ML16133A334
| ML16133A334 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 05/05/2016 |
| From: | Stull A Wolf Creek |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| CO 16-0002 | |
| Download: ML16133A334 (50) | |
Text
~\ ,,;:
J( ...
'1,,
NUCLEAR OPERATING CORPORATION May 5, 2016 Annette F. Stull Vice President and Chief Administrative Officer co 16-0002 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555
Subject:
Docket No. 50-482: Guarantee of Payment of Deferred Premiums 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 Cynthia R. Hafenstine (620) 364-4204.
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 Ill Kansas Electric Power Cooperative, Inc. Statement of Cash Flows cc: M. L. Dapas (NRC), w/e C. F. Lyon (NRC), w/e
, N. H. Taylor (NRC), w/e Senior Resident Inspector (NRC), w/e P.O. Box 411 I Burlington, KS 66839 I Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET
Enclosure I to CO 16-0002 Kansas Gas and Electric Company Consolidated Statements of Cash Flows (42 pages)
April 26, 2016 Mr. Todd N. Laflin Wolf Creek Nuclear Operating Corporation PO Box 411 Burlington, KS 66839
Dear Todd:
Pursuant to the requirements of 10 CFR 140.2l(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 2015, is true and correct to the best of his knowledge and belief.
Kevin L. Kongs Vice President, Controller Westar Energy, Inc.
lms attachment 818 S Kansas Ave I PO Box 889 /Topeka, KS 66601-0889 / (785) 575-6300
Kansas Gas and Electric Company Consolidated Financial Statements Consolidated Financial Statements for the Years Ended December 31, 2015 and 2014, and Independent Auditors' Report 1
TABLE OF CONTENTS CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014: Page Independent Auditors' Report Consolidated Balance Sheets Consolidated Statements of Income Consolidated Statements of Cash Flows Consolidated Statements of Changes in Eguity Notes to Consolidated Financial Statements 2
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, 2015 and 2014, 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 ~ssessments, 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 fmancial 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, 2015 and 2014, 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.
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
Asof Asof December 31, 2015 December 31, 2014 ASSETS CURRENT ASSETS:
Accounts receivable, net of allowance for doubtful accounts of$2,863 and $2,859, respectively *...*. $ 105,005 $ 106,843' Receivable from affiliates ***..*..*.*........*...*.*...................*.*..*..*...............*..........**.*.*..*..... 21,767 156,002 Fuel inventory and supplies *...*....*.*.*......*..*..............*.**...*.*..*.*..*.*.***...*......*.*.....***......... 125,360 103,349 Prepaid expenses ....*....*..***.**...*....***.*......*...*.....*......*****.*.............***.*..*.....*......**.**.*.... 5,622 5,363 Regulatory assets ...........*......*..*.**...*......*...*....*.*.....................*...................*****.*...*..... 38,637 21,752 Other 3,409 4,850 Total Current Assets 299,800 398,159 PROPERTY, PLANT AND EQUIPMENT, NET 4,211,884 4,038,561 PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITY, NET 190,509 197,624 OTHER ASSETS:
Regulatory assets 298,066 303,230 Nuclear decommissioning trust 184,057 185,016 Other 63,362 61,621 Total Other Assets 545,485 549,867 TOTAL ASSETS $ 5;1.47,678 $ 5,184,211 LIABILITIES AND EQUITY CURRENT LIABILITIES:
Current maturities oflong-tenn debt of variable interest entity $ 25,243 $ 23,743 Accounts payable 89,628 102,505 Accrued interest 43,319 44,303 Accrued taxes 28,602 24,455 Regulatory liabilities 12,386 22,497 Customer deposits 9,113 15,044 Other 10,770 3,336 Total Current Liabilities 219,061 235,883 LONG-TERM LIABILITIES:
Long-tenn debt, net 963,967 963,278 Long-term debt of variable interest entity, net 136,805 162,048 Deferred income taxes 852,938 802,496 Unamortized investment tax credits 28,992 30,793 Regulatory liabilities .......**..**.*.......*...............**.............*................*............................. 176,858 213,188 Asset retirement obligations ...*..*....................*........*......................*........*......*............... 249,769 214,673 Other.......**..*****............**.**..*....*.............*....*............***..*................*....................*.... 136,386 136,290 Total Long-Term Liabilities************************************************************************************------- 2,545,715 - - - -2,522,766 COMMITMENTS AND CONTINGENCIES (See Notes 3, 12 and 14)
EQUITY:
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
- J Paid-in capital ..........*...........................*.*.....*.......*...**.........*....*.*.................*.*.... 1,095,457 1,095,457 Retained earnings ............*..*.......*..............*..*....*.........*****.*..*...*.........*......*.......... 387,367 333,850 Total Kansas Gas and Electric Company Shareholder's Equity .....*...*..*..............*..**.
2,548,458 2,494,941 Noncontro!ling Interest ........*......*..*...........*.*.......................*............................*....*...... (65,556) (69,379)
Total Equity ................*.*.*..*...*......*.......***.*....*....*.**.*..................*.****.*.........
2,482,902 2,425,562 TOTAL LIABILITIES AND EQUITY ............*..**.......*.........*...*...**..................**...*...*...........*. $
5;1.47,678 $ 5,184,211
==
The accompanying notes are an integral part of these consolidated financi!ll statements.
4
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 2015 2014 REVENUES ..*.........*.*...*...*...***.*.....*..*.........*****.*.*...*...***.......*............*.*.*..... .$ 1,041,109 $ 1,108,470 OPERATING EXPENSES:
Fuel and purchased power .......................................................................... . 202,296 278,064 SPP transmission network costs ...................*...........*.*..*.***.................*......... 114,522 109,462 Operating and maintenance ..............**...................................*..*.*................. 176,848 204,240 Depreciation and amortization ........*.....*.........*..............*..*.........................*. 136,019 123,653 Selling, general and administrative ....*...*....................*.....*.............*.............. 116,692 117,673 Taxes other than income tax ..................*.................**............................*...... 45,545 43,958 Total Operating Expenses *.............................*..............*...............*..*....
791,922 877,050 INCOME FROM OPERATIONS ........................................................................ .
249,187 231,420 OTHER INCOME (EXPENSE):
Other income ............*...*.............*............*...*.....................*.*............*....*. 18,586 26,246 Other expense ......................................................................................... . (17,637) (18,388)
Total Other Income *.......*..*.*.............*.*..............*...........*.***....*....*...........*.*****..
949 7,858 Interest expense .............................................................................................. . 63,788 57,311 INCOME BEFORE INCOME TAXES ................................................................. .
186,348 181,967 Income tax expense........*.....*..........................*.....****...*........*......................*..*. 54,008 51,453 NETINCOME .*.*.................*.................*...............*...*.*...................*..............
132,340 130,514 Less: Net income attributable noncontrolling interest ..........*.*...*............*.**......*.....
to 3,823 2,503 NET INCOME ATTRIBUTABLE TO KANSAS GAS AND ELECTRIC COMPANY .*.*.. .$
128,517 $ 128,011 The accompanying notes are an integral part of these consolidated financial statements.
5
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 2015 2014 CASH FWWS FROM (USED IN) OPERATING ACTIVITIES:
Net income ..........*.....*......*.**...*....*...**..*.**.*..........*..*..*.*.............*..***.*.*...*.*........ .$ 132,340 $ 130,514 Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization .........*....*.*..........................*.......................**...... 136,019 123,653 Amortization of nuclear fuel *..*.....*...........*.*..*.........*.............*.......*.....*...*....*... 26,974 26,051 Amortization of deferred regulatory gain from sale leaseback .................................. .. (5,495) (5,495)
Amortization of corporate-owned life insurance ..**....*.........................................*.. 17,958 18,402 Net deferred income taxes and credits ................*............*..................*....*........... 53,886 51,656 Allowance for equity funds used during construction *..*...*..........................*.*......... (1,684) (12,182)
Changes in working capital items:
Accounts receivable ...*.....*...*.....*.*...*.....................**...............*.........*..*.......... (625) (8,127)
Fuel inventory and supplies .................................*...*...........*............................ (21,986) (7,272)
Prepaid expenses and other .........................*....*....*.....**.*.................*..........*..*.. (19,576) 41,081 Accounts payable ....*..............................................*....*.*...*.........**...*............. (3,236) 18,858 Other current liabilities ........*..*...**...*.................**...*...*****..........................**.... (60,934) (36,769)
Changes in other assets .....*........*..**...*.*................................*...*...*..*............*......... 3,806 (1,651)
Changes in other liabilities ....*..**....***.*.*.....................*.....*............*.*..*..*..*.............. 7,331 4,697 Cash Flows from Operating Activities ................*.......*.*....*..*..................*...**.*..................
264,778 CASH FWWS FROM (USED IN) INVESTING ACTIVITIES:
343,416 Additions to property, plant and equipment ..........*...........*.........................**.*..*........*.. (343,672) (485,625)
Purchase of securities - trust .....**..*....*............*....................*..................*.......*......... (36,846) (9,075)
Sale of securities - trust .....*.**...........*......*..*...................*...............................*........ 35,194 9,094 Investment in corporate-owned life insurance .**.........................*.........*................*.*.*.*. (14,845) (15,934)
Proceeds from investment in corporate-owned life insurance ............*............................... 66,421 42,733 Advance to parent .................*............*..**.... ~ .**.*...................*......*.*.........**.****....... 133,985 (156,002)
Other investing activities ......*.....*...**.................***......**.**.......*..................**.*.......... (1,110) (2,782)
Cash Flows used in Investing Activities ..*.......*................*.*.........*..*......*.**...
(160,873) (617,591)
CASH FWWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from long-term debt................................................................................... 246,458 Retirements of long-term debt .*.. .*. . . . . ... .. .. .. .* .. .. . .. .. . .. .. .. . .. . . . .. . . .. .. . . . . . . . . . . . .. . . .. .. . . .. .** . ... (177 ,500)
Retirements of long-term debt of variable interest entity.................................................. (23,743) (22,332)
(Repayment of) borrowings from parent...................................................................... (105,968)
Investment by parent.............................................................................................. 415,000 Borrowings against cash surrender value of corporate-owned life insurance......................... 59,431 59,766 Repayment of borrowings against cash surrender value of corporate-owned life insurance....... (64,593) (41,249)
Dividends to parent................................................................................................ (75,000) (100,000)
Cash Flows (used in) from Financing Activities .**.**.**..........*...*...........*..................*....*.*.**.._ _ _...;..(1_0_3,_9_05-...) _ _ _ _2_7_4,_17_5_ ------------
NET CHANGE IN CASH AND CASH EQUIVALENTS ...........*...*.................*..*..................
CASH AND CASH EQUIVALENTS:
Beginning of period ...........................**.*.*........................*...*...*......*...........*...*......
End ofperiod .....*.......****....................**....*.*.................**...*.*..****...........*.*.*.....*... .$
SUPPLEMENTAL DISCLOSURES OF CASH FWW INFORMATION:
CASH PAID FOR:
Interest on financing activities, net of amount capitalized ........................................ .$ 52,225 $ 39,672 Interest on financing activities of variable interest entity ................................*......... 9,821 11,122 NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions ..............*.....*.*......................................*. 48,101 85,505 The accompanying notes are an integral part of these consolidated financial statements.
6
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 December 31, 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 December 31, 2014 ......... .$ 1,065,634 $ 1,095,457 $ 333,850 $ (69,379) $ 2,425,562 Net income ................*.*..*............*.... 128,517 3,823 132,340 Dividends on common stock .................. (75,000) (75,000)
Balance as of December 31, 2015 *.**..... .$ 1,065,634 $ 1,095,457 $ 387,367 $ (65,556) $ 2,482,902 The accompanying notes are an integral part of these consolidated financial statements.
7
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," "KGE," "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 324,000 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 injointly-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 24, 2016.
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 different assumptions or conditions.
Regulatory Accounting We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 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.
8
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 Asof De,cember 31, 2015 December 31, 2014 (In Thousands)
Fuel inventory ............................. $ 39,359 $ 24,105 Supplies....................................... 86,001 79,244 Fuel inventory and supplies .... $
125,360 $ 103,349 Property, Plant and Equipment We record the value of property, plant and equipment, including that ofVIEs, at cost. For plant, cost includes contracted services, direc{labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the allowed cost of capital used to finance utility construction activity.
We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:
Year Ended December 31, 2015 2014 (Dollars In Thousands)
Borrowed funds ................................$ 2,613 $ 8,680 Equity funds...................................... 1,684 12,182 Total... ........................................$ 4,297 $ 20,862 AverageAFUDC Rates .................... . 2.9% 6.7%
We charge maintenance costs and replacements of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.
Depreciation We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated 2.1 % in 2015 and 2.0% in 2014.
Depreciable lives of property, plant and equipment are as follows.
Years Fossil fuel generating facilities .................... . 6 to 74 Nuclear fuel generating facility ................... . 55 to 71 Transmission facilities ................................. . 15 to 75 Distribution facilities ................................... . 22 to 63 Other ............................................................ . 5 to 30 9
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. The accumulated amortization of nuclear fuel in the reactor was $59.1 million as ofDecember 31, 2015, and $72.3 million as of December 31, 2014. The cost of nuclear fuel charged to fuel and purchased power expense was $27.3 million in 2015 and
$27.3 million in 2014.
Cash Surrender Value of Life Insurance We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance policies.
As of December 31, 2015 2014 (In Thousands)
Cash surrender value of policies .......................$ 1,223,322 $ 1,228,628 Borrowings against policies ............................ .. (1,168,794) (1,173,957)
Corporate-owned life insurance, net ..........$ 54,528 $ 54,671
~======
(
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 ele~tricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.
Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $32.0 million as of December 31, 2015, and $29.6 million as of December 31, 2014.
Allowance for Doubtful Accounts We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management's judgment.
Income Taxes We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.
We record deferred tax assets to the extent capital losses, operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.
The application of income tax law is complex. Laws and regulations in this area .are voluminous and often ambiguous.
Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 10, "Taxes," for additional detail on our accounting for income taxes.
10
Sales Tax We accowit 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 accowiting, the Financial Accowiting Standards Board (FASB) issued the following new accounting pronouncements which may affect our accowiting and/or disclosure.
Presentation of Financial Statements In November 2015, the FASB issued Accounting Standard Update (ASU) No. 2015-17 to simplify the presentation of deferred income taxes. This guidance requires that deferred tax liabilities and assets be classified as long-term in a classified statement of position. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to retrospectively adopt effective December 31, 2015, resulting in reducing long-term deferred income tax liabilities as of December 31, 2014, by $23.3 million previously presented as current deferred tax assets.
In April 2015, the FASB issuedASU No. 2015-03 to simplify the presentation of debt issuance costs. This guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discowits. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We have elected to adopt effective December 31, 2015, resulting in reducing long-term debt as of December 31, 2014, by $0.6 million previously presented in other current assets and
$6.7 million previously presented in other long-term assets.
Extraordinary and Unusual Items In January 2015, the FASB issued ASU No. 2015-01, which eliminates the accounting concept of extraordinary items.
The objective of the new guidance is to reduce complexity in accowiting 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 elected to adopt effective January 1, 2015, without an impact to our financial statements.
Revenue Recognition In May_2014, the FASB issuedASUNo. 2014-09, which 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 was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.
11
- 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 ofDecember 31, 2015 2014 (In Thousands)
Regulatory Assets:
Amounts due from customers for future income taxes, net ........ $ 101,423 $ 107,605 Deferred employee benefit costs................................................ 63,772 70,696 Depreciation ...... ... .. .... ..... .. .. .. ... ... ... .... ... .... ..... .. .. ..... .... .. .. ........... 61,215 63,485 Debt reacquisition costs.............................................................. 23,234 24,840 Asset retirement obligations....................................................... 21, 734 20,419 Wolf Creek outage...................................................................... 16,561 -11,165 Disallowed plant costs................................................................ 15,639 15,809 La Cygne environmental costs 15,446 Ad valorem tax........................................................................... 10,943 6,375 Energy efficiency program costs................................................ 3,794 3,530 Other regulatory assets ..... .......................................... .. .............. 2,942 1,058 Total regulatory assets ......................................................... $
336,703 $ 324,982
==
Regulatory Liabilities:
Deferred regulatory gain from sale-leaseback ............................ $ 75,560 $ 81,055 Nuclear decommissioni6g ............................................. ............. 30,659 43,641 Removal costs............................................................................. 26,928 47,502 La Cygne leasehold dismantling costs........................................ 25,330 22,918 Jurisdictional allowance for fund used during construction....... 22,515 21,462 Retail energy cost adjustment..................................................... 6,237 16,637 Other regulatory liabilities.......................................................... 2,015 2,470 Total regulatory liabilities .................................................... $
189,244 $ 235,685
==
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.
12
Deferred employee benefit costs: Includes $57 .2 million for Wolf Creek pension and post-retirement benefit obligations and $6.6 million for actual Wolf Creek pension expense in excess of the amount of such expense recognized in setting our prices. The decrease from 2014 to 2015 is primarily attributable to an increase in the discount rates used to calculate Wolf Creek's pension benefits obligations and the adoption ofupdated mortality tables. During 2015, we will amortize to expense approximately $4.4 million of the benefit obligations and approximately $1.l 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 fmancial reporting purposes. We earn a return ori 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.
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.
Disallowed plant costs: Originally there was a decision to disallow certain costs related to the Wolf Creek plant. Subsequently, in 1987, the Kansas Corporation Commission (K.CC) revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.
La Cygne environmental costs: Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.
Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.
- Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.
Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.
13
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 unit 2. We amortize the gain over the lease term.
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.
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.
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 assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.
Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period.
Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.
KCC Proceedings General and Abbreviated Rate Reviews In September 2015, the KCC issued an order in our state general rate review allowing us to adjust our prices to include, among other things, additional investment in La Cygne environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $37.6 million. The KCC also approved our request to file an abbreviated rate review within 12 months of the effective date of this order to update our prices to include additional capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015.
Environmental Costs In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future we will need to seek approval from the KCC for individual projects. In the most recent two years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately $5.1 million effective in June 2015 and approximately
$5.3 million effective in June 2014.
14
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 rdte (TFR) 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 $3.2 million effective in April 2015 and approximately $17.1 million effective in April 2014.
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 October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent two years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately $2.3 million effective in January 2015 and $5.8 million effective in January 2014.
FERC Proceedings In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent two years, we posted our TFR, which was expected to adjust our annual transmission revenues by approximately $2.3 million decrease effective in January 2015 and approximately $22.1 million increase effective in January 2014.
In August 2014, the KCC filed a complaint against Westar Energy with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act (FPA). The complaint sought to lower our and Westar Energy's base return on equity (ROE) used in determining our TFR, which would result in a refund obligation and reduce our future transmission revenues. In June 2015, Westar Energy filed a settlement agreement with the FERC, which if approved, would result in an ROE of 10.3%, which consists ofa 9.8% base ROE plus a 0.5% incentive ROE for participation in anRTO. In July 2015, FERC staff filed comments supporting the proposed settlement. As a result, for the year ended December 31, 2015, we recorded a liability of $6.9 million for our estimated refund obligation from the refund effective date of August 20, 2014 through December 31, 2015. In addition, we estimate our future transmission revenues would be reduced by approximately
$5.5 million on an annualized basis as a result of the reduced ROE.
- 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 1 - Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on public exchanges.
Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically 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.
15
We record 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 featrires, 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 ofDecember 31, 2015 As ofDecember 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (In Thousands)
Fixed-rate debt ......................$ 925,000 $ 1,061,174 $ 925,000 $ 1,118,865 Fixed-ratedebtofVIEs......... 162,048 174,344 185,791 204,173 16
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 ofDecember 31, 2015 Level 1 Level2 Level3 Total (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .............................................. $ $ 50,872 $ 6,050 $ 56,922 International equity funds ......................................... 33,595 33,595 Core bond fund ......................................................... 25,976 25,976 High-yield bond fund ................................................ 15,288 15,288 Emerging market bond fund ..................................... 13,584 13,584 Combination debt/equity/other funds ........................ 11,343 11,343 Alternative investment fund ...................................... 16,439 16,439 Real estate securities fund ......................................... 10,823 10,823 Cash equivalents ....................................................... 87 87 Total Nuclear Decommissioning Trust............................. $ 87 $ 150,658 $ 33,312 $ 184,057 As of December 31, 2014 Level I Level 2 Level 3 Total (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .............................................. $ $ 54,925 $ 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 Cash equivalents ....................................................... 340 340 Total Nuclear Decommissioning Trust............................. $ 340 $ 152,111 $ 322565 $ 1852016 17
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 31, 2015 and 2014.
Domestic Alternative Real Estate Equity Investment Securities Net Funds Fund Fund Balance (In Thousands)
Balance as of December 31, 2014 ......$ 6,047 $ 16,970 $ 9,548 $ 32,565 Total realized and unrealized gains and (losses) included in:
Regulatory liabilities ................... 899 (531) 1,275 1,643 Purchases ............................................ 400 406 806 Sales ................................................... (I,296) (406) (1,702)
Balance as of December 31, 2015 ......$ 6,050 $ 16,439 $ 10,823 $ 33,312 Balance as of December 31, 2013 ..... .$ 5,817 $ 15,675 $ 8,511 $ 30,003 Total realized and unrealized gains and (losses) included in:
Regulatory liabilities ................... 391 1,295 1,037 2,723 Purchases ............................................ 335 351 686 Sales ................................................... (496) (351) (847)
Balance as of December 31, 2014 ......$ 6,047 $ 16,970 $ 9,548 $ 32,565 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, 2015 and 2014, attributed to level 3 assets. See Note 3, "Rate Matters and Regulation,"
for additional information regarding our regulatory assets and liabilities.
Domestic Alternative Real Estate Equity Investment Securities Net Funds Fund Fund Balance (In Thousands)
Total unrealized gains (losses):
Year ended December 31, 2015 ..................... .$ (397) $ (531) $ 869 $ (59)
Year ended December 31, 2014 ..................... . (105) 1,296 685 1,876 Some of our investments in the NDT are measured at net asset value and do not have readily determinable fair values.
These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations these investments may have redemption restrictions. The following table provides additional information on these investments.
As of December 31, 2015 As of December 31, 2014 As ofDecember 31, 2015 Unfunded Unfunded Redemption Length of Fair Value Commitments Fair Value Commitments Frequency Settlement (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .....................$ 6,050 $ 1,948 $ 6,047 $ 2,348 (a) (a)
Alternative investment fund (b) ....... 16,439 16,970 Quarterly 65 days Real estate securities fund (c) .......... 10,823 9,548 Quarterly 80 days Total Nuclear Decommissioning Trust ......................................$ 33,312 $ 1,948 $ 32,565 $ 2,348 18
(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 of2013. This fund's term is expected to be 15 years, subject to the general partner's right to extend the term for up to three additional one-year periods.
(b) There is a holdback on final redemptions.
(c) In January 2016, we initiated a plan to sell this investment. We expect to receive proceeds in the amount of the investment's fair value, determined as ofMarch 31, 2016.
Derivative Instruments Price Risk We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated 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 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 and diversifying maturity dates. We may also use other financial derivative instruments such as treasury yield hedge transactions and 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, 2015 and 2014.
Using the specific identification method to determine cost, we realized a loss on our available-for-sale securities of
$0.9 million in 2015 and a $0.1 million gain on our available-for-sale securities in 2014. 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.
19
The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as ofDecember 31, 2015 and 2014.
Gross Unrealized Security Type Cost Gain Loss Fair Value Allocation (Dollars In Thousands)
As ofDecember 31, 2015:
Domestic equity funds ................. $ 49,488 $ 7,436 $ (2) $ 56,922 32%
International equity funds ............ 33,458 1,372 (1,235) 33,595 18%
Core bond fund ............................ 26,397 (421) 25,976 14%
High-yield bond fund .................. 17,047 (1,759) 15,288 8%
Emerging market bond fund ........ 16,306 (2,722) 13,584 7%
Combination debt/equity/other funds ....................................... 8,239 3,104 11,343 6%
Alternative investment fund ........ 15,000 1,439 16,439 9%
Real estate securities fund ........... 11,026 (203) 10,823 6%
Cash equivalents .......................... 87 87 <1%
Total...................................... $ 177,048 $ 13,351 $ (6,342) $ 184,057 100%
As ofDecember 31, 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%
Total...................................... $ 164,088 $ 24,770 $ (3,842) $ 185,016 100%
20
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, 2015 and 2014.
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, 2015:
Domestic equity funds ............... $ $ - $ 668 $ (2) $ 668 $ (2)
International equity funds ........... 6,717 (1,235) 6,717 (1,235)
Core bond funds ......................... 25,976 (421) 25,976 (421)
High-yield bond fund .................. 15,288 (1,759) 15,288 (1,759)
Emerging market bond fund ....... 13,584 (2,722) 13,584 (2,722)
Real estate securities fund .......... 10,823 (203) 10,823 (203)
Total. ....................................$ 41,264 $ (2,180) $ 31,792 $ (4,162) $ 73,056 $ (6,342)
As ofDecember 31, 2014:
Domestic equity funds ............... $ $ - $ 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. ................................... $ 23,882 $ (576) $ 26,691 $ (3,266) $ 50,573 $ (3,842)
- 6. PROPERTY, PLANT AND EQUIPMENT The following is a summary of our property, plant and equipment balance.
As of December 31, 2015 2014 (In Thousands)
Electric plant in service ............................................. $ 5,501,508 $ 4,712,103 Electric plant acquisition adjustment ....................... . 800,971 800,971 Accumulated depreciation........................................ . (2,323,141) (2,233,750)
- -3,979,338
--- 3,279,324 Construction work in progress ................................. . 150,239 679,600
_Nuclear fuel, net ....................................................... . 68,349 79,637 Plant to be retired, net (a) ......................................... . 13,958
=
Net property, plant and equipment ..................... $ 4,211,884 $ 4,038,561
=
21
_)
(a) Represents the retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.
The following is a summary of property, plant and equipment ofVIEs.
As ofDecember 31, 2015 2014 (In Thousands)
Electric plant ofVIEs ............................................ $ 392,100 $ 392,100 Accumulated depreciation ofVIEs ..................... .. (201,591) (194,476)
Net property, plant and equipment ofVIEs ... $ 190,509 $ 197,624
==
We recorded depreciation expense on property, plant and equipment of $114.2 million in 2015 and $101.9 million in 2014. Approximately $7 .1 million of depreciation expense in 2015 and 2014 was attributable to property, plant and equipment oftheVIE.
- 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, 2015, is shown in the table below.
In~Service Accumulated Construction Net Ownership Plant Dates Investment Depreciation Work in Progress MW Percentage (Dollars in Thousands)
La Cygne unit 1 (a) ....... June 1973 $ 602,599 $ 152,737 $ 22,461 368 50 JEC unit 1 (b) ............... July 1978 180,166 44,815 4 146 20 JEC unit 2 (b) ............... May 1980 123,202 48,234 2,216 142 20 JEC unit 3 (b) ............... May 1983 164,093 79,371 4,167 142 20 Wolf Creek (c) .............. Sept. 1985 1,880,243 817,353 72,864 551 47 Total ...................... $ 2,950,303 $ 1,142,510 $ 101,712 1,349 (a) Jointly owned with Kansas City Power & Light Company (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 331 megawatts (MW) ofnet capacity. The VIE's investment in the 50% interest was $392. l million and accumulated depreciation was $201.6 million as of December 31, 2015. 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.
22
- 8. SHORT-TERM DEBT We had no short-term debt as of December 31, 2015 and 2014. Our short-term liquidity needs are met with cash advances from Westar Energy.
In September 2015, Westar Energy extended the term of its $730.0 million revolving credit facility to terminate in September 2019, $20. 7 million of which will expire in September 2017. As long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $1.0 billion, both subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds.
As of December 31, 2015, no amounts had been borrowed and $19.2 million of letters of credit had been issued under this revolving credit facility. 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.
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 was scheduled to terminate in February 2016. In April 2015, the $20.0 million was extended to also terminate in February 2017. 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 byKGE first mortgage bonds. As of December 31, 2015 and 2014, 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 $250.3 million and $257 .6 million of commercial paper issued and outstanding as of December 31, 2015 and 2014, respectively.
In addition, total combined borrowings under Westar Energy's commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time. The weighted average interest rate on short-term borrowings outstanding as ofDecember 31, 2015 and 2014, was 0.77% and 0.52%, respectively.
23
- 9. LONG-TERM DEBT Outstanding Debt The following table summarizes our long-term debt outstanding.
As of December 31, 2015 2014 (In Thousands)
First mortgage bond series:
6.70% due2019 ............................................................................................. .$ 300,000 $ 300,000 6.15% due2023 ............................................................................................ .. 50,000 50,000 6.53% due2037 ............................................................................................. . 175,000 175,000 6.64% due 2038 ............................................................................................ .. 100,000 100,000 4.30% due 2044 ............................................................................................. . 250,000 250,000 875,000 875,000 Pollution control bond series:
Variable due2027, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014 ...... . 21,940 21,940 4:85% due 2031 (c)........................................................................................ .. 50,000 50,000 Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014 ...... . 14,500 14,500 Variable due2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014 .....*. 10,000 10,000
~
96,440 96.440 Total long-term debt ....*......*..*.......................*.............*................................*.......... 971,440 971,440 Unamortized debt discount (a) **.....*****.....*.*..******.................*..*..***............*...*..........*. (789) (864)
Unamortized debt issuance expense (a) (6,684) (7,298)
Long-term debt, net ........................................................................................ .$===~==~
963,967 $ 963,278 Variable Interest Entity 5.647%due2021 (b) ....................................................................................... .$ 162,048 $ 185,791 Amounts due within one year ............................................................................._ _ _(25,243)
..____... (23,743) 136,805 $
Long-term debt of variable interest entities, net. ................................................ =.$==========="'=='= 162,048 (a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.
(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.
(c) We have entered into an agreement to refund this debt in June 2016.
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 ofTrust 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, 2015, approximately $1.5 billion principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage.
As of December 31, 2015, we had $46.4 million of variable rate, tax-exempt bonds outstanding. 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 February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a refunding of$162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 15, "Variable Interest Entities," for additional infonnation regarding our La Cygne sale-leaseback.
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 $177.5 million in principal amount of pollution control bonds bearing stated interest rates between 5.00% and 5.30%.
24
Maturities The principal amounts of our long-term debt maturities as of December 31, 2015, are as follows.
Long-term Year Long-term debt debt of VIEs (In Thousands) 2016 ....................................... $ $ 25,243 2017 ...................................... . 26,838 2018 *************************************** 28,534 2019 *************************************** 300,000 30,337 2020 ...................................... . 32,254 Thereafter............................... 671,440 18,842 Total maturities ............... $
971,440 $ 162,048
==
Interest expense on long-term debt net of debtAFUDC was $51.8 million in 2015 and $44.2 million in 2014. Interest expense on long-term debt of VIE was $9.5 million in 2015 and $10.8 million in 2014.
- 10. TAXES Income tax expense is comprised of the following components.
Year Ended December 31, 2015 2014 (In Thousands)
Income Tax Expense (Benefit):
Current income taxes:
Federal .................................................................................. $ 100 $ (170)
State ..................................................................................... . 22 (33)
Deferred income taxes:
Federal ................................................................................. . 45,815 44,018 State ..................................................................................... . 9,874 9,524 Investment tax credit amortization .......................................... . _____ (1,803)
..;... (1,886)
Income tax expense ......................................................... $ 54,008 $ 51,453
~====
The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.
25
As ofDecember 31, 2015 2014 (In Thousands)
Deferred tax assets:
Net operating loss carryforward (a) .................$ 97,753 $ 107,377 Deferred regulatory gain on sale-leaseback ... . 33,287 35,706 Deferred employee benefit costs .................... . 22,566 25,952 Deferred compensation .................................. . 20,610 20,951 Disallowed plant costs ........................ :........... . 10,211 10,829 La Cygne dismantling costs ........................... . 10,018 9,064 Accrued liabilities .......................................... . 5,825 6,818 Other............................................................... . 15,515 17,221 Total deferred tax assets ............................$
215,785 $ 233,918 Deferred tax liabilities:
Accelerated depreciation .................................$ 767,664 $ 718,409 Acquisition premium ...................................... . 155,597 163,595 Amounts due from customers for future income taxes, net ........................................ . 101,423 107,605 Deferred employee benefit costs .................... . 22,566 25,952 Pension expense tracker ................................. . 5,900 6,380 Debt reacquisition costs ................................. . 5,581 5,769 Storm costs ..................................................... . 5,533 Other............................................................... . 9,992 3,171 Total deferred tax liabilities ..........................$
1,068,723 $ 1,036,414 Net deferred tax liabilities ....................................$ 852,938 $ 802,496 (a) As of December 31, 2015, we had a federal net operating loss carryforward of$247.0 million, which is available to offset federal taxable income. The net 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.
26
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.
_o Year Ended December 31, 2015 2014 Statutory federal income tax rate ................................................... . 35.0% 35.0%
Effect of:
Corporate-owned life insurance policies ................................ . (10.6) (10.4)
State income taxes ..... :............................................................ . 3.5 3.4 Flow through depreciation for plant-related differences ........ . 3.2 3.2 Amortization of federal investment tax credits ..................... .. (1.0) (1.0)
AFUDC equity ...................... ,................................................ . (0.4) (2.3)
Liability for unrecognized income tax benefits ...................... . (0.2)
Other ...................................................................................... . (0.7) 0.6 Effective income tax rate .............................................................. ..
29.0% 28.3%
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 Service or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year 2012 and I forward.
There were no significant changes to our unrecognized income tax benefits from December 31, 2014, to December 31, 2015. We do not expect significant changes in the unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amounts ofunrecognized income tax benefits is as follows:
2015 2014 (In Thousands)
Unrecognized income tax benefits as of January 1 .............................................. $ 371 $ 355 Additions based on tax positions related to the current year .............................. . 4 16 Additions for tax positions of prior years ......................................................... ..
Lapse of statute of limitations............................................................................. (201)
Settlements ......................................................................................................... .
Unrecognized income tax benefits as of December 31 ....................................... $ 174 $ 371
==
The amounts of unrecognized income tax benefits that, ifrecognized, would favorably impact our effective income tax rate, were $0.2 million arid $0.4 million (net of tax) as of December 31, 2015 and 2014, respectively.
Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of December 31, 2015 and 2014, we had no amounts accrued for interest related to unrecognized income tax benefits. We accrued no penalties at either December 31, 2015, or December 31, 2014.
As of December 31, 2015 and 2014, we had recorded $0. 7 million for probable assessments of taxes other than income taxes.
27
- 11. WOLF CREEK EMPLOYEE BENEFIT PLANS As a co-owner of Wolf Creek, we are indirectly responsible for 4 7% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. We accrue our47% 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 4 7% share of the Wolf Creek pension and post-retirement benefit plans.
Pension Benefits Post-retirement Benefits As of December 31, 2015 2014 2015 2014 (In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year ................................ $ 210,320 $ 162,820 $ 8,240 $ 10,010 Service cost .............................................................. .. 7,595 5,695 138 173 Interest cost ............................................................... . 9,016 8,469 314 464 Plan participants' contributions ..................................... .. 934 766 Benefits paid ............................................................ .. (6,217) (5,039) (1,622) (1,292)
Actuarial (gains) losses ................................................. - - - (14,296)
-- 38,375 (211) (1,881)
Benefit obligation, end of year ................................... $ 206,418 $ 210,320 $ 7,793 $ 8,240
==
Change in Plan Assets:
Fair value of plan assets, beginning of year ........................ $ 124,660 $ 114,734 $ 6 $ 17 Actual return on plan assets .......................................... .. (2,879) 7,626 Employer contributions ................................................ . 5,805 7,089 787 515 Plan participants' contributions ..................................... .. 934 766 Benefits paid .............................................................. _ _ _(5,964) ..__ (4,789) (1,622) (1,292)
Fair value of plan assets, end of year............................ ..;..$_ _ ..;...;;.;=--- $
121,622 124,660 $ 105 $ 6 Funded status, end of year ..................................................... $ (84,796) $ (85,660) $ (7,688) $ (8,234)
=
Amounts Recognize{I in the Balance Sheets Consist of:
Current liability........................................................... $ (247) $ (247) $ (597) $ (575)
Noncurrent liability ..................................................... .
Net amount recognized ............................................. =$====-====
(84,549)
(84,796) $
(85,413)
(85,660) $
(7,091)
(7,688) $
(7,659)
(8,234)
Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain) ................................................. $ 56,747 $ 65,049 $ (184) $ 29 Prior service cost ....................................................... .. 501 559 Net amount recognized............................................. $
57,248 $ 65,608 $ (184) $ 29
=
28
Pension Benefits Post-retirement Benefits As of December 31, 2015 2014 2015 2014 (Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation............................................ $ 206,418 $ 210,320 $ $
Fair value of plan assets .*.***..*.*...****....*..*..............*..**.*. 121,622 124,660 Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation....................................... $ 180,718 $ 179,228 $ $
Fair value of plan assets ........*....*......*....*.*.**** , .............* 121,622 124,660 Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation .................. $ $ $ 7,793 $ 8,240 Fair value of plan assets ............................................... . 105 6 Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate ............................................................. . 4.61% 4.20% 4.27% 3.89%
Compensation rate increase *.....*.*............*..................*.*. 4.00% 4.00%
Wolf Creek uses a measurement date of December 31 for its pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year's pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan's projected benefit payments discounted at this rate with the market value of the bonds selected. The increase in the discount rates used as of December 31, 2015, decreased Wolf Creek's pension and post-retirement benefit obligations by approximately $12.4 million and $0.3 million, respectively.
Wolf Creek utilizes actuarial assumptions about mortality to calculate the pension and post-retirement benefit obligations. In 2015, a revised mortality table was issued reflecting updated future projections oflife expectancies based on additional years of actual mortality experience. Wolf Creek adopted a modified version of the revised mortality table as of December 31, 2015, resulting in a decrease to the pension benefit obligation by approximately $4.8 million.
29
The prior service cost (benefit) is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain or loss is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. Following is additional information regarding our 47% share of the Wolf Creek pension and other post-retirement benefit plans.
Pension Benefits Post-retirement Benefits Year Ended December 31, 2015 2014 2015 2014 (Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost ..***.*..*..****.*.*.***............*.*....$ 7,595 $ 5,695 $ 138 $ 173 Interest cost ........................................... 9,016 8,469 314 464 Expected return on plan assets ...*.*.*............ (9,044) (8,084)
Amortization of unrecognized:
Prior service costs ............................... 57 58 Actuarial loss, net ............................... 5,930 2,987 3 165 Net periodic cost before regulatory adjustment ........................................ 13,554 9,125 455 802 Regulatory adjustment (a) .......**.*............... (1,485) 2,328 Net periodic cost .....................................$ 12,069 $ 11,453 $ 455 $ 802 Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain) loss .................$ (2,373) $ 38,833 $ (211) $ (1,881)
Amortization of actuarial gain ..................... (5,930) (2,987) (3) (165)
Amortization of prior service cost ..*...*........* (57) (58)
Total recognized in regulatory assets ............$ (8,360) $ 35,788 $ (214) $ (2,046)
Total recognized in net periodic cost and regulatory assets ................................$ 3,709 $ 47,241 $ 241 $ (1,244)
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate .......................................... 4.20% 5.11% 3.89% 4.70%
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 between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.
We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.
Pension Post-retirement Benefits Benefits (In Thousands)
Actuarial loss (gain) ................$ 4,357 $ (14)
Prior service cost ......... ........... 55 Total .................................$ 4,412 $ (14)
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.
30
For measurement purposes, the assumed annual health care cost growth rates were as follows.
As ofDecember 31, 2015 2014 Health care cost trend rate assumed for next year ....................................................... . 7.0% 7.0%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) ........ . 5.0% 5.0%
Year that the rate reaches the ultimate trend rate ......................................................... . 2020 2019 The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.
One-One- Percentage-Percentage- Point Point Increase Decrease (In Thousands)
Effect on total of service and interest cost ............$ (8) $ 8 Effect on post-retirement benefit obligation ........ . (95) 97 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 fmancial 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 oflarge losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.
The target allocations for Wolf Creek's pension plan assets are 31 % to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies, 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 for 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.
31
The following table provides the fair value of our share of Wolf Creek's pension plan assets and the corresponding level ofhierarchy as ofDecember 31, 2015 and 2014.
As of December 31, 2015 Level 1 Level 2 Level 3 Total (In Thousands)
Assets:
Domestic equity funds ....................... $ $ 30,503 $ $ 30,503 International equity funds .................. 37,682 37,682 Core bond funds ................................. 30,287 30,287 Real estate securities fund .................. 6,123 6,434 12,557 Commodities fund ............................. 5,811 5,811 Alternative investment fund ............... 4,258 4,258 Cash equivalents ................................ 524 524 Total Assets Measured at Fair Value ......... $ $ 110,930 $ 10,692 $ 121,622 As ofDecember 31, 2014 Level 1 Level 2 Level 3 Total Assets: (In Thousands)
Domestic equity funds ....................... $ $ 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 ......... $ $ 114,702 $ 9,958 $ 124,660 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, 2015 and 2014.
Real Estate Alternative Securities Investment Fund Fund Total (In Thousands)
Balance as of December 31, 2014 ...........*........................... $ 5,649 $ 4,309 $ 9,958 Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date ......... . 785 (51) 734 Balance as of December 31, 2015 ....................................... $ 6,434 $ 4,258 $ 10,692 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 32
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)
To/(From) Trust Company Assets To/(From) Trust Company Assets (In Millions)
Expected contributions:
2016 ................................... $ 8.0 $ 0.6 Expected benefit payments:
2016 ................................... $ (6.0) $ (0.3) $ (1.8) $
2017 .................................. . (6.9) (0.3) (2.0) 2018 .................................. . (7.8) (0.3) (2.3) 2019 .................................. . (8.7) (0.3) (2.6) 2020 .................................. . (9.6) (0.3) (2.9) 2021 - 2025 ....................... . (61.3) (1.3) (18.2)
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 $1.6 million in 2015 and $1.4 million in 2014.
- 12. COMMITMENTS AND CONTINGENCIES Purchase Orders and Contracts
)
As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under "-Fuel, Purchased Power and Transmission Commitments." These commitments relate to purchase obligations issued and outstanding at year-end.
The yearly detail of the aggregate amount ofrequired payments as of December 31, 2015, was as follows.
Committed Amount (In Thousands) 2016 ..................................................... .$ 90,998 2017...................................................... 7,813 2018 ..................................................... . 33,393 Thereafter ............................................ . 29,335 Total amount committed .............. $ 161,539 33
Environmental Matters Federal Clean Air Act We must comply with the federal Clean Air Act (CAA), state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (S02), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.
Emissions from our generating facilities, including PM, S02 and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze.
Sulfur Dioxide and Nitrogen Oxide Through the combustion of fossil fuels at our generating facilities, we emit S02 and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits, we could be subject to fines and penalties. In order to meet S02 and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.
We are subject to the S02 allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its S02 emissions for that year. In 2015, we had adequate S02 allowances to meet generation and we expect to have enough to cover emissions under this program in 2016.
\
Cross-State Air Pollution Rule In November 2015, the EPA proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport ofNOx emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient'Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.
National Ambient Air Quality Standards Under the federal CAA, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including two classes of PM, ozone, NOx (a precursor to ozone), CO and S02, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.
In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results.
In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We cannot at this time predict the impact this designation may have on our operations or consolidated financial results, but it could be material.
In 2010, the EPA revised the NAAQS for S02. In March 2015, a federal court approved a consent decree between the
~PA and environmental groups. The decree includes specific S02 emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016.
We are working with KDHE to determine the appropriate designation for the areas surrounding the facility. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS 34
could have on our operations and consolidated financial re(sults. If areas surrounding our facilities are designated as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.
Greenhouse Gases Byproducts of burning coal and other fossil fuels include carbon dioxide (C02) and other gases referred to as greenhouse gases (GHG), which are believed by many to contribute to climate change. Various regulations under the federal CAA limit C02 and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.
In October 2015, the EPA published a rule establishing new source performance standards that limit C02 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate C02 emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review. However, the U.S. Court of Appeals for the D.C. Circuit placed the case on an expedited review schedule with oral arguments scheduled for June 2016. Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay. In February 2016, the U.S. Supreme Court granted the stay request. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.
Mercury and Air Toxics Standards In 2012, the Mercury and Air Toxics Standards (MATS) rule became effective. Under the MATS rule the EPA regulates the emissions of mercury, non-mercury metals, acid gases and organics. MATS required compliance to begin in April 2015, three years after the effective date. Sources could petition their state air regulatory agency to ask for an additional year to prepare for compliance. We petitioned the KDHE and our petition request was granted. Our current compliance date is April 2016 for all of our MATS affected units.
In June 2015, the U.S. Supreme Court reversed and remanded a decision by the U.S. Court of Appeals for the District of Columbia Circuit regarding the need for the EPA to consider costs during the initial phase of MATS development. In December 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an order leaving MATS in effect while EPA develops a final cost determination. The Court anticipates this final determination to be completed prior to the MATS compliance deadline in April 2016. Based on the final MATS rule, we do not expect there to be a material impact on our operations or consolidated financial results.
Water We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants.
Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling.
Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.
In October 2014, the EPA's 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 available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule's impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but we do not expect it to be material.
35
In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, 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 rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. We are currently evaluating the final rule. The resulting impact of the /
rule 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. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we have recorded an increase of approximately $28.0 million to our ARO and property, plant and equipment to recognize estimated future costs associated with closure and post-closure of disposal sites. We believe further impact on our operations or consolidated financial results could be material. See Note 13, "Asset Retirement Obligations," for additional infonnation.
SPP Revenue Crediting We are a member of the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization, which coordinates the operation of a multistate interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades.
Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.
We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results.
Renewable Energy Standard In May 2015, Kansas repealed a state mandate to maintain a minimum amount ofrenewable energy sources, effective January 1, 2016.
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.
36
In 2014, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately
$360.0 million. This amount compares to the prior site study estimate of $296.2 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.
We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated 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 2015 and $2.8 million in 2014. We record our investment in the NDT fund at fair value, which approximated
$184.1 million and $185.0 million as of December 31, 2015 and 2014, 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 ofa cent for each kilowatt-hour of net nuclear generation delivered to customers, was $0.8 million in 2014. We included this cost 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. The NRC has not yet issued its decision.
Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.
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 are 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 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 $13.5 billion. This limit of liability consists of the maximum available commercial insurance of$375.0 million and the remaining $13.1 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.
37
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 under the current policies of approximately $42.0 million (our share is $19.7 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 for price escalation and minimum purchase commitments. As of December 31, 2015, our share of Wolf Creek's nuclear fuel commitments was approximately $16. 7 million for uranium concentrates expiring in 2017,
$2.5 million for conversion expiring in 2017, $94.6 million for enrichment expiring in 2027 and $33.2 million for fabrication expiring in 2025.
As of December 31, 2015, our coal and coal transportation contract commitments. under the remaining terms of the contracts were approximately $129 .3 million. The contracts are for plants tbat we operate and expire at various times through 2020.
As of December 31, 2015, our natural gas transportation contract commitments under the remaining terms of the contract were approximately $2.3 million. The contract expires in 2020.
We have acquired rights to transmit a total of approximately 100 MW of power with such rights expiring in 2016. As of December 31, 2015, we are committed to spend approximately $1.6 million over the remaining terms of these agreements.
See Note 3, "Rate Matters and Regulation - FERC Proceedings," for information regarding a pending settlement ofa complaint that was filed by the KCC against us with the FERC under Section 206 of the FPA.
- 13. ASSET RETIREMENT OBLIGATIONS Legal Liability We have recognized legal obligations associated with the disposal oflong-lived assets that result from the acquisition, construction, development or normal operation of such assets. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.
We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (our 47% share), dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl (PCB)-contaminated oil.
38
The following table summarizes our legal AROs included on our consolidated balance sheets in long-term liabilities.
As of December 31, 2015 2014 (In Thousands)
Beginning ARO ........................................... :................... $ 214,673 $ 152,747 Increase in nuclear decommissioning ARO liability ...... . 50,683 Increase in other ARO liabilities .................................... . 28,047 1,935 Liabilities settled ............................................................ . (1,212) (284)
Accretion expense .......................................................... . 11,986 9,592 Revisions in estimated cash flows .................................. . (3,725)
Ending ARO ............................................................. $
249,769 $
214,673
==
In 2015, we recorded an approximately $28.0 million increase in our ARO in response to the EPA's published rule to regulate CCBs. The increase is to recognize costs associated with closure and post-closure of disposal sites to be compliant.
See Note 12, "Commitments and Contingencies - Regulation of Coal Combustion Byproducts," for additional information.
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 a~bestos disposal was recorded as of 1990~ the date when the EPA published the National Emission Standards for Hazardous A!ir Pollutants: Asbestos NESHAP Revision; Final Rule."
l 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 onginally placed in service.
I PCB-contaminated oil is contained within companyielectrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regrilations 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, 2015 and 2014, we had $26.9 million and $47.5 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 ofa VIE, we assess the entity's purpose and design, including the nature of the entity's activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary ofa VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trust holding our 50% interest in La Cygne unit 2 is a VIE of which we are the primary beneficiary.
39
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 contnbution 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 fo direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We .have the potential to receive benefits from the trust that could potentially be significant ifthe fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGB effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 9, "Long-term Debt," for additional information.
Financial Statement Impact We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above.
As of As of December 31, 2015 December 31, 2014 (In Thousands)
Assets:
Property, plant and equipment of variable interest entity, net ........... .$ 190,509 $ 197,624 Liabilities:
Current maturities oflong-term debt of variable interest entity ....... .$ 25,243 $ 23,743 Accrued interest (a) .......................................................................... . 2,288 2,623 Long-term debt of variable interest entity, net ................................. .. 136,805 162,048 (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 40
transactions, we had a receivable of$21.8 million as of December 31, 2015 and a receivable of$156.0 million as of December 31, 2014.
Westar Energy made no additional investment in us for the year ended December 31, 2015 and approximately
$415.0 million for the year ended December 31, 2014. We declared and recorded dividends of $75.0 million to Westar Energy in 2015. We declared and recorded dividends of$100.0 million to Westar Energy in 2014.
41
Enclosure II to CO 16-0002 Kansas City Power & Light Company Consolidated Statements of Cash Flows (2 pages)
April 12, 2016 Wolf Creek Nuclear Operating Corporation PO Box411 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 2015 is true and correct to the best of their knowledge and belief.
Sincerely,
)If~
Steven P. Busser Vice President- Risk Management and Controller attachment KCP&l P.O. 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 2015 Cash Flows from Operating Activities (millions)
Net income $ 152.8 Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization 235.7 Amortization of:
Nuclear fuel 26.8 Other 29.1 Deferred income taxes, net 99.4 Investment tax credit amortization (1.0)
Other operating activities (Note 2) ~61.5)
Net cash from operating activities 481.3 Cash Flows from Investing Activities Utility capital expenditures (518.3)
Allowance for borrowed funds used during construction (3.9)
Purchases of nuclear decommissioning trust investments (50.9)
Proceeds from nuclear decommissioning trust investments 47.6 Other hi.vesting activities ~5.5)
Net cash from investing activities (551.0)
Cash Flows from Financing Activities Issuance of long-term debt 348.8 Issuance of long-term debt :from remarketing 146.5 Repayment oflong-tenn debt from remarketing (146.5)
Issuance fees (3.0)
Repayment of long-tenn debt (85.9)
Net change in short-tenn borrowings (178.0)
Net money pool borrowings ~12.6)
Net cash from financing activities 69.3 Net Change in Cash and Cash Equivalents (0.4)
Cash and Cash Equivalents at Beginning of Year 2.7 Cash and Cash Equivalents at End of Period $ 2.3 Ii
Enclosure Ill to CO 16-0002 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 5, 2016 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 $1.138 million.
The undersigned certifies that the foregoing memorandum with respect to Kansas Electric Power Cooperative, lnc.'s. Cash flow for the year 2015 is true and correct to the best of their knowledge and belief.
Sincerely yours, Coleen M. Wells VP and CFO Enclosure (1) j : ' ' ' ' .' .,.'."* 'I ; -~ *' :, "* '..
KANSAS ELECTRIC POWER COOPERATIVE, INC.
CONSOLIDATED SIATEMENTS OF CASH FLOWS For the years ending December 31, 2015 2014 Cash Flows from Operating Activities Net margin s 3,281,140 $ 3.492.432 Adjustments fo reconcile net margin to net cash fl<>Ws from operating activities Depreciation an(.! amortization 7,976,377 7,028,254 Decommissioning
- 4.400,516 1,495,700 Amortization of ni.tclearfuel 3,330.466 3,240;394 Amortization of deferred charges 3,901,324 4,122,662 Amortization ordeferred incremental outage costs 2.387,697 5,666,059 Amortization of debt issuance costs 56;342 67,609 Chaoge5Jri Member accounts receivable 2,048,341 {8,376,832)
Materials and supplies {253,460) {635,064)
Other assets ~n.d prepai';l e~pense (6,416) 35.701 Sul'Vey and inveStigatioti {14,915)
A~unts payable (1,146,640) (323,319)
P~yroll and payroll-related liabilities (16,170) 14,479 Accrued .Pri:>Petfy tax (59,425) (148,104)
Acerued Jnterest. payable (38,864) {45,341)
Accrued income taxes (3,564) 3,518 Other long-tei:m liabilities 841,066 445;958 Prepald,pension cost 131,428 472,371 Deferred revenue 2,778,884 2.1-00,898 Net cash flows from operating activities 29,594,127 18,659,375 Cash Flows From Investing Activities Additions to electrlcal plant (13,317,627) {15,556,312)
Additions to nuclear fuel (1,980,468) (5~243,757)
Reduci\ions in deferred charges 17,720 174,656 Additions to deferred Incremental outage costs (3,170,364), (594,202) lnvesJments.ln de~mmi~si<;ming fun~ assets {617,917) (1,533,935)
Proeeeds from asso.ciated .cirgani~tions 615,915 339,892 Investments in bond reserve assetS 4,490,786 (24,918)
Proceeds from the sale of property 39.350 14.402 Net cash flows from investing activities (13,922,605) (22,424,174)
Cash Flows From Financing Activities Ptincipal Pli!ytnents onfong*term debt (15,700,763) {19,429.155)
Proceeds from issuariee of long-term debt 9,887,110 25,993,166 Short term notes payable (1,429,000) (5,071,000)
Pa)'(nents unapplied {3,324,091) {1.707,113)
Net cash flows 1rom financing activities {10,566,744} {214.102}
Net increase (decrease} in cash and cash equivalents 5,104,778 (3,978,901)
Cash and Cash Equivalents, Beginning of Year 1,202,643 5,181,544 '
Cash and Cash Equlvalentsj End of Year $ 6,307.421 $ 1,202,643 Supplemental Disclosure of Cash Flow Information Interest paid $ 9,279,800 $ 9,868,600
~\ ,,;:
J( ...
'1,,
NUCLEAR OPERATING CORPORATION May 5, 2016 Annette F. Stull Vice President and Chief Administrative Officer co 16-0002 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555
Subject:
Docket No. 50-482: Guarantee of Payment of Deferred Premiums 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 Cynthia R. Hafenstine (620) 364-4204.
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 Ill Kansas Electric Power Cooperative, Inc. Statement of Cash Flows cc: M. L. Dapas (NRC), w/e C. F. Lyon (NRC), w/e
, N. H. Taylor (NRC), w/e Senior Resident Inspector (NRC), w/e P.O. Box 411 I Burlington, KS 66839 I Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET
Enclosure I to CO 16-0002 Kansas Gas and Electric Company Consolidated Statements of Cash Flows (42 pages)
April 26, 2016 Mr. Todd N. Laflin Wolf Creek Nuclear Operating Corporation PO Box 411 Burlington, KS 66839
Dear Todd:
Pursuant to the requirements of 10 CFR 140.2l(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 2015, is true and correct to the best of his knowledge and belief.
Kevin L. Kongs Vice President, Controller Westar Energy, Inc.
lms attachment 818 S Kansas Ave I PO Box 889 /Topeka, KS 66601-0889 / (785) 575-6300
Kansas Gas and Electric Company Consolidated Financial Statements Consolidated Financial Statements for the Years Ended December 31, 2015 and 2014, and Independent Auditors' Report 1
TABLE OF CONTENTS CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014: Page Independent Auditors' Report Consolidated Balance Sheets Consolidated Statements of Income Consolidated Statements of Cash Flows Consolidated Statements of Changes in Eguity Notes to Consolidated Financial Statements 2
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, 2015 and 2014, 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 ~ssessments, 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 fmancial 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, 2015 and 2014, 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.
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
Asof Asof December 31, 2015 December 31, 2014 ASSETS CURRENT ASSETS:
Accounts receivable, net of allowance for doubtful accounts of$2,863 and $2,859, respectively *...*. $ 105,005 $ 106,843' Receivable from affiliates ***..*..*.*........*...*.*...................*.*..*..*...............*..........**.*.*..*..... 21,767 156,002 Fuel inventory and supplies *...*....*.*.*......*..*..............*.**...*.*..*.*..*.*.***...*......*.*.....***......... 125,360 103,349 Prepaid expenses ....*....*..***.**...*....***.*......*...*.....*......*****.*.............***.*..*.....*......**.**.*.... 5,622 5,363 Regulatory assets ...........*......*..*.**...*......*...*....*.*.....................*...................*****.*...*..... 38,637 21,752 Other 3,409 4,850 Total Current Assets 299,800 398,159 PROPERTY, PLANT AND EQUIPMENT, NET 4,211,884 4,038,561 PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITY, NET 190,509 197,624 OTHER ASSETS:
Regulatory assets 298,066 303,230 Nuclear decommissioning trust 184,057 185,016 Other 63,362 61,621 Total Other Assets 545,485 549,867 TOTAL ASSETS $ 5;1.47,678 $ 5,184,211 LIABILITIES AND EQUITY CURRENT LIABILITIES:
Current maturities oflong-tenn debt of variable interest entity $ 25,243 $ 23,743 Accounts payable 89,628 102,505 Accrued interest 43,319 44,303 Accrued taxes 28,602 24,455 Regulatory liabilities 12,386 22,497 Customer deposits 9,113 15,044 Other 10,770 3,336 Total Current Liabilities 219,061 235,883 LONG-TERM LIABILITIES:
Long-tenn debt, net 963,967 963,278 Long-term debt of variable interest entity, net 136,805 162,048 Deferred income taxes 852,938 802,496 Unamortized investment tax credits 28,992 30,793 Regulatory liabilities .......**..**.*.......*...............**.............*................*............................. 176,858 213,188 Asset retirement obligations ...*..*....................*........*......................*........*......*............... 249,769 214,673 Other.......**..*****............**.**..*....*.............*....*............***..*................*....................*.... 136,386 136,290 Total Long-Term Liabilities************************************************************************************------- 2,545,715 - - - -2,522,766 COMMITMENTS AND CONTINGENCIES (See Notes 3, 12 and 14)
EQUITY:
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
- J Paid-in capital ..........*...........................*.*.....*.......*...**.........*....*.*.................*.*.... 1,095,457 1,095,457 Retained earnings ............*..*.......*..............*..*....*.........*****.*..*...*.........*......*.......... 387,367 333,850 Total Kansas Gas and Electric Company Shareholder's Equity .....*...*..*..............*..**.
2,548,458 2,494,941 Noncontro!ling Interest ........*......*..*...........*.*.......................*............................*....*...... (65,556) (69,379)
Total Equity ................*.*.*..*...*......*.......***.*....*....*.**.*..................*.****.*.........
2,482,902 2,425,562 TOTAL LIABILITIES AND EQUITY ............*..**.......*.........*...*...**..................**...*...*...........*. $
5;1.47,678 $ 5,184,211
==
The accompanying notes are an integral part of these consolidated financi!ll statements.
4
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 2015 2014 REVENUES ..*.........*.*...*...*...***.*.....*..*.........*****.*.*...*...***.......*............*.*.*..... .$ 1,041,109 $ 1,108,470 OPERATING EXPENSES:
Fuel and purchased power .......................................................................... . 202,296 278,064 SPP transmission network costs ...................*...........*.*..*.***.................*......... 114,522 109,462 Operating and maintenance ..............**...................................*..*.*................. 176,848 204,240 Depreciation and amortization ........*.....*.........*..............*..*.........................*. 136,019 123,653 Selling, general and administrative ....*...*....................*.....*.............*.............. 116,692 117,673 Taxes other than income tax ..................*.................**............................*...... 45,545 43,958 Total Operating Expenses *.............................*..............*...............*..*....
791,922 877,050 INCOME FROM OPERATIONS ........................................................................ .
249,187 231,420 OTHER INCOME (EXPENSE):
Other income ............*...*.............*............*...*.....................*.*............*....*. 18,586 26,246 Other expense ......................................................................................... . (17,637) (18,388)
Total Other Income *.......*..*.*.............*.*..............*...........*.***....*....*...........*.*****..
949 7,858 Interest expense .............................................................................................. . 63,788 57,311 INCOME BEFORE INCOME TAXES ................................................................. .
186,348 181,967 Income tax expense........*.....*..........................*.....****...*........*......................*..*. 54,008 51,453 NETINCOME .*.*.................*.................*...............*...*.*...................*..............
132,340 130,514 Less: Net income attributable noncontrolling interest ..........*.*...*............*.**......*.....
to 3,823 2,503 NET INCOME ATTRIBUTABLE TO KANSAS GAS AND ELECTRIC COMPANY .*.*.. .$
128,517 $ 128,011 The accompanying notes are an integral part of these consolidated financial statements.
5
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 2015 2014 CASH FWWS FROM (USED IN) OPERATING ACTIVITIES:
Net income ..........*.....*......*.**...*....*...**..*.**.*..........*..*..*.*.............*..***.*.*...*.*........ .$ 132,340 $ 130,514 Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization .........*....*.*..........................*.......................**...... 136,019 123,653 Amortization of nuclear fuel *..*.....*...........*.*..*.........*.............*.......*.....*...*....*... 26,974 26,051 Amortization of deferred regulatory gain from sale leaseback .................................. .. (5,495) (5,495)
Amortization of corporate-owned life insurance ..**....*.........................................*.. 17,958 18,402 Net deferred income taxes and credits ................*............*..................*....*........... 53,886 51,656 Allowance for equity funds used during construction *..*...*..........................*.*......... (1,684) (12,182)
Changes in working capital items:
Accounts receivable ...*.....*...*.....*.*...*.....................**...............*.........*..*.......... (625) (8,127)
Fuel inventory and supplies .................................*...*...........*............................ (21,986) (7,272)
Prepaid expenses and other .........................*....*....*.....**.*.................*..........*..*.. (19,576) 41,081 Accounts payable ....*..............................................*....*.*...*.........**...*............. (3,236) 18,858 Other current liabilities ........*..*...**...*.................**...*...*****..........................**.... (60,934) (36,769)
Changes in other assets .....*........*..**...*.*................................*...*...*..*............*......... 3,806 (1,651)
Changes in other liabilities ....*..**....***.*.*.....................*.....*............*.*..*..*..*.............. 7,331 4,697 Cash Flows from Operating Activities ................*.......*.*....*..*..................*...**.*..................
264,778 CASH FWWS FROM (USED IN) INVESTING ACTIVITIES:
343,416 Additions to property, plant and equipment ..........*...........*.........................**.*..*........*.. (343,672) (485,625)
Purchase of securities - trust .....**..*....*............*....................*..................*.......*......... (36,846) (9,075)
Sale of securities - trust .....*.**...........*......*..*...................*...............................*........ 35,194 9,094 Investment in corporate-owned life insurance .**.........................*.........*................*.*.*.*. (14,845) (15,934)
Proceeds from investment in corporate-owned life insurance ............*............................... 66,421 42,733 Advance to parent .................*............*..**.... ~ .**.*...................*......*.*.........**.****....... 133,985 (156,002)
Other investing activities ......*.....*...**.................***......**.**.......*..................**.*.......... (1,110) (2,782)
Cash Flows used in Investing Activities ..*.......*................*.*.........*..*......*.**...
(160,873) (617,591)
CASH FWWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from long-term debt................................................................................... 246,458 Retirements of long-term debt .*.. .*. . . . . ... .. .. .. .* .. .. . .. .. . .. .. .. . .. . . . .. . . .. .. . . . . . . . . . . . .. . . .. .. . . .. .** . ... (177 ,500)
Retirements of long-term debt of variable interest entity.................................................. (23,743) (22,332)
(Repayment of) borrowings from parent...................................................................... (105,968)
Investment by parent.............................................................................................. 415,000 Borrowings against cash surrender value of corporate-owned life insurance......................... 59,431 59,766 Repayment of borrowings against cash surrender value of corporate-owned life insurance....... (64,593) (41,249)
Dividends to parent................................................................................................ (75,000) (100,000)
Cash Flows (used in) from Financing Activities .**.**.**..........*...*...........*..................*....*.*.**.._ _ _...;..(1_0_3,_9_05-...) _ _ _ _2_7_4,_17_5_ ------------
NET CHANGE IN CASH AND CASH EQUIVALENTS ...........*...*.................*..*..................
CASH AND CASH EQUIVALENTS:
Beginning of period ...........................**.*.*........................*...*...*......*...........*...*......
End ofperiod .....*.......****....................**....*.*.................**...*.*..****...........*.*.*.....*... .$
SUPPLEMENTAL DISCLOSURES OF CASH FWW INFORMATION:
CASH PAID FOR:
Interest on financing activities, net of amount capitalized ........................................ .$ 52,225 $ 39,672 Interest on financing activities of variable interest entity ................................*......... 9,821 11,122 NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions ..............*.....*.*......................................*. 48,101 85,505 The accompanying notes are an integral part of these consolidated financial statements.
6
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 December 31, 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 December 31, 2014 ......... .$ 1,065,634 $ 1,095,457 $ 333,850 $ (69,379) $ 2,425,562 Net income ................*.*..*............*.... 128,517 3,823 132,340 Dividends on common stock .................. (75,000) (75,000)
Balance as of December 31, 2015 *.**..... .$ 1,065,634 $ 1,095,457 $ 387,367 $ (65,556) $ 2,482,902 The accompanying notes are an integral part of these consolidated financial statements.
7
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," "KGE," "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 324,000 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 injointly-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 24, 2016.
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 different assumptions or conditions.
Regulatory Accounting We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 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.
8
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 Asof De,cember 31, 2015 December 31, 2014 (In Thousands)
Fuel inventory ............................. $ 39,359 $ 24,105 Supplies....................................... 86,001 79,244 Fuel inventory and supplies .... $
125,360 $ 103,349 Property, Plant and Equipment We record the value of property, plant and equipment, including that ofVIEs, at cost. For plant, cost includes contracted services, direc{labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the allowed cost of capital used to finance utility construction activity.
We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:
Year Ended December 31, 2015 2014 (Dollars In Thousands)
Borrowed funds ................................$ 2,613 $ 8,680 Equity funds...................................... 1,684 12,182 Total... ........................................$ 4,297 $ 20,862 AverageAFUDC Rates .................... . 2.9% 6.7%
We charge maintenance costs and replacements of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.
Depreciation We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated 2.1 % in 2015 and 2.0% in 2014.
Depreciable lives of property, plant and equipment are as follows.
Years Fossil fuel generating facilities .................... . 6 to 74 Nuclear fuel generating facility ................... . 55 to 71 Transmission facilities ................................. . 15 to 75 Distribution facilities ................................... . 22 to 63 Other ............................................................ . 5 to 30 9
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. The accumulated amortization of nuclear fuel in the reactor was $59.1 million as ofDecember 31, 2015, and $72.3 million as of December 31, 2014. The cost of nuclear fuel charged to fuel and purchased power expense was $27.3 million in 2015 and
$27.3 million in 2014.
Cash Surrender Value of Life Insurance We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance policies.
As of December 31, 2015 2014 (In Thousands)
Cash surrender value of policies .......................$ 1,223,322 $ 1,228,628 Borrowings against policies ............................ .. (1,168,794) (1,173,957)
Corporate-owned life insurance, net ..........$ 54,528 $ 54,671
~======
(
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 ele~tricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.
Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $32.0 million as of December 31, 2015, and $29.6 million as of December 31, 2014.
Allowance for Doubtful Accounts We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management's judgment.
Income Taxes We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.
We record deferred tax assets to the extent capital losses, operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.
The application of income tax law is complex. Laws and regulations in this area .are voluminous and often ambiguous.
Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 10, "Taxes," for additional detail on our accounting for income taxes.
10
Sales Tax We accowit 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 accowiting, the Financial Accowiting Standards Board (FASB) issued the following new accounting pronouncements which may affect our accowiting and/or disclosure.
Presentation of Financial Statements In November 2015, the FASB issued Accounting Standard Update (ASU) No. 2015-17 to simplify the presentation of deferred income taxes. This guidance requires that deferred tax liabilities and assets be classified as long-term in a classified statement of position. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to retrospectively adopt effective December 31, 2015, resulting in reducing long-term deferred income tax liabilities as of December 31, 2014, by $23.3 million previously presented as current deferred tax assets.
In April 2015, the FASB issuedASU No. 2015-03 to simplify the presentation of debt issuance costs. This guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discowits. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We have elected to adopt effective December 31, 2015, resulting in reducing long-term debt as of December 31, 2014, by $0.6 million previously presented in other current assets and
$6.7 million previously presented in other long-term assets.
Extraordinary and Unusual Items In January 2015, the FASB issued ASU No. 2015-01, which eliminates the accounting concept of extraordinary items.
The objective of the new guidance is to reduce complexity in accowiting 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 elected to adopt effective January 1, 2015, without an impact to our financial statements.
Revenue Recognition In May_2014, the FASB issuedASUNo. 2014-09, which 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 was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.
11
- 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 ofDecember 31, 2015 2014 (In Thousands)
Regulatory Assets:
Amounts due from customers for future income taxes, net ........ $ 101,423 $ 107,605 Deferred employee benefit costs................................................ 63,772 70,696 Depreciation ...... ... .. .... ..... .. .. .. ... ... ... .... ... .... ..... .. .. ..... .... .. .. ........... 61,215 63,485 Debt reacquisition costs.............................................................. 23,234 24,840 Asset retirement obligations....................................................... 21, 734 20,419 Wolf Creek outage...................................................................... 16,561 -11,165 Disallowed plant costs................................................................ 15,639 15,809 La Cygne environmental costs 15,446 Ad valorem tax........................................................................... 10,943 6,375 Energy efficiency program costs................................................ 3,794 3,530 Other regulatory assets ..... .......................................... .. .............. 2,942 1,058 Total regulatory assets ......................................................... $
336,703 $ 324,982
==
Regulatory Liabilities:
Deferred regulatory gain from sale-leaseback ............................ $ 75,560 $ 81,055 Nuclear decommissioni6g ............................................. ............. 30,659 43,641 Removal costs............................................................................. 26,928 47,502 La Cygne leasehold dismantling costs........................................ 25,330 22,918 Jurisdictional allowance for fund used during construction....... 22,515 21,462 Retail energy cost adjustment..................................................... 6,237 16,637 Other regulatory liabilities.......................................................... 2,015 2,470 Total regulatory liabilities .................................................... $
189,244 $ 235,685
==
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.
12
Deferred employee benefit costs: Includes $57 .2 million for Wolf Creek pension and post-retirement benefit obligations and $6.6 million for actual Wolf Creek pension expense in excess of the amount of such expense recognized in setting our prices. The decrease from 2014 to 2015 is primarily attributable to an increase in the discount rates used to calculate Wolf Creek's pension benefits obligations and the adoption ofupdated mortality tables. During 2015, we will amortize to expense approximately $4.4 million of the benefit obligations and approximately $1.l 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 fmancial reporting purposes. We earn a return ori 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.
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.
Disallowed plant costs: Originally there was a decision to disallow certain costs related to the Wolf Creek plant. Subsequently, in 1987, the Kansas Corporation Commission (K.CC) revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.
La Cygne environmental costs: Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.
Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.
- Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.
Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.
13
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 unit 2. We amortize the gain over the lease term.
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.
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.
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 assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.
Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period.
Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.
KCC Proceedings General and Abbreviated Rate Reviews In September 2015, the KCC issued an order in our state general rate review allowing us to adjust our prices to include, among other things, additional investment in La Cygne environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $37.6 million. The KCC also approved our request to file an abbreviated rate review within 12 months of the effective date of this order to update our prices to include additional capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015.
Environmental Costs In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future we will need to seek approval from the KCC for individual projects. In the most recent two years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately $5.1 million effective in June 2015 and approximately
$5.3 million effective in June 2014.
14
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 rdte (TFR) 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 $3.2 million effective in April 2015 and approximately $17.1 million effective in April 2014.
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 October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent two years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately $2.3 million effective in January 2015 and $5.8 million effective in January 2014.
FERC Proceedings In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent two years, we posted our TFR, which was expected to adjust our annual transmission revenues by approximately $2.3 million decrease effective in January 2015 and approximately $22.1 million increase effective in January 2014.
In August 2014, the KCC filed a complaint against Westar Energy with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act (FPA). The complaint sought to lower our and Westar Energy's base return on equity (ROE) used in determining our TFR, which would result in a refund obligation and reduce our future transmission revenues. In June 2015, Westar Energy filed a settlement agreement with the FERC, which if approved, would result in an ROE of 10.3%, which consists ofa 9.8% base ROE plus a 0.5% incentive ROE for participation in anRTO. In July 2015, FERC staff filed comments supporting the proposed settlement. As a result, for the year ended December 31, 2015, we recorded a liability of $6.9 million for our estimated refund obligation from the refund effective date of August 20, 2014 through December 31, 2015. In addition, we estimate our future transmission revenues would be reduced by approximately
$5.5 million on an annualized basis as a result of the reduced ROE.
- 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 1 - Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on public exchanges.
Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically 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.
15
We record 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 featrires, 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 ofDecember 31, 2015 As ofDecember 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (In Thousands)
Fixed-rate debt ......................$ 925,000 $ 1,061,174 $ 925,000 $ 1,118,865 Fixed-ratedebtofVIEs......... 162,048 174,344 185,791 204,173 16
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 ofDecember 31, 2015 Level 1 Level2 Level3 Total (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .............................................. $ $ 50,872 $ 6,050 $ 56,922 International equity funds ......................................... 33,595 33,595 Core bond fund ......................................................... 25,976 25,976 High-yield bond fund ................................................ 15,288 15,288 Emerging market bond fund ..................................... 13,584 13,584 Combination debt/equity/other funds ........................ 11,343 11,343 Alternative investment fund ...................................... 16,439 16,439 Real estate securities fund ......................................... 10,823 10,823 Cash equivalents ....................................................... 87 87 Total Nuclear Decommissioning Trust............................. $ 87 $ 150,658 $ 33,312 $ 184,057 As of December 31, 2014 Level I Level 2 Level 3 Total (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .............................................. $ $ 54,925 $ 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 Cash equivalents ....................................................... 340 340 Total Nuclear Decommissioning Trust............................. $ 340 $ 152,111 $ 322565 $ 1852016 17
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 31, 2015 and 2014.
Domestic Alternative Real Estate Equity Investment Securities Net Funds Fund Fund Balance (In Thousands)
Balance as of December 31, 2014 ......$ 6,047 $ 16,970 $ 9,548 $ 32,565 Total realized and unrealized gains and (losses) included in:
Regulatory liabilities ................... 899 (531) 1,275 1,643 Purchases ............................................ 400 406 806 Sales ................................................... (I,296) (406) (1,702)
Balance as of December 31, 2015 ......$ 6,050 $ 16,439 $ 10,823 $ 33,312 Balance as of December 31, 2013 ..... .$ 5,817 $ 15,675 $ 8,511 $ 30,003 Total realized and unrealized gains and (losses) included in:
Regulatory liabilities ................... 391 1,295 1,037 2,723 Purchases ............................................ 335 351 686 Sales ................................................... (496) (351) (847)
Balance as of December 31, 2014 ......$ 6,047 $ 16,970 $ 9,548 $ 32,565 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, 2015 and 2014, attributed to level 3 assets. See Note 3, "Rate Matters and Regulation,"
for additional information regarding our regulatory assets and liabilities.
Domestic Alternative Real Estate Equity Investment Securities Net Funds Fund Fund Balance (In Thousands)
Total unrealized gains (losses):
Year ended December 31, 2015 ..................... .$ (397) $ (531) $ 869 $ (59)
Year ended December 31, 2014 ..................... . (105) 1,296 685 1,876 Some of our investments in the NDT are measured at net asset value and do not have readily determinable fair values.
These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations these investments may have redemption restrictions. The following table provides additional information on these investments.
As of December 31, 2015 As of December 31, 2014 As ofDecember 31, 2015 Unfunded Unfunded Redemption Length of Fair Value Commitments Fair Value Commitments Frequency Settlement (In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds .....................$ 6,050 $ 1,948 $ 6,047 $ 2,348 (a) (a)
Alternative investment fund (b) ....... 16,439 16,970 Quarterly 65 days Real estate securities fund (c) .......... 10,823 9,548 Quarterly 80 days Total Nuclear Decommissioning Trust ......................................$ 33,312 $ 1,948 $ 32,565 $ 2,348 18
(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 of2013. This fund's term is expected to be 15 years, subject to the general partner's right to extend the term for up to three additional one-year periods.
(b) There is a holdback on final redemptions.
(c) In January 2016, we initiated a plan to sell this investment. We expect to receive proceeds in the amount of the investment's fair value, determined as ofMarch 31, 2016.
Derivative Instruments Price Risk We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated 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 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 and diversifying maturity dates. We may also use other financial derivative instruments such as treasury yield hedge transactions and 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, 2015 and 2014.
Using the specific identification method to determine cost, we realized a loss on our available-for-sale securities of
$0.9 million in 2015 and a $0.1 million gain on our available-for-sale securities in 2014. 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.
19
The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as ofDecember 31, 2015 and 2014.
Gross Unrealized Security Type Cost Gain Loss Fair Value Allocation (Dollars In Thousands)
As ofDecember 31, 2015:
Domestic equity funds ................. $ 49,488 $ 7,436 $ (2) $ 56,922 32%
International equity funds ............ 33,458 1,372 (1,235) 33,595 18%
Core bond fund ............................ 26,397 (421) 25,976 14%
High-yield bond fund .................. 17,047 (1,759) 15,288 8%
Emerging market bond fund ........ 16,306 (2,722) 13,584 7%
Combination debt/equity/other funds ....................................... 8,239 3,104 11,343 6%
Alternative investment fund ........ 15,000 1,439 16,439 9%
Real estate securities fund ........... 11,026 (203) 10,823 6%
Cash equivalents .......................... 87 87 <1%
Total...................................... $ 177,048 $ 13,351 $ (6,342) $ 184,057 100%
As ofDecember 31, 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%
Total...................................... $ 164,088 $ 24,770 $ (3,842) $ 185,016 100%
20
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, 2015 and 2014.
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, 2015:
Domestic equity funds ............... $ $ - $ 668 $ (2) $ 668 $ (2)
International equity funds ........... 6,717 (1,235) 6,717 (1,235)
Core bond funds ......................... 25,976 (421) 25,976 (421)
High-yield bond fund .................. 15,288 (1,759) 15,288 (1,759)
Emerging market bond fund ....... 13,584 (2,722) 13,584 (2,722)
Real estate securities fund .......... 10,823 (203) 10,823 (203)
Total. ....................................$ 41,264 $ (2,180) $ 31,792 $ (4,162) $ 73,056 $ (6,342)
As ofDecember 31, 2014:
Domestic equity funds ............... $ $ - $ 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. ................................... $ 23,882 $ (576) $ 26,691 $ (3,266) $ 50,573 $ (3,842)
- 6. PROPERTY, PLANT AND EQUIPMENT The following is a summary of our property, plant and equipment balance.
As of December 31, 2015 2014 (In Thousands)
Electric plant in service ............................................. $ 5,501,508 $ 4,712,103 Electric plant acquisition adjustment ....................... . 800,971 800,971 Accumulated depreciation........................................ . (2,323,141) (2,233,750)
- -3,979,338
--- 3,279,324 Construction work in progress ................................. . 150,239 679,600
_Nuclear fuel, net ....................................................... . 68,349 79,637 Plant to be retired, net (a) ......................................... . 13,958
=
Net property, plant and equipment ..................... $ 4,211,884 $ 4,038,561
=
21
_)
(a) Represents the retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.
The following is a summary of property, plant and equipment ofVIEs.
As ofDecember 31, 2015 2014 (In Thousands)
Electric plant ofVIEs ............................................ $ 392,100 $ 392,100 Accumulated depreciation ofVIEs ..................... .. (201,591) (194,476)
Net property, plant and equipment ofVIEs ... $ 190,509 $ 197,624
==
We recorded depreciation expense on property, plant and equipment of $114.2 million in 2015 and $101.9 million in 2014. Approximately $7 .1 million of depreciation expense in 2015 and 2014 was attributable to property, plant and equipment oftheVIE.
- 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, 2015, is shown in the table below.
In~Service Accumulated Construction Net Ownership Plant Dates Investment Depreciation Work in Progress MW Percentage (Dollars in Thousands)
La Cygne unit 1 (a) ....... June 1973 $ 602,599 $ 152,737 $ 22,461 368 50 JEC unit 1 (b) ............... July 1978 180,166 44,815 4 146 20 JEC unit 2 (b) ............... May 1980 123,202 48,234 2,216 142 20 JEC unit 3 (b) ............... May 1983 164,093 79,371 4,167 142 20 Wolf Creek (c) .............. Sept. 1985 1,880,243 817,353 72,864 551 47 Total ...................... $ 2,950,303 $ 1,142,510 $ 101,712 1,349 (a) Jointly owned with Kansas City Power & Light Company (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 331 megawatts (MW) ofnet capacity. The VIE's investment in the 50% interest was $392. l million and accumulated depreciation was $201.6 million as of December 31, 2015. 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.
22
- 8. SHORT-TERM DEBT We had no short-term debt as of December 31, 2015 and 2014. Our short-term liquidity needs are met with cash advances from Westar Energy.
In September 2015, Westar Energy extended the term of its $730.0 million revolving credit facility to terminate in September 2019, $20. 7 million of which will expire in September 2017. As long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $1.0 billion, both subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds.
As of December 31, 2015, no amounts had been borrowed and $19.2 million of letters of credit had been issued under this revolving credit facility. 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.
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 was scheduled to terminate in February 2016. In April 2015, the $20.0 million was extended to also terminate in February 2017. 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 byKGE first mortgage bonds. As of December 31, 2015 and 2014, 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 $250.3 million and $257 .6 million of commercial paper issued and outstanding as of December 31, 2015 and 2014, respectively.
In addition, total combined borrowings under Westar Energy's commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time. The weighted average interest rate on short-term borrowings outstanding as ofDecember 31, 2015 and 2014, was 0.77% and 0.52%, respectively.
23
- 9. LONG-TERM DEBT Outstanding Debt The following table summarizes our long-term debt outstanding.
As of December 31, 2015 2014 (In Thousands)
First mortgage bond series:
6.70% due2019 ............................................................................................. .$ 300,000 $ 300,000 6.15% due2023 ............................................................................................ .. 50,000 50,000 6.53% due2037 ............................................................................................. . 175,000 175,000 6.64% due 2038 ............................................................................................ .. 100,000 100,000 4.30% due 2044 ............................................................................................. . 250,000 250,000 875,000 875,000 Pollution control bond series:
Variable due2027, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014 ...... . 21,940 21,940 4:85% due 2031 (c)........................................................................................ .. 50,000 50,000 Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014 ...... . 14,500 14,500 Variable due2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014 .....*. 10,000 10,000
~
96,440 96.440 Total long-term debt ....*......*..*.......................*.............*................................*.......... 971,440 971,440 Unamortized debt discount (a) **.....*****.....*.*..******.................*..*..***............*...*..........*. (789) (864)
Unamortized debt issuance expense (a) (6,684) (7,298)
Long-term debt, net ........................................................................................ .$===~==~
963,967 $ 963,278 Variable Interest Entity 5.647%due2021 (b) ....................................................................................... .$ 162,048 $ 185,791 Amounts due within one year ............................................................................._ _ _(25,243)
..____... (23,743) 136,805 $
Long-term debt of variable interest entities, net. ................................................ =.$==========="'=='= 162,048 (a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.
(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.
(c) We have entered into an agreement to refund this debt in June 2016.
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 ofTrust 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, 2015, approximately $1.5 billion principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage.
As of December 31, 2015, we had $46.4 million of variable rate, tax-exempt bonds outstanding. 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 February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a refunding of$162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 15, "Variable Interest Entities," for additional infonnation regarding our La Cygne sale-leaseback.
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 $177.5 million in principal amount of pollution control bonds bearing stated interest rates between 5.00% and 5.30%.
24
Maturities The principal amounts of our long-term debt maturities as of December 31, 2015, are as follows.
Long-term Year Long-term debt debt of VIEs (In Thousands) 2016 ....................................... $ $ 25,243 2017 ...................................... . 26,838 2018 *************************************** 28,534 2019 *************************************** 300,000 30,337 2020 ...................................... . 32,254 Thereafter............................... 671,440 18,842 Total maturities ............... $
971,440 $ 162,048
==
Interest expense on long-term debt net of debtAFUDC was $51.8 million in 2015 and $44.2 million in 2014. Interest expense on long-term debt of VIE was $9.5 million in 2015 and $10.8 million in 2014.
- 10. TAXES Income tax expense is comprised of the following components.
Year Ended December 31, 2015 2014 (In Thousands)
Income Tax Expense (Benefit):
Current income taxes:
Federal .................................................................................. $ 100 $ (170)
State ..................................................................................... . 22 (33)
Deferred income taxes:
Federal ................................................................................. . 45,815 44,018 State ..................................................................................... . 9,874 9,524 Investment tax credit amortization .......................................... . _____ (1,803)
..;... (1,886)
Income tax expense ......................................................... $ 54,008 $ 51,453
~====
The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.
25
As ofDecember 31, 2015 2014 (In Thousands)
Deferred tax assets:
Net operating loss carryforward (a) .................$ 97,753 $ 107,377 Deferred regulatory gain on sale-leaseback ... . 33,287 35,706 Deferred employee benefit costs .................... . 22,566 25,952 Deferred compensation .................................. . 20,610 20,951 Disallowed plant costs ........................ :........... . 10,211 10,829 La Cygne dismantling costs ........................... . 10,018 9,064 Accrued liabilities .......................................... . 5,825 6,818 Other............................................................... . 15,515 17,221 Total deferred tax assets ............................$
215,785 $ 233,918 Deferred tax liabilities:
Accelerated depreciation .................................$ 767,664 $ 718,409 Acquisition premium ...................................... . 155,597 163,595 Amounts due from customers for future income taxes, net ........................................ . 101,423 107,605 Deferred employee benefit costs .................... . 22,566 25,952 Pension expense tracker ................................. . 5,900 6,380 Debt reacquisition costs ................................. . 5,581 5,769 Storm costs ..................................................... . 5,533 Other............................................................... . 9,992 3,171 Total deferred tax liabilities ..........................$
1,068,723 $ 1,036,414 Net deferred tax liabilities ....................................$ 852,938 $ 802,496 (a) As of December 31, 2015, we had a federal net operating loss carryforward of$247.0 million, which is available to offset federal taxable income. The net 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.
26
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.
_o Year Ended December 31, 2015 2014 Statutory federal income tax rate ................................................... . 35.0% 35.0%
Effect of:
Corporate-owned life insurance policies ................................ . (10.6) (10.4)
State income taxes ..... :............................................................ . 3.5 3.4 Flow through depreciation for plant-related differences ........ . 3.2 3.2 Amortization of federal investment tax credits ..................... .. (1.0) (1.0)
AFUDC equity ...................... ,................................................ . (0.4) (2.3)
Liability for unrecognized income tax benefits ...................... . (0.2)
Other ...................................................................................... . (0.7) 0.6 Effective income tax rate .............................................................. ..
29.0% 28.3%
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 Service or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year 2012 and I forward.
There were no significant changes to our unrecognized income tax benefits from December 31, 2014, to December 31, 2015. We do not expect significant changes in the unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amounts ofunrecognized income tax benefits is as follows:
2015 2014 (In Thousands)
Unrecognized income tax benefits as of January 1 .............................................. $ 371 $ 355 Additions based on tax positions related to the current year .............................. . 4 16 Additions for tax positions of prior years ......................................................... ..
Lapse of statute of limitations............................................................................. (201)
Settlements ......................................................................................................... .
Unrecognized income tax benefits as of December 31 ....................................... $ 174 $ 371
==
The amounts of unrecognized income tax benefits that, ifrecognized, would favorably impact our effective income tax rate, were $0.2 million arid $0.4 million (net of tax) as of December 31, 2015 and 2014, respectively.
Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of December 31, 2015 and 2014, we had no amounts accrued for interest related to unrecognized income tax benefits. We accrued no penalties at either December 31, 2015, or December 31, 2014.
As of December 31, 2015 and 2014, we had recorded $0. 7 million for probable assessments of taxes other than income taxes.
27
- 11. WOLF CREEK EMPLOYEE BENEFIT PLANS As a co-owner of Wolf Creek, we are indirectly responsible for 4 7% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. We accrue our47% 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 4 7% share of the Wolf Creek pension and post-retirement benefit plans.
Pension Benefits Post-retirement Benefits As of December 31, 2015 2014 2015 2014 (In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year ................................ $ 210,320 $ 162,820 $ 8,240 $ 10,010 Service cost .............................................................. .. 7,595 5,695 138 173 Interest cost ............................................................... . 9,016 8,469 314 464 Plan participants' contributions ..................................... .. 934 766 Benefits paid ............................................................ .. (6,217) (5,039) (1,622) (1,292)
Actuarial (gains) losses ................................................. - - - (14,296)
-- 38,375 (211) (1,881)
Benefit obligation, end of year ................................... $ 206,418 $ 210,320 $ 7,793 $ 8,240
==
Change in Plan Assets:
Fair value of plan assets, beginning of year ........................ $ 124,660 $ 114,734 $ 6 $ 17 Actual return on plan assets .......................................... .. (2,879) 7,626 Employer contributions ................................................ . 5,805 7,089 787 515 Plan participants' contributions ..................................... .. 934 766 Benefits paid .............................................................. _ _ _(5,964) ..__ (4,789) (1,622) (1,292)
Fair value of plan assets, end of year............................ ..;..$_ _ ..;...;;.;=--- $
121,622 124,660 $ 105 $ 6 Funded status, end of year ..................................................... $ (84,796) $ (85,660) $ (7,688) $ (8,234)
=
Amounts Recognize{I in the Balance Sheets Consist of:
Current liability........................................................... $ (247) $ (247) $ (597) $ (575)
Noncurrent liability ..................................................... .
Net amount recognized ............................................. =$====-====
(84,549)
(84,796) $
(85,413)
(85,660) $
(7,091)
(7,688) $
(7,659)
(8,234)
Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain) ................................................. $ 56,747 $ 65,049 $ (184) $ 29 Prior service cost ....................................................... .. 501 559 Net amount recognized............................................. $
57,248 $ 65,608 $ (184) $ 29
=
28
Pension Benefits Post-retirement Benefits As of December 31, 2015 2014 2015 2014 (Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation............................................ $ 206,418 $ 210,320 $ $
Fair value of plan assets .*.***..*.*...****....*..*..............*..**.*. 121,622 124,660 Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation....................................... $ 180,718 $ 179,228 $ $
Fair value of plan assets ........*....*......*....*.*.**** , .............* 121,622 124,660 Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation .................. $ $ $ 7,793 $ 8,240 Fair value of plan assets ............................................... . 105 6 Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate ............................................................. . 4.61% 4.20% 4.27% 3.89%
Compensation rate increase *.....*.*............*..................*.*. 4.00% 4.00%
Wolf Creek uses a measurement date of December 31 for its pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year's pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan's projected benefit payments discounted at this rate with the market value of the bonds selected. The increase in the discount rates used as of December 31, 2015, decreased Wolf Creek's pension and post-retirement benefit obligations by approximately $12.4 million and $0.3 million, respectively.
Wolf Creek utilizes actuarial assumptions about mortality to calculate the pension and post-retirement benefit obligations. In 2015, a revised mortality table was issued reflecting updated future projections oflife expectancies based on additional years of actual mortality experience. Wolf Creek adopted a modified version of the revised mortality table as of December 31, 2015, resulting in a decrease to the pension benefit obligation by approximately $4.8 million.
29
The prior service cost (benefit) is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain or loss is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. Following is additional information regarding our 47% share of the Wolf Creek pension and other post-retirement benefit plans.
Pension Benefits Post-retirement Benefits Year Ended December 31, 2015 2014 2015 2014 (Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost ..***.*..*..****.*.*.***............*.*....$ 7,595 $ 5,695 $ 138 $ 173 Interest cost ........................................... 9,016 8,469 314 464 Expected return on plan assets ...*.*.*............ (9,044) (8,084)
Amortization of unrecognized:
Prior service costs ............................... 57 58 Actuarial loss, net ............................... 5,930 2,987 3 165 Net periodic cost before regulatory adjustment ........................................ 13,554 9,125 455 802 Regulatory adjustment (a) .......**.*............... (1,485) 2,328 Net periodic cost .....................................$ 12,069 $ 11,453 $ 455 $ 802 Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain) loss .................$ (2,373) $ 38,833 $ (211) $ (1,881)
Amortization of actuarial gain ..................... (5,930) (2,987) (3) (165)
Amortization of prior service cost ..*...*........* (57) (58)
Total recognized in regulatory assets ............$ (8,360) $ 35,788 $ (214) $ (2,046)
Total recognized in net periodic cost and regulatory assets ................................$ 3,709 $ 47,241 $ 241 $ (1,244)
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate .......................................... 4.20% 5.11% 3.89% 4.70%
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 between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.
We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.
Pension Post-retirement Benefits Benefits (In Thousands)
Actuarial loss (gain) ................$ 4,357 $ (14)
Prior service cost ......... ........... 55 Total .................................$ 4,412 $ (14)
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.
30
For measurement purposes, the assumed annual health care cost growth rates were as follows.
As ofDecember 31, 2015 2014 Health care cost trend rate assumed for next year ....................................................... . 7.0% 7.0%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) ........ . 5.0% 5.0%
Year that the rate reaches the ultimate trend rate ......................................................... . 2020 2019 The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.
One-One- Percentage-Percentage- Point Point Increase Decrease (In Thousands)
Effect on total of service and interest cost ............$ (8) $ 8 Effect on post-retirement benefit obligation ........ . (95) 97 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 fmancial 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 oflarge losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.
The target allocations for Wolf Creek's pension plan assets are 31 % to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies, 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 for 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.
31
The following table provides the fair value of our share of Wolf Creek's pension plan assets and the corresponding level ofhierarchy as ofDecember 31, 2015 and 2014.
As of December 31, 2015 Level 1 Level 2 Level 3 Total (In Thousands)
Assets:
Domestic equity funds ....................... $ $ 30,503 $ $ 30,503 International equity funds .................. 37,682 37,682 Core bond funds ................................. 30,287 30,287 Real estate securities fund .................. 6,123 6,434 12,557 Commodities fund ............................. 5,811 5,811 Alternative investment fund ............... 4,258 4,258 Cash equivalents ................................ 524 524 Total Assets Measured at Fair Value ......... $ $ 110,930 $ 10,692 $ 121,622 As ofDecember 31, 2014 Level 1 Level 2 Level 3 Total Assets: (In Thousands)
Domestic equity funds ....................... $ $ 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 ......... $ $ 114,702 $ 9,958 $ 124,660 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, 2015 and 2014.
Real Estate Alternative Securities Investment Fund Fund Total (In Thousands)
Balance as of December 31, 2014 ...........*........................... $ 5,649 $ 4,309 $ 9,958 Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date ......... . 785 (51) 734 Balance as of December 31, 2015 ....................................... $ 6,434 $ 4,258 $ 10,692 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 32
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)
To/(From) Trust Company Assets To/(From) Trust Company Assets (In Millions)
Expected contributions:
2016 ................................... $ 8.0 $ 0.6 Expected benefit payments:
2016 ................................... $ (6.0) $ (0.3) $ (1.8) $
2017 .................................. . (6.9) (0.3) (2.0) 2018 .................................. . (7.8) (0.3) (2.3) 2019 .................................. . (8.7) (0.3) (2.6) 2020 .................................. . (9.6) (0.3) (2.9) 2021 - 2025 ....................... . (61.3) (1.3) (18.2)
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 $1.6 million in 2015 and $1.4 million in 2014.
- 12. COMMITMENTS AND CONTINGENCIES Purchase Orders and Contracts
)
As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under "-Fuel, Purchased Power and Transmission Commitments." These commitments relate to purchase obligations issued and outstanding at year-end.
The yearly detail of the aggregate amount ofrequired payments as of December 31, 2015, was as follows.
Committed Amount (In Thousands) 2016 ..................................................... .$ 90,998 2017...................................................... 7,813 2018 ..................................................... . 33,393 Thereafter ............................................ . 29,335 Total amount committed .............. $ 161,539 33
Environmental Matters Federal Clean Air Act We must comply with the federal Clean Air Act (CAA), state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (S02), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.
Emissions from our generating facilities, including PM, S02 and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze.
Sulfur Dioxide and Nitrogen Oxide Through the combustion of fossil fuels at our generating facilities, we emit S02 and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits, we could be subject to fines and penalties. In order to meet S02 and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.
We are subject to the S02 allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its S02 emissions for that year. In 2015, we had adequate S02 allowances to meet generation and we expect to have enough to cover emissions under this program in 2016.
\
Cross-State Air Pollution Rule In November 2015, the EPA proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport ofNOx emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient'Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.
National Ambient Air Quality Standards Under the federal CAA, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including two classes of PM, ozone, NOx (a precursor to ozone), CO and S02, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.
In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results.
In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We cannot at this time predict the impact this designation may have on our operations or consolidated financial results, but it could be material.
In 2010, the EPA revised the NAAQS for S02. In March 2015, a federal court approved a consent decree between the
~PA and environmental groups. The decree includes specific S02 emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016.
We are working with KDHE to determine the appropriate designation for the areas surrounding the facility. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS 34
could have on our operations and consolidated financial re(sults. If areas surrounding our facilities are designated as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.
Greenhouse Gases Byproducts of burning coal and other fossil fuels include carbon dioxide (C02) and other gases referred to as greenhouse gases (GHG), which are believed by many to contribute to climate change. Various regulations under the federal CAA limit C02 and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.
In October 2015, the EPA published a rule establishing new source performance standards that limit C02 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate C02 emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review. However, the U.S. Court of Appeals for the D.C. Circuit placed the case on an expedited review schedule with oral arguments scheduled for June 2016. Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay. In February 2016, the U.S. Supreme Court granted the stay request. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.
Mercury and Air Toxics Standards In 2012, the Mercury and Air Toxics Standards (MATS) rule became effective. Under the MATS rule the EPA regulates the emissions of mercury, non-mercury metals, acid gases and organics. MATS required compliance to begin in April 2015, three years after the effective date. Sources could petition their state air regulatory agency to ask for an additional year to prepare for compliance. We petitioned the KDHE and our petition request was granted. Our current compliance date is April 2016 for all of our MATS affected units.
In June 2015, the U.S. Supreme Court reversed and remanded a decision by the U.S. Court of Appeals for the District of Columbia Circuit regarding the need for the EPA to consider costs during the initial phase of MATS development. In December 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an order leaving MATS in effect while EPA develops a final cost determination. The Court anticipates this final determination to be completed prior to the MATS compliance deadline in April 2016. Based on the final MATS rule, we do not expect there to be a material impact on our operations or consolidated financial results.
Water We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants.
Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling.
Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.
In October 2014, the EPA's 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 available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule's impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but we do not expect it to be material.
35
In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, 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 rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. We are currently evaluating the final rule. The resulting impact of the /
rule 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. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we have recorded an increase of approximately $28.0 million to our ARO and property, plant and equipment to recognize estimated future costs associated with closure and post-closure of disposal sites. We believe further impact on our operations or consolidated financial results could be material. See Note 13, "Asset Retirement Obligations," for additional infonnation.
SPP Revenue Crediting We are a member of the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization, which coordinates the operation of a multistate interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades.
Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.
We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results.
Renewable Energy Standard In May 2015, Kansas repealed a state mandate to maintain a minimum amount ofrenewable energy sources, effective January 1, 2016.
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.
36
In 2014, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately
$360.0 million. This amount compares to the prior site study estimate of $296.2 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.
We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated 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 2015 and $2.8 million in 2014. We record our investment in the NDT fund at fair value, which approximated
$184.1 million and $185.0 million as of December 31, 2015 and 2014, 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 ofa cent for each kilowatt-hour of net nuclear generation delivered to customers, was $0.8 million in 2014. We included this cost 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. The NRC has not yet issued its decision.
Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek's spent nuclear fuel and will continue to monitor this activity.
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 are 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 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 $13.5 billion. This limit of liability consists of the maximum available commercial insurance of$375.0 million and the remaining $13.1 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.
37
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 under the current policies of approximately $42.0 million (our share is $19.7 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 for price escalation and minimum purchase commitments. As of December 31, 2015, our share of Wolf Creek's nuclear fuel commitments was approximately $16. 7 million for uranium concentrates expiring in 2017,
$2.5 million for conversion expiring in 2017, $94.6 million for enrichment expiring in 2027 and $33.2 million for fabrication expiring in 2025.
As of December 31, 2015, our coal and coal transportation contract commitments. under the remaining terms of the contracts were approximately $129 .3 million. The contracts are for plants tbat we operate and expire at various times through 2020.
As of December 31, 2015, our natural gas transportation contract commitments under the remaining terms of the contract were approximately $2.3 million. The contract expires in 2020.
We have acquired rights to transmit a total of approximately 100 MW of power with such rights expiring in 2016. As of December 31, 2015, we are committed to spend approximately $1.6 million over the remaining terms of these agreements.
See Note 3, "Rate Matters and Regulation - FERC Proceedings," for information regarding a pending settlement ofa complaint that was filed by the KCC against us with the FERC under Section 206 of the FPA.
- 13. ASSET RETIREMENT OBLIGATIONS Legal Liability We have recognized legal obligations associated with the disposal oflong-lived assets that result from the acquisition, construction, development or normal operation of such assets. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.
We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (our 47% share), dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl (PCB)-contaminated oil.
38
The following table summarizes our legal AROs included on our consolidated balance sheets in long-term liabilities.
As of December 31, 2015 2014 (In Thousands)
Beginning ARO ........................................... :................... $ 214,673 $ 152,747 Increase in nuclear decommissioning ARO liability ...... . 50,683 Increase in other ARO liabilities .................................... . 28,047 1,935 Liabilities settled ............................................................ . (1,212) (284)
Accretion expense .......................................................... . 11,986 9,592 Revisions in estimated cash flows .................................. . (3,725)
Ending ARO ............................................................. $
249,769 $
214,673
==
In 2015, we recorded an approximately $28.0 million increase in our ARO in response to the EPA's published rule to regulate CCBs. The increase is to recognize costs associated with closure and post-closure of disposal sites to be compliant.
See Note 12, "Commitments and Contingencies - Regulation of Coal Combustion Byproducts," for additional information.
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 a~bestos disposal was recorded as of 1990~ the date when the EPA published the National Emission Standards for Hazardous A!ir Pollutants: Asbestos NESHAP Revision; Final Rule."
l 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 onginally placed in service.
I PCB-contaminated oil is contained within companyielectrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regrilations 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, 2015 and 2014, we had $26.9 million and $47.5 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 ofa VIE, we assess the entity's purpose and design, including the nature of the entity's activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary ofa VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trust holding our 50% interest in La Cygne unit 2 is a VIE of which we are the primary beneficiary.
39
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 contnbution 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 fo direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We .have the potential to receive benefits from the trust that could potentially be significant ifthe fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGB effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 9, "Long-term Debt," for additional information.
Financial Statement Impact We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above.
As of As of December 31, 2015 December 31, 2014 (In Thousands)
Assets:
Property, plant and equipment of variable interest entity, net ........... .$ 190,509 $ 197,624 Liabilities:
Current maturities oflong-term debt of variable interest entity ....... .$ 25,243 $ 23,743 Accrued interest (a) .......................................................................... . 2,288 2,623 Long-term debt of variable interest entity, net ................................. .. 136,805 162,048 (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 40
transactions, we had a receivable of$21.8 million as of December 31, 2015 and a receivable of$156.0 million as of December 31, 2014.
Westar Energy made no additional investment in us for the year ended December 31, 2015 and approximately
$415.0 million for the year ended December 31, 2014. We declared and recorded dividends of $75.0 million to Westar Energy in 2015. We declared and recorded dividends of$100.0 million to Westar Energy in 2014.
41
Enclosure II to CO 16-0002 Kansas City Power & Light Company Consolidated Statements of Cash Flows (2 pages)
April 12, 2016 Wolf Creek Nuclear Operating Corporation PO Box411 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 2015 is true and correct to the best of their knowledge and belief.
Sincerely,
)If~
Steven P. Busser Vice President- Risk Management and Controller attachment KCP&l P.O. 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 2015 Cash Flows from Operating Activities (millions)
Net income $ 152.8 Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization 235.7 Amortization of:
Nuclear fuel 26.8 Other 29.1 Deferred income taxes, net 99.4 Investment tax credit amortization (1.0)
Other operating activities (Note 2) ~61.5)
Net cash from operating activities 481.3 Cash Flows from Investing Activities Utility capital expenditures (518.3)
Allowance for borrowed funds used during construction (3.9)
Purchases of nuclear decommissioning trust investments (50.9)
Proceeds from nuclear decommissioning trust investments 47.6 Other hi.vesting activities ~5.5)
Net cash from investing activities (551.0)
Cash Flows from Financing Activities Issuance of long-term debt 348.8 Issuance of long-term debt :from remarketing 146.5 Repayment oflong-tenn debt from remarketing (146.5)
Issuance fees (3.0)
Repayment of long-tenn debt (85.9)
Net change in short-tenn borrowings (178.0)
Net money pool borrowings ~12.6)
Net cash from financing activities 69.3 Net Change in Cash and Cash Equivalents (0.4)
Cash and Cash Equivalents at Beginning of Year 2.7 Cash and Cash Equivalents at End of Period $ 2.3 Ii
Enclosure Ill to CO 16-0002 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 5, 2016 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 $1.138 million.
The undersigned certifies that the foregoing memorandum with respect to Kansas Electric Power Cooperative, lnc.'s. Cash flow for the year 2015 is true and correct to the best of their knowledge and belief.
Sincerely yours, Coleen M. Wells VP and CFO Enclosure (1) j : ' ' ' ' .' .,.'."* 'I ; -~ *' :, "* '..
KANSAS ELECTRIC POWER COOPERATIVE, INC.
CONSOLIDATED SIATEMENTS OF CASH FLOWS For the years ending December 31, 2015 2014 Cash Flows from Operating Activities Net margin s 3,281,140 $ 3.492.432 Adjustments fo reconcile net margin to net cash fl<>Ws from operating activities Depreciation an(.! amortization 7,976,377 7,028,254 Decommissioning
- 4.400,516 1,495,700 Amortization of ni.tclearfuel 3,330.466 3,240;394 Amortization of deferred charges 3,901,324 4,122,662 Amortization ordeferred incremental outage costs 2.387,697 5,666,059 Amortization of debt issuance costs 56;342 67,609 Chaoge5Jri Member accounts receivable 2,048,341 {8,376,832)
Materials and supplies {253,460) {635,064)
Other assets ~n.d prepai';l e~pense (6,416) 35.701 Sul'Vey and inveStigatioti {14,915)
A~unts payable (1,146,640) (323,319)
P~yroll and payroll-related liabilities (16,170) 14,479 Accrued .Pri:>Petfy tax (59,425) (148,104)
Acerued Jnterest. payable (38,864) {45,341)
Accrued income taxes (3,564) 3,518 Other long-tei:m liabilities 841,066 445;958 Prepald,pension cost 131,428 472,371 Deferred revenue 2,778,884 2.1-00,898 Net cash flows from operating activities 29,594,127 18,659,375 Cash Flows From Investing Activities Additions to electrlcal plant (13,317,627) {15,556,312)
Additions to nuclear fuel (1,980,468) (5~243,757)
Reduci\ions in deferred charges 17,720 174,656 Additions to deferred Incremental outage costs (3,170,364), (594,202) lnvesJments.ln de~mmi~si<;ming fun~ assets {617,917) (1,533,935)
Proeeeds from asso.ciated .cirgani~tions 615,915 339,892 Investments in bond reserve assetS 4,490,786 (24,918)
Proceeds from the sale of property 39.350 14.402 Net cash flows from investing activities (13,922,605) (22,424,174)
Cash Flows From Financing Activities Ptincipal Pli!ytnents onfong*term debt (15,700,763) {19,429.155)
Proceeds from issuariee of long-term debt 9,887,110 25,993,166 Short term notes payable (1,429,000) (5,071,000)
Pa)'(nents unapplied {3,324,091) {1.707,113)
Net cash flows 1rom financing activities {10,566,744} {214.102}
Net increase (decrease} in cash and cash equivalents 5,104,778 (3,978,901)
Cash and Cash Equivalents, Beginning of Year 1,202,643 5,181,544 '
Cash and Cash Equlvalentsj End of Year $ 6,307.421 $ 1,202,643 Supplemental Disclosure of Cash Flow Information Interest paid $ 9,279,800 $ 9,868,600