursuant to a court approved settlement. KCP&L generation facilities with cooling water intake structures are subject to the best technology available standards based on studies completed to comply with such standards. The rule provides flexibility to work with the states to develop the best technology available to minimize aquatic species impacted by being pinned against intake screens (impingement) or drawn into _cooling water systems (entrainment). Estimated costs to comply with Section 3 l 6(b) of the Clean Water Act are included in the estimated capital expenditures table above.
KCP&L holds a permit from the Missouri Department of Natural Resources (MDNR) covering water discharge from its Hawthorn Statioll. The permit authorizes KCP&L to, among other things, 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 s.ubmitted an interim objection letter regarding the allowable amount of heat that can pe contained in the returned water. Until this matter is resolved, KCP&L continues to operate under its current permit Future water permit renewals at KCP&L's Iatan Station and at GMO's Sibley and Lake Road Stations could also be impacted by the allowable amount of heat that can be contained in the returned water. Great Plains Energy and KCP&L cannot predict the outcome of these matters; hQwever, while less significant outcomes.
are possible, these matters may require a reduction in generation, installation of cooling towers or other technology to cool the water, or both, any of which could have a significant impact on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.
In September 2015, the EPA finalized a revision of the technology-based effluent limitations guidelines and standards regulation to make the existing controls on discharges from steam electric power plants more stringent.
The final rule sets the first federal limits on the levels of toxic metals in wastewater that can-be discharged from power plants. The new requirements for existing power plants would be phased in between 2018 and 2023. The
.final rule establishes new or additional requirements for wastewaters associated with the following processes and byproducts at certain KCP&L and GMO stations: flue gas desulfurization, fly ash, bottom ash, flue gas mercury 104
control, and combustion residual leachate from landfills and surface impoundments. Estimated capital costs to comply with the final rule are included in the estimated capital expenditures table above.
Solid Waste Solid and hazardous waste generation, storage, transportation, treatment and disposal are regulated at the federal and state levels under various laws and regulations, In December 2014, the EPA finalized regulations to regulate CCRs under the Resource Conservation and Recovery Act (RCRA) subtitle D to address the risks from the disposal ofCCRs generated from the combustion*of coal at electric generating facilities.* The. Companies use coal in generating electricity and dispose qf the CG Rs in both on-site facilities andJacilities owned by third partl~s. KCP&L's Iatan,' La Cygne, arid M6ntro~e Stations' a~d GMO'~ Sibley St~tion ha~e on-site facilities affected by the rule. The rule requires periodic assessments; groundwater monltoring; location restrictions; design and operating requirements; recordkeeping and notifications; and closure, among other requirements, for CCR units.
The rule was promulgated in the Federal Register onApril 17, 2015, and became effective six moriths after *
- promulgation with various obligations effective at specified times within the rule. Estimated capital costs to*
comply with the CCR rule are included in the estimated capital expenditures table above. Certain requirements of th~ rule would* require Great Plains Energy or KCP&L to expedite or incur additional capital expenditUres ill the future.
Great Plains Energy and KCP&L have AROs on their balance sheets for closure and post-closure of ponds and landfills containing CCRs. Certain requirements of the rule could in the future require further evaluation of the expected method of compliance and refinement of asslp11ptions underlying the cost estimates for closure and post-s closui:e. Great Plains Energy's and KCi>&L1 ARbs could increase from the amounts presently recorded.
Remediation Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability .
Act (CERCLA), hold current and previOus owners or operators of contaminated facilities and persons who arranged for the disposal or treatn;ient of hazardous substances liable for the cost of investigation and cleanup. CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that ai:e determined to present an actual or potential threat to human health or the environment. GMO retains some environmental liability for several operations and investments it no longer owns. In addition, GMO also owns, or has acquired liabilities from companies that once owned or-operated; ~ormer manufactured gas plant (MGP) sites, which are subject to the supervision of the EPA and various state environmental agencies .
. At December 31, 2016 and 2015, KCP&L had $0.3 million accrued for environmental remediation ~xpenses, which covers ground water monitoring at a former MGP si.t~. Tl;i~.:imcrnpt,accrued was established on an undiscou~ted basis and KCP&L does not currently have an estimated time frame over which the accrued amount may be paid.
In addition to the $0.3 million accrual above, at December 31; 2016 and 2015, Great Plains Energy had $1.4 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites and retained liabilities. This estimate was. based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary. This estimate could change materially after further.investigation, and could also be affected by the actions of environmental agencies and the fina:r:icial viability: of other potentially responsible parties; however, given the uncertainty of these items the possible loss or range of loss in excess of the amount accrued is not estimable.
GMO has pursued recovery of remediation costs from insurance carriers and other potentially* responsible parties. As a result of a settlement with an insurance carrier, approximately $1.5 million in insurance proceeds less I an annual deductible is available to GMO to recover qualified MGP remediation expenses. GMO would seek recovery of additional remediation costs and expenses through rate increases; however, there can be no assurance that such rate increases would be granted.
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Contractual Commitments Great Plains Energy's and KCP&L's expenses related to lease commitments are detailed in the following table.
2016 2015 2014 (millions)
Great Plains Energy $* 15.0 $ 16.8 $* I 16.0' KCP&L 13.7 15.0 14:0 Great Plains Energy's and KCP&L's contractual commitments at December 31; 2016, excluding pensions and long-term debt, are detailed in the following tables. *. . ' . . ** '... ,
- Great Plains Energy 2017 2018 2019 .* 2020 2021 After 2021 Total Lease commitments * (millions)
Operating lease $ 12.9 $ 11.0 $ 9.3 $ 9.7 $ 9.7 $ 110.. 5 $ 163.1 Capital lease I 0.4 0.4 0.4 0.4 . 0.4 3.1 5.1 Purchase commitments Fuel 259.0 145.8 62.2 53.8 11.2 100.8 632.8 Power 47.3 47.3 *. 47.3 . .47.3 47.4 462.2 698:8 other 50.1 32,0. 33.3 5.9 . 6.5 38.7 166.5
'Total contractual commitments $ 369.7 $ 236.5 $ ' 152.5 .$ 117.1 * $ . 75.2. $ 715.3 $ 1,666.3 KCP&L 2017 .2018 2019 2020 2021 . After 1021 Total Lease commitments (millkms)
Operating lease $ . 12.0 $ 11.0 $ 9.3 $ 9.7 $ 9.7 . $ .. 110.5' $ 162.2 Capital lease 0:2 0.2 0.2 0.2 0.2 1.6 2.6 Purchase commitments Fuel-'* '221.5 119.4 43.6 35.1 1.8
- 100.8 522.2 Power 34.8 34.8 34.8. 34.8 34.9 324.9 499.0 Other 49.3 3_1.l 30.6 5.0 . : . 5.6 33.0 154.6 Total contractual commitments $ . 317.8.. $ )96.5 $ 118:5. $ 84.8 $ 52.2 $ 570.8 $ 1,340.6 Great Plains Energy's and KCP&L's lease commitments end in 2048. Operating lease commitments include rail .
cars to serve jointly-owned generating units where KCP&Lis the managing partner. Of the amounts included in the table above; KCP&L will be reimbursed by the other owners for approximately $1.5 million in:2017, $1.2 million in 2018 and Jipproximately $0.4 million per year from 2019 to 2025, for a total of $5.5 million:
Fuel commitments consist of commitments for nuclear fuel, coal and coal transpo1;1ation. Power commitments coris,ist of commitments for renewable energy under power purchase agreements. Other represents.ip.dividual commitments entered into in the ordinary course of business. *
' 16. LEGAL PROCEEDINGS GMO Western Energy Crisis . .
. In response to complaints of excessive prices. in the California energy markets, FERC issued an order in July ioo 1 requiring n.et sellers *of power in the California market~;' from October 2, 2000, through June 20, 2001, at prices above a FERC-determined competitive market clearing price, to make refunds *to net purchasers of pow~r in the California market during that time period. Because MPS Merchant was a net purchaser of power during the refund
- period, it has received approximately $8 million in refunds through settlements with certain sellers of power. MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC 106
has used in this case once a comprehensive resettlement of those markets occurs, as required by FERC. FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined.
In November 2014, FERC issued an order finding that MPS Merchant engaged in tariff violations during the periods prior to October 2, 2000 (the Summer Period) and ordered refunds in the form of disgorgement of certain a
revenues. MPS Merchant (and other paiiies) filed request for rehearing challenging FERC's findings of tariff violations and the remedy imposed in the Novernber 2014 order. Additionally, several parties representing California utilities and governmental agencies filed a request for clarification or rehearing focusing on the remedy.
In November 2015, FERC issued an order denying MPS Merchant's request for rehearing and expanded the remedy to include additional MPS Merchant sales in the California markets. MPS Merchant filed another request for rehearing, challenging the expanded remedy.
In February 2016, FERC issued an order expanding the amount ofrevenues that MPS Merchant would be required to disgorge to include all revenues in excess of the FERC-determined competitive market clearing price for all sales in the California markets during the Summer Period that occurred in any hour in which any remaining respondent in the proceeding was found to have committed a tariff violation.
In October 2016, MPS Merchant reached a settlement agreement with certain California utilities and governmental agencies that would settle all issuesin the. ca.se in exchange for $7.5 million of cash consideration as well as MPS .
Merchant's interest in additional funds it was entitled to during the refund period discussed above. The settlement agreement was filed with FERC in December 2016. In accordance with the terms of the settlement agreement, the
- $7.5 million of cash consideration will ~egin accruing intere~t at the FERC interest rate beginni;ng on January 1, 2017, until the date paid. . . . *
- In Januaiy 2017, FERC issued an order denying a motion filed in conjunction with and as a condition of the settlement agreement and ordered MPS Merchant and the California utilities ;md governmental agencies to notify FERC by February 27, 2017 whether they intended to revise the settlement agreement or withdraw it. I~ February 201 7, MPS Merchant and the California utilities and governmental agencies filed a notice with FERC revising the.
settlement agreement to waive the condition of the settlement agreement that was contingent upon the motion denied by FERC. The revised settlement agreen;ient is subject to approval by the Public Utilities Commi.ssion of the State of California and FERC. *
- As a result of the developments noted above, Great Plain~ Ene;gy recorded a $7.5 millio'n loss i~ other operating .
expenses in 2016.
- 17. Gl{ARANTEES In the ordinary 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 anq letters of credit. 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 subsidiary's 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.
At December 31, 2016, Great Plains Energy has provided $135.3 million of credit support for GMO as follows:
G~eat Plains Energy direct guarantees to GMO counterparties totaling $38.7 million, which expire in 2017 and 2018 and * *
- Great Plains Energy guarantee of GMO long-term debt totaling $96.6 million, which includes debt with maturity dates ranging from 2017 to 2023.
- Great Plains Energy has also guaranteed GMO's commercial paper program. At December 31, 2016, GMO had
$201.9 million commercial paper outstanding.
- 107
- 18. RELATED PARTY TRANSACTIONS AND RELATIONSHIPS KCP&L employees manage GMO's business and operate its facilities at cost, including GMO's 18% ownership interest in KCP&L's Iatan Nos. 1 and 2. The operating expenses and capital costs billed from KCP&L_to GMO were $194.4 million for 2016, $183.6 million for 2015 and $173.9 million for 2014. Additionally, KCP&L.and GMO engage in wholesale electricity transactions with each other. KCP&L's net wholesale sales to GMO were
$0.8 million, $0.2 million and $12.7 million.in 2016, 2015 and 2014, respectively. * .
KCP&L and GMO are also authorized to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO from Great Plains Energy and between KCP&L and GMO. At December 31: 2016 and 2015, KCP&L had no outstanding receiv~bles or payables
- under the money pool.
The following table summarizes KCP&L's related party net receivables ..
December 31 2()16 2015 (millions)
Net receivable from .GMO $ 64.6 $ 50.0 Net receivable from Great Plains Energy .. 2.6 15.8
- 19. DERIVATIVE INSTRUMENTS Great Plains Energy and KCP&L are exposed to a variety of market risks including interest rates and commodity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on Great Plains Energy's and KCP&L's operating results. Great Plains Energy's and KCP&L's interest rate risk management activities have included using derivative instruments to hedge against future interest rate fluctuations on anticipated debt issuances. Commodity risk management activities, including the use of certain derivative instruments, are subject to the management, direction-and control of an internal commodity risk committee. Management maintains commodity price risk management strategies that use derivative instruments to reduce the effects of fluctuations in wholesale sales and fuel and purchased power expense caused by commodity price volatility.
_Counterparties to commodity derivatives expose Great Plains Energy and KCP&L to credit loss in the event of nonperformance; This credit loss is limited to the cost ofreplacing these contracts at current market rates:
Derivative instruments, excluding those instruments that qualify for the NPNS election, which are accounted for by accrual accounting, are recorded on the balance sheet at fair value as an asset or liability. Changes in the fair value of derivative instruments .are recognized in net income, except hedges for KCP&L's and GMO's utility operations that are recorded to a regulatory asset or liability consistent with KCC and MPSC regulatory orders. For derivative contracts with counterparties under master netting arrangements, Great Plains Energy and KCP&L can net
- receivables and payables with each respective counterparty.
Interest Rate Risk Management In June 2016, Great Plains Energy entered into four interest rate swaps, with a total notional amount of $4.4 billion, to hedge against interest rate fluctuations on future issuances oflong-term debt expected to be iss.ued to finance a portion of the cash consideration for the anticipated acquisition of Westar. Settlement of the interest rate swaps is contingent on the consummation of the anticipated acquisition of Westar. The interest rate swaps have been designated as economic hedges (non-hedging derivatives). The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry recorded to interest charges.
Commodity Risk Management KCP&L and GMO have Transmission Congestion Rights (TCRs) that they utilize to hedge against congestion costs and protect load prices in the Southwest Power Pool, Inc. (SPP) Integrated Marketplace. These financial contracts have been designated as economic hedges (non-hedging derivatives). The fair values of these instruments are 108
recorded as derivative assets or liabilities with an offsetting entry recorded to a 'regulatory asset or liability. The settlement costs are included in a recovery mechanism. A regulatory asset or liability is recorded to reflect the change in the timing of recognition authorized by KCC and MPSC. Recovery of actual costs will not impact earnings, but will impact cash flows due to the timing of the recovery mechanism.
MPS Merchant, which has certain long-term natural gas contracts remaining from its former non-regulated trading operations, manages the daily delivery of its remaining contractual.commitments with economic hedges (non-hedging derivatives) to reduce its exposure to changes in market prices: Within the trading portfolio, MPS Merchant takes certain positions to hedge physical sale or purchase contracts. MPS Merchant records the fair value of physkal trading energy contracts as derivative assets or liabilities with an offsetting entry to the consolidated statements of comprehensive income.
The gross notional contract amount and recorded fair values o:f open positions for derivative instruments are summarized in the following table. The fair values of these derivatives are recorded on the consolidated balance sheets. The fair values below are gross values before netting agreements and netting of cash collateral.
December 31 2016 2015 Notional Notional Contract Fair Contract Fair Amount Value Amount Value Great Plains Energy (millions)
Non-hedging derivatives Futures contracts $ $ $ 26.6 $ (5.7)
Forward contracts 9.8 2.4 15.6 3.1
- Transmission congestion rights 3.7 1.3 5.6 (0.5)
Interest rate swaps 4,415.0 79.3 KCP&L Non-hedging derivatives Futures contracts $ $ $ 0.9 $ (0.1)
Transmission congestion rights 2.7 - 0.9 4.1 (0.4)
The fair values of Great Plains Energy'~ and KCP&L's open derivative positions and balance sheet classification are summarized in the following tables. The fair values below are gross values before netting agreements and netting of cash collateral.
Great Plains Energy Balance 'Sheet Asset Derivatives Liability Derivatives
.December 31, 2016 Classification Fair Value Fair Value Derivatives Not Designated as Hedging Instruments (millions)
Commodity contracts Derivative instruments/Other $ 4.3 $ 0.6 Interest rate contracts Derivative instruments 79.3 December 31, 2015 Derivatives Not Designated as Hedging Instruments Commodity contracts Other/Derivative instruments $ 3.3 .$
109
KCP&L Balance Sheet Asset Derivatives
- Liability Derivativ~s Dece11,1ber 31, 2016 Classification Fair Value . Fair Value Derivatives Not Designated as Hedging Instruments (millions)
Commodity* contracts Other $ 1.3 $ 0.4 December 31, 2015
- Derivatives Not Designated as Hedging Instruments Comriiodity contracts * ,* 0th.er $ 0.2 $ 0.7...
The following tables provide information regarding Great Plains Energy's and KCP&L's offsetting of derivative assets and liabilities.
Great Plains Energy Gross AmQ.unts Not Offset in the Statement of Financial Position Gross Amounts Net Amounts Offset in the Presented in Gross Statement of the Statement Amounts* Financial of Financial Financial Cash Description Recognized Position ~os'ition Instruments Collateral Net Amount De_cember 31, 2016. (millions)
Derivative assets $ 83.6 $. (0.5) $ 83.1 $ $ $ 83.1.
Derivative liabilities 0.6'- (0.5) 0.1 0.1 December 31, 2015 Derivativ~ assets $ 3.3 $ (0.2) $ 3.1 $ $ $ 3.1 Derivative liabilities 6.4 (5.9) 0.5 0.5 KCP&L Gross Anwunts Not Offset in
. the Statement of Financial Position
- Gross Amounts Net Amounts Offset in the Presented in Gross Statement of * - the Statement Amounts . Financial of Financial Financial Cash Description *
- Recognized Position * *Position Instruments . Collateral Net Amount December 31, 2016 **(millions)
Derivative assets $ 1.3 $. (0.4) $. 0.9 $ $ $ 0.9 Derivative liabilities 0.4 . (0.4)
December 31, 2015
- Derivative assets $ 0.2 $ (0.2) $ $ $
Derivative liabilities *
- 0.7 (0.3) 0.4 0.4 At December 31, 2015, Great Plains Energy had offset $5. 7 million of cash collateral posted with counterparties against net derivative positions.
110
See Note 21 for information regarding amounts reclassified out of accumulated other comprehensive loss for Great Plains Energy and KCP&L.
Great Plains Energy's accumulated OCI at December 31, 2016, includes $7.8 million that is expected to be reclassified to expenses over the next twelve months. KCP&L's accumulated OCI at December 31, 2016, includes
$7.5 million that is expected to be reclassified to expenses over the next twelve months.
The following tables summarize the amounts of gain (loss) recognized for the change in fair value of derivatives not designated as hedging instruments for Great .Plains Energy and KCP&L.
Great Plains Energy Derivatives Not Designated as Hedging Instruments 2016 2015 2014 Location of Gain (Loss) (millions)
Electric revenues $ 3.5 $ (8.2) $ (14.2)
Fuel and purchased power (2.7) (4.0) (3.4)
Interest charges 79.3 Regulatory asset * (6.8) (2.7)
Regulatory liability 1.3 '
Total $ 81.4 ' $ (19.0) $ (20.3)
KCP&L Derivatives Not Designated as Hedging Instruments 2016 2015 2014 Location of Gain (Loss) (millions)
Electric revenues $ 3.5 $ (8.2), $ (14.2)
Fuel and purchased power 0.1 1.5 1.1 Regulatory asset (0.5) (0.2)
Regulatory liability 1.0 Total $ 4.6 $ (7.2) $ (13.3)
- 20. FAIR VALUE MEASUREMENTS GAAP defines faii- value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measl,lrement date. GAAP establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad categories, gh;ing the highest priority to quoted prices in active markets for identical assets or liabilities and lowest priority to
- unobservable inputs. A definition of the various levels, as well as discussion of the various measurements within the levels, is as follows:
Level 1 - Unadjusted quoted prices for identical assets or liabilities in active markets that Great Plains Energy and KCP&L have access to at the measurement date.
Level 2- Market-based inputs for assets or liabilities that are observable (either directly or indirectly) or inputs that are not observable but are corroborated by market data.
Level 3 - Unobservable inputs, reflecting Great Plains Energy's and KCP&L's own assumptions about the assumptions market participants would use in pricing the asset or liability.
Great Plains Energy and KCP&L record cash and cash equivalents and short-term borrowings on the balance shee.t at cost, which approximates fair value due to the short-term nature of these instruments.
Great Plains Energy and KCP&L record long-term debt on the balance sheet at amortized cost. The fair value of.
long-term debt is measured as a Level 2 liability and is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices are not available. At 111
December 31, 2016, the book value and fair value of Great Plains Energy's long-term debt, including current maturities, were $3.8 billion and $4.0 billion, respectively. At December 31, 2015, the book value and fair value of Great Plains Energy's long-term debt, including current maturities, were $3.7 billion and $4.0 billion, respectively.
At December 31, 2016, the book value and fair value of KCP &L's long-term debt, including current maturities, were $2.6 billion and $2.7 billion, respectively. At December 31, 2015, the book value and fair value ofKCP&L's long-term debt, including current !'.llaturities, were $2.6 billion and $2.8 billion, respectively.
The following tables include Great Plains Energy's and KCP&L's balances of financial assets and liabilities measured at fair value on a recurring basis. The fair values below are gross values before netting arrangements and netting of cash collateral.
December31 Description 2016 Level 1 Level 2 Level 3 KCP&L (millions)
Assets Nuclear decommissioning trust (a)
Equity securities $ 153.9 $ 153.9 $ $
Debt securities .
U.S. Treasury 27.8 27.8
- u.s. Agency 1.7 1.7 State and local obligations 3.2 3.2 Corporate bonds 32.4 32.4
, Foreign governments 0.1 0.1
. Cash equivalents 3.8 3.8 Total nuclear decommissioning trust 222.9 185.5 37.4 Self-insured health plan trust (b)
Equity securities 0.9 0.9 Debt securities 4.8 0.1 4.7*
Cash and cash equivalents 5.6 5.6 Total self-insured health plan trust 11.3 6.6 4.7 Derivative instruments - commodity (c) 1.3 1.3 Total $ 235.5 $ 192.l . $ 42.1 $ 1.3 Liabilities Derivative instruments - commodity (c>, 0.4 0.4 Total $ 0.4 $ $ $ 0.4 Other Great Plains Energy Assets Derivative instruments Commodity (c) $ 3.0 $ $ 2.2 $ 0.8 Interest rate (d) 79.3 79.3 Total $ 82.3 $ $ 2.2 $ 80.1 Liabilities Derivative instruments - commodity (c) 0.2 0.1 '0.1 Total $ 0.2 $ $ 0.1 $ 0.1 Great Plains Energy Assets Nuclear decommissioning trust (a) $ 222.9 $ 185.5 $ 37.4 $
. Self-insured health plan trust (b) . 11.3 6.6 4.7 Derivative instruments (c)(d) 83.6 2.2 81.4 Total $ 317.8 $ 192.1 $ .44.3 $ 81.4 Liabilities J?erivative instruments (?)
- 0.6 0.1 0.5 Total $ 0.6 $ $ 0.1 $ 0.5 112
December31 Description 2015 Level 1 Level 2 Level3 KCP&L (millions)
Assets Nuclear decommissionmg trust (a)
Equity securities $ 135.4 $ 135.4 .$ $
Debt securities U.S. Treasury 26.4 26.4 U.S. Agency 1.8 1.8 State and local obligations 4.0 4.0 Corporate bonds 29.2 29.2 Foreign governments 0.3 0.3 Cash equivalents 3.6 3.6 Total nuclear decommissioning trust 200.7 165.4 35.3 Self-insured h~alth plan trust (b)
Equity securities 1.1 1.1 Debt securities 7.3 7.3 Cash and cash equivalents 5.2 5.2 Total self-insured health plan trust 13.6 6.3 7.3 Derivative instruments - commodity (c) 0.2 0.2 Total $ 214.5 $ 171.7 $ 42.6 $ 0.2 Liabilities Derivative instruments - commodity (cl 0.7 0.1 0.6 Total $ 0.7 $ 0.1 $ $ 0.6 Other Great Plains Energy Assets Derivative instruments - commodity (c) $ 3.1 $ $ 2.7 $ 0.4 SERP .rabbi trusts (e)
Equity securities 0.1 0.1 Total $ 3.2 $ 0.1 $ 2.7 $ 0.4 Liabilities Derivative instruments - commodity(c) 5.7 5.6 0.1 Total $ 5.7 $ 5.6 $. $ 0.1 Great Plains Energy Assets Nuclear decommissioning trust <*l_ $ - 200.7 $ 165.4 $ 35.3 $
Self-insured health plan trust (b) - 13.6 6.3 7.3 Derivative instruments (c) 3.3 2.7 0.6 SERP rabbi trusts (el 0.1 0.1 Total $ 217.7 $ 171.8 $ 45.3 $ 0.6 Liabilities Derivative instruments (cl 6.4 5.7 0.7 Total $ 6.4 $ 5.7 $ $ 0.7 (a)
Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.
(b)
Fair value is based on quoted market prices of the investments held by the trust. Debt securities classified as Level 1 are comprised of U.S. Treasury securities. Debt securities classified as Level 2 are comprised of corporate bonds, U.S. Agency, state and local obligations, and other asset-backed securities.
(c)
The fair value of commodity derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlations among fuel prices, net of estimated credit risk. Derivatiye instruments classified as Level 1 represent exchange traded derivative instruments. Derivative instruments classified as Level 2 represent non-exchange traded derivative instruments valued using pricing models for which observable market data is available* to corroborate the valuation inputs. Derivative instruments classified as Level 3 represent non-exchang~ traded derivative instruments valued using pricing models for which observable market data is ~ot available to corroborate the valuation inputs and TCRs valued at the most recent auction price in the SPP Integrated Marketplace.
(d)
The fair value of interest rate derivative instruments is determined by calculating the net present value of expected payments and receipts under the interest rate swaps using observable market inputs including interest rates and LIBOR swap rates. As of December 31, 2016, the calcufated net present value was discounted by a contingency factor of 0.35 that management believes is representative of what a market participant would use in valuing these instruments in order to account for the contingent nature of the settlement of these instruments. See Note 19 for more details *on the interest rate swaps.
113
A decrease in the contingency factor would result in a higher fair value measurement. Management expects that the contingency factor will decrease as the Company obtains certain regulatory approvals connected with the anticipated acquisition of Westar and due to the passage of time. Because of the unobservable nature of the contingency factor, the interest rate derivatives have been classified as Level 3.
(e)
At December 31, 2016 and 2015, the Supplemental Executive Retirement Plan (SERP) rabbi trusts also included $16.0 million and
$16.6 million, respectively, of fixed income funds valued at NAV per share (or its equivalent) that are not categorized in the fair value hierarchy. The fixed income fund invests primarily in intermediate and long-term debt securities, can be redeemed immediately and is not subject to any restrictions on redemptions.
The following tables reconcile the beginning and ending balances for all Level 3 assets and liabilities measured at fair value on a recurring basis.*
Great Plains Energy Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Derivative Instruments 2016 2015 (millions)
Net asset (liability) at January 1 $ (0.1) $ 3.5 Total realized/unrealized gains (losses):
included in electric revenue 3.5 (8.2) included in fuel and purchased power expense 0:8 (1.5) included in non-operating income 11.3 8.6 included in interest charges 79.3 included in regulatory (asset) liability 1.3 (0.5)
Purchases 0.3 Settlements (15.5) (2.0)
Net asset (liability) at December 31 $ 80.9 $ (0.1)
Total unrealized gains (losses) relating to assets and liabilities still on the consolidated balance sheet at December 31 :
included in non-operating income $ 0.1 $ (0.2) included in interest charges 79.3 included in regulatory (asset) liability 1.3 (0.5)
KCP&L Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Derivative Instruments 2016 2015 (millions)
Net asset (liability) at January 1 $ (0.4) $ 3.1 Total realized/unrealized gains (losses):
included in electric revenue 3.5 (8.2) included in regulatory (asset) liability 1.0 (0.4)
Purchases (0.3) (0.8)
Settlements (2.9) 5.9' Net asset (liability) at December 31 $ . 0.9 $ (0.4)
Total unrealized gains (losses) relating to assets and liabilities still on the consolidated balance
- sheet at December 31:
included in regulatory (asset) liability $ 1.0 $ (0.4) 114
- 21. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following tables reflect the change in the balances of each component of accumulated other comprehensive loss for Great Plains Energy and KCP&L.
Great Plains Energy Gains and Defined Losses on Benefit Cash Flow Pension Hedges<*l Items<*l Tota1<*l (millions) 2016 Beginning balance January 1 $ (10.1) $ (1.9) $ (12.0)
Other comprehensive income (loss) before reclassifications (0.7) (0.7)
Amounts reclassified fro.m accumulated other comprehensive loss 5.6 0.5 6.1 Net current period other comprehensive income 5.6 (0.2) 5.4 Ending balance December 31 $ (4.5) $ (2.1) $ (6.6) 2015 .
Beginning balance January 1 $ (15:8) $ (2.9) $ (18.7)
Other comprehensive income before reclassifications 0.6 0.6 Amounts reclassified from accumulated other comprehensive loss 5.7 0.4 6.1 Net current period other comprehensive income 5.7 1.0 6.7 Ending balance December 31 $ (10.1) $ (1.9) $ (12.0)
(a) Net of tax KCP&L Gains and Losses on Cash Flow Hedges<*l (millions) 2016 Beginning balance January 1 $ (9.6)
Amounts reclassified from accumulated other comprehensive loss 5.4 Net current period other comprehensive income 5.4 Ending balance December 31 $ (4.2) 2015 Beginning balance January 1 $ (14.9)
Amounts reclassified from accumulated other comprehensive loss 5.3 Net current period other comprehensive income 5.3 Ending balance December 31 $ (9.6)
(a) Net of tax 115
The following tables reflect the effect on certain line items of net income from amounts reclassified out of each component of accumulated other comprehensive loss for Great Plains Energy and KCP&L.
Great Plains Energy Amount Reclassified from Accumulated Details about Accumulated Other Other Affected Line Item in the Income Comprehensive Loss Components Comprehensive Loss Statement 2016 2015 (millions)
Gains and (losses) on cash flow hedges (effective portion)
Interest rate contracts $ (9.2) $ (9.2) Interest charges Income before income tax expense and (9.2) (9.2) income from equity investments 3.6 3.5 Income tax benefit
$ (5.6) $ (5.7) Net income Amortization of defined benefit pension items Net losses included in net periodic benefit costs $ (0.8)
~~~~~~~~~
$ (0.7) Utility operating and maintenance expenses Income before income tax expense and (0.8) (0.7)
- income from equity investments 0.3 0.3 Income tax benefit
$ (0.5) $ (0.4) Net income Total reclassifications, net of tax $ (6.1) $ (6.1) Net income KCP&L Amount Reclassified from Accumulated Details about Accumulated Other Other Affected Line Item in the Income Comprehensive Loss Components Comprehensive Loss Statement 2016 2015 (millions)
Gains and (losses) on cash flow hedges (effective portion)
Interest rate contracts $ .(8.8) $ (8.7) Interest charges (8.8) (8.7) Income before income tax expense 3.4 3.4 Income tax benefit Total reclassifications, net of tax $ (5.4) $ (5.3) Net income 116
- 22. TAXES Components of income tax expense are detailed in the following tables.
Great Plains Energy 2016 2015 '2014 .
. Current income taxes . * (millions)
Federal $ 0.3 $ (0.2) $ 0.4 State 0.7 (1.1) (0.1)
Total 1.0 (1.3) 0.3 Deferred income taxes Federal 140.6 96.9 104.2
- State 29.5. 28.0 21.6 Total 170.l 124.9 125.8 Noncun:ent income taxes Federal (2.4)
State (0.5)
Foreign . . .(6))
Total (9.0)
Irivestment tax credit Deferral 2.5 0.5 Amortization (1.4) (i.4) (104)
Total 1.1 (0.9) (1.4)
Income tax expense $ 172.2 $ 122.7 $ 115.7 .
KCP&L 2016. 2015 2014 Current income taxes (millions) ..
Federal $ 24.8 $ (18.7) $ (9.4)
State 4.7 (3.4) (2.3)
Total 29.5 (22.1) (11. 7)
Deferred income taxes Federal . 76.4 81.9 72.6 State 17.0 17.5 15.8 Total 93.4 99.4 88.4 Investment tax credit Deferral 0.5 Amortization (1.0) (1.0) (1.0)
Total (1.0) (0.5) (1.0)
I Income tax *expense $ 121.9 $ 76.8 $ 75.7 117
Effective Income Tax Rates Effective income tax rates reflected l.n the financial statements and the reasons for their differences from the statutory federal rates are detailed in the following tables.
Great Plains Energy 2016 2015 2014 Federal statutory income tax rate 35.0% 35.0% 35.0%
Differences between book and tax depreciation not normalized (0.1). (0.7)
Amortization of investment tax credits (0.3) (0.4) (0.4)
Federal income tax credits (2.6) (4.1) (3~8)
State income taxes 4.2 4.0 3.8 Changes in uncertain tax positions, net (1.7)
Transaction costs 0.9 Valuation allowance 1.5 Other 0.2 0.5 0.1
. Effective income tax rate 37.3% 36.5% 32.3%
KCP&L 2016 2015 2014 Federal statutory income tax rate 35.0% 35.0% 35.0%
Differences between book and tax depreciation not normalized (0.3) (0.9)
Amortization of investment tax credits (0.3) (0.5) (0.4)
Federal income tax credits (3.1) (5.6) (5.6)
State income taxes 4.1 4.0 3.7 Valuation allowance 0.3 ,
Other (0.2) 0.3 Effective income tax rate 35.2% 33.5% 31.8%
118
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 ~nergy KCP&L December31 2016 2015 2016 2015 Noncurrent deferred income taxes Plant related (2,107.6) (1,967~0) (1,492.2) (1,398.9)
Income taxes on future regulatory recoveries (148.7) (151.3) (123.9) (125.0) .
Derivative instruments (17.0) 20.5 8.5 14:0 Pension and post-retirement benefits 10.5 (0.1) 38.6 27.4 802 emission allowance sales 24.1 25.7 24.1 25.7 Fuel recovery mechanisms (22.3) (4.5) (27.2) (6.3)
Tax credit carryforwards 271.1 256.8 177.4 166.6 Customer demand programs (34.3) (22.7) (21.8) .* (16.9)
Solar rebates ' . (27.3) (31.9) (11.4) (13.1)
Net operating loss carryforward 718.0 734.9 198.3 204.2 Other 20.2 0.7 1.3 (9.6)
Net noncurrent deferred income tax liability before valuation allowance (1,313.3) (1,138.9) (1,228.3) (1,131.9)
Valuation allowance (16.4) (19.9) (0.7)
Net noncurrent deferred income tax liability (1,329.7) . (1,158.8) (1,228.3) (1,132.6)
- Great Plains Energy KCP&L December31 2016 2015 2016 2015 (millions)
Gross deferred income tax assets $_ 1,360.9 $ 1,368.5 $ 747.7 . $ 740.9 Gross deferred income tax liabilities (2,690.6) (2,527.3) (1,97q.O), . (1,8,73.5)
Net deferred income tax liability $(1,329.7) $(1,158.8) $(1,228.3) $(1,132.6)
Tax Credit Carryforwards At December 31, 2016 and 2015, Great Plains Energy had $183.5 million and $169.2 million, respectively, of federal general business income tax credit carryforwards. At December 31, 2016 and 2015, KCP &L had $177.4 million and $166.6 million, respectively, of federal general business income tax credit carryforwards. The carryforwards for both Great Plains Energy and KCP&L relate primarily to Advanced Coal Investment Tax Credits and Wind Production tax credits and expire in the years 2028 to 2036. Approximately $0.5 million of Great Plains Energy's credits are related to Low Income Housing credits that were acquired~in the GMO acquisition. Due to federal limitations on the utilization of income tax attributes acquired in the GMO acquisition, management expects a portion of these credits to expire unutilized and has provided a valuation allowance against $0.4 million of the federal income tax benefit.
At December 31, 2016 and 2015, Great Plains Energy had $87.6 million of federal alternative minimum tax credit carryforwards, all of which was acquired in the* GMO acquisition; These credits do not expire and can be used to reduce taxes paid in the future.
Net Operating Loss Carryforwards At December 31, 2016 and 2015, Great Plains Energy had $643.8 million and $656.1 million, respectively, of tax benefits related to federal net operating loss (NOL) carryforwards. Approximately $306.2 million at December 31, 2016 and $313.2 million at December 31, 2015, respectively, are tax benefits related to NOLs that were acquired in the GMO acquisition. The tax benefits for NO Ls originating in 2003 are $23 .0 million, $152.4 million originating in 2004, $74.1 million originating in 2005, $53.3 million originating in 2006, $1.3 million originating in 2007, $2.4 million originating in 2008,_$36.5 million originating in 2009, $4.1 million originating in 2010, $108.8 million 119
originating in 2011, $2. l million originating in 2012, $ (4 million originating in 2013, $86.3 million originating in 2014 and $98.1 million originating in 2015. The federal NOL carryforwards expire in years 2023 to 2036.
In addition, Great Plains Energy also had deferred tax benefits of $74.2 million and $78.8 million related to state NOLs as of December 31, 2016 and 2015, respectively. Of these amounts, approximately $36.1 million and $39.2 million at December 31, 2016 and 2015, respectively, were acquired in the GMO acquisition. Management does not expect to utilize $16.0 million ofNOLs in state tax jurisdictions-where the Company does not expect to operate in the future. Therefore, a valuation allowance has been provided against $16.0 million of state tax benefits. '
Valuation Allowances Great Plains Energy is required to assess the ultimate realization of deferred tax assets using a "more likely than not" assessment threshold. This assessment takes into consideration tax planning strategies within Great Plains Energy's control. As a result of this assessment, Great Plains Energy has established a partial valuation al.lowance for federal and state tax NOL carryforwards and tax credit carryforwards. During 2016, $3.5 million of tax expense was recorded in continuing operations primarily related to state NOL carryforwards that expired at December 31, 2016. .
- 23. SEGMENTS AND RELATED INFORMATION Great Plains Energy has one reportable segment based on.its method of internal reporting, which segregates reportable segments based on products and services, management responsibility and regulation. The one reportable business segment is electric utility, consisting ofKCP&L, GMO's regulated utility operations and GMO Receivables Company. Other includes GMO activity other than its regulated utility operations, GPETHC and unallocated corporate charges, including certain costs to achieve the anticipated acquisition of Westar. The summary of significant accounting policies applies to the reportable segment. Segment performance is evaluated based on net income.
The following tables reflect summarized financial information concerning Great Plains Energy's reportable segment.
Electric Great Plains 2016 Utility Other Eliminations Energy (millions)
Operating revenues $ 2,676.0 $ $ . $ 2,676.0 Depreciation and amortization (344.8) (344.8)
Interest charges (196.1) 2.5 32.1 (161.5)
Income tax expense (164.3) (7.9) (172.2)
Net income (loss) 292.1 (2:1) 290.0 Electric Great Plains 2015 Utility Other Eliminations Energy (millions)
Operating revenues $ 2,502.2 $ $ $ 2,502.2 Depreciation and amortization (330.4) (330.4).
Interest charges (190.9) (40.5) 32.1 (199.3)
Income tax expense (120.8) (1.9) (122.7)
Net income (loss) 223.8 (10.8) 213.0 120
Electric Great Plains 2014 Utility Other Eliminations Energy*
(millions) .
Operating revenues ' $ 2,568.2 $ $ $ 2,568.2 Depreciation and amortizatfon (306.0) (306.0)
Interest charges (183.0) (41.2) 35.7 (188.5)
Income tax (exp~nse) benefit. (125.6) ' 9.9 (115.7)
Net income (loss)
- 243.5 (0,7) 242.8 Electric Great Plains Utility Other Eliminations *Energy 2016 (millions)
Assets $11,444.2 $ 2,461.3 $ (335.5) $13,570.0 Capital expenditures 609.4 - .. 609.4 2015 Assets $11,045.5 $ (51.1) $ (255.8) $10,738.6 Capital expenditllres 67Z.l 677.1 2014 -,.;; . "
Assets $10,727.7 $ 29.2 . $ (303.5) $10,453.4 Capital expenditures 773.7. 773.7
- 24. JOINTLY-OWNED ELECTRIC UTILITY PLANTS .
Great Plains Energy's and KCP&L's share of jointly-oWned electric utility plants at December 31, 2016, are detailed in the following 'tables. * * ** * .
Great Plains Energy
- Jeffrey.***
Wolf Creek La Cygne Iatan No.1 Iatan No. 2 Iatan Energy Unit Units Unit Unit Common Center (miliioris, except MW amourits)
Gr~at Plains Energy's share .47% .* 5.0%. .88% 73% 79% 8%
Utility plant in service $ 1,853.1 $ 1,099.5 $ 670.2 $ 1,334.9 $ 490.6 $ 196.1 .
Accumulated depreciation 889.6 275.6 261.6 387.3 126.3
. 80.1 Nuclear fuel, net 62.0 Construction work in progress 83.5 30.6 19.9 41.7 22.1 3.7 .
2017 accredited capacity-MWs 549 699 616 641 NA *172 KCP&~
Wolf Creek La Cygne Iatan No.1 Iatan No. 2 Iatan Unit Units Unit 'Unit Common.
(millions, except MW amounts)
KCP&L's share 47% 50% 70% 55% 61%
Utility plant in service $ 1,853.1 $ 1,099.5 $ 532.8 $ 1,022.4 $ 403.1 Accumulated depreciation 889.6 275.6 . 210.8 '346.6 113.0 Nuclear fuel, net 62.0 .
Construction work in progres.s 83.5 30.6 8.4 23.l 5.0 2017 accredited capacity-MWs 549 699 490 482 NA 121
Each owner must fund its own portion of the plant's operating expenses and capital expenditures. :J_{CP&L's and GMO's share of direct expenses are included in the appropriate operating expense classifications in Great Plains Energy's and KCP&L's financial statements.
- 25. QUARTERLY OPERATING RESULTS (UNAUDITED)
Quarter Great Plains Energy 1st 2nd 3rd 4th 2016 (millions, except per share amounts)
Operating revenue $ 572.1 $ 670.8 $ 856.8 $ 576.3 Operating income 89.9 182.3 281.9 64.8 Net income 26.4 32.0 133.6 98.0 Basic and diluted earnings per common share 0.17 0.20 0.86 0.39 2015 Operating revenue $ 549.1 $ 609.0 $ 781.4 $ 562.7 Operating income 70.l 119.9 256.7 83.4 Net income 18.9 44.4* 126.8 22.9 Basic and diluted earnings per common share 0.12 0.28 0.82 0.15
- Quarter KCP&L 1st 2nd 3rll 4th 2016 (millions)
Operating revenue $ 400.9 $ 475.6 $ 597.6 $ 401.3 Operating income i0.6 137.9 219.2 54.4 Net income 24.6 65.9 117.7 16.8 2015 Operating revenue $ 370.4 $ 417.4 $ 526.3 $ 399.7 Operating income 45.J 79.3 170.8 68.6 Net income 13.2 29.4 84.3 25.9 Quarterly data is subject to seasonal fluctuations with peak periods occurring in the summer months.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
ITEM 9A. CONTROLS AND PROCEDURES GREAT PLAINS ENERGY Disdosure Controls and Procedures Great Plains Energy carried out an evaluation 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 (the Exchange Act)). This evaluation was conducted under the supervision1 and with the participation, of. Great Plains Energy's management, including the chief executive officer and chief financial officer, and Great Plains Energy's disclosure committee; Based upon this evaluation, 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 were
. effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting There has been no change *in Great Plains Energy's internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) that occurred during the quarterly period ended December 31, 2016, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
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.
Management is responsible for establishing and maintaining adequate internal control* over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) for Great Plains Energy. Under the supervision and with the participation of Great Plains Energy's chief e~ecutive officer and chief financial officer, management evaluated the effectiveness of Great Plains Energy's internal control over financial reporting as of December 31, 2016. Management used for this evaluation the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission.
Management has concluded that, as of December 31, 2016, 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 attestation report on Great Plains Energy's internal control over financial reporting, which is included below..
123.
_____ J__
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, 2016, based on criteria established in Internal Control - Integrated.
Framework (2013) issued by the Comniittee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and fQr its, assessment of the effectiveness of internal control over financial reporting, includ.ed in the accompanying . ' * '
0 Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an op inion -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). 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 perfonning such other procedures as we considered necessary in !he circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision qf, 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 generally accepted accounting principles. A conipany'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 financi.al staterp.ents in accordance with generally accepted a,ccounting 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 statemepts.
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.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Cqntr.ol - Integrated Framework (2013)
-issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2016, of the Company and our report dated February 23, 2017, expressed an unqualified opinion on those financial statements and financial statement schedules.
/s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 23, 2017 124
KCP&L Disclosure Control~ and Procedures KCP&L carried out an evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) or lSd-15 *
(e) under the Exchange Act). This evaluation was 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. Based upon this evaluation, 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 ofKCP&L were effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting "
There has beeh no change inKCP&L's internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) that occurred during the quarterly period ended December 31, 2016, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Management's Report on Internal Control Over Financial Reporting Because of the inherent limitations of internl:l-1 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 futlire 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.
- Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) for KCP&L. Under the supervision and with the participation ofKCP&L's chief executive officer and chief financial officer, management evaluated the effectiveness ofKCP&L's internal control over financial reporting as of December 31, 2016. Management used for
- this evaluation the framework in-Internal Control - Integrated Framework (2013) issued by tpe COSO of the Treadway Commission.
Management has concluded that, as of December 31, 2016, KCP&L's internal control over financial reporting is effective based on the criteria ~et 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 attestation report on KCP&L's internal control over financial reporting, which is included below.
I 125 L
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholder of Kansas City Power & Light Company Kansas City, Missouri We have audited the internal control over financial reporting of.Kansas City Power &, Light Company ~nd subs.idiaries (the "Company") as of December 31, 2016, based on criteria established in InternaJ Control -* ;
Integrated Framework (2013) 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 Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our au~it.
We conducted our audit in accordance with the standards of the Public Company Accounting *oversight Board (United States). 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 *materfal respects: Our audit inc;luded 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 ofinternal 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.
A company's intei:nal control ov~r financial reporting is .a pr~cess d~si'gn~d by, ~r 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 generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance ofrecords that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of tlie assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordru.we with generally accepted accounting principles, arid 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.
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.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2016, of the Company and our report dated February 23, 201 7, expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/DELOITTE & TOUCHE LLP Kansas City, Missouri February 23, 201 7 126
ITEM 9B. OTHER INFORMATION On February 21, 2017, Scott H. Heidtbrink, Executive Vice President and Chief Operating Officer ofKCP&L and GMO, informedthe companies of his decision to retire from his position as Executive Vice President and Chief Operating Officer effective upon the closing of Great_ Plains Energy's anticipated acquisition of Westar.
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 201 7 Proxy Statement (Proxy Statement), which will be filed with the SEC no later than March 23, 2017:
Information regarding the directors of Great Plains Energy required by this item is contained in the Proxy
- Statement section titled "Election of Directors."
- 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 "Security Ownership of Certain Beneficial Owners, Directors and Officers - Section 16(a) Beneficial Ownership Reporting Compliance."
Information regarding the Audit Committee of Great Plains Energy required by this item is contained in the Proxy Statement section titled "Corporate Governance - Committees of the Board."
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 section titled "Executive Officers."
Great Plains Energy and KCP&LCode of Ethical Business Conduct The Companies have 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 corporate governance page of the 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, 1200 .
Main St., Kansas City, Missouri 64105. GreafPlains 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 ori the corporate governance page of the Internet websites. *
- Other KCP&L Information The other information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).
ITEM 11. EXECUTIVE COMPENSATION Great Plains Energy The information required by this item contained in the sections titled "Executive Compensation," "Director Compensation," "Compensation Discussion and Analysis", "Compensation Committee Report" and "Director Independence - Compensation Cominittee Interlocks and Insider Participation" of the Proxy Statement is incorporated by reference. .
- KCP&L.
The other information required by this item regarding KCP &L has been omitted in reliance on General Instruction*
(I).
127
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 Proxy Statement is incorporated by reference.
KCP&L The information required by this item regarding KCP&L has been omitted in reliance on General Instmcti~n (I).
Equity Compensation Plans Great Plains Energy'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, restricted stock units, bonus shares, stock options, stock appreciation rights, 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.
KCP&L does not have an equity compensation plan; however, KCP&L officers and certain employees participate in Great Plains Energy's Long-Term Incentive Plan.
The following table provides information, as of December 31, 2016, 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. The table excludes shares issued or issuabl.e under Great Plains Energy's defined contribution savings plans.
Number of securities Number of remaining available securities for future issuance to be issued upon Weighted-average under equity exercis*e of ' exercise price of compensation plans outstanding options, outstanding options, (excluding securities warrants and rights warrants and rights reflected in column (a))
Plan Category (a) (!>) (c)
Equity compensation plans approved by security holders (2)
Great Plairis Energy Long-Term Incentive Plan 763,687 (I) $ 4,239,813 Equity compensation plans not approved by security holders (2)
Total 763,687 (!) $ 4,239,813 (I) Includes 625, 100 performance shares at target performance levels and director deferred share units for 1~8,587 shares of Great Plains Energy common stock outstanding at December 31, 2016.
(ZJ The performance shares and director deferred share units have no exercise price and therefore are not reflected in the weighted average
- exercise price.
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 "Related Party Transactions" of the Proxy Statement is incorporated by reference.
KCP&L The information required by this item regarding KCP&L has been omitted in reliance on General Instruction (I).
128
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 "Ratification of Appointment of Independent Auditors" of the Proxy Statement is incorporated by reference. *
- KCP&L Tµe Audit Committee of the Great Plains Energy Board functions as the Audit Committee ofKCP&L. The following table sets forth the aggregate fees billed by Deloitte & Touche LLP for audit ser\rices rendered in connection with the consolidated financial statements and reports for 2016 and 2015 and for other services rendered during 2016 and 2015 on behalf of KCP&L, as well as all out-of-pocket costs incurred in connection with these services:
Fee Category 2016 2015 Audit Fees $ 1,184,550 $ 1,201,819 Audit-Related Fees 21,000 20,000 Tax Fees 24,822 5,751 All Other Fees 8,802 Total Fees $ 1,230,372 $ 1,236,372 Audit Fees: Consists of fees billed for professional services rendered for the audits of the annual consolidated financial statements ofKCP&L 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 other attesf 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.
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 ancj are not reported under "Audit Fees". These services include consultation concerning financial accounting and reporting standards.
Tax Fees: Consists offees billed for tax compliance and related support of tax returns and other tax services, including assistance with tax audits, and tax research and planning.
All Other Fees: Consists of fees for all other services other than those described above.
Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services The Audit Committee has adopted policies and procedures for the pre-approval of all audit services, audit-related services, tax services and other services to be provided by the independent registered public accounting firm for KCP&L. The Audit Committee's policy is to pre-approve all audit, audit-related, tax or other services to be provided by the independent registered public accounting firm. Under these policies and procedures, the Audit Committee may pre-approve certain types of services, up to the aggregate fee levels it sets. 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 audit, audit-related, tax or other 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 Compani provides quarterly updates to the Audit Committee regarding actual fees spent with respect to pre-approved services. The Chairman of the Audit Committee may pre-approve audit, audit-related, tax and other services provided by the independent registered public accounting firm as required between meetings and report such pre-approval at the next Audit Committee meeting.
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PART IV ITEM 15. EXHIBITS AN.D FINANCIAL STATEMENT SCHEDULES Financial Statements Great Plains Energy Page No.
- a. Consolidated Statements of Comprehensive Income for the years ended December 31, . 60 2016, 2015 and 2014
- b. Consolidated Balance Sheets - December 31, 2016 and 2015 61
- c. Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 63 and 2014
- d. Consolidated Statements of Shareholders' Equity for the years ended December 31, 64 2016, 2015 and 2014
- e. Notes to Consolidated Financial Statements 70
- f. Report of Independent Registered Public Accounting Firm 58 KCP&L
- g. Consolidated Statements of Comprehensive Income for the years ended December 31, 65 2016, 2015 and 2014
- h. Consolidated Balance Sheets - December 31, 2016 and 2015 66'
- i. Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 68 and 2014 J. Consolidated Statements of Common Shareholder's Equity for the years ended 69 December 31, 2016, 2015 and 2014
- k. Notes to Consolidated Financial Statements 70
- 1. Report of Independent Registered Public Accounting Firm 59 Financial Statement Schedules Great Plains Energy
- a. Schedule I - Parent Company Financial Statements 144
- b. Schedule II - Valuation and Qualifying Accounts and Reserves 147 KCP&L
- c. Schedule II - Valuation and Qualifying Accounts and Reserves 148 130
Exhibits Exhibit Number Description of Document Registrant 2.1
- Agreement and Plan of Merger, dated as of May 29, 2016, by and Great Plains Energy among Westar Energy, Inc., Great Plains Energy Incorporated and,
. from and after its accession thereto, Merger Sub (as defined therein) (Exhibit2.1 to Form 8-K filed on May 31, 2016).
3 .1
- Articles of Incorporation of Great Plains Energy Incorporated, as Great Plains Energy amended effective September 26, 2016 (Exhibit 3 .1 to Form 10-Q for the quarter ended September 30, 2016).
3.2
- Certificate of Designations of the 7.00% Series B Mandatory Great Plains Energy Convertible Preferred Stock of Great Plains Energy Incorporated, filed with the Secretary of State of the State of Missouri and effective September 30, 2016. (Exhibit 3.1 to Form 8-K filed on October 3, 2016).
3.3
- Amended and Restated By-laws of Great Plains Energy Great Plains Energy Incorporated, as amended December 10, 2013 (Exhibit 3.1 to Form 8-K filed on December 16, 2013) ..
3.4 *
- Amended and Restated Articles of Consolidation of Kansas City KCP&L Power & Light Company, restated as of May 6, 2014 (Exhibit 3.2 to Form 10-Q for the quarter ended March 31, 2014).
3.5
- Amended and Restated By-laws of Kansas City Power & Light KCP&L Company, as amended December 10, 2013 (Exhibit 3.3 to Form 8-*
K filed on December 16, 2013).
4.1
- Indenture, dated as of June 1, 2004, between Great Plains Energy Great Plains Energy Incorporated and BNY Midwest Trust Company, as trustee (Exhibit 4.4 to Form 8-A/A filed on June 14, 2004).
4.2
- First Supplemental Indenture, dated as of June 14, 2004, between Great Plains Energy Great Plains Energy Incorporated and BNY Midwest Trust Company, as trustee (Exhibit 4.5 to Form 8-A/A filed on June 14, 2004).
4.3
- Second Supplemental Indenture, dated as of September 25, 2007, Great Plains Energy between Great Plains Energy Incorporated and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on September 26, 2007).
4.4
- Third Supplemental Indenture, dated as of August 13, 2010, Great Plains Energy between Great Plains Energy Incorporated and TheBank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on August 13, 2010).
4.5
- Fourth Supplemental Indenture, dated as of May 19, 2011, Great Plains Energy between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on May 19, 2011).
4.6
- Subordinated Indenture, dated as of May 18, 2009, between Great Great Plains Energy Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on May 19, 2009).
131
4.7
- Supplemental Indenture No. 1, dated as ofMay*l8, 2009, between Great Plains Energy Great Plains Energy Incorporated andThe Bank of New York Mellon Trust Company, N.A., as trustee (EXliibit 4.2 to Form 8-K filed on May 19, 2009).
4.8
- Supplemental Indenture No. 2, dated as of March 22, 2012, Great Plains Energy
.between Great Plains Energy Incorporated and The Bank of New*
York Mellon J:rust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on March 23, 2012).
4.9
- Indenture, dated as of August 24, 2001, between Aquila, Inc. and Great Plains Energy BankOne Trust Company, N.A., as trustee (Exhibit 4(d) to Registration Statement on Form S-3 (File No. 333-68400) filed by Aquila, Inc. on August 27, 2001).
4.10
- Second Supplemental Indenture, dated as of July 3, 2002, between Great Plains Energy Aquila, Inc. and BankOne Trust Company, N.A., as trustee (Exhibit 4(c) to Form S-4 (File No. 333-100204) filed by Aquila, Inc. on September 30, 2002).
. 4.11
- General Mortgage and Deed of Trust, dated as of December 1, Great Plains Energy 1986, between Kansas City Power & Light Company and UMB KCP&L Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), as trustee (Exhibit 4-bb to Form 10-K for the year ended December 31, 1986).
- 4.12
- Fifth Supplemental Indenture, dated as of September 15, 1992, Great Plains Energy between Kansas City Power & Light Company and UMB Bank, KCP&L N.A. (formerly United Missouri Bank of Kansas City, N.A.), as trustee (Exhibit 4-a to Form 10-Q for the quarter ended September.30, 1992).
4.13
- Eighth Supplemental Indenture, dated as of December 1, 1993, Great Plains Energy between Kansas City Power & Light Company and UMB Bank, KCP&L N.A. (formerly United Missouri Bank of Kansas City, N.A.), as .
trustee (Exhibit 4-o to Registration Statement, Registration No.
33-51799).
4.14
- Eleventh Supplemental Indenture, dated as of August 15, 2005, Great Plains Energy between Kansas City Power & Light Company and UMB Bank, KCP&L N.A. (formerly United Missouri Bank of Kansas City, N.A.), as trustee (Exhibit 4.2 to Form 10-Q for the quarter ended Septeipber 30, 2005).
4.15
- Twelfth Supplemental Indenture, dated as of March 1, 2009, Great'Plains Energy between Kansas City Power & Light Company and UMB Bank, KCP&L N.A. (formerly United Missouri Bank of Kansas City, N.A.), as trustee (Exhibit 4.2 to Form 8-K filed on March 24, 2009).
4.16
- Thirteenth Supplemental Indenture, dated as of March 1, 2009, Great Plains Energy between Kansas City Power & Light Company and UMB Bank, KCP&L N.A. (formerly United Missouri Bank of Kansas City, N.A.), as trustee (Exhibit 4.3 to Form 8-K filed on March 24, 2009) ..
4.17
- Fourteenth Supplemental Indenture, dated as of March 1, 2009, Great Plains Energy*
between Kansas City Power & Light Company and UMB Bank, KCP&L N.A. (formerly United Missouri Bank of Kansas City, N.A.), as trustee (Exhibit 4.4 to Form 8-K filed on March 24, 2009).
132
4.18 ** Fifteenth Supplemental Indenture, dated as of June 30, 2011, Great Plains Energy between Kansas City Power & Light Company and UMB Bank, KCP&L N.A.. (formerly United Missouri Bank Of Kansas City, N.A.), as trustee (Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2011).
4.19 -* Indenture, dated as of December 1, 2000, between Kansas City Great Plains Energy Power & Light Company and The Bank of New York, as trustee KCP&L (Exhibit 4(a) to Form 8-K filed on December 18, 2000).
4.20
- Indenture, dated as of March 1, 2002, between Kansas City Power Great Plains Energy
& Light Company and The Bank of New York, as trustee (Exhibit KCP&L .
4.1.b. to Form 10-Q for the quarter ended March 31, 2002).
4.21
- Supplemental Indenture No. 1, dated as of November 15, 2005,
- Great Plains Energy between Kansas City Power & Light Company and The Bank of KCP&L New York, as trustee (Exhibit 4.2.j to Form 10-K for the year ended December 31, 2005).
4.22
- Indenture, dated as of May 1, 2007, between Kansas City Power
- Great *Plains Energy
& Light Company and The Bank of New York Trust Company, KCP&L N.A., as trustee (Exhibit 4.1 to Form 8-K filed on June 4, 2007).
4.23
- Supplemental Indenture No. 1, dated as of June 4, 2007, b~tWeen Great Plains Energy Kansas City Power & Light Company and The Bank of New York KCP&L Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on June 4, 2007).
4.24
- Supplemental Indenture No. 2, dated as of March 11, 2008, Great Plains Energy between Kansas City Power & Light Company and The Bank of KCP&L New York Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on March 11, 2008).
4.25
- Supplemental Indenture No. 3, dated as of September 20, 2011, Great Plains Energy between Kansas City Power & Light Company and The Bank of KCP&L New York Mellon Trust Company, N.A., Trustee (Exhibit 4.1 to Form 8-K filed-on September 20, 2011).
4.26
- Supplemental Indenture No. 4, dated as of March 14, 2013, Great Plains Energy between Kansas City Power & Light Company and The Bank of KCP&L New York Mellon Trust Company, N.A., Trustee (Exhibit 4.lto Form 8-K filed on March 14, 2013).
4.27
- Supplemental Indenture No. 5, dated as of August 18, 2015, Great Plains Energy between Kansas City Power & Light Company and The Bank of
- KCP&L New York Mellon Trust Company, N.A., Trustee (Exhibit'4.1 to Form 8-K filed on August 18, 2015).
4.28
- Note Purchase Agreement, dated August 16, 2013, among KCP&L Great Plains Energy Greater Missouri Operations Company and the purchasers party thereto (Exhibit 4.1 to Form 8-K filed on August 19, 2013).
- 10.I *+ Great Plains Energy Incorporated Amended Long-Term Incentive Great Plain'.s Energy Plan, effective on May 7, 2002 (Exhibit 10.1.a to Form 10-K for KCP&L the year ended December 31, 2002).
133
10.2 *+ Great Plains Energy Incorporated Amended Long-Tenn Incentive Great Plains Energy Plan, as amended effective on May 1, 2007 (Exhibit 10.l to Form KCP&L 8-K filed on May 4, 2007).
10.3 *+ Great Plains Energy Incorporated Amended Long-Tenn Ince1<1tive Great Plains Energy Plan, as amended effective on May 3, 2011 (Exhibit 10.1 to Form KCP&L
. 8-K filed on May 6, 2011).
10.4 *+ Great Plains Energy Incorporated Amended Long-Term Incentive Great .Pfains Energy Plan, as amended effecti\'.e on January 1, 2014 (Exhibit 10 .1 to KCP&L Form 10-Q for the quarter ended June 30, 2013).
10.5 *+ Great Plains Energy Incorporated Amended Long-Tenn Incentive Great Plains Energy Plan, as amended effective on May 3, 2016 (Exhibit 10.4 to Form KCP&L 10-Q for the quarter ended June 30, 2016).
10.6 *+ Great Plains Energy Incorporated Long-Tenn Incentive Plan Great Plains Energy Awards Standards and Performance Crite1ia Effective as of KCP&L January 1, 2013 (Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2013).
10.7 *+ Great Plains Energy Incorporated Long-Tenn Incentive Plan Great Plains Energy Awards Standards and Performance Criteria Effective as of KCP&L January 1, 2014 (Exhibl.t 10.3 to Form 10-Q for the quarter ended March 31, 2014).
10.8 *+ Great Plains Energy Incorporated Long-Tenn Incentive Plan Great Plains Energy Awards Standards and Performance Criteria Effective as of KCP&L January 1, 2015 (Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 201.5).
10.9 *+ Great Plains Energy Incorporated Long-Tenn Incentive Plan Great Plains Energy Awards Standards and Performance Criteria Effective as of KCP&L January 1, 2016 (Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2016).
10.10 *+ Form of 2013 three-year Performance Share Agreement (Exhibit Great Plal.ns Energy 10.1 to Fonn 10-Q for the quarter ended March 31, 2013 ). KCP&L 10.11 *+ Form of 2013 Restricted Stock Agreement (Exhibit 10.2 to Form Great Plains Energy 10-Q for the quarter ended March 31, 2013). KCP&L 10.12 *+ Form of2014 three-year Performance Share Agreement (Exhibit Great Plains Energy 10.l to Form 10-Q for the quarter ended March 31, 2014). KCP&L 10.13 *+ Form of 2014 Restricted Stock Agreement (Exhibit 10.2 to Form Great Plains Energy 10-Q for the quarter ended March 31, 2014). KCP&L
. 10.14 *+ Form of 2015 three-year Performance Share Agreement (Exhibit Great Plains Energy 10.1 to Form 10-Q for the quarter ended March 31, 2015). KCP&L .
10.15 *+ Form of 2015 Restricted Stock Agreement (Exhibit 10.2 to Form .Great Pfains Energy 10-Q for the quarter ended March 31, 2015). KCP&L 10.16 *+ Form of 2016 three-year Performance Share Agreement (Exhibit Great Plains Energy 10.1 to Form 10-Q for the quarter ended March 31, 2016). KCP&L 134
10.17 *+ Form of20l6 Restricted Stock Agreement (Exhibit 10.2 to Form Great Plains Energy 10-Q for the quarter ended March 31, 2016). KCP&L 10.18 *+ Aquila, Inc. 2002 Omnibus Incentive Compensation Plan (Exhibit Great Plains Energy 10.3 to Form 10-Q for the quarter ended September 30, 2002, filed by Aquila, Inc.).
10.19 *+ Great Plains Energy Incorporated, Kansas City Power & Light Great Plains Energy Company and KCP&L Greater Missouri Operations Company KCP&L Annual Incentive Plan amended effective as of January 1, 2016 (Exhibit 10.4 to Form 10-Q for the quarter ended March 31, 2016).
10.20 *+ Form of Indemnification Agreement with each officer and dfrector Great Plains Energy (Exhibit 10-fto Form 10-K for year ended December 31, 1995). KCP&L 10.21 *+ Forrp of Conforming Amendment to Indemnification Agreement Great Pliiins Energy with each officer and director (Exhibit 10.1.a to Form 10-Q for the KCP&L quarter ended March 31, 2003).
10.22 *+ Form of Indemnification Agreement with each director and officer Great Plains Energy (Exhibit 10.1 to Form 8-K filed on December 8, 2008). KCP&L 10.23 *+ Form of Indemnification Agreement with officers and directors' Great Plains Energy (Exhibit 10.1.p to Form 10-K for the year ended December 31, KCP&L 2005).
. 10.24 *+ Form of Indemnification Agreement with officers and directors Great Plains Energy (Exhibit 10.1 to Form 8-K filed on December 16, 2013). KCP&L 10.25 *+ Form of Change in Control Severance Agreement with other Great Plains Energy executive officers of Great Plains Energy Incorporated and Kansas . KCP&L City Power & Light Company (Exhibit 10.1.e to Form 10-Q for the quarter ended September 30, 2006).
10.26 *+ Great Plains Energy Incorporated Supplemental Executive Great Plains Energy Retirement Plan (As Amended and Restated for I.R.C. §409A) KCP&L (Exhibit 10.1.10 to Form 10-Q for the quarter ended September 30, 2007). .
10.27 *+ Great Plains Energy Incorporated Supplemental Executive Great Plains Energy Retirement Plan (As Amended and Restated for I.R.C. §409A), as KCP&L amended February 10, 2009 (Exhibit 10.1.29 to Form 10-K for the year ended December 31, 2008 10.28 *+ Great Plains Energy Incorpor_ated Supplemental Executive Great Plains Energy Retirement Plan (As Amended and Restated for I.R.C. §409A), as KCP&L amended December 8, 2009 (Exhibit 10.1.27 to Form 10-K for the year ended December 31, 2009).
10.29 *+ Amendment dated October 28, 2014, to the Great Plains Energy Great Plains Energy Incorporated Supplemental Executive Retirement Plan as KCP&L amended and restated on December 8, 2009 (Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2014).
135
10.30 *+ Great Plains Energy Incorporated Nonqualified Deferred Great Plains Energy Compensation Plan (As Amended and Restated for I.R.C. §409A) KCP&L (Exhibit 10.1.11 to Form 10-Q for the quarter ended September 30, 2007).
10.31 *+ Great Plains Energy Incorporated Nonquaiified Deferred Great Plains Energy Compensation Plan (As Amended and Restated for I.R.C. §409A), KCP&L amended effective January 1, 2010 (Exhibit 10.1.5 to Form 10-Q for the quarter ended March 31, 2010). * * *
- 10.32
- Joint Motion and Settlement Agreement, dated as of February 26, Great Plains Energy 2008, among Great Plains Energy Incorporated, Kansas City KCP&L Power & Light Company, the Kansas Corporation Commission Staff, the Citizens' Utility Ratepayers Board, Aquila, Inc. d/b/a Aquila Networks, Black Hills Corporation, and Black Hills/
Kansas Gas Utility Company, LLC (Exhibit 10.1.7 to Form 10-Q for the quarter ended March 31, 2008).
10.33
- Credit Agreeme~t, dated as of August 9, 2010, among Great Plains Great Plains Energy Energy Incorporated, Certain Lenders, Bank of America, N.A., as Administrative Agent, and Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Barclays Bank PLC and U.S. Bank National Association, as Documentation Agents, Banc of America Securities LLC, Union Bank, N.A. arid.
Wells Fargo Securities, LLC as Joint Lead Arrangers arid Joint Book Managers (Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2010). *
- 10.34
- First Amendment to Credit Agreement, dated as of December 9, Great Plains Energy 2011, among Great Plains Energy Incorporated, Certain Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Bank of America, N.A., as Administrative Agent, Barclays Bank PLC and U.S. Bank National Association, as Documentation Agents, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Union Bank, N.A. and Wells Fargo Securities, LLC as Joint Lead Arrangers and Joint Book Managers (Exhibit 10:59 to Form 10-K for the year ended December 31, 2011 ).
10.35
- Second Amendment to Credit Agreement, dated as of October 17, Great Plains Energy 2013, among Great Plains Energy Incorporated, Certain Lenders, Bank of America, N.A., JPMorgan Chase Bank, N.A. and Union*
Bank, N.A., as Syndication Agents and Wells Fargo Bank, National Association, as Administrative Agent, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and Union Bank, N.A.,
as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.l to Form 10-Q for the quarter ended September 30, 2013).
10.36
- First Extension Agreement and Waiver, dated as of December 17, Great Plains Energy 2014, among Great Plains Energy Incorporated, Certain Lenders, Bank of America, N.A., JPMorgan Chase Bank, N.A., and MUFG Union Ban:lc, N.A., as Syndication Agents and Wells Fargo Bank, National A~sociation, as Administrative Agent, Swing Line Lender and an Issuer, Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC,'
- and MUFG Union Bank, N.A., as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.37 to Form 10-K for the year ended December 31, 2014).
- 136
10.37
- Third Amendment to the Credit Agreement, dated as of June 13, Great Plains Energy 2016, among Great Plains Energy Incorporated, Certain Lenders, Bank of America, N.A., JPMorgan Chase Bank, N.A., and Union Bank, N.A., as Syndication Agents and Wells Fargo Bank, National Association, as Administrative Agent, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and Union Bank, N.A.,
as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2016).
10.38
- Credit Agreement, dated as of August 9, 2010, among Kansas City Great Plains Energy Power & Light Company, Certain Lenders, Bank of America, KCP&L N.A., as Administrative Agent, and Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, JPMorgan Chase Bank, N.A. and The Bank of Nova Scotia, as Documentation Agents, Banc of America Securities LLC, Union Bank, N.A. and Wells Fargo Securities, LLC as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2010).
10.39
- First Amendment to Credit Agreement, dated as of December 9, Great Plains Energy 2011, among Kansas City Power & Light Company, Certain KCP&L Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Bank of America, N.A., as Administrative Agent, JPMorgan Chase Bank, N.A. and The Bank of Nova Scotia, as Documentation Agents, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Union Bank, N.A. and Wells Fargo Securities, LLC as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.61 to Form 10-K for the year ended December 31, 2011).
10.40
- Second Amendment to Credit Agreement, dated as of October 17, Great Plains Energy 2013, among Kansas City Power & Light Company, Certain , KCP&L Lenders, Bank of America, N.A., JPMorgan Chase Bank, N.A.,
and Union Bank, N.A., as Syndication Agents and Wells Fargo Bank, National Association, as Administrative Agent, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and Union B~, N.A.,
as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2013).
10.41
- First Extension Agreement and Waiver, dated as of December 17, Great Plains Energy 2014, among Kansas City Power & Light Company, Certain KCP&L Lenders, Bank of America, N.A., JPMorgan Chase Bank, N.A.,
and MUFG Union Bank, N.A., as Syndication Agents and Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and an Issuer, Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and MUFG Union Bank, N.A., as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.41 to Form 10-K for the year ended December 31, 2014).
137
10.42
- Credit Agreement, dated as of August 9, 2010, among KCP&L Great Plains Energy .
Greater Missouri Operations Company, Great Plains Energy
- Incorporated, as Guarantor, Certain Lenders, Bank of America, N.A., as Administrative Agent, and Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, The Royal Bank of Scotland PLC and BNP Paribas , as Documentation
.Agents, Banc of America Securities LLC, Union Bank, N.A. and Wells Fargo Secmities, LLC as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2010).
10.43
- First Amendment to Credit Agreement, dated as of December 9, ' Great Plains Energy
- 2011, among KCP&L Greater Missouri Operations Company, Great Plains Energy Incorporated, as Guarantor, Certain Lenders, Union Bank, N.A. and Wells Fargo Bank, National Association, as Syndication Agents, Bank of America, N.A., as Administrative
. Agent, The Royal Bank of Scotland PLC and BNP Paribas, as Documentation Agents, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Union Bank, N.A. and Wells Fargo Securities, LLC
- as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.63 to Form 10-K for the year ended December 31, 2011).
10.44
- Second Amendment to Credit Agreement, dated as of October 17, Great Plains Energy 2013, among KCP&L Greater Missouri Operations Company, Certain Lenders, Bank of America, N.A., JPMorgan Chase Bank, N.A., and Union Bank, N.A., as Syndication Agents and Wells Fargo Bank, National Association, as Administrative Agent, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner &
Smith Incorporated, J.P. Morgan Securities LLC, and Union Bank, N.A., as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2013).
10.45
- First Extension Agreement and Waiver; dated as of December 17, Great Plains Energy 2014, among KCP&L Greater Missouri Operations Company,
- Certain Lenders, Bank of America, N.A., JPMorgan Chase Bank, N.A., and MUFG Union Bank, N.A., as Syndication Agents and Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and an Issuer, Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and MUFG Union Bank, N.A., as Joint Lead Arrangers and Joint Book Managers (Exhibit 10.45 to Form 10-K for the year ended December 31, 2014).
10.46
- Guaranty, dated as of July 15, 2008, issued by Great Plains Energy Great Plains Energy Incorporated in favor of Union Bank of California, N.A., as successor trustee, and the holders of the Aquila, Inc., 8.27%
Senior Notes due November 15, 2021(Exhibit10.6 to Form 8-K filed on July 18, 2008).
10.47
- Insurance Agreement, dated as of September 1, 2005, between Great Plains Energy Kansas City Power & Light Company and XL Capital Assurance KCP&L Inc. (Exhibit 10.2.e to Form 10-K for the year ended December 31, 2005).
10.48
- Insurance AgreeJ,Tient, dated as of September 1, 2005, between Great Plains Energy Kansas City Power & Light Company and XL Capital Assurance KCP&L Inc. (Exhibit 10.2.fto Form 10-K for the year ended December 31, 2005).
138
10.49
- Purchase and Sale Agreement, dated as of July 1, 2005, between Great Plains Energy Kansas City Power & Light Company, as Originator, and Kansas KCP&L City Power & Light Receivables Company, as Buyer (Exhibit 10.2.b to Form 10-Q for the quarter ended June 30, 2005) .
. 10.50
- Receivables Sale Agreement, dated as of July 1, 2005, among Great Plains Energy Kansas City Power & Light Receivables Company, as the. Seller, KCP&L 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). '
10.51
- Amendment No. 1, dated as of April 2, 2007, among Kansas City Great Plains Energy Power & Light Receivables Company, Kansas City Power & KCP&L Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation to the*
Receivables Sale Agreement dated as of July 1, 2005 (Exhibit 10.2.2 to Form 10-Q for the quarter ended March 31, 2007).
10.52
- Amendment No. 2, dated as of July 11, 2008, among Kansas City Great Plains Energy Power & Light Receivables Company, Kansas City Power & KCP&L Light Company, The Bank ofTo.kyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation to the
- Receivables Sale Agreement dated as of July 1, 2005 (Exhibit.
10.2.2 to Form 10-Q for the quarter ended June 30, 2008).
10.53
- Amendment, dated as of July 9, 2009, to Receivables Sale
- Great Plains Energy Agreement *dated as of July 1, 2005 among Kansas City Power & KCP&L Light Receivables Company, Kansas* City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation (Exhibit 10.4 to Form 8-K filed on July 13, 2009).
10.54
- Amendment and Waiver, dated as of September 25, 2009, to the Great Plains Energy.
Receivables Sale Agreement dated as of July 1, 2005 among KCP&L .
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 (Exhibit 10.2.2 to Form 10-Q for the* quarter ended September 30, 2009).
10.55
- Amendment, dated as of May 5, 2010,' to Receivables Sale Great Plains Energy Agreement dated as of July 1, 2005 among Kansas City Power & KCP&L Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Lt!f., New York Branch and Victory Receivables Corporation (Exhibit 10.2.2 to Form 10-Q for the quarter ended March 31, 2010).
10.56
- Amendment, dated as of February 23, 2011, to Receivables Sale Great Plains Energy Agreement dated as of July 1, 2005 among Kansas City Power & KCP&L Light Receivables Company, Kansas City Power & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation. (Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2011).
139
10.57
- Amendment, dated as of September 9, 2011, to Receivables Sale Great Plains Energy Agreement dated as of July 1, *2005, among Kansas City Power& KCP&L Light Receivables Company, Kansas City Povyer & Light Company, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Victory Receivables Corporation (Exhibit 10.1 to Form.8-K filed on September 13, 2011).
10.58
- Amendment dated as of September 9, 2014, to the Receivables Great Plains Energy
- Sales Agreement dated as ofJuly 1, 2005, among Kansas City
- KCP&L 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, as the Purchaser (Exhibit 10.1 to Form 8-K filed on September 15, 2014).
10.59 * *Amendment dated as of September 9, 2015, to the Receivables Great Plains Energy Sales Agreement dated as of July 1, 2005, among Kansas City KCP&L 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, as the Purchaser (Exhibit 10.1 to Form 8-K filed on September 11, 2015).
10.60
- Amendment dated as of September 9, 2016, to the Receivables Great Plains Energy Sales Agreement dated as of July 1, 2005, among Kansas City KCP&L Power & Light Receivables Company, as the Seller, Kansas City Power & Light Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as the Agent and Victory Receivables Corporation, as the Purchaser (Exhibit 10.1 to Form 8-K filed on September 13, 20!6).
10.61
- Purchase and Sale Agreement, dated as of May 31, 2012, between Great Plains Energy KCP&L Greater Missouri Operations Company, as Originator, and GMO Receivables Company, as Buyer (Exhibit 10.2. to Form 10-Q for the quarter ended June 30, 2012).
10.62
- Receivables Sale Agreement, dated as of May 31, 2012, among Great Plains Energy .
GMO Receivables Company, as the Seller, KCP&L Greater Missouri Operations Company, as the Initial Collection Agent,*
The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent, and Victory Receivables Corporation (Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2012).
10.63
- First Amendment dated as of September 9, 2014, to the Great Plains Energy Receivables Sales Agreement dated as of May 31, 2012, among GMO Receivables Company, as the Seller, KCP&L Greater Missouri Operations Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent and'Victory Receivables Corporation, as the Purchaser.
(Exhibit 10.2 to Form 8-K filed on September 15, 2014).
10.64
- Second Amendment dated as of September 9, 2015, to the Great Plains Energy Receivables Sales Agreement dated as of May 31, 2012, among GMO Receivables Company, as the Seller, KCP&L Greater Missouri Operations Company, as the Initial Collection Agent, The Bank of Tokyo-Mitsubishi, Ltd., New York Branch, as the Agent and Victory Receivables Corporation, as the Purchaser.
. (Exhibit 10.2 to Form 8-K filed on September 11, 2015) ..
140
10.65
- Third Amendment dated as of September 9, 2016, to the Great Plains Energy Receivables Sales Agreement dated as. of May 31, 2012, among .
GMO Receivables Company, as the Seller, KCP$cL Greater Missouri Operations Company, as th~ Initial Colleetion Agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as the Agent and Victory Receivables Corporation, as the Purchaser (Exhibit 10.2 to Form 8-K filed September 13, 2016).
10.66
- Iatan Unit 2 and Common Facilities Ownership Agreement, dated Great Plains Energy as ofMay 19, 2006, among Kansas City Power & Light Company, KCP&L 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).
10.67
- Joint Motion and Settlement Agreement dated as of February 26, Great Plains Energy 2008, among Great Plains Energy Incorporated, Kansas City KCP&L Power & Light Company, the Kansas Corporation Commission Staff, the Citizens' Utility Ratepayers Board, Aquila, Inc. d/b/a Aquila Networks, Black Hills Corporation, and Black Hills/
Kansas Gas Utility Company, LLC (Exhibit 10.1.7 to Form 10-Q for the quarter ended March 31, 2008).
10.68 *
- Stipulation and Agreement dated April 24, 2009, among Kansas Great Plains Energy City Power & Light Company, Sti;iff of the. Missouri Public KCP&L Service Commission, Office of Public Counsel, P~axair, Inc.,
Midwest Energy Users Association, U.S. Department of Energy and the U.S. Nuclear Security Administration, Ford Motor
- Company, Missouri Industrial Energy Consumers and Missouri Department of Natural Resources (Exhibit 10.1 to Form 8-K filed April 30, 2009).
10.69
- Non-Unanimous Stipulation and Agreement dated May 22, 2009 Great Plains Energy among KCP&L Greater Missouri Operations Company, the Staff of the Missouri Public Service Commission, the Office of the Public Counsel, Missouri Depaliment of Natural Resources and Dogwood Energy, LLC (Exhibit 10.1 to Form 8-K filed on May 27, 2009).
10.70
- Collaboration Agreement dated as of March 19, 2007, among Great Plains Energy Kansas City Power & Light Company, Sierra Club and Concerned KCP&L Citizens of Platte County, Inc. (Exhibit 10.1 to Form 8-K filed on March 20, 2007).
10.71
- Amendment to the Collaboration Agreement ~ffective as of Great Plains Energy September 5, 2008 *among Kansas City Power & Light Company, KCP&L Sierra Club and Concerned Citizens of Platte <;::ounty, Inc. (Exhibit 10.2.20 to Form 10-K for the year ended December 31, 2009).
10.72
- Joint Operating Agreement between Kansas City Power & Light Great Plains Energy Company and Aquila, Inc., dated as of October 10, 2008 (Exhibit KCP&L 10.2.2 to Form 10-Q for the quarter ended September 30, 2008).
10.73
- Commitment letter, dated as of May 29, 2016, by Goldman Sachs Great Plains Energy Bank USA and Goldman Sachs Lending Partners LLC to Great Plains Energy Incorporated (Exhibit 10.1 to Form 8-K filed on ,:1' May 31, 2016).
141
10.74
- Stock Purchase Agreement, dated as of May 29, 2016, by and
- Great Plains Energy between OCM Credit Portfolio LP and Great Plains Energy Incorporated (Exhibit 10.2 to Form 8-K filed on May 31, 2016).
12.1 Computation of Ratios of Earnings to Fixed Charges and Earnings Great Plains Energy to Combined Fixed Charges and Preferred Dividend Requirements.
12.2 Computation of Ratio of Earnings to Fixed Charges. KCP&L 21.l List of Subsidiaries of Great Plains Energy Incorporated. Great Plains Energy 23.1 Consent of Independent Registered Public Accounting Firm. Great Plains Energy 23.2 Consent of Independent Registered Public Accounting Firm. ' KCP&L 24.1 Powers of Attorney. Great Plains Energy 24.2 Powers of Attorney. KCP&L 31.l Rule 13a-14(a)/15d-14(a) Certification of Terry Bassham. Great Plains Energy 31.2 Rule 13a-14(a)/15d-14(a) Certification of Kevin E. Bryant. Great Plains Energy 31.3 Rule 13a-14(a)/15d-14(a) Certification of Terry Bassham. KCP&L 31.4 Rule 13a-14(a)/15d-14(a) Certification of Kevin E. Bryant. KCP&L 32.1 ** Section 1350 Certifications. Great Plains Energy 32.2 :!<* Section 1350 Certifications. KCP&L 101.INS XBRL Instance Document. Great Plains Energy KCP&L 101.SCH XBRL Taxonomy Extension Schema Document. Great Plains Energy KCP&L 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document. Great Plains Energy KCP&L*
101.DEF XBRL Taxonomy Extension Definltion Linkbase Document. Great Plains Energy KCP&L 101.LAB XBRL Taxonomy Extension Labels Li~base Document. Great Plains Energy KCP&L 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document. Great Plains Energy KCP&L
- 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.
142
- Furnished and shall not be deemed filed for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act). Such document shall not be incori)orated by reference into any registration statement or other document pursuant to the Exchange Act or the Securities Act of 1933, as amended, unless otherwise indicated in such registration statement or other document.
+ Indicates management contract or compensatory plan or arrangement.
Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from KCP&L upon written request.
The registrants agree 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 such registrant and its subsidiaries on a consolidated basis.
143 L
Schedule I - Parent Company Financial Statements
- GREAT PLAINS ENERGY INCORPORATED Statements of Comprehensive Income of Parent Company Year Ended December 31 2016 2015 2014 Operating Expenses (millions, except per share amounts)*
General and administrative $ 2.7 $ 0.9 $ 1.1 Costs to achieve the acquisition of Westar Energy, Inc. 18.3 General taxes 0.1 '0.2 0.4 Total 21.1 1.1 1.5 Operating loss (21.1) (1.1) (1.5)
Equity in earnings from subsidiaries 287.5 220.9 251.1 Non-operating income 31.3 29.7 33.1 Interest (charges) income 2.6 (40.3) (44.3)
Income before income taxes 300.3 209.2 238.4 Income tax (expense) benefit (10.3) 3.8 4.4 Net income 290.0 213.0 242.8 Preferred stock dividend requirements and redemption premium 16.5 1.6 1.6 Earnings available for common shareholders $ 273.5 $ 211.4 $ 241.2 Average number of basic common shares outstanding 169.4 154.2 153.9 Average number of diluted common spares outstanding 169.8 154.8 154.1 Basic and diluted earnings per common share $ 1.61 $ 1.37 $ 1.57 Comprehensive Income Net income $ 290.0 $ 21:3.0 $ 242.8 Other comprehensive income Derivative hedging activity Reclassification to expenses 0.4 0.5 4.4 Income tax expense (0.2) (0.1) (1.7)
Net reclassification to expenses 0.2 0.4 2.7 Derivative hedging activity, net of tax 0.2 '0.4 2.7 Other comprehensive income from subsidiaries, net of tax 5.2 6.3 3.9 Total other comprehensive income 5.4 6.7 6.6 Comprehensive income '$ 295.4 $ 219.7 $ 249.4 The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.
144
GREAT PLAINS ENERGY INCORPORATED Balance Sheets of Parent Company December31 2016* 2015 ASSETS (millions, except share amounts)
Current Assets Cash and cash equivalents $ 1,283.9 $
Time deposit 1,000.0 Accounts receivable from subsidiaries 10.6 4.1 Notes receivable from subsidiaries 2.0 2.0 Money pool receivable 3.7 Derivative instruments 79.3 Other 26.1 0.4 Total 2,401.9 10.2 Investments and Other Assets Investment in KCP&L 2,541.5 2,433.1 Investment in other subsidiaries 1,341.6 1,385.9 Note receivable from subsidiaries 634.9 634.9 Deferred income taxes 12.8 34.8 Other 16.3 1.6 Total 4,547.1 4,490.3 T9tal $ 6,949.0 $ 4,500.5 LIABILITIES AND CAPITALIZATION Current Liabilities Notes payable $ $ 10.0 Current maturities of long-term debt 100.0 Accounts payable to subsidiaries 10.8 31.T Accrued taxes 12.9 4.5 Accrued interest 10.1 4.1 Other ,. 12.8 9.5 Total 146.6 59.8 Deferred Credits and Other Liabilities 2.2 7.1 Capitalization Great Plains Energy shareholders' equity Common stock - 600,000,000 and 250,000,000 shares authorized without par value 215,479,105 and 154,504,900 shares issued, stated value 4,217.0 2,646.7.
Cllinulative preferred stock - 390,000 shares authorized, $100 par value 0 and 390,000 shares issued and outstanding 39.0 -
Preference stock - 11,000,000 shares authorized without par value 7.00% Series B Mandatory Convertible Preferred Stock
$1,000 per share liquidation preference, 862,500 and 0 shares issued and outstanding 836.2 Retained earnings 1,119.2 1,024.4 Treasury stock - 128,087 and 101,229 shares, at cost (3.8) (2.6)
Accumulated other comprehensive loss (6.6) (12.0)
'Total shareholders' equity 6,162.0 3,695.5 Long-term debt 638.2 738.1 T.otal 6,800.2 4,433.6 Commitments and Contingencies Total $ 6,949.0 $ 4,500.5 The accompanying Notes to Financial Statements of Parent Company are an integral part of these statements.
145
GREAT PLAINS ENERGY INCORPORATED Statements of Cash Flows of Parent Company Year Ended December 31 2016 2015 2014 Cash Flows from Operating Activities (millions)
Net income $ 290.0 $ 213.0 $ 242.8 Adjustments to reconcile income to net cash from operating activities:.
Amortization 30.4 0.8 4.8 Deferred income. taxes, net 21.8 (1.7) (1.4)
Fair value impact of interest rate swaps (79.3)
Equity in earnings from subsidiaries (287.5) (220.9) (251.1) c.ash flows affected by changes in:
Accounts receivable from subsidiaries (9.8) (0.1) (3.8)
Taxes receivable 0.2 Accounts payable to subsidiaries (20.9) 1.3 (3.2)
Other accounts payable 7.0 Accrued taxes 8.4 0.3 4.3 Accrued interest 6.0 (0.1)
Cash dividends from subsidiaries 239.0 157.0 144.0 Uncertain tax positions (0.4) (2.9)
Other 8.4 8.7 11.8 Net cash from operating activities 213.1 158.4 145.4 Cash Flows from Investing Activities Purchase of time deposit (1,000.0)
Intercompany lending ' (1.4)
Net money pool lending 3.7 (0.4) 6.1 Investment in subsidiary (7.3) (7.8) (3.6)
Net cash from investing activities (1,003.6) (9.6) 2.5 Cash Flows from Financing Activities Issuance .of common stock 1,603.7 3.0 4.8 Issuance of preference stock 862.5 Issuance fees (143.4) (0.1)
Net change in short-term borrowings (10.0) 6.0 (5.0)
Dividends paid (194.0) (155.5) (145.6)
Redemption of cumulative preferred stock (40.1)
Purc~ase of treasury stock (5.0) (1.6) . (2.5)
Other financing activities 0.7 (0.7) 0.5 Net cash from financing activities 2,074.4 (148.8) (147.9)
Net Change in Cash and Cash Equivalents 1,283.9 Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year . $ 1,283.9 $ $
The accompanying-Notes to Financial Statements of Parent Company are an integral part of these statements.
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 c~~junction with the Great Plains Energy Incorporated Parent Company Financial Statements.
The Great Plains Energy Incorporated Parent Company Financial Statements have been prepared to present the financial position, results o(operations and cash flows of Great Plains Energy on a stand-alone basis as a holding company. . Investments in subsidiaries . are. accounted for using the equity method.
146
Schedule II - Valuation and Qualifying Accounts and Reserves Great Plains Energy Incorporated Valuation and Qualifying Accounts Years Ended December 31, 2016, 2015 and 2014 Additions Charged Balance At To Costs Charged Balance
- Beginning And To Other At End Description Of Period Expenses Accounts Deductions Of Period Year Ended Decembe.r 31, 2016 (millions)
Allowance for uncollectible accounts $ 3.8 $, 9.0 $ 8.1 (a) $ 16.9 (b)
$ 4.0 (c)
Legal reserves 5.9 10.4 0.2 16.1 Environmental reserves 1.7 1.7 (d)
Tax valuation allowance 19.9 0.1 3.6 16.4 Year Ended December 31, 2015 8.7 (b)
Allowance for uncollectible accounts $ 2.8 $ 10.5 $ (a) $, 18.2 $ 3.8 (c)
Legal reserves 4.7 2.6 1.4 5.9 Environmental reserves
- 1.7 1.7 (d)
Tax valuation allowance 16.6 4.9 1.6 19.9 Year Ended December 31, 2014
$
- 8.5 (b)
Allowance for uncollectible accounts $ 2.5 $ 11.4 (a) $ 19.6 $ 2.8 (c)
Legal reserves 4.6 2.7 2.6 4.7 Environmental. reserves 1.7 1.7 (d)
Tax valuation allowance 20.7 0.5 4.6 16.6
- (a) Recoveries. .
(b) Uncollectible accounts charged off.
(c) Payment of claims.
(d) Reversal of tax valuation allowance.
147
Kansas City Power & Light Company Valuation and Qualifying Accounts Years Ended December 31, 2016, 2015 alid.2~14 Additions Charged Balance At To Costs Charged Balance Beginning And To Other AtEnd Description Of Period Expenses Accounts Deductions Of Period Year Ended December 31, 2016 (millions) 5.5 (b)
Allowance for uncollectible accounts $ .1.8 $ 6A $ (a) $ 11.9 $ 1.8 (c)
Legal reserves 5.3 9.8 15J Environmental reserves 0.3 0.3 (d)
Tax valuation allowance 0.7 0.7 Year Ended December 31, 20 i 5 Allowance for uncollectible accounts $ 1.2 $ . 7.1' $ 5.8.
(a)
.$ 12.3 (b)
$ 1.8 (c)
Legal reserves 2.9 2.6 0.2 5.3 Environmental reserves 0.3 0.3 Tax valuation allowance 0.7 Year Ended December 31, 2014.
(a) (b)
Allowance for uncollectible accounts $ 1.1 . ,$.. 7.6 $ 5.5 $ 13.0 $ 1.2 (c)
Legal reserve~ 2.9 2.3 2.3 2.9 Environmental reserves 0.3 0.3 (a) Recoveries.
(b) Uncollectible accounts charged off.
.Cc) Payment of c~aims.
(d) Reversal of tax valuation allowance.
148
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the reg;istrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
GREAT PLAINS ENERGY INCORPORATED Date: February 23, 2017 By: Isl Terry Bassham Terry Bassham Chairman, 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 Isl Terry Bassham Chairman, President and Chief Executive Officer )
Terry Bassham (Principal Executive Officer) )
)
Senior Vice President - Finance and Strategy and Chief Isl Kevin E. Bryant Financial Officer )
Kevin E. Bryant (Principal Financial Officer) )
)
Isl Steven P. Busser Vice President - Risk Management and Controller )
Steven P. Busser (Principal Accounting Officer) )
)
David L. Bodde* Director )
)
Randall C. Ferguson, Jr.* Director )
) February 23, 2017 Gary D. Forsee* Director )
)
Scott D. Grimes* Director )
)
Thomas D. Hyde* Director )
)
James A. Mitchell* Director )
)
Ann D. Murtlow* Director )
)
Sandra J. Price* Director )
)
John J. Sherman* Director )
- By Isl Terry Bassham Terry Bassham Attorney-in-Fact*
149
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Se~urities 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 23, 2017 By: Isl Terry Bassham Terry Bassham
- Chairman, 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 Isl Terry Bassham Chairman, President and Chief Executive Officer )
Terry Bassham (Principal Executive Officer) )
)
Senior Vice President - Finance and Strategy and Chief Isl Kevin E. Bryant Financial Officer )
Kevin E. Bryant (Principal Financial Officer) )
)
Isl Steven P. Busser Vice President - Risk Management and Controller )
Steven P. Busser (Principal Accounting Officer) )
)
David L. Bodde* Director )
)
Randall C. Ferguson, Jr.* Director * )
) February 23, 2017 Gary D. Forsee* Director )
)
Scott D. Grimes* Director )
)
Thomas D. Hyde* l)irector )
)
James A. Mitchell* Director )
)
Ann D. Murtlow* Director )
)
Sandra J. Price*
- Director )
)
John J. Sherman* Director )
- By Isl Terry Bassham Terry Bassham Attorney-in-Fact*
150
This page intentionally left blank DIRECTORS AND OFFICERS B O ARD OF DI R ECTORS Great Plains Energy TER RY BASSHAM GARY D. FORSEE JAMES A. MITCHELL SANDRA J. PRICE Chairman of the Board, President and Chief Former President, University Executive Fellow Leadership, Center for Former Senior Vice President Human Executive Officer of Missoun System Ethical Business Cultures, a non-profit Resources, Sprint Corporation organization assisting business leaders 1n DR . DAVID L. BODDE SCOTT D. GRIMES creating ethical and profitable cultures JO H N J. SHERM AN Professor Emeritus, Chief Executive Officer and Founder, Vice Chairman, Cleveland Indians Baseball Clemson University Cardlytics. Inc an international technology ANN D. MURTLDW Club and Director of Crestwood Equity company President and Chief Executive Officer, GP LLC RANDALL C. FERGUSON , JR . Urnted Way of Central Indiana Former Senior Partner for Business THOMAS D. HYDE Development. Tsh1banda & Associate~ , LLC, Former Executive Vice President, Legat, a consulting and pro1ect management Compliance: Etti cs and Corporate Secretary, service~ firm Wal-Mart Stores. Inc OFFIC ERS Great Plains Energy TERRY BA SS HAM STEVEN P. BU SS ER ELLEN E. FAIRC HI LD LOR I A. WRIGHT Chairman of the Board, President and Chief Vice President Risk Management and Vice President, Chief Compliance Officer Vice President - Corporate Planning, Executive Officer Controller and Corporate Secretary Investor Relations and Treasurer KEVIN E. BRYANT CH AR LES A. CAIS LEY HEATHER A. HUM PHREY Senior Vice President Finance and Vice President Marketing Senior Vice President Corporate Services Strategy and Chief Financial Officer and Pubhc Affairs and General Counsel OFFICERS KCP&L TERRY BASSHAM CHARLES A. CAISLEY HEATHER A. HUMPHREY KEVIN T. NOBLET Chau rnan of the Board, President and Chief Vice President Marketing Senior Vice Pre* ident Corporate Serv1r.es Vice President Delivery Executive Officer and Public Affairs and General Counsel LOR I A. WRIGHT DUANE D. ANSTAETT ELLEN E. FAIRCHILD DARR IN R. tV ES Vice President Corporate Planning, Vice President Generation Vice President, Chief Compliance Officer Vice President Regulatory Affa1rs Investor Relat1llns and Treasurer and Corp Jrate Secretary KEVIN E. BRYANT MARIA R. JENKS Senior Vice President Finance and SC OTT H. HEIDTBR INK Vice President Supply Chain Strategy and Chief Financial Officer Executive Vice President and Chief Operating Officer CHAR LES L. KING STEVEN P. BU SSER Vice President and Chief Vr:e President Risk Management Information Officer and Controller SHAREHOLDER INFORMATION GREAT PLAINS ENERGY FORM 10 - K TWO -YEAR COMM O N STOCK HI S TORY Great Plains Energy's 2016 annual report on Form 10-K filed with the Securities and 2016 2015 Exchange Commission can be found at www greatpla1nsenergy.com. The 10-K is QUARTER HIGH LOW H IGH LOW available at no charge upon written request to, First $32.26 $26.34 $30.06 $25.80 Second 32.68 28.35 27.52 24.16 Corporate Secretary Third 31.22 26.53 27.35 24.21 Great Plains Energy Incorporated Fourth 28.60 26.20 28.02 25.74 PO. Box 418679 Kansas City, MO 64141-9679 ANNU A L MEETING O F SHARE HOLDERS Great Plains Energy's annual meeting of shareholders will be held at 10,00 a m.,
MA RK ET INFORMATI O N May 2, 2017, at Great Plains Energy, One Kansas City Place. 1200 Main Street, Great Plains Energy common stock 1s traded on the New York Stock Exchange under the Kan,;as City, MO 64105.
ti<:ker symbol 'GXP." We had 14,886 shareholders of record as of February 21. 2017.
REGISTERED SH A RE HO LDER IN Q UIRIES INTERNET SITE For account 1nformat1on or assistance, 1nclud1ng change of address. stock transfers.
We have a website at www.greatpla1nsenergy.com. Information available includes our d1v1dend payments, duplicate accounts or to report a lost certificate, please contact SEC filings, news releases, stock quotes, customer account information. community and Investor Relations at 800-245-5275.
environmental efforts and information of general interest to investors and customers.
FINA NCIAL COM MUN ITY INQ UIRI ES Also located on the website are our Code of Ethical Business Conduct, Corporate Secunt1es analysts and investment professionals seeking 1nformallon about Governance Guidelines and the charters of the Audit Committee. Governance Great Plains Energy may contact Investor Relations at 816-556-2312.
Committee and Compensation and Development Committee of the Board of Directors, which are available at no charge upon wntten request to the Corporate Secretary.
TRA N S F ER AGEN T AND STOC K REGI STR A NT Computershare Trust Company, N.A. Investor Services COMM ON STO CK DIVID END P. 0. Box 30170 QUARTER 201 6 2015 College Station, TX 77842-3170 First $0.2625 $0.245 TeL 866-239-8177 Second 0.2625 0.245 Third 0.2625 0.245 Fourth 0.2750 0.2625
ABOUT THE COMPANIES Headquartered in Kansas City, Mo., Great Plains Energy Incorporated (NYSE: GXP) is the holding company of Kansas City Power & Light Company (KCP&U and KCP&L Greater Missouri Operations Compa ny (GMO), two of the leading regulated providers of electricity in the Midwest. KCP&L and GMO use KCP&L as a brand name. More information about the compan ies is available on the internet at www.greatplainsenergy.com or www.kcpl.com.
NYSE:GXP
<JRfftT Plftlns*fnf R<JI -1
2016 ANNUAL REPORT KEPCo Kansas Electric Power Cooperative, Inc.
Contents Page Financial Statements Page Organization and Resources ... ... .... ........ .. ... .. .... 1 Balance Sheets .. ........... .. ... .... ... ............ ... .... 16-17 Leadership Message ... ......... ... .. ... ... .. ... .. ..... ..... 2-5 Statements of Margin ... ...... .. .. ......... .. .... ..... ....... 18 2016 Highlights .. .. .. .... ..... ... ... ..... ............. ... ... ... 6-8 Statements of Patronage Capital. .... .... .. ....... ....19 KEPCo Trustees and Managers ..... .... ...... ... .. 9-12 Statements of Cash Flows ... .. .. .. .... ...... ... ... ... ... .20 Operating Statistics ...... ........ ....... ...... ... .... .. ... ... . 13 Notes to Financial Statements .. ............ .... ... 21-40 Report of Independent Public Accountants .. 14-15 Mission & Vision Statement I Area Map ... .. .... .. .41 KEPCo Staff Marcus Harris .. .... .. .... .... Executive Vice President Robert Hammersmith ............. ..... ...... .Sr. SCADA/
& Chief Executive Officer Metering Technician Les Evans .... ...... ... .. ..... ... .... Senior Vice President Shari Koch ... .. .. .. ... ...... ... .. .. ... .Finance & Accounts
& Chief Operating Officer Payable/Payroll Specialist 2 Coleen Wells .... ... ..... ...... ... Senior Vice President Elizabeth Lesline ... ...... .. .Administrative Assistant/
& Chief Financial Officer Receptionist Stephanie Anderson .. ........... ........... .. ....... Finance Mitch Long ... ... ... ....... ..... .. ...... ........ .... Sr. SCADA/
& Benefits Analyst 2 Metering Technician Mark Barbee ..... .. ..Vice President of Engineering , Matt Ottman ..... .lnformation System Specialist 2 KSI Vice President of Engineering John Payne ........ ........ ... .... ....... ..Senior Engineer Chris Davidson .............. ......... .. ... .. .. .. ... Engineer 3 Rita Petty ..... .... .. ...... .. ... .. .. .... . Executive Assistant Terry Deutscher .... ..... .. ... ...... .... Manager, SCADA & Manager of Office Services
& Meter Maintenance Kelsey Schrempp .. ... ..... . Administrative Assistant Mark Doljac ...... .... .Director of Rates & Regulation & Benefits Specialist Carol Gardner ... ... ..... ..... ..... Operations Analyst 2 Paul Stone .... .... .. .... .... ... ... .. .... .... System Operator Shawn Geil. ......... Director of Information Systems Jill Taggart ... ... Director of Forecasting & Planning Maurice Hall ....... Sr. SCADA/Metering Technician Phil Wages ..... .... .... Director of Member Services, Government Affairs & Business Development
Organization and Resources Kansas Electric Power Cooperative, Inc. (KEPCo) , headquartered in Topeka , Kansas, was incorporated in 1975 as a not-for-profit generation and transmission cooperative (G& T) . It is KEPCo's responsibility to procure an adequate and reliable power supply for its nineteen distribution rural electric cooperative members at a reasonable cost.
Through their combined resources , KEPCo Members support a wide range of other services , such as rural economic development, marketing and diversification opportunities, power requirement and engineering studies , and rate design, among others.
KEPCo is governed by a Board of Trustees representing each of its nineteen Members which collectively serve more than 120,000 electric meters in two-thirds of Kansas . The KEPCo Board of Trustees meets regularly to establish policies and act on issues that often include recommendations from working committees of the Board and KEPCo staff. The Board also elects a seven-person Executive Committee which includes the President, Vice President, Secretary, Treasurer, and three additional Executive Committee members.
KEPCo was granted a limited certificate of convenience and authority by the Kansas Corporation Commission 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; 30 MW of owned generation from the Iatan 2 Generating Unit; the 20 MW Sharpe Generating Station located in Coffey County; Prairie Sky Solar, a one-megawatt solar facility in Butler County; hydropower purchases of an equivalent 100 MW from the Southwestern Power Administration ; and 13 MW from the Western Area Power Administration ; plus partial requirement power purchases from regional utilities.
KEPCo is a Touchstone Energy Cooperative. Touchstone Energy is a nationwide alliance of more than 750 cooperatives committed to promoting the core strengths of electric cooperatives -
integrity, accountability, innovation, personal service and a legacy of community commitment. The national program is anchored by the motto "The Power of Human Connections".
Kansas Electric Power Cooperative, Inc.
P.O. Box 4877 Topeka , KS 66604 600 SW Corporate View Topeka, KS 66615 (785) 273-7010 www.kepco.org A Touchstone Energy Cooperative ~T~
1
2016 Message from Kevin Compton KEPCo President Marcus Harris Executive Vice President
& Chief Executive Officer At KEPCo's November Board of Trustees meeting, Mr. Kevin Compton (right) was elected as KEPCo's 12th president. Mr. Compton is Vice-President of the Brown-Atchison Electric Cooperative Association , Inc.
Board of Trustees , located in Horton , KS .
As KEPCo completes its 42nd year of 2013 . KEPCo has also seen a flattening of operation , our focus remains the same as year demand . In 2011 , a record peak demand of 455 one - to provide superior service to our megawatts was set. Since 2013, KEPCo's peak members, while using our mission of providing demand has averaged 431 megawatts. The safe, reliable, and affordable energy as the decrease in demand is predominantly attributed compass to navigate through to four factors : several of challenging times. Each year "Since 2012, KEPCo 's average KEPCo's member many strategic decisions are wholesale rate has decreased by cooperatives have installed made , often centered around over 5% and has remained diesel-fired generators which regulatory, political , and relatively constant, averaging are called upon by KEPCo to energy resource issues. Each 75.6 mills since 2013." run during peak times; the decision is made purposefully, accumulative effect of several with the same end result in mind - for the years of energy efficiency measures , such as betterment of our nineteen-member rural the installation of high-efficiency HVAC systems electric cooperatives . by cooperative members, which is promoted by KEPCo's heat pump rebate program ; the An essential element of providing superior decrease in production within the oil and natural service to the rural communities of Kansas is gas industries; and the aggressive demand-side KEPCo 's ability to provide electricity at not only response program administered by KEPCo.
an economical price, but a stable price as well. This year, KEPCo was able to shed Since 2012 , KEPCo 's average wholesale rate approximately 35 megawatts of demand , saving has decreased by over 5% and has remained our members approximately $4 million.
relatively constant, averaging 75.6 mills since Reducing peak demand , while retaining energy 2
sales, reduces the wholesale price of power to KEPCo had a solid financial performance in KEPCo's member cooperatives. 2016 . KEPCo ended the year with total revenue of $160.2 million and a consolidated net margin Through careful and deliberate planning , of $1 .9 million. KEPCo's total assets, including KEPCo has crafted a power supply that is quite those of its subsidiary, KSI , were $291 million .
diverse, which enables KEPCo to shield its The solid financial performance allowed KEPCo member cooperatives from price fluctuations of to maintain key financial metrics within a particular generation fuel. This year, KEPCo acceptable levels and enabled KEPCo 's equity-further augmented its diverse power supply with to-asset ratio to reach 24.14%, which is a the addition of a one-megawatt solar facility, historic high for KEPCo . KEPCo members designed and engineered by KEPCo Services , received $1 .93 million in patronage capital and Inc. (KSI) , a KEPCo-owned subsidiary. The realized cost savings of $11 .5 million through facility was named Prairie Sky Solar, and is the Margin Stabilization Adjustment for 2016 .
anticipated to generate 1,980 Such notable financial megawatt hours of electricity "If carbon dioxide regulation performance is confirmation of the first year. KEPCo's remains a national point of KEPCo's comm itment of member cooperatives will emphasis, KEPCo's cost to keeping rates affordable and have the ability to offer, at the meet regulatory standards will consistent to its members, prerogative of the member be substantially lower relative to particularly during periods cooperative , subscribing the other utilities as a result of its when upward cost pressures generation from the facility in diverse power supply." have arisen .
100 kilowatt hour blocks to the membership of the cooperatives choosing to Uncertainty still exists regard ing carbon participate in the subscription program . The dioxide regulation . Th is has dissuaded utilities facility was financed with low-interest New from building new coal-fired power plants , in Clean Renewable Energy Bonds (NCREBs) large part due to the uncertainty of the through National Rural Utilities Cooperative technology to mitigate emissions and the uncertainty of a permit even being granted for the facility. Even if regulations are relaxed , as anticipated under the new administration , the likelihood of a comp rehensive and permanent rollback of em ission regulations is most unlikely.
Our industry is reliant upon prudent investments in long-lived assets and the industry places value on regulatory certainty, stability, From I to r: Mark Dolj ac, Director of Rates and Regu lation and predictability, and gradualism. As such , coal-Mark Barbee , Vice President of Engineering .
fired generation will likely continue to be Finance Corporation (CFC) . The addition of the supplanted by renewable energy and natural solar facility will enable KEPCo to reduce the gas-fired generation. For many utilities, the demand on traditional generation sources in the thought of a carbon-constrained industry is peak summer months, further reducing demand quite troublesome, due to the cost and costs to KEPCo's members. complexities of regulatory compliance .
However, KEPCo is in a more favorable 3
_j
position . With nearly 53% of our energy originating from resources producing zero greenhouse gasses, KEPCo 's exposure to generation sources impacted by current and future greenhouse gas emission regulations is far less than utilities with a large exposure to fossil fuels . If carbon dioxide regulation remains a national point of emphasis, KEPCo 's cost to meet regulatory standards will be substantially lower relative to other utilities as a result of its diverse power supply.
KEPCo's owned generation assets performed exceptionally well this year. Wolf Creek completed refueling outage 21 this past fall and performed several maintenance procedures during the outage, including one that has never been done before in the United States. Wolf Creek is the first nuclear power plant in the country to use water jet peening , a mechanical process developed in Japan by Mitsubishi Nuclear Energy Services , that works a metal Water jet peening of the Wolf Creek reactor vessel.
surface to improve its resistance to cracking on coal plants in the U.S.
its reactor vessel nozzle welds. In the U.S.,
three plants have had reactor vessel nozzle In May of 2016 , Great Plains Energy (GPE) ,
cracks in the past 15 years and two have had parent company of Kansas City Power & Light, bottom-mounted nozzle cracks. This process is announced its agreement to purchase Westar expected to mitigate the risk of stress corrosion Energy in a transaction valued at over $12 cracking for the remaining life of the plant. billion . The proposed acquisition includes a significant merger premium to be paid by Great Plains and a significant amount of debt to be added to the liabilities of the consolidated company, if the transaction is ultimately approved by regulators . KEPCo has multi-faceted relationships with both GPE and Westar, including generation plant ownership, transmission dependency, and power supply arrangements. KEPCo staff worked throughout the year to protect KEPCo and its members Iatan 2 from potential adverse impacts of this Iatan 2, owned in part by KEPCo, is a coal- transaction on our members. KEPCo played a fired facility in Weston , Missouri, which major role in the regulatory processes at the provided KEPCo's Members with approximately Federal Energy Regulatory Commission eight percent of their energy requirements for (FERC) and the Kansas Corporation 2016 and continues to be one of the most Commission (KCC) . The final decisions from efficient and lowest greenhouse gas emitting 4
the KCC and the FERC are expected in the utility. Each year, the Board of Trustees and spring of 2017 . KEPCo staff demonstrate the expertise and resolve necessary to provide an economical ,
The KEPCo Board of Trustees deserves a reliable , and safe supply of energy for our special thank you for their hard work and members. It's what we have done for the past leadership this year. It has also been a four decades and it's our commitment and challenging year for KEPCo staff, who have privilege to do the same for decades to come.
done a remarkable job meeting the special demands of 2016 while fulfilling the responsibil ities necessary to operate an electric
~t> - ~
Marcus Harris Kevin D. Compton KEPCo EVP & CEO KEPCo President
& a i I I KEPCo staff 5
2*016 KEPCo Highlights KEPCo's Board of Trustees unanimously approved KEPCo's addition of a one-megawatt solar farm to its already diverse resource mix. The solar farm was aptly named Prairie Sky Solar and is located in Andover, Kansas. KEPCo Services, Inc.
(KSI) designed and engineered the facility and KEPCo will operate and maintain the facility as well. The facility was put into service on February 22 , 2017 .
Prairie Sky Solar, a one-megawatt solar facility located in Butler County.
In August, KEPCo filed a Lien Accommodation with Rural Utilities Service to secure New Clean Renewable Energy Bonds (NCREBs) financing through CFC. The NCREBs financing will enable KEPCo to finance the Prairie Sky Solar project at a net effective interest rate of approximately one percent interest per year for 25 years.
Energy and Environmental Economics, Inc.
(E3) was retained by KEPCo to provide external perspectives in the development of a strategic plan . At KEPCo's July Board of Trustees meeting, Kush Patel , Senior Managing Consultant at E3 , facilitated a discussion with the KEPCo Board of Trustees and KEPCo senior staff that was used as the basis to create a strategic plan for KEPCo to meet its future goals of providing a power supply to its members in a reliable , low-cost, and low-risk manner, while beginning to migrate toward a business Mr. Kush Patel , E3, discusses the KEPCo Strategic Plan with Scott Whittington , Lyon-Coffey , and Marcus Harris, KEPCo EVP & CEO .
model recognizing and capitalizing on trends that are changing the utility industry.
KEPCo staff, completed Load Forecasts for Rolling Hills, Twin Valley, LJEC, Bluestem, Caney Valley, and Sedgwick County. Power Cost Projections were also completed for Radiant, LJEC, DS&O, Bluestem, Heartland, Rolling Hills, Sedgwick, and Caney Valley.
6
KEPCo Services , Inc. completed 44 engineering projects in 2016.
One project of particular note was the Saddlehorn Substation project. KSI provided engineering and project management for the Ninnescah Rural Electric Cooperative Saddlehorn Substation. The new 115 kV to 4 .16 kV, 7.5 MVA substation will serve a pump
- Ks I station on the 550 mile Saddlehorn Pipeline from Platteville ,
Colorado to Cushing , Oklahoma . The pipeline is a joint venture En g ine18 ring between Magellan Midstream Partners LP , along with Plains All-American Pipeline and Anadarko Petroleum Corp. The substation was put into service on schedule and under budget in early September 2EM 6.
The Wolf Creek Nuclear Operating Company successfully completed refueling outage 21 in the fall and the Wolf Creek Nuclear Generating Station has run continuously since the refueling. In December, the plant set an all-time production record of 912, 600 megawatt hours. Wolf Creek has made great strides with regulatory and operational performance in recent years.
Wolf Cree k Nuclear Generating Station KEPCo staff participated in the annual Southwest Power Pool (SPP) legislative conference. The conference was a three-day visit to Washington, D.C. to discuss issues with several members of Congress and industry lobbyists, such as federal energy legislation , as well as an update from three of the plaintiff attorneys in the Clean Power Plan lawsuit.
KEPCo Staff also continued to work diligently with the KEC and Sunflower on legislative issues in Kansas and Washington, D.C. Staff testified From I to r: Wayne Penrod and Clare Gustin , Sunflower; Mike on several bills in 2016 and tracked numerous Morley, Midwest; and Phil Wages , KEPCo , at the SPP pieces of legislation . Conference in Washington , D.C.
7
USDA KEPCo continues to work with its Member cooperatives in an aggressive rural development program that has successfully created rural jobs and wealth retention in Rural Kansas. The USDA Rural Economic Development Loan &
Development Grant (REDLG) program provides zero interest loans to worthy projects.
ommill d to th fu1ur of ru r I ommlJniti .
In August, KEPCo submitted to the Western Area Power Administration (WAPA) an Integrated Resource Plan (/RP) . Every five years, KEPCo is required to submit an /RP to WAPA. The /RP includes extensive data, such as; identifying and comparing all practicable energy efficiency and energy supply resources; an action plan with timing established by KEPCo; a description of efforts to minimize adverse environmental efforts of new resource acquisitions; public participation to comment on the /RP; conducting a load forecast; and a measurement strategy for options identified in the /RP to determine whether objectives are being met.
KEPCo's Marcus Harris, Bill Riggins , and Phil Wages, along with a contingent of another 17 Kansas electric cooperative representatives, attended the NRECA Legislative Conference in Washington, D.C. The Kansas contingent, along with 1,500 electric cooperative representatives from across the country conveyed industry issues to their respective congressional leaders.
Kansas electric cooperative representatives at the NRECA Legislative Conference in Washington , D.C.
Safety of our employees is essential to the continued operational success of KEPCo. Appropriate safety meetings are held throughout the year for KEPCo staff. KEPCo is proud to report there were no lost time accidents recorded in 2016.
8
KEPCo Member Cooperatives Trustees, Alternates and Managers Ark Valley Electric Cooperative Assn. , Inc.
PO Box 1246, Hutchinson, KS 67504 620-662-6661 Trustee Rep . -- Joseph Seiwert Alternate Trustee -- Jackie Holmberg Manager -- Jackie Holmberg Joseph Seiwert Jackie Holmberg Bluestem Electric Cooperative, Inc.
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 -- Robert Ohlde Manager -- Kenneth J. Maginley Ken Maginley Bob Ohlde Brown-Atchison Electric Cooperative , Assn. , Inc.
PO Box 230, Horton , KS 66439 785-486-2117 Trustee Rep . -- Kevin Compton Alternate Trustee -- James Currie Manager -- James Currie Kevin Compton Jim Currie Butler Electric Cooperative Assn ., Inc.
PO Box 1242, El Dorado , KS 67402 316-321 -9600 Trustee Rep . -- Dale Short Alternate Trustee -- Riley Walters Manager -- Dale Short Dale Short Riley Walters Caney Valley Electric Cooperative Assn ., Inc.
PO Box 308 , Cedar Vale , KS 67204 620-758-2262 Trustee Rep . -- Dwane Kessinger Alternate Trustee -- Allen A. Zadorozny Manager -- Allen A. Zadorozny Dwane Kessinger Allen Zadorozny 9
CMS Electric Cooperative , Inc.
PO Box 790, Meade, KS 67864 620-873-2184 Trustee Rep. -- Kirk A. Thompson Alternate Trustee -- Clifford Friesen Manager -- Kirk A. Thompson Kirk Thompson Cliff Friesen
(~ DS&O Electric Cooperative, Inc.
PO Box 286 , Solomon , KS 67480 785-655-2011 Trustee Rep. -- Dean Allison
- J..
Alternate Trustee -- Tim Power I -- . Manager -- Tim Power Tim Power Flint Hills Electric Cooperative Assn ., Inc.
PO Box B, Council Grove, KS 66846 620-767-5144 Trustee Rep. -- Robert E. Reece Alternate Trustee -- Terry Olsen Manager -- Robert E. Reece Bob Reece Terry Olsen Heartland Rural Electric Cooperative, Inc.
PO Box 40 , Girard , KS 66743 620-724-8251 Trustee Rep. -- Dennis Peckman Alternate Trustee -- Dale Coomes Manager -- Dale Coomes Dennis Peckman Dale Coomes LJEC PO Box 70, Mclouth , KS 66054 913-796-6111 Trustee Rep . -- Steven 0 . Foss Alternate Trustee -- Harlan Hunt Manager -- Steven 0. Foss Steven Foss Harlan Hunt Lyon-Coffey Electric Cooperative , Inc.
PO Box 229, Burlington, KS 66839 620-364-2116 Trustee Rep. -- Scott Whittington Alternate Trustee -- Robert Converse Manager -- Scott Whittington Scott Whittington Robert Converse 10
KEPCo Member Cooperatives Trustees, Alternates and Managers Ninnescah Electric Cooperative Assn ., Inc.
PO Box 967, Pratt, KS 67124 620-672-5538 Trustee Rep. -- Paul Unruh Alternate Trustee -- Teresa Miller Manager -- Teresa Miller Paul Unruh Teresa Miller Prairie Land Electric Cooperative, Inc.
PO Box 360, Norton , KS 67654 785-877-3323 District Office , Bird City 785-734-2311 District Office , Concordia 785-243-1750 Trustee Rep. -- Bill Peterson Alternate Trustee -- Allan J. Miller Bill Peterson Manager -- Allan J. Miller Allan Miller Radiant Electric Cooperative , Inc.
PO Box 390, Fredonia , KS 66736 620-378-2161 Trustee Rep. -- Dennis Duft Alternate Trustee -- Tom Ayers Administrative Manager -- Leah Tindle Operations Manager -- Dennis Duft Denn is Duft Tom Ayers Leah Tindle Rolling Hills Electric Cooperative, Inc.
PO Box 339 , Beloit, KS 67420 785-534-1601 Trustee Rep . -- Douglas J. Jackson Alternate Trustee -- Leon Eck Manager -- Douglas J. Jackson Doug Jackson Leon Eck Sedgwick County Electric Cooperative Assn ., Inc.
PO Box 220, Cheney, Ks 67025 316-542-3131 Trustee Rep . -- Donald Metzen Alternate Trustee -- David Childers Manager -- David Childers Donald Metzen Dave Childers 11
Sumner-Cowley Electric Cooperative , Inc.
PO Box 220, Wellington , KS 67152 620-326-3356 Trustee Rep. -- John Schon Alternate Trustee -- Cletas Rains Manager -- Cletas Rains John Schon Cletas Rains Twin Valley Electric Cooperative, Inc.
PO Box 368 , Altamont, KS 67330 620-784-5500 Trustee Rep. -- Bryan Coover Alternate Trustee -- Ron Holsteen Manager -- Ron Holsteen Bryan Coover Ron Holsteen Victory Electric Cooperative Assn ., Inc.
PO Box 1335, Dodge City, KS 67801 620-227-2139 Trustee Rep. -- Shane Laws Alternate Trustee -- Daryl Tieben Manager -- Shane Laws Shane Laws Daryl Tieben 2016 - 2017 KEPCo Executive Committee Back row, left to right: Kevin Compton - President; Dale Short - Vice President; Doug Jackson - Secretary; Dean Allison -
Treasurer. Front row, left to right: Steve Foss - Executive Committee ; Kirk Thompson - Executive Committee ; Scott Wh ittington -
Executive Committee.
12
Operating Statistics 2,300,000 Energy Sales
~
- s 0
- c Operating Expenses
~ 1,800,000 KEPCo O&M Nuclear Fuel andA&G 2.1%
"'en Q) 4.5%
Iatan 2 Fuel 1.5%
- !E lnteres 5.5% Iatan 20&M andA&G 1.5%
Oepr. and Amo rt.
1,300,000 7.6%
2012 2013 2014 2015 2016 Purchased Power Year Wolf Creek O&M 66.5%
andA&G 500 10.8%
Peak Demand 450 I/)
CV
~ 400 Cl Cl>
Sources of Energy 350 WAPA Iatan 2 300 7 .6%
2012 2013 2014 2015 2016 Year Westar Energy 85.0 35%
Rates Sunflower 16.7%
~65.0
.!!J.
45.0 2012 2013 2014 2015 2016 Year 13
INDEPENDENT AUDITORS' REPORT To the Board of Directors Kansas Electric Power Cooperative, Inc.
Topeka, Kansas We have audited the accompanying consolidated financial statements of Kansas Electric Power Cooperative, Inc. and subsidiary (" KEPCo" ), which comprise the consolidated balance sheets as of December 31, 2016 and 2015, and the related consolidated statements of margin, patronage capital, and cash flows for the years then ended and the related notes to the financial statements.
Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors' Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America and Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control.
Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our qualified audit opinion .
Basis for Qualified Opinion As more fully described in Note 3 to the financial statements, certain depreciation and amortization methods have been used in the preparation of the 2016 and 2015 consolidated 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 consolidated financial statements of the aforementioned departure are explained in Note 3.
Qualified Opinion In our opinion, except for the effects of using the aforementioned depreciation and amortization methods as discussed in Note 3, the consolidated financial statements referred to in the first paragraph present fairly, in all material respects, the financial position of KEPCo as of December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America .
14
Changes in Accounting Principle As described in Note 1 to the financial statements, the Company adopted the provisions of Accounting Standards Updates 2016-01 and 2015-07 in 2016. Our opinion is not modified with respect to these matters.
Other Reporting Required by Government Auditing Standards In accordance with Government Auditing Standards, we also have issued our report dated April 13, 2017, 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 Government Auditing Standards in considering KEPCo's internal control over financial reporting and compliance.
Mayer Hoffman Mccann P.C.
Topeka, Kansas April 13, 2017 15
Consolidated Balance Sheets Assets December 31, 2016 2015 Utility Plant In-service $ 358,299,394 $ 352,889,719 Less allowances for depreciation (162,033, 119) (155,634,830)
Net in-service 196,266,275 197 ,254,889 Construction work in progress 13,587,572 9,970,255 Nuclear fuel (less accumulated amortization of
$21, 184,282 and $23,765,663 for 2016 and 2015, respectively) 7,671,517 8,459,672 Total utility plant 217,525,364 215,684,816 Restricted Assets Investments in the National Utilities Cooperative Finance Corporation 11,552,345 11, 108,619 Decommissioning fund 21,662,907 19,996, 196 Investments in other associated organizations 306,626 282, 188 Total restricted assets 33,521,878 31,387,003 Current Assets Cash and cash equivalents 13,097,952 6,307,421 Member account receivables 13,584,071 11,993,431 Materials and supplies inventory 6,587,450 6,645,359 Other assets and prepaid expenses 699,538 705,652 Total current assets 33,969,011 25,651,863 Other Long-term Assets Deferred charges Wolf Creek disallowed costs (less accumulated amortization of $18,692,371 and $17,935,208 for 2016 and 2015, respectively) 7,290,549 8,047,713 Wolf Creek deferred plants costs (less accumu-lated amortization of $46,948,793 and
$43,818,873 for 2016 and 2015, respectively) 3, 129,920 Wolf Creek decommissioning regulatory asset (7,017,075) (6,624,525)
Deferred incremental outage costs 2,421,944 1,968, 169 Other deferred charges (less accumulated amor-tization of $9, 782,828 and $9,681,046 for 2016 and 2015, respectively) 6,664 359, 142 Unamortized debt issuance costs 8,322 23,713 Other 311,016 270,943 Prepaid Southwest Power Pool 2,320,364 Prepaid pension cost 810,468 941,896 Total long-term assets 6,152,252 8, 116,971 Total assets $ 291,168,505 $ 280,840,653 See Notes to the Consolidated Financial Statements 16
Consolidated Balance Sheets Patronage Capital and Liabilities December 31, 2016 2015 Patronage Capital Memberships $ 3,200 $ 3,200 Patronage capital 78,731,784 76,798,889 Accumulated other comprehensive loss (8,440,302) (7,284,730)
Total patronage capital 70,294,682 69,517,359 Long-term Debt 151,532,880 147,216,732 Other Long-term Liabilities Wolf Creek decommissioning liability 19,418,417 18,314,245 Wolf Creek pension and postretirement benefit plans 12,469,376 11,824,521 Wolf Creek deferred compensation 1,319,029 1,249,381 Other deferred credits 9,250 Total other long-term liabilities 33,216,072 31,388,147 Current Liabilities Current maturities of long-term debt 11, 129,805 11,456,396 Accounts payable *14,393,732 13,053,258 Payroll and payroll-related liabilities 233,212 241,353 Deferred revenue 8,704,942 6,104,206 Accrued property taxes 1, 157,946 1,312,387 Accrued income taxes 479 (45)
Accrued interest payable 504,755 550,860 Total current liabilities 36,124,871 32,718,415 Total patronage capital and liabilities $ 291, 168,505 $ 280,840,653 See Notes to the Consolidated Financial Statements 17
Consolidated Statements of Margin For the years ending December 31, 2016 2015 Operating Revenues Sale of electric energy $ 160,274,808 $ 161, 763,501 Operating Expenses Power purchased 106, 192,839 105,484,032 Nuclear fuel 3,303,026 3,368,666 Plant operations 15,719,345 17,340,438 Plant maintenance 5,830,421 5,406,848 Administrative and general 7,050,359 6,205,902 Amortization of deferred charges 3,988,865 4,053,051 Depreciation and decommissioning 8,686, 169 8.480,727 Total operating expenses 150,771,024 150,339,664 Net operating revenues 9,503,784 11,423,837 Interest and Other Deductions Interest on long-term debt 8,558,224 9,090, 142 Amortization of debt issuance costs 15,391 56,343 Other deductions 139.195 150,753 Total interest and other deductions 8.712.810 9.297.238 Operating income 790 974 2. 126.599 Other lncome/(Expense)
Interest income 860,660 667,857 Other income 285,944 488,538 Income tax (4.683) (1.854)
Total other income 1. 141.921 1 154 541 Net margin $ 1,932,895 $ 3,281,140 Net Margin $ 1,932,895 $ 3,281, 140 Other comprehensive (loss)/income Net (loss)/earnings arising during year on pen-sion obligation (1, 716,993) 329,818 Amortization of prior year service costs included in net periodic pension costs 561 421 764 678 Comprehensive income $ 777,323 $ 4,375,636 See Notes to the Consolidated Financial Statements 18
Consolidated Statements of Patronage Capital Accumulated Other Patronage Comprehensive Memberships Capital Income (Loss) Total Balance at December 31, 2014 $ 3,200 $ 73,517,749 $ (8,379,226) $ 65,141,723 Net margin 3,281, 140 3,281,140 Defined benefit pension plans:
Net earnings arising during year 329,818 329,818 Amortization of prior year service costs included in net periodic pension costs 764,678 764,678 Balance at December 31, 2015 3,200 76,798,889 (7 ,284, 730) 69,517,359 Net margin 1,932,895 1,932,895 Defined benefit pension plans:
Net loss arising during year (1,716,993) (1, 716,993)
Amortization of prior year service costs included in net periodic pension costs 561,421 561,421 Balance at December 31, 2016 $ 3,200 $ 78,731,784 $ ~8,440,302~ $ 70,294,682 See Notes to the Consolidated Financial Statements 19
Consolidated Statements of Cash Flows For the years ending December 31, 2016 2015 Cash Flows From Operating Activities Net margin $ 1,932,895 $ 3,281,140 Adjustments to reconcile net margin to net cash flows from operating activities Depreciation and amortization 8,173,568 7,976,377 Decommissioning 1,496,722 4,400,516 Amortization of nuclear fuel 3,294,777 3,330,466 Amortization of deferred charges 3,898,956 3,901,324 Amortization or deferred incremental outage costs 2,373,725 2,387,697 Amortization of debt issuance costs 15,391 56,342 Changes in Member accounts receivable (1,590,640) 2,048,341 Materials and supplies 57,909 (253,460)
Other assets and prepaid expense (3,509,895) 1,064,675 Accounts payable 1,340,474 (1, 146,640)
Payroll and payroll-related liabilities (8,141) (16,170)
Accrued property tax (154,440) (59,425)
Accrued interest payable (46,105) (38,864)
Accrued income taxes 525 (3,564)
Other long-term liabilities 723,753 (244,940)
Prepaid pension cost 131,427 131,428 Deferred revenue 2,600,736 2,778,884 Net cash flows from operating activities 20,731,637 29,594,127 Cash Flows From Investing Activities Additions to electrical plant (10,825,350) (13,317,627)
Additions to nuclear fuel (2,506,622) (1,980,468)
Reductions in deferred charges 340,606 17,720 Additions to deferred incremental outage costs (2,827,500) (3,170,364)
Investments in decommissioning fund assets (1,666,711) (617,917)
Proceeds from associated organizations (468, 165) 615,915 Investments in bond reserve assets 4,490,786 Proceeds from the sale of property 23,079 39,350 Net cash flows from investing activities (17,930,663) (13,922,605)
Cash Flows From Financing Activities Principal payments on long-term debt (11,457,281) (15,700,763)
Proceeds from issuance of long-term debt 21,229,828 9,887, 110 Short term notes payable (1,429,000)
Payments unapplied (5,782,990) (3,324,091}
Net cash flows from financing activities 3,989,557 (10,566,744}
Net increase in cash and cash equivalents 6,790,531 5,104,778 Cash and Cash Equivalents, Beginning of Year 6,307,421 1,202,643 Cash and Cash Equivalents, End of Year . $ 13,097,952 $ 6,307,421 Supplemental Disclosure of Cash Flow Information Interest paid $ 8,743,500 $ 9,279,800 See Notes to the Consolidated Financial Statements 20
Notes to Consolidated Financial Statements (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 tax-exempt generation and transmission cooperative (G&T). KEPCo was granted a limited certificate of convenience and authority by the Kansas Corporation Commission (KCC) 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 approximately 120,000 electric meters in rural Kansas.
Recent Accounting Pronouncements - In January 2016, the Financial Accounting Standards Board (FASS) published Accounting Standards Update (ASU) No. 2016-01, which, among other things, changes the presentation and disclosure requirements for non-public entities related to fair value disclosures required for financial instruments not recognized at fair value. Previous GAAP required the disclosure of the fair value of debt if a non-public entity had in excess of $100 million of assets. Under the new standard, non-public entities, regardless of size, no longer need to disclose the fair value of debt. The standard is not fully effective until periods beginning after December 15, 2018; however, early adoption of this specific change is permitted. Management has decided to early adopt this provision, and will, therefore no longer disclose the fair value of financial instruments that are not reported at fair value.
In May 2015, the Financial Accounting Standards Board ("FASS") issued Accounting Standards Update
("ASU") 2015-07, "Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)." The ASU removes the requirement to categorize within the fair value hierarchy investments for which fair values are estimated using the net asset value per share as a practical expedient provided by FASS Accounting Standards Codification ("ASC") 820 Fair Value Measurement. Disclosures about investments in certain entities that calculate net asset value per share are limited under this ASU to investments for which the entity has elected to estimate the fair value using the net asset value practical expedient. The guidance requires retrospective application and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016.
Early adoption is permitted. Management elected to early adopt the provisions of this new standard.
The adoption has been reflected in Note 9 to the financial statements.
System of Accounts - KEPCo maintains its accounting records substantially in accordance with the Rural Utilities Service (RUS) Uniform Systems of Accounts and in accordance with accounting practices prescribed by the KCC.
Rates - Under a 2009 change in Kansas state law, KEPCo has elected to be exempt from KCC regulation for most purposes, including the setting of rates. Rates are set by action of the Board, subject only to statutory review by the KCC if demanded by four or more members. KEPCo's rates were last set by the KCC by an order effective September 1, 2008. KEPCo's rates now include an Energy Cost Adjustment (ECA) mechanism, an annual Demand Cost Adjustment (DCA) mechanism and a Margin Stabilization Adjustment (MSA) mechanism, allowing KEPCo to pass along increases in certain energy and demand costs to its member cooperatives.
Principles of Consolidation - The consolidated financial statements include the accounts of KEPCo and its wholly 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.
21
Notes to Consolidated Financial Statements Iatan 2 - Iatan 2 is an 850 MW high efficiency coal-fired power plant utilizing state-of-the-art environmental controls that became commercially operational December 31, 2010. KEPCo owns a 3.53% share of Iatan 2, or 30 MW. Iatan 2, located in Weston, MO, is operated and majority owned by KCP&L. KEPCo's undivided interest in Iatan 2 is consolidated on a pro rata basis. KEPCo is entitled to a proportionate share of the capacity and energy from Iatan 2, which is used to supplement a portion of KEPCo's members' requirements. KEPCo is billed on a daily basis for 3.53% of the operations, maintenance, administrative and general costs, and cost of plant additions related to Iatan 2.
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 & 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. KEPCo's undivided interest in WCNOC is consolidated on a pro rata basis. KEPCo is entitled to a proportionate share of the capacity and energy from WCNOC, which is used to supplement a portion of KEPCo's members' requirements. KEPCo is billed on a daily basis for 6% of the operations, maintenance, administrative and general costs, and cost of plant additions related to WCNOC.
WCNOC's operating license expires in 2045. Wolf Creek is regulated by the nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety related requirements.
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 three years under current regulations.
Estimates - The preparation of consolidated financial statements in conformity with accounting principles generally accepted 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 reporting period. Actual results could differ from those estimates.
Management's estimates and assumptions include, but are not limited to, estimates of salvage values, estimated useful lives of fixed assets, estimated asset retirement obligations, incremental outage costs and pension and postretirement liability costs. Management's estimates and assumptions are derived 1 from and are continually evaluated based upon available information, judgment and experience.
Utility Plant and Depreciation - Utility plant is stated at cost. Cost and additions to utility plant include contractual work, direct labor, materials and interest on funds used during construction. No interest has been capitalized in 2016 and 2015. The cost of repairs and minor replacements are charged to operating expenses as appropriate. The original cost of utility plant retired and the cost of removal less salvage are charged to accumulated depreciation.
The composite depreciation rates for electric generation plant for the years ended December 31, 2016 and 2015 are 3.79% and 3.76%, respectively.
The provision for depreciation computed on a straight-line basis for electric and other components of utility plant is as follows:
Transportation and equipment 25-33 years Office furniture and fixtures 10-20 years Leasehold improvements 20 years Transmission equipment (metering, communication and SCADA) 10 years Nuclear Fuel - The cost of nuclear fuel in the process of refinement, conversion, enrichment and fabrication is recorded as a 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.
22
Notes to Consolidated Financial Statements Nuclear Decommissioning - Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC will terminate a plant's license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.
The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the revised nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval of a funding schedule prepared by the owner of the plant detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.
In 2014, the nuclear decommissioning study was revised. Based on the study, KEPCo's share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be
$45.9 million. This amount compares to the prior site study estimate of $37.8 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials, and equipment.
KEPCo is allowed to recover nuclear decommissioning costs in its prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. KEPCo believes that the KCC approved funding level will also be sufficient to meet the NRG requirement. The consolidated financial results would be materially affected if KEPCo was not allowed to recover in its prices the full amount of the funding requirement.
KEPCo recovered in its prices and deposited in an external trust fund for nuclear decommissioning approximately $0.5 million in 2016 and $0.5 million in 2015. KEPCo records its investment in the NOT fund at fair value, which approximated $21.7 million and $20.0 million as of December 31, 2016 and 2015, respectively.
Asset retirement obligation - KEPCo recognizes and estimates the legal obligation associated with the cost to decommission Wolf Creek. KEPCo initially recognized an asset retirement obligation at fair value for the estimated cost with a corresponding amount capitalized as part of the cost of the related long-lived asset and depreciated over the useful life.
A reconciliation of the asset retirement obligation for the years ended December 31, 2016 and 2015 is as follows:
2016 2015 Balance at January 1 $ 18,314,245 $ 13,320,625 2014 decommission study 3,952,587 Accretion 1, 104, 172 1,041,033 Balance at December 31 $ 19,418,417 $ 18,314,245 Any net margin effects are deferred in the Wolf Creek decommissioning regulatory asset and will be collected from members' in future electric rates.
23
Notes to Consolidated Financial Statements 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 consisted primarily of repurchase agreements, money market accounts and certificates of deposit.
The Federal Deposit Insurance Corporation insures amounts held by each institution in the organization's name up to $250,000. At various times during the fiscal year, the organization's cash in bank balances exceeded the federally insured limits.
KEPCo's repurchase agreements have collateral pledged by a financial institution, which are securities that are backed by the federal government.
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 information and existing economic conditions.
Materials and Supplies Inventory - Materials and supplies inventory are valued at average cost.
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.
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 included in other long-term assets on the consolidated balance sheets.
2016 2015 Cash surrender value of contracts $ 7,797,588 $ 7,423,520 Borrowings against contracts (7,528, 198) (7, 167,492)
$ 269,390 $ 256,028 Borrowings against contracts include a prepaid interest charge. KEPCo pays interest on these borrowings at a rate of 5.00% for the years ended December 31, 2016 and 2015.
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 usages as appropriate.
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.
KEPCo Services, Inc., a subsidiary of Kansas Electric Power Cooperative, Inc., is not exempt from income taxes.
Investments - Investments in associated organizations are carried at cost and are classified as held to maturity securities.
24
Notes to Consolidated Financial Statements (2) Factors That Could Affect Future Operating Results KEPCo currently applies accounting standards that recognize the economic effects of rate regulation and, accordingly, has recorded regulatory assets and liabilities related to its generation and transmission operations in accordance with Financial Accounting Standards Board (FASS) Accounting Standards Codification (ASC) 980, Regulated Operations. In the event KEPCo determines that it no longer meets the criteria of ASC 980, 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 ASC 980 include:
- 1) increasing competition that restricts KEPCo's ability to establish prices to recover specific costs and
- 2) a significant change in the manner in which 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 ASC 980 is appropriate. Any changes that would require KEPCo to discontinue the application of ASC 980 due to increased competition, regulatory changes or other events may significantly impact the valuation of KEPCo's investment in utility plant, its investment in Wolf Creek and necessitate the write-off of regulatory assets. At this time, the effect of competition and the amount of regulatory assets that could be recovered in such an environment cannot be predicted.
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. KEPCo has elected to deregulate its rate making for sales to its members under recent statutory amendments.
Subject to the possibility of KCC review, KEPCo's member rates are now set by action of the Board.
KEPCo's ability to timely recover its costs is enhanced by this change.
(3) Departures From Generally Accepted Accounting Principles 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 KEPCo's investment in Wolf Creek
($7.3 million and $8.0 million net of accumulated amortization as of December 31, 2016 and 2015, respectively). 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 service 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 ASC 980- 340, Regulated Operations, Other Assets and Deferred Costs.
Effective February 1, 2002, the KCC issued an order permitting recovery in rates of the $6.5 million cumulative 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 282 phase-in plan that meets the requirements of ASC 980-340.
If the disallowed costs were recovered using a method in accordance with U.S. generally accepted accounting principles, the costs would have been expensed in their entirety upon implementation of the KCC order, with a corresponding decrease in patronage capital.
Amortization of the Wolf Creek disallowed costs is included in amortization of disallowed charges and amounts to $0.4 million for each of the years ended December 31, 2016, and 2015.
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Notes to Consolidated Financial Statements Effective February 1, 1987, the KCC issued an order to KEPCo requiring the use of present worth I (sinking fund) depreciation and amortization. Such depreciation and amortization methods constituted phase-in plans that did not meet the requirements of ASC 980-340 Regulated Operation, Other Assets and Deferred Costs.
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 the Wolf Creek generation plant and disallowed costs over a 15-year period. 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 margin.
Amortization of the Wolf Creek deferred plant costs is included in amortization of deferred charges and amounts to $3.6 million for each of the years ended December 31, 2016 and 2015.
If the deferred plant costs were recovered using a method in accordance with accounting principles generally accepted in the United States of America, the costs would have been expensed in their entirety upon implementation of the KCC order, with a corresponding decrease in patronage capital.
The effect of these departures from accounting principles generally accepted in the United States of America is to overstate (understate) the following items in the consolidated financial statements by the following amounts:
2016 2015 Deferred charges $ - $ 3,563,634 Patronage capital $ - $ 3,563,634 Net margin $ (3,563,634) $ (3,563,634)
(4) Investments in Associated Organizations At December 31, 2016 and 2015, investments in associated organizations consisted of the following:
2016 2015 Cooperative Financial Corporation I
Memberships $ 1,000 $ 1,000 I Capital term certificates 395,970 395,970 Patronage capital certificates 1,831,901 1,575,2311 Equity term certificates 9,323,474 9,136.41a I
11,552,345 11,108,619 Other 306,626 282, 188 I
i $ 11,858,971 $ 11,390,807j 26
Notes to Consolidated Financial Statements (5) Deferred Charges 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 coinciding with the recognition of the related revenues. Additions to the deferred incremental outage costs were $2.8 million and $3.2 million in 2016 and 2015, respectively. The current year amortization of the deferred incremental outage costs was $2.4 million and $2.4 million in 2016 and 2015, respectively.
Other Deferred Charges - KEPCo includes in other deferred charges the early call premium resulting from refinancing. These early call premiums are amortized using the effective interest method over the remaining life of the new agreements.
(6) Prepaid Southwest Power Pool During 2016, KEPCo was assessed historical charges in the amount of $2,442,488 from Southwest Power Pool related to the Z2 billing issue for generation system upgrades from 2008-2016. The total amount of historical charges was paid in October 2016, and will be amortized over a five year period, ending October 2021. Balance as of December 31, 2016 was $2,320,364.
(7) Line of Credit As of December 31, 2016, KEPCo has a $20 million line of credit available with the Cooperative Finance Corporation. There were no funds borrowed against the line of credit at December 31, 2016 or 2015.
The line of credit requires the Cooperative to pay down the balance to zero annually. Interest rates vary and were 2.50% and 2.90% at December 31, 2016, and 2015, respectively. This line of credit expires in March 03, 2017.
At December 31, 2016, KEPCo has a $10 million line of credit available with CoBank, ACB. There were no funds borrowed against the line of credit at December 31, 2016 or 2015. Interest rate options, as selected by the Company, are a weekly quoted variable rate in which CoBank establishes a rate on the first business day of each week or a LIBOR option at a fixed rate equal to LIBOR plus 1.6%. This line of credit expires May 30, 2017.
(8) Long-Term Debt Long-term debt consists of mortgage notes payable to the United States of America acting through the Federal Financing Board, the CFC and others. Substantially all of KEPCo's assets are pledged as collateral.
27
Notes to Consolidated Financial Statements The terms of the notes as of December 31 are as follows:
2016 2015 Mortgage notes payable to the FFB at fixed rates varying from .818% to 9.21%, payable in quarterly installments through 2043 $ 65,406,702 $ 59,050,988 !
Mortgage notes payable to the Granter Trust Series 1997 at a rate of 7.522%, payable semi-annually, principal payments commencing in 1999 and continuing annually through 2017 3,240,000 7,240,000 Note payable to CoBank at a rate of 3.03%,
payable in quarterly installments through 2023 866,802 991,073 Mortgage notes payable, equity certificate loans and member capital security notes to the CFC at fixed rates of 3.25% to 7.50%, payable quarterly through 2045 93,149,181 91,391,067 162,662,685 158,673, 128 Less current maturities {11, 129,805} (11,456,396}
$ 151,532,880 $ 147,216,732 Aggregate maturities of long-term debt for the next five years and thereafter are as follows:
2017 $ 11,129,805 2018 7,980,579 2019 8,334,149 2020 8,476,343 2021 7,564,990 Thereafter 119,176,819
$ 162,662,685 Restrictive covenants related to the CFC debt require KEPCo to design rates that would enable it to maintain a times-interest earned ratio of at least 1.05 and debt-service coverage ratio of at least 1.0, on average, in the two best years out of the three most recent calendar 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 the Rural Utility Service. KEPCo was in compliance with such restrictive covenants as of December 31, 2016 and 2015.
Restriction covenants related to the CoBank debt require KEPCo to design rates that would enable it to maintain a debt-service coverage ratio, as defined by CoBank of at least 1.10. KEPCo was in
. compliance with the restrictive covenant as of December 31, 2016 and 2015.
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Notes to Consolidated Financial Statements In 1997, KEPCo refinanced its mortgage notes payable to the 1988 CFC Granter Trust through the establishment of a new CFC Granter 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%. The mortgage notes payable are pre-payable at any time with no prepayment penalties. The Trust holds certain rights the Cooperative assigned to the Trust under an interest rate swap agreement.
The swap agreement was put into place in order to mitigate the interest rate risk inherent in the Trust, which holds a fixed rate asset with a variable rate obligation.
The swap agreement terminates in 2017, but is subject to early termination upon the early redemption of the debt. However, any termination costs relating to the termination of the assigned interest rate swaps is KEPCo's responsibility. At December 31, 2016, the termination obligation associated with the assigned swap agreement to early retire the mortgage notes payable is approximately $186,800.
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.
(9) Benefit Plans National Rural Electric Cooperative Association (NRECA) Retirement and Security Program KEPCo participates in the NRECA Retirement and Security Program for its employees. The NRECA is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501 (a) of the Internal Revenue Code. It is a multiemployer plan under the accounting standards. The plan sponsor's Employer Identification Number is 53-0116145 and the Plan Number is 333.
A unique characteristic of a multiemployer plan compared to a single employer plan is that all plan assets are available to pay benefits of any plan participant. Separate asset accounts are not maintained for participating employers. This means that assets contributed by one employer may be used to provide benefits to employees of other participating employers.
KEPCo's contributions to the RS Plan in 2016 and 2015 represented less than 5 percent of the total contributions made to the plan by all participating employers. KEPCo made contributions to the RS Plan of $470,000, and $410,000, for the years ended December 31, 2016 and 2015, respectively. There have been no significant changes that affect the comparability of 2016 and 2015 contributions.
For the RS Plan, a "zone status" determination is not required, and therefore not determined, under the Pension Protection Act (PPA) of 2006. In addition, the accumulated benefit obligations and plan assets are not determined or allocated separately by individual employer. In total, the RS Plan was over 80 percent funded on January 1, 2016 and over 80 percent funded on January 1, 2015 based on the PPA funding target and PPA actuarial value of assets on those dates.
Because the provisions of the PPA do not apply to the RS Plan, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience.
At the December 2012 meeting of the l&FS Committee of the NRECA Board of Directors, the Committee approved an option to allow participating cooperatives in the RS Plan to make a contribution prepayment and reduce future required contributions. The prepayment amount is a cooperative's share, as of January 1, 2013, of future contributions required to fund the RS Plan's unfunded value of benefits earned to date using RS Plan actuarial valuation assumptions. The prepayment amount will typically equal approximately 2.5 times a cooperative's annual RS Plan required contribution as of January 1, 2013. After making the prepayment, for most cooperatives the billing rate is reduced by approximately 29
Notes to Consolidated Financial Statements 25%, retroactive to the January 1st of the year in which the amount is paid to the RS Plan. The 25% dif-ferential in billing rates is expected to continue for approximately 15 years from January 1, 2013. How-ever changes in interest rates, asset returns and other plan experience different from expected, plan assumption changes and other factors may have an impact on the differential in billing rates and the 15 year period.
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 completion of one year of service, of the respective employ-ee's base pay to provide additional retirement benefits. KEPCo contributed approximately $120,000 and
$100,000 to the plan for the years ended December 31, 2016 and 2015.
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. Bene-fits under the plans reflect the employee's compensation, years of service and age at retirement.
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Notes to Consolidated Financial Statements WCNOC uses a measurement date of December 31 for its retirement plan, supplemental retirement plan and postretirement plan (collectively, the Plans). Information about KEPCo's 6% of the Plans' funded status follows:
Pension Benefits Postretirement Benefits 2016 2015 2016 2015 Change in benefit obligation:
Benefit obligation beginning of year $ 26,351,186 $ 26,849,361 $ 994,854 $ 1,051,925 Service cost 861,508 969,547 16,209 17,627 Interest cost 1,232,522 1, 150,940 41,529 40, 150 Plan participants' contributions 126,206 119, 195 Benefits paid (890,285) (793,702) (195,427) (207,086)
Actuarial (gains) losses 1,682,308 (1,824,960) (62,247) (26,957)
Benefit obligations, end of year $ 29,237,239 $ 26,351,186 $ 921, 124 $ 994,854 Change in plan assets:
Fair value of plan assets, beginning of year $ 15,526,150 $ 15,914,004 $ 13,369 $ 762 Actual return on plan assets 1, 144,696 (367,512) (456)
Employer contributions 1,891,919 741,046 58,500 100,500 Plan participants' contributions 126,206 119, 195 Benefits paid (857,971) (761,388) (195,427) (207,088)
Fair value of plan assets, end of year 17,704,794 15,526, 150 2, 192 13,369 Funded status, end of year $ ~11,532,445l $ p0,825,036l $ ~9181931l $ ~981,485l Amounts recognized in the consolidated balance sheets:
2016 2015 Other long-term liabilities Wolf Creek pension and postretirement benefit plans $ 12,451,376 $ 11,806,521 Wolf Creek provision for injuries 18,000 18,000 Total other long-term liabilities $ 12,469,376 $ 11,824,521 31
Notes to Consolidated Financial Statements '
Amounts recognized in accumulated other comprehensive income (loss) not yet recognized as components of net periodic benefit cost consist of:
Pension Benefits Postretire ment Benefits 2016 2015 2016 2015 Net (loss) gain $ (8,466,849) $ (7,244,265) $ 83,474 $ 23,533 Prior service cost (56,927) (63,998) -
$ ~8,523, 776l $ ~7,308,263l $ 83,474 $ 23,533 Information for the pension plan with an accumulated benefit obligation in excess of pIan assets:
Pension Benefits Postretirem ent Benefits 2016 2015 2016 2015 Projected benefit obligation $29,237,239 $26,351, 186 $ 921, 124 $ 994,854 Accumulated benefit obligation $25,782,492 $23,070,405 $ $ -
Fair value of plan assets $17,704,794 $15,526,150 $ 2, 193 $ 13,370 Weighted average actuarial assumptions used to determine net periodic benefit oblig ation:
Pension Benefits Postreti rement Benefits 2016 2015 2016 2015 Discount rate 4.26% 4.61% 3.95% 4.27%
Annual salary increase rate 4.00% 4.00% N/A NIA Wolf Creek uses a measurement date of December 31 for its pension and post-retirement benefit plans. The discount rate to determine the current year pension obligation and th e following year's pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bond s that generate a sufficient cash flow to provide for the projected benefit payments of the plan. After th e bond portfolio is selected, a single interest rate is determined that equates the present value of th e plan's projected benefit payments discounted at this rate with the market value of the bonds selected.
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Notes to Consolidated Financial Statements Pension Benefits Postretirement Benefits 2016 2015 2016 2015 Components of net periodic cost (benefit):
Service cost $ 861,508 $ 969,548 $ 16,209 $ 17,628 Interest cost 1,232,522 1, 150,940 41,529 40, 150 Expected return on plan assets (1,241,172) (1, 154,587)
Amortization Transition obligation, net Prior service cost 7,071 7,325 Actuarial loss, net 556,200 757,059 (1 ,850) 294 Net periodic cost $ 1,416, 129 ~ 1,730,285 ~ 55,888 ~ 58,072 Other changes in plan obligations recognized in other comprehensive income:
Current year actuarial loss(gain) $ 1,778,784 $ (302,862) $ (61,791) $ (26,957)
Amortization of actuarial loss (556,200) (757,059) 1,850 (294)
Amortization of prior service cost (7,071) (7,325)
Amortization of transition obligation Total recognized in other comprehensive income 1,215,513 (1,067,246) (59,941) (27,251)
Total recognized in net periodic cost and other comprehensive income $ 2,631,642 $ 663,040 $ (4,053) $ 30,821 Weighted average actuarial assumptions used to determine net periodic cost:
Discount rate 4.61% 4.20% 4.27% 3.89%
Expected long term return on plan assets 7.25% 7.50% N/A N/A Compensation rate increase 4.00% 4.00% N/A N/A I
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Notes to Consolidated Financial Statements KEPCo estimates they will amortize the following amounts from regulatory assets into net periodic cost in 2017:
Pension Postretirement Benefits Benefits Actuarial loss $ 635,663 $ (6,441)
Prior service cost 7,071 Total $ 642,734 $ (6,441)
The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans' investment portfolios. Assumed 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 allocations for each asset class, the overall expected rate of return for the portfolios was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
For measurement purposes, the assumed annual health care cost growth rates were as follows:
2016 2015 Health care cost trend rate assumed for next year 6.50% 7.00%
Rate to which the cost trend rate is assumed to decline 5.00% 5.00%
Year that the rate reaches the ultimate trend rate 2020 2020 The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table:
One percentage One percentage point increase point decrease Effect on total service and interest cost (893) 921 Effect on post-retirement benefit obligation (16,058) 16,972 In 2012, Wolf Creek changed its investment advisor resulting in the sale of its then existing levels 1, 2 I
and 3 investments and the purchase of other level 2 and 3 investments. Its pension and post-retiremen t 1 plan investment strategy is to manage assets in a prudent manner with regard to preserving princip~I while providing reasonable returns. It has adopted a long-term investment horizon such that the chances and duration of investment losses are carefully weighed against the long-term potential fo:r appreciation of assets. Part of its strategy includes managing interest rate sensitivity of plan asset; relative to the associated liabilities. The primary objective of the pension plan is to provide a source 34
Notes to Consolidated Financial Statements of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. Wolf Creek delegates the management of its pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors strive to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.
The target allocations for Wolf Creek's pension plan assets are 31 % to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies and investment funds with underlying investments similar to those previously mentioned. The investments in debt include core and high-yield bonds. Core bonds include funds invested in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and private debt securities.
High-yield bonds include a fund with underlying investments in non-investment grade debt securities of corporate entities, private placements and bank debt. Real estate securities include funds invested in commercial and residential real estate properties while commodity investments include funds invested in commodity-related instruments.
All of Wolf Creek's pension plan assets are recorded at fair value using daily net asset values as reported by the trustee.
Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the Wolf Creek pension trust may buy and sell investments resulting in changes within the hierarchy. Where quoted market prices are available in an active market, plan assets are classified within Level 1 of the valuation hierarchy. Level 1 plan assets include cash equivalents, equity and debt investments. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of plan assets with similar characteristics or discounted cash flows. Level 2 investments include cash equivalents, equity, debt and commodity investments. In certain cases where Level 1 or Level 2 inputs are not available, plan assets are classified within Level 3 of the hierarchy and include certain real estate investments. Significant inputs and valuation techniques used in measuring Level 3 fair values include market discount rates, projected cash flows and the estimated value into perpetuity. Investments that do not have a readily determinable fair value are measured at NAV. These investments do not consider the observability of inputs, therefore, they are not included within the fair value hierarchy. We include in this category investments in private equity, real estate and alternative investment funds that do not have a readily determinable fair value. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments.
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Notes to Consolidated Financial Statements The following table provides the fair value of KEPCo's 6% share of Wolf Creek's pension plan assets and the corresponding level of hierarchy as of December 31, 2016 and 2015:
Fair Value Measurements Using Quoted prices in Significant active other Significant markets for observable unobservable identical assets inputs inputs December 31, 2016 Fair Value (Level 1) (Level 2) (Level 3)
Cash equivalents $ 76,575 $ - $ 76,575 $ -
Equity securities U.S. 4,415,136 - 4,415, 136 -
International 5,523,744 - 5,523,744 -
Debt securities Core bonds 4,474,271 - 4,474,271 -
Alternative investments 1,796,594 1,796,594 -
Total $ 16,286,320 $ - $ 16,286,320 $ -
Investments measured at NAV 1,418,474 Total $ 17,704,794 Fair Value Measurements Usino Quoted prices in Significant active other Significant markets for observable unobservable identical assets inputs inputs December 31, 2015 Fair Value (Level 1) (Level 2) (Level 3)
Cash equivalents $ 66,902 $ - $ 66,902 $ -
Equity securities U.S. 3,893,997 - 3,893,997 -
International 4,810,439 - 4,810,439 -
Debt securities -
Core bonds 3,866,471 - 3,866,471 -
Commodities 741,858 - 741,858 -
Real estate 781,678 - 781,678 -
Total $ 14,161,345 $ - $ 14, 161,345 $ _/
Investments measured at NAV 1,364,805 Total $ 15,526,150 36 I
Notes to Consolidated Financial Statements Estimated future benefit payments as of December 31, 2016, for the Plans, which reflect expected future services, are as follows:
Pension Benefits Postretirement Benefits From company From company To/from trust assets To/from trust assets Expected contributions:
2017 $ 1,380,000 $ $ 72,254 $
Expected benefit payments:
2017 $ 913,684 $ 32,325 $ 250,615 $
2018 1,029,583 32,023 287,843 2019 1, 143,591 32,199 325,899 2020 1,256,447 32,205 366,871 2021 1,366, 180 31,991 407,719 2022-2026 8,427,597 165,769 2,573,891 (10) Commitments and Contingencies Current Economic Environment - KEPCo considers the current economic conditions when planning for future power supply and liquidity needs. The current economic climate may also affect the Cooperative's ability to obtain financing.
Given the volatility of the current economic conditions, the values of assets and liabilities recorded in the financial statements could change rapidly, resulting in material future adjustments that could negatively impact the Cooperative's ability to meet debt covenants or maintain sufficient liquidity.
Currently under state statutes, the Cooperative's rate making is deregulated and, therefore, expects to be able to recover any economic losses through future rates.
Litigation - The Cooperative is subject to claims and lawsuits that arise primarily in the ordinary course of business. It is the opinion of management that the disposition or ultimate resolution of such claims and lawsuits will not have an adverse effect on the consolidated financial position, results of operations and cash flows of the Cooperative.
There is a provision in the Wolf Creek operating agreement whereby the owners treat certain claims and losses arising out of the operations 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.
Letter of Credit - KEPCo has an open letter of credit with the Cooperative Finance Committee in the amount of $1,500,000 which matures May 23, 2017. The letter of credit is intended to provide financial security to Southwest Power Pool pursuant to its credit policy.
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Notes to Consolidated Financial Statements Nuclear Liability Insurance - Pursuant to the Price-Anderson Act, KEPCo insures against public nuclear liability claims resulting from nuclear incidents to the required limit of public liability, which is approximately $13.4 billion. This limit of liability consists of the maximum available commercial insurance of $375.0 million and the remaining $13.0 billion is provided through mandatory participation in an industry-wide retrospective assessment program. For incidents after January 1, 2017, this commercial insurance limit increased to $450.0 million. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to $127.3 million (KEPCo's share is $7.64 million), payable at no more than $19.0 million (KEPCo's share is $1.14 million) per incident per year per reactor for any commercial U.S. nuclear reactor qualifying incident. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in 2018. In addition, Congress could impose additional revenue-raising measures to pay claims.
The owners of Wolf Creek carry decontamination liability, nuclear property damage and premature nuclear decommissioning liability insurance for Wolf Creek totaling approximately $2.8 billion. (KEPCo's share is $168 million) Insurance coverage for non-nuclear property damage accidents total approximately $2.3 billion. In the event of an extraordinary nuclear accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or, if certain requirements are met, including decommissioning the plant, toward a shortfall in the NOT fund.
The owners also carry additional insurance with NEIL to help 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, we may be subject to retrospective assessments under the current policies of approximately
$37.5 million (KEPCo's share is $2.25 million).
Although KEPCo maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, KEPCo's insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in KEPCo's prices, would have a material effect on our consolidated financial results.
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 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 Regulatory Commission (NRC) and to pay for on site property damages.
- 1 Once the NRC property rule requiring insurance proceeds to be used first for stabilization an9 decontamination has been complied with, the premature decommissioning coverage could pay for the decommissioning fund shortfall in the event an accident at Wolf Creek exceeds $500 million in covered damages and causes Wolf Creek to be prematurely decommissioned. I Nuclear Fuel Commitments - At December 31, 2016, KEPCo's share of WCNOC's nuclear fuel commitments was approximately $4.2 million for uranium concentrates, $10.8 million for conversion
$10.6 million for enrichment, and $3.8 million for fabrication, all expiring at various times from 2022 through 2045. I Purchase Power Commitments - KEPCo has supply contracts with various utility companies to purchase power to supplement generation in the given service areas. KEPCo has provided the Southwest Power Pool a letter of credit to help insure power is available if needed.
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Notes to Consolidated Financial Statements (11) Fair Value of Assets and Liabilities ASC Topic 820, Fair Value Measurements, defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
ASC Topic 820 also establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:
Level 1 Quoted prices in active markets for identical assets or liabilities Level 2 Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities Level 3 Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities Following is a description of the valuation methodologies used for assets and liabilities measured at fair value on a recurring basis and recognized in the accompanying consolidated balance sheets, as well as the general classification of such assets and liabilities pursuant to the valuation hierarchy.
Decommissioning Fund - The decommissioning fund consists of various mutual funds where fair value is determined by quoted market prices in an active market and, as such, are classified within Level 1 of the valuation hierarchy.
The following table presents the fair value measurements of assets recognized in the accompanying consolidated balance sheets measured at fair value on a recurring basis and the level within the ASC 820 fair value hierarchy in which the fair value measurements fall at December 31, 2016:
Fair Value Measurements Using Quoted price in active Significant markets for other Significant identical observable unobservable assets inputs inputs Fair Value (Level 1) (Level 2) (Level 3)
Decommissioning fund Domestic fund $ 11,909,616 $ 11,909,616 $ $
International fund 1,468,769 1,468,769 Domestic bond fund 7,670,901 7,670,901 Money market 613,621 613,621 Total $ 21,662,907 $ 21,662,907 $ $
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Notes to Consolidated Financial Statements The following table presents the fair value measurements of assets recognized in the accompanying consolidated balance sheets measured at fair value on a recurring basis and the level within the ASC 820 fair value hierarchy in which the fair value measurements fall at December 31, 2015:
Fair Value Measurements Using Quoted price in active Significant markets for other Significant identical observable unobservable assets inputs inputs Fair Value (Level 1) (Level 2) (Level 3)
Decommissioning fund Domestic fund $ 10,865,536 $ 10,865,536 $ $
International fund .1,440,767 1,440,767 Domestic bond fund 7, 189,822 7,189,822 Money market 500,071 500,071 Total $ 19,996, 196 $ 19,996, 196 $ $
(12) Patronage Capital In accordance with KEPCo's bylaws, KEPCo's 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 gene.rally accepted in the United Stated of America, total patronage capital would be substantially less. As noted in the consolidated statements of changes in patronage capital, no patronage capital distributions were made to members in 2016 and 2015.
(13) Subsequent Events The Company has evaluated subsequent events through April 13, 2017, which is the date the financial statements were available to be issued. No events were significant enough to warrant disclosures in the accompanying financial statements or notes.
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KEPCo's Mission Statement KEPCo exists on behalf of its Members to produce, procure, transmit, deliver and maintain a reliable supply of wholesale electricity within financial guidelines and risk tolerances established by the Board.
KEPCo Member System Map KEPCo's Vision Statement KEPCo will work to provide Consumer-Members the best possible value in reliable electricity and to play an active role in helping improve the economy and quality of life.
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Kansas Electric Power Cooperative, Inc.
A Touchstone Energy Cooperative ~T~
PO Box 4877 - Topeka, KS 66604 600 SW Corporate View - Topeka, KS 66615 (785)-273-7010 www.kepco.org