ML15132A653

From kanterella
Jump to navigation Jump to search
Guarantee of Payment of Deferred Premiums, 10 CFR 140.21
ML15132A653
Person / Time
Site: Wolf Creek Wolf Creek Nuclear Operating Corporation icon.png
Issue date: 05/05/2015
From: Stull A
Wolf Creek
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
CO 15-0003
Download: ML15132A653 (49)
v • d • e


Text

W&F CREEK 'NUCLEAR OPERATING CORPORATION Annette F. Stull Vice President and Chief Administrative Officer May 5, 2015 CO 15-0003 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

Subject:

Docket No. 50-482: Guarantee of Payment of Deferred Premiums, 10 CFR 140.21 Gentlemen:

Pursuant to the requirements of 10 CFR 140.21, each operating reactor licensee is required to maintain financial protection through guarantees of payment of deferred premiums. The owners of Wolf Creek Generating Station (WCGS) are providing the enclosed documentation of their ability to pay deferred premiums in the amount of eighteen million nine hundred sixty-three thousand dollars, as determined by 10 CFR 140.11(a)(4).

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), have each provided audited Consolidated Statements of Cash Flows in order to demonstrate sufficient funds are available to meet their share of the deferred premiums.

This letter contains no commitments. If you have any questions concerning this matter, please contact me at (620) 364-4004, or Mr. Steven R. Koenig at (620) 364-4041.

Sincerely, Annette F. Stull AFS/rlt

Enclosures:

I Kansas Gas and Electric Company Consolidated Statements of Cash Flows II Kansas City Power & Light Company Consolidated Statements of Cash Flows III Kansas Electric Power Cooperative, Inc. Statement of Cash Flows cc: M. L. Dapas (NRC, w/e C. F. Lyon (NRC), w/e A. A. Rosebrook (NRC), w/e Senior Resident Inspector (NRC), w/e P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET kt L

Enclosure I to CO 15-0003 Kansas Gas and Electric Company Consolidated Statements of Cash Flows (41 pages)

April 24, 2015 Mr. Todd N. Laflin Wolf Creek Nuclear Operating Corporation PO Box 411 Burlington, KS 66839

Dear Todd:

Pursuant to the requirements of 10 CFR 140.21(e), Kansas Gas & Electric Company is providing the attached audited Consolidated Statements of Cash Flows as evidence of the ability to make payment of its share of deferred premiums in an amount of $8.913 million.

The undersigned certifies that the foregoing memorandum with respect to Kansas Gas & Electric Company's cash flow for the year 2014, is true and correct to the best of his knowledge and belief.

Sincerely, r Kevin L. Kongs Vice President, Controller Westar Energy, Inc.

Ims attachment 818 S Kansas Ave / PO Box 889 / Topeka, KS 66601-0889 / (785) 575-6300

INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholder of Kansas Gas and Electric Company Topeka, Kansas We have audited the accompanying consolidated financial statements of Kansas Gas and Electric Company and its subsidiaries (the "Company"), a wholly-owned subsidiary of Westar Energy, Inc., which comprise the consolidated balance sheets as of December 31, 2014 and 2013. and the related consolidated statements of income, changes in equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management's Responsibility for the Consolidated 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. 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 Company'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 Company'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 audit opinion.

Opinion In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Kansas Gas and Electric Company and its subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/si Deloitte & Touche LLP Kansas City, Missouri February 25, 2015

KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)

As of As of December 3 1, 2014 December 3 1.2013 ASSETS CURRENT ASSETS:

Accounts receivable, net of allowance for doubtful accounts of $2,859 and $2,4 12. respectively . $ 106,843 $ 98,716 Receiva ble fro m a ffilia te s ................... .. ........ ......... ........... .. ............................................................ 156,002 Fue l in ven to ry and supp lie s .. . ..... ........ .................. ............................................. . .......... . . ...... .. 103,349 96.860 D e ferred tax asse ts .............. ......... . . ..... . . ........... .............. 23,311 24,151 Pre pa id e xpe n se s ....... ..... ...................... ........................................................... ... .............. .............. 5.363 5404 R e g u la to ry a sse ts . .................... .. ...... ... .. ......... .............. .................. ............................ ............... 21,752 63,996 O th er ............ . . . . . . . . . . . . ......... ............. ......... ............ .. . . . ........... .................................. 5,464 3.740 T ota l C urre nt A sse ts ..... . .......................................................................... ..................... . ...... 422,084 292,867 PROPERTY. PLANT AND EQUIPMENT. NET ................................................................. . ........ 4,038.561 3,627.331 PROPERTY, PLANT AND EQUIPMENT OF VARIAI3LE INTEREST ENTITY. NET ................. 197,624 204,739 OT1HER ASSETS:

Reg u la to ry as se ts ........ .. ........................................ . . ... ............. .............................. ....................... 303,230 277,352 Nuc le ar deco m m issio n in g tru st .......... ..................... ......... ........ ............... . ........... . ....... ...... ........ tiS.016 175.625 O t her ....................... .. ............... ..................... .......... .. .............................................. .......... . .......... 68.306 65.918 T ota l O the r A sse ts ....................... ........... ............................................. ..................... ...... 556,552 518,895 T OT A L A SSET S......................... . .................. ......... . . . ............ ............................ ................ . . .... ..... S$ 5.214.821 $ 4.643,832 LIABILITIES AND EQUITY CURRENT I.IABILITIES:

Current maturities of lonu-tesm debt of variable interest entity ............................................... $ 23,743 $ 22.332 A cco u n ts p ay ab le .... .. ..... ................. ..... .......... . ........ . . .............................................................. 102.505 95.211 Pav a b le to a ffilia te .... ...... . ........... ...................................................................................... ............. -- 105,968 Acc ru e d in te re s t ... ..... ... ... ............... ......... .. .............. ..... . . ..... . .............. . ........... ........... . .. . . . 44,303 38.735 A c c ru e d ta x es .. .. .. ...... . ............... ............ . .............. . ........ ................... . . .............. ....... ..... ..... 24.455 23.153 Re gu la to ry lia b ilitie s ............. .................. .. ....... ....... .. ........................................................... ......... 22,497 5.562 C u stom er de po s its .................. ................... ................................ ... . .......................... ....................... 15,044 15,511 Other ................................ 3.336 7,033 l'o tal C urre nt L iabilitie s............. .. . ............. ....................................................... ... ................ 235,883 313.505 LONG-TERM LIABILITIES:

Lo ng -te rm d e b t. ne t............ .. . ............... .. ............... ... .... . ................. . .............. . . ......... . .......... 970.576 898,644 L ong-term debt o variable interest entity, net ....... ....................................................................... 162.048 185,791 De fe rred in co m e ta xe s ....... .......................................................... ......... . ....... ........... ....................... 825.808 779,373 U nam o rtized investm ent tax cred its... ............................................................ ............................. 30,793 32,676 Re gu la to ry lia b ilitie s ......... ....... ..... . . . . . . ...... ................ 213.188 205,725 A sset re tire m e nt o b ligatio n s .............................. .............. . . ................................ ........ ..... ....... 214.673 152,747 O the r ...... .. ... ........... ..... . ... ....... . .. ........................................... .................................................. . 136,290 95,323 ro ta l Lo n g- e r n L ia bilities ..... ...... .... ............. ... .. ... .. .. . ........... . .. ...... ... . ......... ... 2.553,376 2.350,279 COMMITMENTS AND CONTINGENCIES (See Notes 12 and 141 EQUJITY Kansas Gas and Electric Company Shareholder's Equity:

Common stock, without par value: authorized, issued and outstanding 1,000 shares ............... . 1,065.634 1,065.634 P aid -in cap ita l .. ............. ....................................................... .......... ......................................... 1.0 95 ,4 5 7 6 80 .4 57 Reta in ed ea rn in g s ... ....... ......... ... ................. . ...................................................... ..... .......... .. . 3 33 ,85 0 30 5,8 39 Total Kansas Gas and Electric Company Shareholder's Equity ........................................ 2,494,941 2,051,930 No nco n tro llin g Inte rest ......................................................................................................................... (6 9 .3 79 ) (7 1,8 82 )

To ta l E q u ity ...... .................. . ..... . ................................ ............................ I. ................ 2,4 25i,56 2 1,9 0 0 48 TOTAL LIABILITIES AND EQUJITY .......................... ............................... $ 5.214.821 $ 4,643,832 The accompanying notes are an integral part of these consolidated financial statements.

KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)

Year Ended Decemher 31, 2014 2013 R E V ENUE S ........ .. ... ......... .................. .................. .......... ....... ........................... ......... 1,10 8,4 7 0 1.0 0 1.5 3 8 OPERATING EXPENSES Fuel and purchased pow er ............. .... ....................................................................... 278,064 24 1,54 5 SPP transm ission netvw ork costs .... ............................................................................. 109,462 89,302 Operating and m aintenance ......... ................................. ..................................... 204,240 196,756 Depreciation and am ortization .. ............................................................................. 123,653 116.808 Selling, general and adm inistrative ............. ............... .............................................. 117,673 111,008 Taxes other than incom e tax ....................... ....................................................... . 43,958 4 3,139 T otal Operating E xpenses ................................ ....................................... 877,050 798.558 INCO M E FRO M O PERA TIO N S ............................................... ................................. 231,420 202,980 OTHER INCOME (EXPENSE):

O th e r inc o m e ... ................................. .. ........... ................................. . ..................... . 26 ,2 4 6 3 2,2 0 9 O th e r e x pen se ... ....... . ...... .. ..... ... .... ..... ........ . ........... ...... ............................. ...... ( 18 ,38 8 ) ( 18 ,0 9 8 )

To ta l Oth e r Inc om e ............................ .. .............. ...... ................................. 7 ,85 8 144......................

.1 11 In te re st e xp en se ....................... . ... ............ ............... ............................... ......................... 7 ,3 1 60 ,44 8 INCO M E BEFO RE INCO M E TAX ES ................. ........... ....................................... 181.967 156.643 In co m e ta x ex pe n se ............ ............... ........................ . ........... ................ ........................... 5 1,4 5 3 34.4 0 2 NET IN C O M E ........ .. ............ .. . . ........................... .. ..... ................................................. 130 ,5 14 12 2 ,2 4 1 Less: Net income attributable to noncontrolling interests ................ .... 2,503 1.260 NET INCOME A'TTRIBI fITABIE TO KANSAS GAS AND ELECTRIC COMPANY $ 128,011 $ 120,981 The accomnpanying notes are an integral part of these consolidated financial statements.

KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)

Year Ended December 3 1, 2014 2013 CASH FLOWS FROM (I JSED IN)OPERATING ACTIVIrIES:

Ne t in c o m e .......... ... ..................................................... ..... ............................. . ................. ... . S 130,514 $ 122,241 Adjustments to reconcile net income to net cash provided by operating activities D eprec iation and am ortization .. ............................................................................. ....... 123,653 116.80(1 A m ortization of nuclear luel ........................................... 26,051 22,690 Amortization ofdeferred regulatory gain from sale leaseback ......................................... (5,495) (5.495)

A m ortization of corporate-owned life insurance ............................................................. 18,402 18,179 N et deterred incom e taxes and credits .......... . .... ........................................................ 51,656 34,236 A llowance for equity funds used during construction ................................................... (12,1821 (11,1681 Changes in working capital items:

A c c o un ts re ce iv ab le .......... . ... . ......................... .. .......................................... ....... 18,1271 (10552)

Fue l inv ento ry and sup plies ................. .................... ... . ...... .. .. ... ................. ................ (7,272) 2365 P're pa id ex pe nses an d o th e r . ............................................................................................... 41.081 (9,472)

A c c ou n ts pay a b le ............. . ......... .......... ... . ... ............. ............. .............................. .... 18.858 (32,118)

O th e r c urre n t lia b ilitie s .................. . ...... ............................................................................ (36,769) (47,861)

C han ge s in o th e r assets...................... ........... . .................................................................... (1.651) (13,709)

C ha n ges in o th er lia b ilities ... .............. ............................. . ...... . ............. ........................... . .. 4.697 6,734 Cash Flows from Operating Activities ........................... ........................................... 343,416 193,278 CASII FLOWS FROM IUSED IN) INVESTING ACTIVITIES:

Additions to property, plant and equipment .............................................. 1485,625) t455,624)

Purc hase of se c uritie s - tru st ........... . . . .... ..... ................. ........... . .............................. ........... (9,075) (64.602)

Sa le o f se cu rities - tru st .................................. . ........ ................................. ................................ 9.094 64,656 Investnent in corporate-owned life insurance ................................................................ 115.934) (17.408)

P'roceeds froni investment in corporate-owned life insurance ..................................................... 42,733 85,228 A dv anc e to pare n t...................................... .... .. .......................... ............................. ................. 1156.002)

O ther investing activities ... .................. .. . ...... ................. 12,7821 (2.913)

Cash Flows used in Investing Activities ........................................................... (617,591) (390.663)

CASH FLOWS FROM (USEI) IN) FINANCING ACTIVITIES:

P ro ceed s fro m lo ng -term d eb t .... ........................................................... .............. .................. . 246,458 Retirements of long-term debt ....................................................................... (177,500) (100,000)

Retirem ents of long-term debt of variable interest entit ...................................................... (22,332) (21,005)

(Repayment of) borrowings front parent ..... ............... (105,968) 42,244 Investm ent by parent .............................. ...................................... 415,000 300,000 Borrowings against cash surrender value of corporate-owned life insurance ......................... 59,766 59U565 Repayment of borrowings against cash surrender value of corporate-owvned life insurance ....... (41,249) (83,419)

Dividends to parent ............................................................... (100,000) -

C ash Flow s fro m Financing Activ ities .......................................................................................... .... 274,175 197,385 NET CHANGE IN CASH AND CASH EQIJIVALENTS ............................................................

CASH AND CASH EQUIVALENI'S:

B e g in n in g o f pe riod .......... ... ..... . . ................................ .................................... ........... ....

En d o f pe rio d .......................... ........... . ......... ..... ......... ................................. ... . ... .......... . $ -- --

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION CASH PAID FOR:

Interest on Financing activities, net of amount capitalized ......................................... . $ 39,672 S 46,646 Interest on financing activities of variable interest entity. ................................................ 11,122 12,346 NON-CASH INVESTING tRANSACTIONS:

Property, plant and equipm ent additions ........................................................................ 85,505 77,140 The accompanying notes are an integral part of these consolidated financial statements.

KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Dollars in Thousands)

Kansas Gas and Electric Company Common Paid-in Retained Noncontrolling Total stock capital earnings interest equity' Balance as of December31, 2012 .......... $ 1,065,634 $ 380A457 $ 184.858 $ (73,142) $ 1,557,807 Net income ................................ - - 120,981 1.260 122,241 Investment hy parent company ................. - 300.000 - - 300,000 Other ......................................- - - - -

Balance as of December31, 2013 ........... $ 1.065,634 $ 680,457 $ 305,839 $ (71,882) $ 1,980,048 Net income .............................. . .........- - 128,011 2,503 130.514 Dividends on common stock ................ - - -- (100,000) - (100,000)

Investment by parent company ................. - 415,000 - - 415.000 Balance as of December31, 2014 $ 1.065,634 $ 1.095,457 $ 333,850 S (69,379) S 2,425,562 The accompanying notes are an integral part of these consolidated financial statements.

KANSAS GAS AND ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS Kansas Gas and Electric Company is a regulated electric utility incorporated in 1990 in Kansas. Unless the context otherwise indicates, all references in these notes to "the company," "KGEB" "we," "us," "our" and similar words are to Kansas Gas and Electric Company.

We are a wholly-owned subsidiary of Westar Energy, Inc. (Westar Energy) and we provide rate-regulated electric service using the name Westar Energy. We provide electric generation, transmission and distribution services to approximately 322.000 customers in south-central and southeastern Kansas, including the city of Wichita. Our corporate headquarters is located in Wichita. Kansas.

2.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation We prepare our consolidated financial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America. Our consolidated financial statements include our undivided interests in jointly-owned generation facilities on a proportionate basis and a variable interest entity (VIE) of which we are the primary beneficiary reported as a single reportable segment. We are allocated certain operating expenses jointly incurred with Westar Energy.

Intercompany accounts and transactions have been eliminated in consolidation. We evaluated subsequent events up to the time Westar Energy issued its consolidated financial statements and our consolidated financial statements were available to be issued on February 25. 2015.

Use of Management's Estimates When we prepare our consolidated financial 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 financial 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, our portion of Wolf Creek Generating Station's (Wolf Creek) pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek. environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under diflerent 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 3, "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.

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 As of December 31. 2014 December 31, 2013 (In Thousands)

Fuel inventory ............................ S 24,105 $ 23,682 Supplies ...................................... 79,244 73,178 Fuel inventory and supplies... $ 103,349 S 96,860 Property, Plant and Equipment We record the value of property, plant and equipment, including that of the VIE, 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 finds) 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 3 1, 2014 2013 (Dollars In Thousands)

Borrowed funds ............................... $ 8,680 $ 9,269 Equi ty funds ..................................... 12.182 11L 168 Total .......................................... S 20,862 S 20,437 Averrage AFUDC Rates .................... 6.7% 4.8%

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 2.0% for 2014 and 2013.

Depreciable lives of property, plant and equipment are as follows.

Years Fossil fuel generating tacilities .................... 6 to 74 Nuclear fuel generating facility ............. 55 to 71 Transmission facilities ................................. 15 to 75 Distribution facilities ................................... 22 to 63 O th e r ............................................................ 5 to 30

Nuclear Fuel We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refinement.

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 (MMBtu). The accumulated amortization of nuclear fuel in the reactor was $72.3 million as of December 3 1, 2014, and $46.2 million as of December 31, 2013. The cost of nuclear fuel charged to fuel and purchased power expense was $27.3 million in 2014 and

$26.5 million in 2013.

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, 2014 2013 (In Thousands)

Cash surrender value of policies ...................... $ 1,228,628 $ 1,209.764 Borrowings against policies ............................ (1,173,957) (1.156,341)

Corporate-owned life insurance, net ........ $ 54,671 $ 53,423 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 tluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $29.6 million as of December 31, 2014. and $29.3 million as of December 3 1, 2013.

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 ourjudgments can materially affect amounts we recognize in our consolidated financial statements. See Note 10, "Taxes," for additional detail on our accounting for income taxes.

Sales lax 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.

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, regulatory bodies have issued the following new accounting pronouncements that may affect our accounting and/or disclosure.

Extraordinary and Unusual Items In January 2015. the Financial Accounting Standards Board (FASB) issued guidance that eliminates the accounting concept of extraordinary items. The objective of the new guidance is to reduce complexity in accounting standards while maintaining or improving the usefulness of information provided. The guidance is effective for fiscal years beginning after December 15, 2015. with early adoption permitted. We have elected to adopt effective January 1, 2015, without a material impact to our financial statements.

Revenue Recognition In May 2014, the FASB issued guidance that addresses revenue from contracts with customers. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing, and uncertainty of revenue from contracts with customers. This guidance is effective for fiscal years beginning after December 15. 2016. Early application of the standard is not permitted. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

3. 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, 2014 2013 (In Thousands)

Regulatory Assets:

Amounts due from customers for future income taxes, net ....... $ 107,605 $ 113,803 Deferred employee benefit costs ............................................... 70.696 39,333 D epreciation ............................................................................... 63,485 65,756 Debt reacquisition costs .................................. 24,840 23,036 Asset retirem ent obligations ...................................................... 20,419 19.132 D isallow ed plant costs ............................................................... 15,809 15,964 Wolf C reek outage ..................................................................... 11,165 29.026 A d valorem tax ........................................................................... 6,375 5,336 Energy efficiency program costs ................................................ 3,530 6.378 Retail energy cost adjustm ent .................................................... - 22,138 O ther regulatory assets .............................................................. 1,058 1,446 Total regulatory assets ........................................................ .$ 324.982 $ 341,348 Regulatory Liabilities:

Deferred regulatory gain from sale-leaseback ........................... $ 81,055 $ 86,551 Removal costs ....................................... 47.502 55.822 N uclear decom m issioning .......................................................... 43,641 43,272 La Cygne leasehold dismantling costs ....................................... 22,918 20.505 Jurisdictional A FU DC ................................................................ 2 1.462 1,741 Retail energy cost adjustm ent .................................................... 16,637 G ain on sale o f oil ...................................................................... 1,803 3.329 O ther regulatory liabilities ......................................................... 667 67 Total regulatory liabilities ................................................... $ 235.685 $ 211.287 Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.

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.

Deferred employee benefit costs: Includes $65.6 million for Wolf Creek pension and post-retirement benefit obligations and $5.1 million for actual Wolf Creek pension expense in excess of the amount of such expense recognized in setting our prices. The increase from 2013 to 2014 is primarily attributable to a decrease in the discount rates used to calculate Wolf Creek's pension benefits obligations and the adoption of updated mortality tables. During 2015, we will amortize to expense approximately $6.0 million of the benefit obligations and approximately $1.0 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.

  • 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.
  • 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.
  • Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 13, "Asset Retirement Obligations." We recover these amounts over the life of the related plant. 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.

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 cam a return on this asset.
  • 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.

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.

  • 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 we recorded on the 1987 sale and leaseback of our 50% interest in La Cygne Generating Station (La Cygne) unit 2. We amortize the gain over the lease term.

" 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.

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 4. 5 and 13. "Financial Instruments and Risk Management," "Financial Investments" and "Asset Retirement Obligations," respectively, for information regarding our nuclear decommissioning trust (NDT) and our ARO.

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.

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 charges are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.

Gain on sale of oil: We discontinued the use of a certain type of oil in our plants. As a result, we sold this oil inventory for a gain. This item represents the remaining portion of the gain that will be refunded to customers over a three-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.

KCC Proceedings General and Abbreviated Rate Reviews Westar Energy, staff of the Kansas Corporation Commission (KCC) and a consumer advocate joined in a request filed with the KCC to defer depreciation expense and carrying costs related to our capital investment associated with environmental upgrades at La Cygne until new retail prices become effective following a general rate case expected to be filed in March 2015.

Westar Energy estimates their share of these deferred costs to be approximately $20.0 million and we expect to begin deferring these costs in March 2015. In September 2014, the KCC issued an order approving the joint application that will allow us to include these deferred costs in our next general rate case. which is expected to increase Westar Energy's annual revenues by approximately $4.0 million.

In November 2013, the KCC issued an order allowing us to adjust our prices to include the additional investment in the La Cygne environmental upgrades, as discussed below, and to reflect cost reductions elsewhere. The new prices were cxpected to increase our annual retail revenues by approximately $14.8 million.

Environmental Costs In August 2011, the KCC issued an order ruling that Kansas City Power & Light Company's (KCPL) decision to make environmental upgrades at La Cygne to comply with environmental regulations is prudent and the $1.2 billion project cost estimate is reasonable. We have a 50% interest in La Cygne and intervened in the proceeding. The KCC denied our request to collect our approximately $610.0 million share of the capital investment for the environmental upgrades through our environmental cost recovery rider IECRR). However, as noted above, we and Westar Energy received an order regarding an abbreviated rate review to update our prices to include a portion of the capital costs associated with the project. We will request to collect our remaining investment in La Cygne environmental upgrades as part of a general rate case expected to be filed in March 2015.

We and Westar Energy also 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. In the most recent two years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately $5.3 million effective in June 2014 and approximately $3.3 million effective in June 2013.

Transmission Costs We and Westar Energy make annual filings with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate discussed below. In the most recent two years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately $17.1 million effective in April 2014 and approximately $5.8 million effective in March 2013.

Energy Efficiency We and Westar Energy make annual filings with the KCC to adjust our prices to include previously deferred amounts associated with various energy efficiency programs. In the most recent two years, the KCC issued orders related to such filings authorizing us to decrease our annual retail revenues by approximately $2.4 million effective in November 2014 and

$0.6 million effective in November 2013.

Property Tax Surcharge We and Westar Energy make annual filings with the KCC to adjust our prices to include the cost incurred for property taxes. In the most recent two years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately $5.8 million effective in January 2014 and $7.5 million effective in January 2013.

FERC Proceedings in October of each year, we post an updated transmission formula rate 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 two years, we posted our transmission formula rate, which was expected to increase our annual transmission revenues by approximately $22.1 million effective in January 2014 and approximately $6.1 million effective in January 2013.

In August 2014, the KCC filed a challenge with the Federal Energy Regulatory Commission (FERC) regarding rate making as it pertains to the cost of interstate electrical transmission service we operate. The KCC is requesting that we lower our transmission return on equity by nearly two percentage points, which would result in reductions of the TFR revenue requirement if granted. We are currently in settlement discussions. If we are unable to reach a settlement, FERC may schedule a hearing.

4. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT 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. The three levels of the hierarchy and examples are as follows:
  • Level I - Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level I 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 measured at net asset value, comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or 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. Level 3 includes investments in private equity, real estate securities and other alternative investments, which are measured at net asset value.

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.

All of our level 2 investments are held in investment funds that are measured at fair value using daily net asset values.

In addition, we maintain certain level 3 investments in private equity, alternative investments and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at fair value utilizing both market- and income-based models, public company comparables, investment cost or the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. The underlying real estate investments are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

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. 2014 As of December 31,2013 Carrying Value Fair Value Carrying Value Fair Value

(,InThousands)

Fixed-rate debt ..................... $ 925,000 $ 1,118,865 $ 852.500 $ 971,841 Fixed-rate debt of VIEs ........ 185,791 204,173 208,123 225,873

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. 2014 Level I Level 2 Level 3 Total (In Thousands)

Nuclear Decommissioning Trust:

Domestic equity fhnds ................................................ $ - $ 54,925 S 6.047 $ 60.972 International equity funds ...........................................- 30.791 - 30,791 Core bond fund ................................. -- 19.289 - 19,289 High-yield bond fund ..................................................- 13,198 - 13,198 Emerging market bond fund .......................................- 10.988 - 10,988 Other fixed income fund .............................................- 4,779 - 4,779 Combination debt/equity/other funds .........................- 18,141 - 18,141 Alternative investment fund .......................................- - 16,970 16,970 Real estate securities fund ..........................................- - 9,548 9,548 C ash equivalents ......................................................... 340 I -- 340 Total Nuclear Decommissioning Trust ........................... $ 340 $ 15211 $ 32,565 $ 185,016 As of December 31, 2013 Level I Level 2 Level 3 Total (In Thousands)

Nuclear Decommissioning Trust:

Domestic equity funds ................................................ $ - $ 49,957 S 5,817 $ 55,774 International equity funds ........................................... - 31,816 - 31,816 Core bond fund ........................................................... - 18,107 - 18,107 High-yield bond fund .................................................. - 12,902 - 12,902 Emerging market bond fund ...................................... - 11.055 - 11,055 Other fixed income fund ............................................. - 4.690 - 4.690 Combination debt/equity/other funds ......................... - 17,093 - 17,093 Alternative investment fund ....................................... - - 15.675 15,675 Real estate securities fund ..........................................- - 8,511 8,511 Cash equivalents ......................................................... 2 - - 2 Total Nuclear Decommissioning Trust .............................. $ 2 145,620 $ 30003 $ 175,625

The following table provides reconciliations of assets held in the NDT measured at fair value using significant level 3 inputs for the years ended December 3 1, 2014 and 2013.

Domestic Alternative Real Estate Equity Investment Securities Net Funds Fund Fund Balance (In Thousands)

Balance as of December 31, 2013 .... $ 5.817 $ 15,675 $ 8.511 $ 30.003 Total realized and unrealized gains included in:

Regulatory liabilities ................. 391 1,295 1,037 2,723 Purchases .......................................... 335 - 351 686 Sa le s .................................................. (496) - (351) (847)

Balance as of December 3 1, 2014 .... $ 6,047 $ 16,970 S 9,548 $ 32,565 Balance as of December 31, 2012 .... $ 4,899 $ - $ 7,865 $ 12,764 Total realized and unrealized gains included in:

Regulatory liabilities ................. 940 675 646 2,261 Purchases ................................. 341 15,000 287 15,628 Sales .................................................. (363) - (287) (650)

Balance as of December 31, 2013 .... $ 5,817 $ 15,675 $ 8,511 S 30,003 Portions of the gains and losses contributing to changes in net assets in the above table are unrealized. The following table summarizes the unrealized gains and losses we recorded to regulatory liabilities on our consolidated financial statements during the years ended December 31, 2014 and 2013, attributed to level 3 assets and liabilities.

Domestic Alternative Real Estate Equity Investment Securities Net Funds Fund Fund Balance (In Thousands)

Year ended December 3 1, 2014 ..................... $ (105) $ 1,296 $ 685 $ 1,876 Year ended December 31, 2013 ..................... 577 675 359 1,611

Sonic of our investments in the NDT are measured at net asset value, do not have readily determinable fair values and 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 3t, 2014 As of December 31, 2013 As of December 31, 2014 Unfunded Unfunded Redemption Length of Fair Value Commitments Fair Value Commitments Frequency Settlement (In Thousands)

Nuclear Decommissioning Trust:

Domestic equity funds ................... S 6,047 $ 2.348 $ 5,817 $ 2,683 (a) (a)

Alternative investment fund ........... 16,970 - 15.675 - (b) (b)

Real estate securities fund .............. 9,548 - 8,511 - Quarterly P80D Total Nuclear Decommissioning Trust .................................... $ 32,565 $ 2,348 $ 30,003 $ 2,683 (a) This investment is in three 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 the third quarter of 2013. This fund's term will be 15 years, subject to the general partner's right to extend the term for up to three additional one-year periods.

(b) This fund has an initial lock-up period of 24 months, which began in April 2013. Redemptions are allowed, on a quarterly basis, after 24 months at the sole discretion of the fund's board of directors. A 65-day notice of redemption is required.

There is a holdback on final redemptions.

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 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.

Interest Rate Risk We have entered into numerous fixed and variable rate debt obligations. For details, see Note 9, "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 financial derivative instruments such as interest rate swaps.

5. FINANCIAL INVESTMENTS 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.

2014 and 2013.

Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of

$0.1 million and $5.3 million, 2014 and 2013, respectively. 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 31.2014 and 2013.

Gross Unrealized Security Type Cost Gain Loss Fair Value Allocation (Dollars In Thousands)

As of December 3 I. 2014 Domestic equity funds ............... $ 46,126 $ 14,853 $ (7) $ 60,972 33%

International equity funds .......... 27,521 3,683 (413) 30,791 17%

Core bond fund .......................... 18,811 478 19,289 10%

High-yield bond fund ................. 13,342 (144) 13,198 7%

Emerging market bond fund ...... 12.556 (1,568) 10.988 6%

Other fixed income fund ............ 4,798 (19) 4.779 3%

Combination debt/equity/other funds .............................. 14,975 3,786 (620) 18,141 10%

Alternative investment fund ....... 15,000 1,970 - 16,970 9%

Real estate securities fund .......... 10,619 - (1,071) 9,548 5%

Cash equivalents ........................ 340 - - 340 <1%

Tota l .................................... $ 164.088 $ 24,770 $ (3,842) $ 185,016 100%

As of December 31. 2013 Domestic equity funds ............... $ 40,976 14,799 $ (1) $ 55,774 32%

International equity funds .......... 26,581 5,266 (31) 31,816 18%

Core bond fund .......................... 18,287 (180) 18,107 10%

High-yield bond fund ................. 12,275 627 -- 12,902 7%

Emerging market bond fund ...... 12.207 (1,152) 11,055 6%

Other fixed income fund ............ 4,684 6 - 4,690 3%

Combination debt/equity/other fund s ..................................... 14.964 2.380 (251) 17,093 10%

Alternative investment fund ....... 15.000 675 - 15,675 9%

Real estate securities fund .......... 10,268 - (1,757) 8,511 5%

Cash equivalents ........................ 2- - 2 <1%

T o tal .................................... $ 155,244 $ 23,753 $ (3,372) $ 175.625 100%

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. 2014 and 2013.

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. 2014 Domestic equity funds ......... S -- - $ 263 $ (7) $ 263 $ (7)

International equity funds .... 5.905 (413) - - 5,905 (413)

High-yield bond fund .......... 13,198 (144) - 13,198 (144)

Emerging market bond fund - 10.988 (1.568) 10,988 (1,568)

Other fixed income fund ...... 4.779 (19) - - 4,779 (19)

Combination debt/equity/

other funds ....................- 5,892 (620) 5,892 (620)

Real estate securities fund... - 9.548 (1,071) 9,548 (1,071)

Total .............................. S 23,882 $ (576) $ 26,691 $ (3.266) $ 50,573 S (3,842)

As of December 31. 2013 Domestic equity funds ......... S 59 S (I) $ - $ - $ 59 $ (1)

International equity funds .... 6,244 (31) - 6,244 (31)

Core bond fund .................... 18.107 (180) - 18,107 (180)

Emerging market bond fund 11,055 (1,152) - 11,055 (1,152)

Combination debt/equity/

other funds .................... 6,283 (251) - - 6.283 (251)

Rea 1 estate securities fund .. . . 8,51 I (1,757) 8.511 (1,757)

Total .............................. S 41.748 S (1,615) S 8.511 $ (1.757) $ 50,259 $ (3,372)

6. PROPERTY, PLANTAND EQUIPMENT The following is a summary of our property, plant and equipment balance.

As of December 31, 2014 2013 (In Thousands)

Electric plant in service .............................. $ 4,712,103 $ 4,280,481 Electric plant acquisition adjustment .......... 800,971 800,971 Accumulated depreciation .......................... (2.233.750) (2,177.560) 3,279,324 2,903.892 Construction work in progress .................... 679.600 660.479 Nuclear fuel, net .......................................... 79,637 62,960 Net property, plant and equipment ...... $ 4.038,561 $ 3.627,331

The fbllowing is a summary of property. plant and equipment of VIEs.

As of December 31, 2014 2013 (In Thousands)

Electric plant of VIEs ........................................... $ 392.100 $ 392,100 Accumulated depreciation of VIEs ...................... (194,476) (187,361)

Net property, plant and equipment of VIEs.. S 197,624 S 204,739 We revised our depreciation rates to reflect changes in the estimated useful lives of some of our assets in 2012. We recorded depreciation expense on property, plant and equipment of $101.9 million in 2014 and $95.0 million in 2013.

Approximately $7.1 million of depreciation expense in 2014 and 2013 was attributable to property. plant and equipment of the VIE.

7. JOINT OWNERSHIP OF UTILITY PLANTS Under joint ownership agreements with other utilities, we have undivided ownership interests in three 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 31,2014, 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 I (a) ...... June 1973 $ 345,866 S 157,550 $ 368,445 367 50 JEC unit 1 (b)............... July 1978 175,724 46,143 2,353 144 20 JEC unit 2 (b) ............... May 1980 121,784 46,053 694 143 20 JEC unit 3 (b) ............... May 1983 162,711 75,636 703 144 20 Wolf Creek (c) ............. Sept. 1985 1,818.005 788,602 73,333 549 47 Total ...................... $ 2,624.090 $ 1,113,984 $ 445,528 1,347 (a) Jointly owned with KCPL.

(b) Jointly owned with Westar Energy and KCPL.

(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

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 341 MW of net capacity. The VIE's investment in the 50% interest was $392.1 million and accumulated depreciation was

$194.5 million as of December 31, 2014. We include these amounts in property, plant and equipment of VIE, net on our consolidated balance sheets. See Note 15, "Variable Interest Entities," for additional information about our VIE.

8. SHORT-TERM DEBT We had no short-term debt as of December 31, 2014 and 2013. Our short-term liquidity needs are met with cash advances from Westar Energy.

In September 2014, Westar Energy extended the term of its $730.0 million revolving credit facility to terminate in September 2018, $81.4 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 two years 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, 2014, no amounts had been borrowed and $15.6 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2013, no amounts had been borrowed and $18.4 million of letters of credit had been issued under this revolving credit facility.

In 2011, Westar Energy entered into a revolving credit facility with a syndicate of banks for $270.0 million. In February 2014, Westar Energy extended the term of the $270.0 million revolving credit facility to February 2017, of which

$20.0 million of this facility will terminate in February 2016. So long as there is no default under the facility, Westar Energy 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 KGE first mortgage bonds. As of December 31, 2014 and 2013, Westar Energy had no borrowed amounts or letters of credit outstanding 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 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. Westar Energy had $257.6 million and $134.6 million of commercial paper issued and outstanding as of December 31, 2014 and 2013, 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 3 1, 2014 and 2013, was 0.52% and 0.28%, respectively.

9. LONG-TERNI DEBT Outstanding Debt The following table summarizes our long-term debt outstanding.

As of December 31.

2014 2013 (in Thousands)

First mortgage bond series:

6.70% due 2019 ............ ... .......... . . .... ...... 300,000 $ 300,000 6 .15 % d ue 20 23 ......... ... .. ..................... .......... .... ...... . ......... . .......... ... 50 ,0 00 50 .00 0 6 .531% d ue 20 37 .... ....... ... ......... . ..... ............. ......... .............................. ...... ...... . . ... . 17 5,0 00 17 5 ,0 00 6 6 4% d ue 20 38 ..... . .... .. .. .. ....... ............ . ........... ................... .................... 10 0 .0 00 10 0 ,0 00 4 .30% d u e 20 44 . . ...... . .............................. . .... ... . .... ...... . .... .. . . . ..... .. ...... .... 2 50 ,0 00 875.000 625.000 Pollution control bond series:

Variable due 2027, 0.08% as of December 31. 2014: 0. 10% as of December 3 1. 2013 21,940 21.940 5.30% due 2031 ................................................................. - 108,600 5 30% d u e 20 3 1 ........ ........................ . . . ... . .. . . .. .................................. ......... ........ - 18 ,9 00 4 85% due 2031 .............................................................. 50,000 50,000 5 .0 0% d ue 2(03 1 ........ . ............. . ............. . .............. . .......................... . . ........... ............ - 50 ,0 00 Variable due 2032, 0.08% as of December 31, 2014, 0.10% as of December 31,2013 ...... 14.500 14,500 Variable due 2032, 0.08% as of December 31, 2014, 0.10% as of December 31, 2013... 10,000 10.000 96,440 273.940 To"tal long-term d ebt ...... . ......... .... ....... ...................... . .......... .... ...................................... .. . 9 7 1,4 40 89 8 ,9 40 lJnam ortized debt discount (a) . ... ..................................................... .................. ......... (864 ) (296 )

Long-term debt, net . .... ..... .............. ....... .................... .... . . - 97 6 9 4 Variable Interest Entity 5.647% due 2021 (b) ... . ................ . 185,791 $ 208,123 A mounts due w ithin one year .......... .. ............................................ . ......... (233...........

743) (22,332)

Long-term debt of variable interest entities, net ................................ ... 5.7..

(a) We amortize debt discounts to interest expense over the term of the respective issues.

(hi Portions oftour payments related to this debt reduce the principal balances each year tntil maturiry.

Our mortgage contains provisions restricting the amount of first mortgage bonds that we could issue. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

The amount of first mortgage bonds authorized by our 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. As of December 31. 2014, approximately $1.3 billion principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage.

As of December 31, 2014, we had $46.4 million of variable rate, tax-exempt bonds. While the interest rates for these bonds have been extremely low. we continue to monitor the credit markets and evaluate our options with respect to these bonds.

In July 2014, KGE issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 4.30%

and maturing July 2044, the proceeds of which were used to retire Westar Energy first mortgage bonds in a principal amount of

$250.0 million with a stated interest of 6.00% maturing in July 2014.

In June 2014. KGE redeemed three pollution control bond series totaling $177.5 million principal amount at stated interest rates between 5.00% and 5.30%.

In June 2013, KGE redeemed two pollution control bond series with a principal amount of$100.0 million and stated interest rates at 5.60% and 6.00%.

M atu rities The principal amounts of our long-term debt maturities as of December 31. 2014, are as follows.

Long-tern Year Long-term debt debt of VIEs (In Thousands) 2015 ...................................... $S- $ 23,743 20 16 ...................................... - 25,243 20 17 ...................................... - 26,838 20 18 ...................................... - 28,534 2019 ...................................... 300,000 30,337 Thereafter ............................. 671.440 51,096 Total maturities .............. $ 971,440 $ 185,791 Interest expense on long-term debt was $44.2 million in 2014 and $46.2 million in 2013. Interest expense on long-term debt of VIE was $10.8 million in 2014 and $12.0 million in 2013.

10. TAXES Income tax expense is comprised of the following components.

Year Ended December 31, 2014 2013 (In Thousands)

Income Tax Expense (Benefit):

Current income taxes:

Federal .................................................................................. $ (170 ) $ 137 State ...................................................................................... (3 3) 29 Deferred income taxes:

Federal ................................................................................. 44.0 18 29,690 State ...................................................................................... 9,524 6 .4 35 invcstmcnt tax credit amortization ........................................... (1,886) (1,889)

Incom e tax expense ........................................................ $ 51,453 $ 34,402 Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows.

As of December 3 1, 2014 2013 (In Thousands)

Current deferred tax assets .......................... $ 23,311 $ 24,1 I5 Non-current deferred tax liabilities ............. 825,808 779,373 Net deferred tax liabilities ........................... $ 802,497 $ 755,222

The tax effect of the temporary differences and carry forwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.

As of December 31, 2014 2013 (InThousands)

Defarred tax assets:

Net operating loss carryforward (a) ............... $ 107.377 $ 80,21 1 Deferred regulatory gain on sale-leaseback ... 35,706 38.125 Deferred employee benefit costs .................... 25.952 12,627 Deferred compensation .................................. 20,951 20,809 Disallowed plant costs ................................... 10,829 11,453 La Cygne dismantling costs ........................... 9,064 8,110 Accrued liabilities .......................................... 6,818 3,966 O ther ............................................................... 17,22 1 9,373 Total deferred tax assets ......................... $ 233.918 $ 184,674 Deferred tax liabilities:

Accelerated depreciation ................................ 718,409 $ 606.667 A cquisition prem ium ...................................... 163.595 171,594 Amounts due from customers for future income taxes, net ........................................ 107,605 113.803 Deferred employee benefit costs .................... 25,952 12,627 Pension expense tracker ................................. 6,380 9,565 Debt reacquisition costs ................................. 5,769 3,831 Storm costs ..................................................... 5,533 7,382 O ther ............................................................... 3,172 14.427 Total deferred tax liabilities ............ $ 1,036,415 $ 939,896 Net deferred tax liabilities ................................... S 802.497 $ 755.222 (a) Asot December 31, 2014, we had a federal net operating loss carrylorward of $306.5 million, which is available to offset federal taxable income. The nct operating losses will expire beginning in 2031 and ending in 2034.

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.

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, 2014 2013 Statutory federal income tax rate ................................................... 35.0% 35.0%

Effect of:

Corporate-owned life insurance policies ................................ (10.4) (13.9)

State income taxes .................................................................. 3.4 2.7 Flow through depreciation for plant-related differences ........ 3.2 2.2 AFUDC equity ....................................................................... (2.3) (2.5)

Amortization of federal investment tax credits ...................... (1.0) (1.2)

Liability for unrecognized income tax benefits ...................... (0.2) (0.1)

Other ................................................................................. 0.6 (0.2)

Effective income tax rate ............................................................... 28.3% 22.0%

We are a member of Westar Energy's consolidated tax group. We file consolidated tax returns with Westar Energy.

Westar Energy allocates to us our pro rata portion of consolidated income taxes based on our contribution to consolidated taxable income. As a matter of course, the income tax returns Westar Energy files will likely be audited by the Internal Revenue Services (IRS) or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal, state and local or non-U.S. income tax examinations by tax authorities remains open for tax year 2011 and forward.

Effective January I, 2014, we adopted new regulations released by the IRS and United States Treasury Department regarding the deduction and capitalization of expenditures related to tangible property, including the tax treatment of, among other things, materials and supplies and the determination of whether expenditures with respect to tangible property are a deductible repair or must be capitalized, and regulations regarding dispositions of property under the Modified Accelerated Cost Recovery System. The adoption of these regulations did not have a material impact on our consolidated financial results.

Additionally, also effective January 1. 2014, we implemented new FASB accounting guidance regarding the presentation of an unrecognized tax benefit. An unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, similar tax loss, or a tax credit carryforward. To the extent such tax assets are not available to settle any additional income taxes that would result from the disallowance of a tax position at the reporting date, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. We adopted this guidance with retrospective application to prior periods and it did not have a material impact on our consolidated financial statements.

There were no significant changes to our unrecognized income tax benefits from December 3 1, 2013, to December 3 1, 2014. We do not expect significant changes for 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:

2014 2013 (in Thousands)

Unrecognized income tax benefits as of January I ......................................... $ 355 $ 332 Additions based on tax positions related to the current year .............................. 16 28 Additions for tax positions of prior years ...........................................................

Reductions for tax positions of prior years ............................................ :............ (5)

Settlem ents .......................................................................................................... - -

Unrecognized income tax benefits as of December 31 ...................................... $ 371 $ 355 The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate. were $0.4 million and $0.3 million (net of tax) as of December 31, 2014 and 2013, respectively.

Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of December 31, 2014 and 2013, we had no amounts accrued for interest related to unrecognized income tax benefits. We accrued no penalties at either December 31, 2014, or December 31, 2013.

As of December 31, 2014 and 2013, we had recorded $0.7 million for probable assessments of taxes other than income taxes.

I!. WOLF CREEK EMPLOYEE BENEFIT PLANS As a co-owner of Wolf Creek. we are indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. We accrue our 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 of our 47% share of the Wolf Creek pension and post-retirement benefit plans.

Pension Benefits Post-retirement Benefits As ot'December 31, 2014 2013 2014 2013 (In Thousands)

Change in Benefit Obligation:

Benefit obligation, beginning of year .......................................... $ 162,820 $ 176.891 $ 10,010 $ 11,020 S e rv ice c o st ... . . . .. . .. . .............................................................. 5,695 6,835 173 206 Interest cost .................................... 8.469 7.562 464 413 P lan participants' contributions ........................................................ - - 766 696 Benefits paid ............................................................. (5,039) (4,349) (1.292) (1.022)

Actuarial (g a in s ) lo sses .............................. .................................... 38,375 (24,119) (1.881) (1,303)

Benefit obligation, end of year ............................................. $ 210,320 $ 162.820 $ 8.240 $ 10,010 Change in Plan Assets Fair value of plan assets, beginning of year ..................................... $ 114.734 $ 98M051 $ 17 $ 13 A ctual return on plan assets ............................................................ 7.626 13,166 - -

ISm ploy e r c o ntrib utio ns ....................................... . .............. ..... ...... 7,089 7,624 515 330 Plan participants' contributions ................................................... - - 766 696 B enefits paid .................... . . . . . ........... .. ... ...................... (4,789) (4.107) (1,292) (1,022)

Fair value of plan assets, end of year ....................................... $ 124.660 $ 114,734 $ 6 $ 17 Funded status, end of year ...... ................................................... .............. (85,660) 148.0861 $ (82341 $ 9.993 Amounts Recognized in the Balance Sheets Consist of Current liability ..................... .................. $ (247) $ (237) $ (575) $ (614)

N o ncurrent liab ility ................................................................... .. (85,413) (47.849) (7,659) 19.379)

Net am ount recognized ...................................................... ........ $ (85,660) $ (48,086 (8,2341 $ (.9931 Amounts Recognized in Regulatory Assets Consist of:

Net ac tuaria l lo ss ... .................. ..... ........ ............................ ... $ 65,049 $ 29,203 $ 29 $ 2.076 Prior service cost ....................... .................................. 559 617 - -

Net am ount recognized ........................................................ $ 65.608 $ 29,820 $ 29 $ 2,076

Pension Benefits Post-retirement Benefits As ot December 3 1, 2014 2013 2014 2013 (Dollars inThousands)

Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:

Projected benefit obligation ................... ..................................... 210,320 S 162,820 $ $

Fair value of plan assets .......... .. . ..... .. ........................... 124,660 114734 Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets.

Accumulated benefit obligation ..................................... $ 179.228 $ 137,459 -- $

Fa ir value o t'plan assets ......................................... .................. 124.660 114.734 Post-retirentent Plans With an Accumulated Post-retirentcnt Benefit Obligation In Excess of Plan Assets:

Accumulated post-retirement benefit obligation ............... -- $ 8,240 S 10,010 Fair value of plan assets ......... ..................................... 6 16 Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation D isc o u nt ra te .................................................................... .. ........ 4.20,o 5.11% 3 89% 4.70%

Com pensation 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, 2014. increased Wolf Creek's pension and post-retirement benefit obligations by approximately $26.9 million and $0.6 million, respectively.

Wolf Creek utilizes actuarial assumptions about mortality to calculate the pension and post-retirement benefit obligations. In 2014, revised mortality tables were published which reflect improved life expectancies based on past experience and future projections. Wolf Creek adopted the revised mortality tables as of December 31, 2014, resulting in an increase to the pension and post-retirement benefit obligations by approximately $11.3 million and $0.2 million, respectively.

The prior service cost (benefit) 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 our 47% share of the Wolf Creek pension and other post-retirement benefit plans.

Pension Benefits Post-retirement Benefits Year Ended December 3), 2014 2013 2014 2013 (Dollars in Thousands)

Components of Net Periodic Cost I Benefit):

Serv ice cost .......................................... 5,695 $ 6.835 $ 173 $ 206 Interest cost .......................... 8,469 7.562 464 413 Expected return on plan assets ................... (8,084) t7.373)

Amortization of unrecognized:

Prior service costs ................................ 58 58 - -

A ctuarial loss, net ................................. 2.987 5,421 165 265 Net periodic cost before regulatory ad ju stm e n t ........................................... 9,125 12,503 802 884 Regulatory adjustment (a) ............................... 2,328 (641) - -

Net periodic cost ............................................ $ 11.453 $ 11,862 S 802 $ 884 Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:

Current year actuarial (gain) loss ............... $ 38,833 $ (29,911) $ (1,881) $ (1,303)

Amortization of actuarial loss (gain) ............ (2,987) (5,421) (165) (265)

A inortization of prior service cost ................ (58) (58) - -

Total recognized in regulatory assets .............. $ 35.788 $ (35,390) $ (2.046) $ 1I,568)

Total recognized in net periodic cost and regulatory assets ...................... $ 47.241 $ (23.528) $ (1,244) $ (684)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:

Discount rate ........................... 5.11% 4.16% 4.70% 3.78%

Expected long-term return on plan assets. 7.50% 7.50%

Compensation rate increase ................. .... 4.00% 4.00%

a) The regulatory adjustment represents the difference betveen 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 into net periodic cost in 2015.

Pension Post-retirement Benefits Benefits (In Thousands)

Actuarial loss ...................... $ 5,930 $ 2 Prior service cost ................... 57 -

Total ................................ $ 5,987 $ 2 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.

As of December 3 1, 2014 2013 Health care cost trend rate assumed for next year ...................................................... 7.0% 7.5%

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 ultim ate trend rate ......................................................... 2019 2019 The health care cost trend rate affects the projected benefit obligation. A I% change in assumed health care cost growth rates would have effects shown in the following table.

One-One- Percentage-Percentage- Point Point Increase Decrease (In Thousands)

Effect on total of service and interest cost ........... $ (8) $ 8 Effect on post-retirement benefit obligation ........ (III) 113 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 3 1%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, private equity funds 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. However, level 3 investments in real estate funds and alternative funds are invested in underlying investments that are illiquid and require significant judgment when measuring them at fair value using market- and income-based models.

Significant unobservable inputs tbr underlying real estate investments include estimated market discount rates, projected cash flows and estimated value into perpetuity. Alternative funds invest in a wide range of investments typically with low correlations to traditional investments.

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 4, "Financial Instruments and Risk Management," for a description of the hierarchal framework.

The following table provides the fair value of our share of WolfCreek's pension plan assets and the corresponding level of hierarchy as of December 3 1, 2014 and 2013.

As of December 31, 2014 Level I Level 2 Level 3 Total (In Thousands)

Assets:

Domestic equity funds ...................... S -- $ 31,580 $ - $ 31,580 International equity funds ................. - 38,624 - 38,624 Core bond funds ............................... 31,854 - 31.854 Real estate securities fund ................ - 6.313 5,649 11,962 Commodities fund ............................ - 5,887 - 5,887 Alternative investment fund ............. - - 4,309 4,309 Cash equivalents ............................... 444 - 444 Total Assets Measured at Fair Value ....... $ - S 114,702 $ 9,958 S 124,660 As of December 31, 2013 Assets:

Domestic equity funds ...................... $ - $ 30,599 $ - $ 30,599 International equity funds ................. - 36,868 - 36,868 Core bond funds ............................... - 26,926 *- 26,926 Real estate securities fund ................ - 5,440 5,094 10,534 Commodities fund ............................ - 5,245 - 5,245 Alternative investment fund ............. - 4.147 4.147 Cash equivalents ............................... - 415 - 415 Total Assets Measured at Fair Value ....... $ $ 105,493 S 9,241 S 114.734

The following table provides a reconciliation of our share of Wolf Creek's pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2014 and 2013.

Real Estate Alternative Securities Investment Fund Fund Total (In Thousands)

Balance as of December 31, 2013 ...................................... $ 5,094 $ 4.147 $ 9,241 Actual gain on plan assets:

Relating to assets still held at the reporting date ......... 555 162 717 Balance as of December 31, 2014 ...................................... $ 5.649 $ 4,309 $ 9,958 Balance as of December 31, 2012 ...................................... $ 4,541 $ 3,900 $ 8,441 Actual gain on plan assets:

Relating to assets still held at the reporting date ......... 553 247 800 Balance as of December 31, 2013 ...................................... $ 5,094 $ 4,147 $ 9,241 Cash Flows The following table shows our expected cash flows for our share of Wolf Creek's pension and post-retirement benefit plans for future years.

Expected Cash Flows Pension Benefits Post-retirement Benefits (From) (From) ro/(From) Trust Company Assets To/(From) Trust Company Assets (In Millions)

Expected contributions:

20 15 .................................. S 4.7 $ 0.6 Expected benefit paymcnts:

2015 ................ ... ..... $ (5.4) $ (0.2) $ (0.6) S -

2016 .................................. (6.1) (0.2) (0.6) -

20 17 .................................. (6.8) (0.2) (0.6) -

20 18 .................................. (7.5) (0.2) (0.6) -

2019 .................................. (8.2) (0.2) (0.7) -

2020 - 2024 ....................... (51.0) (1. 1) (3.2) -

Savings Plan Wolf Creek maintains a qualified 401(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.

Our portion of the expense associated with Wolf Creek's matching contributions was $1.4 million in 2014 and $1.4 million in 2013.

12. 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, Purchased Power and Transmission Commitments." These commitments relate to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments as of December 3 1, 2014, was as follows.

Committed Amount (In Thousands) 20 15 .................................................... $ 110,169 20 16 .................................................... 34.222 20 17 .................................................... 6 ,15 5 T hereafter ............................................ 26,566 Total amount committed .............. S 177,112 Environmental Matters Air Emissions We must comply with the federal Clean Air Act, state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (SO,), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO). mercury and acid gases.

Emissions from our generating facilities, including PM. SO, 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 SO, 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. If we exceed these limits we could be subject to fines and penalties. In order to meet SO: 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 SO: 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 SO, emissions for that year. In 2014, we had adequate SO, allowances to meet planned generation and we expect to have enough to cover emissions under this program in 2015.

Cross-State Air Pollution Rule In 201 I, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) requiring 28 states, including Kansas, Missouri and Oklahoma, to further reduce emissions of SO_, NOx and fine PM. In April 2014. the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia Circuit that had vacated CSAPR and remanded CSAPR back to the U.S. Court of Appeals for further proceedings consistent with the U.S. Supreme Court decision.

In June 2014, the U.S. Department of Justice. on behalf of the EPA. filed a motion to lift the CSAPR stay. In October 2014, the U.S. Court of Appeals granted the motion to lift the CSAPR stay and established a schedule to hear arguments on the remaining outstanding issues beginning in March 2015. During the CSAPR stay, wc installed various emission controls at our generation facilities and have projects for additional controls in progress or planned that will reduce the impact of CSAPR. We are unable to determine the full impact of reinstatement of CSAPR until the U.S. Court of Appeals and the EPA take further action, however, we are prepared to comply with CSAPR in its current form.

National Ambient Air Quality Standards Under the federal Clean Air Act, the EPA sets National Ambient Air Quality Standards (NAAQS) for certain emissions considered harmful to public health and the environment, including two classes of PM, NOx (a precursor to ozone). CO and SO,, 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. KDHE, our state environmental regulatory agency, proposed to designate portions of the Kansas City area nonattainment for the eight-hour ozone standard.

The EPA has not acted on KDHE's proposed designation of the Kansas City area and it is uncertain when. or if, such a designation might occur. The Wichita area also exceeded the eight-hour ozone standard and could be designated nonattainment in the future potentially impacting our operations. Nonattainment designations on areas that impact our operations could have a material impact on our consolidated financial results.

In 2010, the EPA strengthened the NAAQS for both NOx and SO,. We continue to communicate with our regulators regarding these standards and are currently evaluating what impact this could have on our operations and consolidated financial results. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results.

In December 2014. the EPA published a proposed rule revising NAAQS for ozone and to make certain other changes, including extending the ozone monitoring season by at least one month. The EPA intends to issue a final rule regarding the ozone NAAQS by October 2015 and make attainment/nonattainment designations for any revised standards by October 2017.

We are currently reviewing this proposed new standard and cannot at this time predict the impact it may have on our operations, but it could be material.

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 cannot at this time predict the impact this designation may have on our operations or consolidated financial results, but it could be material.

Mercury and Air Toxics Standards The operation of power plants results in emissions of mercury, acid gases and other air toxics. In 2012, the EPA's Mercury and Air Toxics Standards (MATS) for power plants became effective, replacing the prior federal Clean Air Mercury Rule (CAMR) and requiring significant reductions in mercury, acid gases and other emissions. Several lawsuits challenging MATS have been filed by other parties and consolidated into a single proceeding before the U.S. Court of Appeals for the District of Columbia Circuit. In April 2014, the U.S. Court of Appeals issued an opinion upholding MATS. In July 2014, numerous states and two trade groups petitioned the U.S. Supreme Court to review this opinion, and in November 2014, the U.S. Supreme Court agreed to such review. The U.S. Supreme Court is expected to rule by June 2015; however, we currently cannot predict the outcome of this litigation, or its impact, if any, on our MATS compliance planning. Nonetheless, we expect to be compliant with the MATS in its current form by April 2016 as currently approved by KDHE. We currently believe that our related investment, based on MATS in its current form, will not be significant.

Greenhouse Gases Byproducts of burning coal and other fossil fuels include carbon dioxide (CO,) and other gases referred to as greenhouse gases (GHGs), which are believed by many to contribute to climate change. The EPA is currently, and has further proposed, using the federal Clean Air Act to limit CO, 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.

In January 2014, the EPA re-proposed a New Source Performance Standard that would limit CO 2 emissions for new coal and natural gas fueled electric generating units. The re-proposal would limit CO, emissions to 1,000 lbs per MWh Cenerated for larger natural gas units and 1.100 lbs per Megawatt hour (MWh) generated for smaller natural gas units and coal units. The EPA issued proposed standards addressing CO, emissions for modified, reconstructed and existing power plants in June 2014. The standards for existing plants is known as the Clean Power Plan. The EPA anticipates issuing final rules for new, modified, reconstructed and existing power plants by summer 2015 and requiring states to submit their implementation state plans to the EPA by no later than summer 2016. The EPA is expected to propose in summer 2015 a federal plan that will implement the Clean Power Plan to be used for states that fail to submit adequate state plans, with such federal plan expected to be finalized by summer 2016. While the Clean Power Plan is not yet final, various legal and judicial challenges to it have been filed. We cannot at this time determine the impact of such proposals on our operations or consolidated financial results, but we believe the costs to comply could be material.

Under regulations formerly known as the Tailoring Rule, the EPA regulates GHG emissions from certain stationary sources. The regulations are implemented pursuant to two federal Clean Air Act programs, the Prevention of Significant Deterioration (PSD) and Title V Operating Permit Programs, that impose recordkeeping and monitoring requirements and also mandate the implementation of best available control technology (BACT) for projects that cause a significant increase in GHG emissions (currently defined to be more than 75.000 tons or more per year or 100,000 tons or more per year, depending on various factors). In June 2014, the 11.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme Court also held that the EPA could impose GHG BACT requirements for sources already required to implement PSD for other pollutants. Therefore. if future modifications to our sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these regulations on our future operations or consolidated financial results as the rule has not been finalized, but we believe the cost of compliance with the regulations 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 are expected to be issued by the EPA by the end of September 2015. Although we cannot at this time determine the timing or impact of compliance with any new regulations, more stringent regulations could have a material impact on our operations or consolidated financial results.

In October 2014. the EPA's final 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 Technology Available 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 LaCygne 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 financial results, but we do not expect it to be material.

In April 2014, the EPA along with the U.S. Army Corps of Engineers issued a proposed rule defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the proposal, which could impact several permitting programs. Although we cannot at this time determine the timing or impact of compliance with any new regulations, more stringent regulations could have a material impact on our operations or consolidated financial results.

Regulation of Coal Combustion Byproducts In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs). including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. In 2010, the EPA proposed a rule to regulate CCB by the federal government. The EPA released a pre-publication version of the rule in December 2014, which we believe will require additional CCB handling, processing and storage equipment and potential closure of certain ash disposal areas, but it has not yet published the final rule. While we cannot at this time estimate the impact and costs associated with future regulations of CCB. we believe the impact on our operations or consolidated financial results could be material.

Environmental Projects We will continue to make significant capital and operating expenditures at our power plants to reduce regulated emissions. The amount of these expenditures could change materially depending on the timing and nature of required investments, the specific outcomes resulting from existing regulations, new regulations, legislation and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce the net production, reliability and availability of the plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of such capital investments.

We are currently permitted to recover certain of these costs through the ECRR, which, in comparison to a general rate review, reduces the amount of time it takes to begin collecting in retail prices the costs associated with capital expenditures for qualifying environmental improvements. We are not allowed to use the ECRR to collect approximately $610.0 million of the projected capital investment associated with the environmental upgrades at La Cygne. In November 2013. the KCC issued an order allowing us to adjust our prices to include the additional investment in the La Cygne environmental upgrades and to reflect cost reductions elsewhere. The new prices are expected to increase our annual retail revenues by approximately

$14.8 million. To change our prices to collect increased operating and maintenance costs, we must file a general rate review with the KCC. We intend to file our next general rate review in March 2015. In addition, the installation ofnew equipment may cause us to reduce the net production, reliability and availability of our plants. Furthermore, enhancements to our power plants, even if they result in greater efficiency, can trigger a regulatory review, which could result in increased costs or other operational requirements. For additional information regarding our abbreviated rate review, see Note 3, "Rate Matters and Regulation."

EPA Consent Decree As part of a 2010 settlement of a lawsuit filed by the U.S. Department of Justice on behalf of the EPA, we completed installation of selective catalytic reduction equipment on one of our three JEC coal units in December 2014, at a cost of approximately $225.0 million. We also completed installation of less expensive NOx reduction equipment on the other two units to satisfy other terms of the settlement. We plan to recover the costs of installing these systems through our ECRR, but such recovery remains subject to the approval of our regulators.

Renewable Energy Standard Kansas law mandates that Westar Energy maintain a minimum amount of renewable energy sources. Through 2015, net renewable generation capacity must be 10% of the average peak retail demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. With Westar Energy's existing wind generation facilities, supply contracts and renewable energy credits, it is able to satisfy the net renewable generation requirement through 2015. With its agreements to purchase an additional 400 MW of installed design capacity from wind generation facilities beginning in 2015 through 2016, it expects to meet the increased requirements for 2020 and thereafter. If Westar Energy is unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

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 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, Wold 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 financial 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

$2.8 million in 2014 and $2.9 million in 2013. We record our investment in the NDT fund at fair value, which approximated

$185.0 million and $175.6 million as of December 31, 2014 and 2013, 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. Wolf Creek paid into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. In November 2013. a federal court of appeals ruled that the DOE must stop collecting this fee effective May 2014. Our share of the fee, calculated as one tenth of a cent for each kilowatt-hour of net nuclear generation delivered to customers, was $0.8 million in 2014 and $3.0 million in 2013. We include these costs in fuel and purchased power expense on our consolidated statements of income.

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 of 2011 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. Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025 and believes it will be able to expand on-site storage as needed past 2025. We cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.

Wolf Creek disposes of most of its low-level radioactive waste at an existing third-party repository in Utah, which we expect will remain available to Wolf Creek. Wolf Creek also contracts with a waste processor to process, take title and dispose in another state most of the remainder of Wolf Creek's low-level radioactive waste. Should on-site waste storage be needed in the future. Wolf Creek has storage capacity on site adequate for approximately four years of plant operations and believes it would be able to expand that storage capacity if needed.

Nuclear Insurance We maintain nuclear liability, property, and business interruption 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 plus any reinsurance, indemnity or any other source recoverable by Nuclear Electric Insurance Limited (NEIL), our property and business interruption 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 may be required to participate in industry-wide retrospective assessment programs as discussed below.

Nuclear Liability Insurance Pursuant to the Price-Anderson Act, which has been reauthorized through December 31, 2025, by the Energy Policy Act of 2005. we are required to insure against public liability claims resulting from nuclear incidents to the current limit of public liability, which is approximately $13.6 billion. This limit of liability consists of the maximum available commercial insurance of $375.0 million and the remaining $13.2 billion is provided through mandatory participation in an industry-wide retrospective assessment program. In addition, Congress could impose additional revenue-raising measures to pay claims.

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. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in 2018.

Nuclear Property and Business Interruption Insurance The owners of Wolf Creek carry decontamination liability, premature nuclear decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. 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 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 tinder the current policies of approximately $39.5 million (our share is $18.6 million).

Accidental Nuclear Outage Insurance Although we maintain various insurance policies to provide coverage for potential losses 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, Purchased Power and Transmission 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 tbr price escalation and minimum purchase commitments. As of December 31, 2014, our share of Wolf Creek's nuclear fuel commitments was approximately $27.1 million for uranium concentrates expiring in 2017.

$4.1 million for conversion expiring in 2017, $93.3 million for enrichment expiring in 2025 and $33.3 million for fabrication expiring in 2023.

As of December 3 1, 2014. our coal and coal transportation contract commitments under the remaining terms of the contracts were approximately $156.5 million. The contracts are for plants that we operate and expire at various times through 2020.

As of December 31, 2014, our natural gas transportation contract commitments under the remaining terms of the contract were approximately $2.9 million. The contract expires in 2020.

We have acquired rights to transmit a total of 100 MW of power with such rights expiring in 2016. As of December 3 I, 2014, we are comm itted to spend approximately $4.4 million over the remaining terms of these agreements.

13. 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. The recording of ARis 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 47% share), dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl (PCB)-contaminated oil.

The following table summarizes our legal AROs included on our consolidated balance sheets in long-term liabilities.

As of December 31, 2014 2013 (In Thousands)

Beginning ARO ............................ $ 152,747 $ 144,418 Increase in nuclear decommissioning ARO liability ...... 50,683 -

Increase in other ARO liabilities .................................... 1,935 -

Liabilities settled .................. ........ ......... (284) (253)

A ccretion expense .......................................................... 9,592 8,582 Ending A RO ............................................................ $ 214,673 $ 152,747 Wolf Creek filed a nuclear decommissioning cost study with the KCC in 2014. As a result of the study, we recorded a

$50.7 million increase in our ARO to reflect revisions to the estimated costs to decommission Wolf Creek.

Conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We determined that our conditional AROs include the disposal of asbestos insulating material at our power plants, the remediation of ash disposal ponds and the disposal of PCB-contaminated oil.

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."

We operate, as permitted by the state of Kansas, ash landfills at several of our power plants. The retirement obligation for the ash landfills was 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. 2014 and 2013. we had $47.5 million and $55.8 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.

14. LEGAL PROCEEDINGS We 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 Note 3, "Rate Matters and Regulation," and Note 12, "Commitments and Contingencies,"

for additional information.

15. VARIABLE INTEREST ENTITIES In determining the primary beneficiary of a 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. Accounting guidance effective in 2010 requires the primary beneficiary of a VIE to consolidate the VIE. The trust holding our 50% interest in La Cygne unit 2 is a VIE 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 VIE 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.

50% Interest in La Cygne Unit 2 Under an agreement that expires in September 2029, we entered into a sale-leaseback transaction with a trust under which the trust purchased our 50% interest in La Cygne unit 2 and subsequently leased it back to us. 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 us, 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 ( I ) the operation and maintenance of the 50% interest in La Cygne unit 2, (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 50% interest in La Cygne unit 2 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.

Financial Statement Impact We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above.

As of As of December 3 1, 20H1 December 3 1, 2013 (In Thousands)

Assets:

Property, plant and equipment of variable interest entity, net .......... $ 197,624 S 204,739 Liabilities:

Current maturities of long-term debt of variable interest entity ....... S 23,743 S 22,332 Accrued interest (a) ........................................................................... 2,623 2,938 Long-term debt of variable interest entity, net .................................. 162.048 185,791 (a) 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 VIE can be used only to settle obligations of the VIE and the VIE's debt holders have no recourse to our general credit. We have not provided financial or other support to the VIE and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIE.

16. RELATED PARTY TRANSACTIONS We are a wholly-owned subsidiary of Westar Energy. Westar Energy provides all employees we use. Our cash management function, including cash receipts and disbursements, is performed by Westar Energy. Certain operating expenses have been allocated to us from Westar Energy. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers and/or other appropriate factors. We believe such allocation procedures are reasonable. Expenses allocated to us by Westar Energy may not reflect what our costs would be if we were not a wholly-owned subsidiary, which would affect our consolidated financial results. Our prices are set based on consolidated filings with Westar Energy.

We and Westar Energy have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions consist primarily of power purchases and sales between us and Westar Energy. As a result of such transactions, we had a receivable of $156.0 million as of December 31, 2014 and a payable of $106.0 million as of December 3 I, 2013. respectively.

For the years ended December 31, 2014 and 2013, Westar Energy made an additional investment in us of approximately $415.0 million and $300.0 million, respectively. We declared and recorded dividends of$100.0 million to Westar Energy in 2014. We did not declare or record any dividends to Westar Energy in 2013.

Enclosure II to CO 15-0003 Kansas City Power & Light Company Consolidated Statements of Cash Flows (2 pages)

April 30, 2015 Wolf Creek Nuclear Operating Corporation PO Box 411 Burlington, KS 66839

Dear Todd:

Pursuant to the requirements of 10 CFR 140.21(e), Kansas City Power & Light Company, is providing the attached audited Consolidated Statements of Cash Flows as evidence of the ability to make payment of its share of deferred premiums in an amount of $8.9 million.

The undersigned certifies that the foregoing memorandum with respect to Kansas City Power & Light Company's cash flow for the year 2014 is true and correct to the best of their knowledge and belief.

Sincerely, Steve P.d Busser Vice President - Business Planning and Controller attachment KCP&L RO. Box 418679 Kansas City, MO 64141-9679 1-888-471-5275 toll-free www.kcpl.com

KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Cash Flows Year Ended December 31 2014 Cash Flows from Operating Activities (millions)

Net income $ 162.4 Adjustments to reconcile income to net cash from operating activities:

Depreciation and amortization 213.9 Amortization of:

Nuclear fuel 26.1 Other 29.3 Deferred income taxes, net 88.4 Investment tax credit amortization (1.0)

Other operating activities (64.7)

Net cash from operating activities 454.4 Cash Flows from Investing Activities Utility capital expenditures (635.9)

Allowance for borrowed funds used during construction (11.1)

Purchases of nuclear decommissioning trust investments (27.5)

Proceeds from nuclear decommissioning trust investments 24.2 Proceeds from sale of transmission assets 4.7 Other investing activities ((15.2)

Net cash from investing activities (660.8)

Cash Flows from Financing Activities Issuance fees (0.4)

Net change in short-term borrowings 265.1 Net money pool borrowings 12.4 Dividends paid to Great Plains Energy (72.0)

Net cash from financing activities 205.1 Net Change in Cash and Cash Equivalents (1.3)

Cash and Cash Equivalents at Beginning of Year 4.0 Cash and Cash Equivalents at End of Year $ 2.7

Enclosure III to CO 15-0003 Kansas Electric Power Cooperative, Inc. Statement of Cash Flows (2 pages)

P.O. Box 4877, Topeka, KS 66604-0877 Kansas Electric 600 Corporate View, Topeka, KS 66615 Phone (785) 273-7010 Fax (785) 271-4888 Power Cooperative, Inc. www.kepco.org April 21, 2015 Mr. Todd N. Laflin Wolf Creek Nuclear Operating Corporation P.O. Box 411 Burlington, KS 66839

Dear Todd:

Pursuant to the requirements of 10 CFR 140.21(e), Kansas Electric Power Cooperative, Inc. is providing the attached audited Statements of Cash Flows as evidence of the ability to make payment of its share of deferred premiums in an amount of $1.137 million.

The undersigned certifies that the foregoing memorandum with respect to Kansas Electric Power Cooperative, Inc.'s. Cash flow for the year 2014 is true and correct to the best of their knowledge and belief.

Sincerely yours, Coleen M. Wells VP and CFO Enclosure (1)

KANSAS ELECTRIC POWER COOPERATIVE. INC CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ending December 31.

2014 2013 Cash Flows From Operating Activities Net margin S 3,492.432 S 2.593,780 Adjustments to reconcile net margin to net cash flows from operating activities Depreciation and amortization 7,028,254 6,540.599 Decommissioning 1,495,700 2.904,092 Amortization of nuclear fuel 3,240,394 2.819,442 Amortization of deferred charges 4,122.662 4,175.257 Amortization or deferred incremental outage costs 5.668.059 5,386,940 Amortization of debt issuance costs 67.609 77.813 Changes in Member accounts receivable (8,376,832) 7.609.332 Materials and supplies (635,064) (485,950)

Other assets and prepaid expense 35.701 106.504 Accounts payable (323,319) 599,854 Payroll and payroll-related liabihties 14,479 (102,839)

Accrued property tax (148,104) (67,149)

Accrued interest payable (45.34 1) 12,556 Accrued income taxes 3,518 1,092 Other long-term liabilities 445.958 1.147,579 Prepaid pension cost ,172,371 (1,545,694)

Deferred revenue 2.100.898 1.224.424 Net cash flows from operating activities 18.659.375 32.997,632 Cash Flows From Investing Activities Additions to electrical plant (15.556.312) (17.278,012)

Additions to nuclear fuel (5,243.757) (503.127)

Reductions in deferred charges 74.656 95.335 Additions to deferred incremental outage costs (594,202) (10,359,443)

Investments in decommissioning fund assets (1.533.935) (2,942.327)

Proceeds from associated organizations 339.892 17,442 Investments in bond reserve assets (24,918) (26,164)

Proceeds from the sale of property 14,402 41 ,837 Net cash flows from investing activities (22.424.174) (30,954.459)

Cash Flows From Financing Activities Principal payments on long-term debt (19.429.155) (20.168,539)

Proceeds from issuance of long-term debt 25,993,166 11,594,273 Short term notes payable (5.071.000) 6,500,000 Payments unapplied (1.707.113) 2.388,503 Net cash flows from financing activities (2 14.102) 314,237 Net (decrease) increase in cash and cash equivalents (3,978,901) 2.357.410 Cash and Cash Equivalents, Beginning of Year 5.181.544 2,824.134 Cash and Cash Equivalents. End of Year S 1.202.643 $ 5.l81.5t44 Supplemental Disclosure of Cash Flow Information Interest paid S 9.868.600 S 9.776.900

Retrieved from "https://kanterella.com/w/index.php?title=ML15132A653&oldid=2033514"