GREAT PLAINS ENERGY INC - FORM 8-K - EX-99.1

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EX-99.4 - EX-99.4 - GREAT PLAINS ENERGY INC	d231312dex994.htm
EX-99.3 - EX-99.3 - GREAT PLAINS ENERGY INC	d231312dex993.htm
EX-99.2 - EX-99.2 - GREAT PLAINS ENERGY INC	d231312dex992.htm
EX-23.1 - EX-23.1 - GREAT PLAINS ENERGY INC	d231312dex231.htm
8-K - FORM 8-K - GREAT PLAINS ENERGY INC	d231312d8k.htm

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Westar Energy, Inc.

Topeka, Kansas

We have audited the accompanying consolidated balance sheets of Westar Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Westar Energy, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Kansas City, Missouri

February 24, 2016

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)


	As of December 31,
	2015		2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,231	$	4,556
Accounts receivable, net of allowance for doubtful accounts of $5,294 and $5,309, respectively		258,286		267,327
Fuel inventory and supplies		301,294		247,406
Prepaid expenses		16,864		15,793
Regulatory assets		109,606		105,549
Other		27,860		28,772

Total Current Assets		717,141		669,403

PROPERTY, PLANT AND EQUIPMENT, NET		8,524,902		8,162,908

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET		268,239		278,573

OTHER ASSETS:
Regulatory assets		751,312		754,229
Nuclear decommissioning trust		184,057		185,016
Other		260,015		238,777

Total Other Assets		1,195,384		1,178,022

TOTAL ASSETS	$	10,705,666	$	10,288,906

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Short-term debt		250,300		257,600
Accounts payable		220,969		219,351
Accrued dividends		49,829		44,971
Accrued taxes		83,773		74,356
Accrued interest		71,426		79,707
Regulatory liabilities		25,697		55,142
Other		106,632		90,571

Total Current Liabilities		836,935		849,631

LONG-TERM LIABILITIES:
Long-term debt, net		3,163,950		3,187,080
Long-term debt of variable interest entities, net		138,097		166,565
Deferred income taxes		1,591,430		1,445,851
Unamortized investment tax credits		209,763		211,040
Regulatory liabilities		267,114		288,343
Accrued employee benefits		462,304		532,622
Asset retirement obligations		275,285		230,668
Other		88,825		75,799

Total Long-Term Liabilities		6,196,768		6,137,968

COMMITMENTS AND CONTINGENCIES (See Notes 3, 13 and 15)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,353,426 shares and 131,687,454 shares, respective to each date		706,767		658,437
Paid-in capital		2,004,124		1,781,120
Retained earnings		945,830		855,299

Total Westar Energy, Inc. Shareholders’ Equity		3,656,721		3,294,856
Noncontrolling Interests		15,242		6,451

Total Equity		3,671,963		3,301,307

TOTAL LIABILITIES AND EQUITY	$	10,705,666	$	10,288,906

The accompanying notes are an integral part of these consolidated financial statements.

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)


	Year Ended December 31,
	2015			2014			2013
REVENUES	$	2,459,164		$	2,601,703		$	2,370,654

OPERATING EXPENSES:
Fuel and purchased power		561,065			705,450			634,797
SPP network transmission costs		229,043			218,924			178,604
Operating and maintenance		330,289			367,188			359,060
Depreciation and amortization		310,591			286,442			272,593
Selling, general and administrative		250,278			250,439			224,133
Taxes other than income tax		156,901			140,302			122,282

Total Operating Expenses		1,838,167			1,968,745			1,791,469

INCOME FROM OPERATIONS		620,997			632,958			579,185

OTHER INCOME (EXPENSE):
Investment earnings		7,799			10,622			10,056
Other income		19,438			31,522			35,609
Other expense		(17,636	)		(18,389	)		(18,099	)

Total Other Income		9,601			23,755			27,566

Interest expense		176,802			183,118			182,167

INCOME BEFORE INCOME TAXES		453,796			473,595			424,584
Income tax expense		152,000			151,270			123,721

NET INCOME		301,796			322,325			300,863
Less: Net income attributable to noncontrolling interests		9,867			9,066			8,343

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	291,929		$	313,259		$	292,520

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (see Note 2):
Basic earnings per common share	$	2.11		$	2.40		$	2.29
Diluted earnings per common share	$	2.09		$	2.35		$	2.27
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING		137,957,515			130,014,941			127,462,994
DIVIDENDS DECLARED PER COMMON SHARE	$	1.44		$	1.40		$	1.36

The accompanying notes are an integral part of these consolidated financial statements.

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


	Year Ended December 31,
	2015			2014			2013
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	301,796		$	322,325		$	300,863
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		310,591			286,442			272,593
Amortization of nuclear fuel		26,974			26,051			22,690
Amortization of deferred regulatory gain from sale leaseback		(5,495	)		(5,495	)		(5,495	)
Amortization of corporate-owned life insurance		19,850			20,202			15,149
Non-cash compensation		8,345			7,280			8,188
Net deferred income taxes and credits		151,332			151,451			123,307
Stock-based compensation excess tax benefits		(1,307	)		(875	)		(576	)
Allowance for equity funds used during construction		(2,075	)		(17,029	)		(14,143	)
Changes in working capital items:
Accounts receivable		9,042			(17,291	)		(24,649	)
Fuel inventory and supplies		(53,263	)		(8,773	)		10,124
Prepaid expenses and other		(23,145	)		36,717			(12,316	)
Accounts payable		6,636			6,189			7,856
Accrued taxes		13,073			6,596			14,218
Other current liabilities		(80,396	)		(31,624	)		(52,829	)
Changes in other assets		2,199			6,378			(4,167	)
Changes in other liabilities		30,386			35,811			41,990

Cash Flows from Operating Activities		714,543			824,355			702,803

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment		(700,228	)		(852,052	)		(780,098	)
Purchase of securities - trusts		(37,557	)		(9,075	)		(66,668	)
Sale of securities - trusts		37,930			11,125			81,994
Investment in corporate-owned life insurance		(14,845	)		(16,250	)		(17,724	)
Proceeds from investment in corporate-owned life insurance		66,794			43,234			147,658
Proceeds from federal grant		—			—			876
Investment in affiliated company		(575	)		(8,000	)		(4,947	)
Other investing activities		(1,223	)		(7,730	)		(2,992	)

Cash Flows used in Investing Activities		(649,704	)		(838,748	)		(641,901	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net		(7,300	)		122,406			(205,241	)
Proceeds from long-term debt		543,881			417,943			492,347
Retirements of long-term debt		(635,891	)		(427,500	)		(100,000	)
Retirements of long-term debt of variable interest entities		(27,933	)		(27,479	)		(25,942	)
Repayment of capital leases		(2,591	)		(3,340	)		(2,995	)
Borrowings against cash surrender value of corporate-owned life insurance		59,431			59,766			59,565
Repayment of borrowings against cash surrender value of corporate-owned life insurance		(64,593	)		(41,249	)		(145,418	)
Stock-based compensation excess tax benefits		1,307			875			576
Issuance of common stock		257,998			87,669			32,906
Distributions to shareholders of noncontrolling interests		(1,076	)		(1,030	)		(2,419	)
Cash dividends paid		(186,120	)		(171,507	)		(162,904	)
Other financing activities		(3,277	)		(2,092	)		(2,719	)

Cash Flows (used in) from Financing Activities		(66,164	)		14,462			(62,244	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,325	)		69			(1,342	)
CASH AND CASH EQUIVALENTS:
Beginning of period		4,556			4,487			5,829

End of period	$	3,231		$	4,556		$	4,487

The accompanying notes are an integral part of these consolidated financial statements.

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)


	Westar Energy, Inc. Shareholders
	Common stock shares		Common stock		Paid-in capital			Retained earnings			Non-controlling interests			Total equity
Balance as of December 31, 2012		126,503,748	$	632,519	$	1,656,972		$	606,649		$	14,115		$	2,910,255
Net income		—		—		—			292,520			8,343			300,863
Issuance of stock		1,256,391		6,282		26,624			—			—			32,906
Issuance of stock for compensation and reinvested dividends		494,090		2,470		7,171			—			—			9,641
Tax withholding related to stock compensation		—		—		(2,719	)		—			—			(2,719	)
Dividends declared on common stock ($1.36 per share)		—		—		—			(174,393	)		—			(174,393	)
Stock compensation expense		—		—		8,103			—			—			8,103
Tax benefit on stock compensation		—		—		576			—			—			576
Deconsolidation of noncontrolling interests		—		—		—			—			(14,282	)		(14,282	)
Distributions to shareholders of noncontrolling interests		—		—		—			—			(2,419	)		(2,419	)

Balance as of December 31, 2013		128,254,229		641,271		1,696,727			724,776			5,757			3,068,531

Net income		—		—		—			313,259			9,066			322,325
Issuance of stock		3,026,239		15,131		72,538			—			—			87,669
Issuance of stock for compensation and reinvested dividends		406,986		2,035		7,120			—			—			9,155
Tax withholding related to stock compensation		—		—		(2,092	)		—			—			(2,092	)
Dividends declared on common stock ($1.40 per share)		—		—		—			(182,736	)		—			(182,736	)
Stock compensation expense		—		—		7,193			—			—			7,193
Tax benefit on stock compensation		—		—		875			—			—			875
Deconsolidation of noncontrolling interests		—		—		—			—			(7,342	)		(7,342	)
Distributions to shareholders of noncontrolling interests		—		—		—			—			(1,030	)		(1,030	)
Other		—		—		(1,241	)		—			—			(1,241	)

Balance as of December 31, 2014		131,687,454		658,437		1,781,120			855,299			6,451			3,301,307

Net income		—		—		—			291,929			9,867			301,796
Issuance of stock		9,249,986		46,250		211,748			—			—			257,998
Issuance of stock for compensation and reinvested dividends		415,986		2,080		8,373			—			—			10,453
Tax withholding related to stock compensation		—		—		(3,277	)		—			—			(3,277	)
Dividends declared on common stock ($1.44 per share)		—		—		—			(201,398	)		—			(201,398	)
Stock compensation expense		—		—		8,250			—			—			8,250
Tax benefit on stock compensation		—		—		1,307			—			—			1,307
Distributions to shareholders of noncontrolling interests		—		—		—			—			(1,076	)		(1,076	)
Other		—		—		(3,397	)		—			—			(3,397	)

Balance as of December 31, 2015		141,353,426	$	706,767	$	2,004,124		$	945,830		$	15,242		$	3,671,963

The accompanying notes are an integral part of these consolidated financial statements.

WESTAR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 700,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly-owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our consolidated financial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America. Our consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation.

Use of Management’s Estimates

When we prepare our consolidated 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, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 3, “Rate Matters and Regulation,” for additional information regarding our regulatory assets and liabilities.

Cash and Cash Equivalents

We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.

Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately.


	As of December 31,
	2015		2014
	(In Thousands)
Fuel inventory	$	113,438	$	70,416
Supplies		187,856		176,990

Fuel inventory and supplies	$	301,294	$	247,406

Property, Plant and Equipment

We record the value of property, plant and equipment, including that of VIEs, at cost. For plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:


	Year Ended December 31,
	2015			2014			2013
	(Dollars In Thousands)
Borrowed funds	$	3,505			12,044			11,706
Equity funds		2,075			17,029			14,143

Total	$	5,580		$	29,073		$	25,849

Average AFUDC Rates		2.7	%		6.7	%		4.8	%

We charge maintenance costs and replacements of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.

Depreciation

We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated 2.5% in 2015, 2.4% in 2014 and 2.5% in 2013.

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


	Years
Fossil fuel generating facilities		6	to	78
Nuclear fuel generating facility		55	to	71
Wind generating facilities		19	to	20
Transmission facilities		15	to	75
Distribution facilities		22	to	68
Other		5	to	30

Nuclear Fuel

We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication. We reflect this at original cost and amortize such amounts to fuel expense based on the quantity of heat consumed during the generation of electricity as measured in millions of British thermal units (MMBtu). The accumulated amortization of nuclear fuel in the reactor was $59.1 million as of December 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, $27.3 million in 2014 and $26.5 million in 2013.

Cash Surrender Value of Life Insurance

We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.


	As of December 31,
	2015			2014
	(In Thousands)
Cash surrender value of policies	$	1,299,408		$	1,306,777
Borrowings against policies		(1,168,794	)		(1,173,956	)

Corporate-owned life insurance, net	$	130,614		$	132,821

We record as income increases in cash surrender value and death benefits. We offset against policy income the interest expense that we incur on policy loans. Income from death benefits is highly variable from period to period.

Revenue Recognition

We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.

Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $66.0 million as of December 31, 2015, and $61.0 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.

Sales Tax

We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect sales tax in our consolidated statements of income.

Earnings Per Share

We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS).

To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our forward sale agreements, if any, and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

The following table reconciles our basic and diluted EPS from net income.


	Year Ended December 31,
	2015		2014		2013
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	301,796	$	322,325	$	300,863
Less: Net income attributable to noncontrolling interests		9,867		9,066		8,343

Net income attributable to Westar Energy, Inc.		291,929		313,259		292,520
Less: Net income allocated to RSUs		646		790		810

Net income allocated to common stock	$	291,283	$	312,469	$	291,710

Weighted average equivalent common shares outstanding – basic		137,957,515		130,014,941		127,462,994
Effect of dilutive securities:
RSUs		299,198		181,397		17,195
Forward sale agreements		1,021,510		2,628,187		818,505

Weighted average equivalent common shares outstanding – diluted (a)		139,278,223		132,824,525		128,298,694

Earnings per common share, basic	$	2.11	$	2.40	$	2.29
Earnings per common share, diluted	$	2.09	$	2.35	$	2.27

(a)	For the years ended December 31, 2015, 2014 and 2013, we had no antidilutive securities.

Supplemental Cash Flow Information


	Year Ended December 31,
	2015			2014			2013
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	161,484		$	160,292		$	148,691
Interest on financing activities of VIEs		10,430			12,183			13,892
Income taxes, net of refunds		(410	)		458			(11	)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		105,169			143,192			127,544
Property, plant and equipment of VIEs		—			(7,342	)		(14,282	)
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends		10,453			9,155			9,641
Deconsolidation of VIEs		—			(7,342	)		(14,282	)
Assets acquired through capital leases		3,130			8,717			334

New Accounting Pronouncements

We prepare our consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements which may affect our accounting 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 $29.6 million previously presented as current deferred tax assets.

In April 2015, the FASB issued ASU 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 discounts. 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 $1.9 million previously presented in other current assets and $26.6 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 accounting standards while maintaining or improving the usefulness of information provided. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We elected to adopt effective January 1, 2015, without an impact to our financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 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.

3. RATE MATTERS AND REGULATION

Regulatory Assets and Regulatory Liabilities

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers through the price setting process. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.


	As of December 31,
	2015		2014
	(In Thousands)
Regulatory Assets:
Deferred employee benefit costs	$	353,785	$	435,590
Amounts due from customers for future income taxes, net		144,120		153,984
Debt reacquisition costs		121,631		61,079
Depreciation		65,797		68,422
Ad valorem tax		44,455		39,428
Asset retirement obligations		31,996		26,106
Treasury yield hedges		25,634		26,614
Wolf Creek outage		16,561		11,165
Disallowed plant costs		15,639		15,809
La Cygne environmental costs		15,446		—
Energy efficiency program costs		7,922		8,933
Other regulatory assets		17,932		12,648

Total regulatory assets	$	860,918	$	859,778

Regulatory Liabilities:
Deferred regulatory gain from sale leaseback	$	75,560	$	81,055
Removal costs		53,834		88,242
Jurisdictional allowance for funds used during construction		32,673		33,103
Pension and other post-retirement benefits costs		32,181		15,473
Nuclear decommissioning		30,659		43,641
La Cygne leasehold dismantling costs		25,330		22,918
Kansas tax credits		12,857		12,725
Retail energy cost adjustment		12,686		33,274
Purchase power agreement		9,972		4,377
Other regulatory liabilities		7,059		8,677

Total regulatory liabilities	$	292,811	$	343,485

Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.

•

Deferred employee benefit costs: Includes $319.7 million for pension and post-retirement benefit obligations and $34.1 million for actual pension expense in excess of the amount of such expense recognized in setting our prices. The decrease from 2014 to 2015 is attributable primarily to an increase in the discount rates used to calculate our and Wolf Creek’s pension benefit obligations and the adoption of updated mortality tables. During 2016, we will amortize to expense approximately $26.0 million of the benefit obligations and approximately $6.8 million of the excess pension expense. We are amortizing the excess pension expense over a five-year period. We do not earn a return on this asset.

•

Amounts due from customers for future income taxes, net: In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we receive them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled in future prices. We do not earn a return on this net asset.

•

Debt reacquisition costs: Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.

•

Depreciation: Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.

•

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.

•

Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 14, “Asset Retirement Obligations.” We recover these amounts over the life of the related plant. We do not earn a return on this asset.

•

Treasury yield hedges: Represents the effective portion of treasury yield hedge transactions. This amount will be amortized to interest expense over the term of the related debt. We do not earn a return on this asset.

•

Wolf Creek outage: We defer the expenses associated with Wolf Creek’s scheduled refueling and maintenance outages and amortize these expenses during the period between planned outages. We do not earn a return on this asset.

•

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 (KCC) revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.

•

La Cygne environmental costs: Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.

•

Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.

•

Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.

Below we summarize the nature and period of amortization for each of the regulatory liabilities listed in the table above.

•

Deferred regulatory gain from sale leaseback: Represents the gain KGE recorded on the 1987 sale and leaseback of its 50% interest in La Cygne unit 2. We amortize the gain over the lease term.

•

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.

•

Jurisdictional allowance for funds used during construction: This item represents AFUDC that is accrued subsequent to the time the associated construction charges are included in our rates and prior to the time the related assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.

•

Pension and other post-retirement benefits costs: Represents amount of pension and other post-retirement benefits expense recognized in setting our prices in excess of actual pension and other post-retirement benefits expense. We amortize the amount over a five-year period.

•

Nuclear decommissioning: We have a legal obligation to decommission Wolf Creek at the end of its useful life. This amount represents the difference between the fair value of the assets held in a decommissioning trust and the amount recorded for the accumulated accretion and depreciation expense associated with our ARO. See Notes 4, 5 and 14, “Financial Instruments and Trading Securities,” “Financial Investments” and “Asset Retirement Obligations,” respectively, for information regarding our nuclear decommissioning trust (NDT) and our ARO.

•

La Cygne leasehold dismantling costs: We are contractually obligated to dismantle a portion of La Cygne unit 2. This item represents amounts collected but not yet spent to dismantle this unit and the obligation will be discharged as we dismantle the unit.

•

Kansas tax credits: This item represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.

•

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.

•

Purchase power agreement: This item represents the amount included in retail electric rates from customers in excess of the costs incurred by us under the purchase power agreement with Westar Generating. We amortize the amount over a three-year period.

•

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 $78.3 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.

In November 2013, the KCC issued an order in our state abbreviated rate review allowing us to adjust our prices to include additional investment in La Cygne environmental upgrades and to reflect cost reductions elsewhere. The new prices were expected to increase our annual retail revenues by approximately $30.7 million.

Environmental Costs

In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future, we will need to seek approval from the KCC for individual projects. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:

•

$10.8 million effective in June 2015;

•

$11.0 million effective in June 2014; and

•

$27.3 million effective in June 2013.

Transmission Costs

We make annual filings with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate (TFR) discussed below. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:

•

$7.2 million effective in April 2015;

•

$41.0 million effective in April 2014; and

•

$11.8 million effective in March 2013.

Property Tax Surcharge

We make annual filings with the KCC to adjust our prices to include the cost incurred for property taxes. In October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent four years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:

•

$5.0 million effective in January 2016;

•

$4.9 million effective in January 2015;

•

$12.7 million effective in January 2014; and

•

$15.2 million effective in January 2013.

FERC Proceedings

In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent four years, we posted our TFR which was expected to adjust our annual transmission revenues by approximately:

•

$21.6 million increase effective in January 2016;

•

$4.6 million decrease effective in January 2015;

•

$44.3 million increase effective in January 2014; and

•

$12.2 million increase effective in January 2013.

In August 2014, the KCC filed a complaint against us with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act (FPA). The complaint sought to lower our 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, we filed a settlement agreement with the FERC, which if approved, would result in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO. 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 $13.8 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 $11.0 million on an annualized basis as a result of the reduced ROE.

4. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

GAAP establishes a hierarchical framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy levels. 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.

We record cash and cash equivalents, short-term borrowings and variable rate debt on our consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed rate debt, a level 2 measurement, based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value.

All of our level 2 investments are held in investment funds that are measured at fair value using daily net asset values. In addition, we maintain certain level 3 investments in private equity, alternative investments and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at fair value utilizing both market- and income-based models, public company comparables, investment cost or the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. The underlying real estate investments are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our fixed-rate debt.


	As of December 31, 2015				As of December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,080,000	$	3,259,533	$	3,105,000	$	3,488,410
Fixed-rate debt of VIEs		166,271		179,030		194,204		213,579

Recurring Fair Value Measurements

The following table provides the amounts and their corresponding level of hierarchy for our assets that are measured at fair value.


As of December 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	50,872	$	6,050	$	56,922
International equity funds		—		33,595		—		33,595
Core bond fund		—		25,976		—		25,976
High-yield bond fund		—		15,288		—		15,288
Emerging market bond fund		—		13,584		—		13,584
Combination debt/equity/other funds		—		11,343		—		11,343
Alternative investment fund		—		—		16,439		16,439
Real estate securities fund		—		—		10,823		10,823
Cash equivalents		87		—		—		87

Total Nuclear Decommissioning Trust		87		150,658		33,312		184,057

Trading Securities:
Domestic equity funds		—		17,876		—		17,876
International equity fund		—		4,430		—		4,430
Core bond fund		—		11,423		—		11,423
Cash equivalents		159		—		—		159

Total Trading Securities		159		33,729		—		33,888

Total Assets Measured at Fair Value	$	246	$	184,387	$	33,312	$	217,945


As of December 31, 2014	Level 1		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		32,565		185,016

Trading Securities:
Domestic equity funds		—		18,698		—		18,698
International equity fund		—		4,252		—		4,252
Core bond fund		—		12,379		—		12,379
Cash equivalents		168		—		—		168

Total Trading Securities		168		35,329		—		35,497

Total Assets Measured at Fair Value	$	508	$	187,440	$	32,565	$	220,513

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 Equity Funds			Alternative Investment Fund			Real Estate Securities Fund			Net 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		(1,296	)		—			(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 Equity Funds			Alternative Investment Fund			Real Estate Securities Fund		Net 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 and our trading securities portfolio 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 of December 31, 2015
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of 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

Trading Securities:
Domestic equity funds	$	17,876	$	—	$	18,698	$	—	Upon Notice	1 day
International equity funds		4,430		—		4,252		—	Upon Notice	1 day
Core bond fund		11,423		—		12,379		—	Upon Notice	1 day

Total Trading Securities		33,729		—		35,329		—

Total	$	67,041	$	1,948	$	67,894	$	2,348

(a)

This investment is in three long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. This fund’s term 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 of March 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, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other financial derivative instruments such as interest rate swaps.

5. FINANCIAL INVESTMENTS

We report our investments in equity and debt securities at fair value and use the specific identification method to determine their realized gains and losses. We classify these investments as either trading securities or available-for-sale securities as described below.

Trading Securities

We hold equity and debt investments which we classify as trading securities in a trust used to fund certain retirement benefit obligations. These obligations totaled $27.4 million and $29.8 million as of December 31, 2015 and 2014, respectively. For additional information on our benefit obligations, see Note 11, “Employee Benefit Plans.”

As of December 31, 2015 and 2014, we measured the fair value of trust assets at $33.9 million and $35.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the years ended December 31, 2015, 2014 and 2013, we recorded unrealized gains of $0.4 million, $2.6 million and $6.7 million, respectively, on assets still held.

Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of December 31, 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. In 2014 and 2013, we realized gains on our available-for-sale securities of $0.1 million and $5.3 million, respectively. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of December 31, 2015 and 2014.


			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
			(Dollars In Thousands)
As of December 31, 2015:
Domestic equity funds	$	49,488	$	7,436	$	(2	)	$	56,922		32	%
International equity funds		33,458		1,372		(1,235	)		33,595		18	%
Core bond fund		26,397		—		(421	)		25,976		14	%
High-yield bond fund		17,047		—		(1,759	)		15,288		8	%
Emerging market bond fund		16,306		—		(2,722	)		13,584		7	%
Combination debt/equity/other funds		8,239		3,104		—			11,343		6	%
Alternative investment fund		15,000		1,439		—			16,439		9	%
Real estate securities fund		11,026		—		(203	)		10,823		6	%
Cash equivalents		87		—		—			87		<1	%

Total	$	177,048	$	13,351	$	(6,342	)	$	184,057		100	%

As of December 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	%

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
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized 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 of December 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	$	11,449,933		$	10,620,292
Electric plant acquisition adjustment		802,318			802,318
Accumulated depreciation		(4,178,885	)		(4,112,483	)

		8,073,366			7,310,127
Construction work in progress		349,402			773,144
Nuclear fuel, net		68,349			79,637
Plant to be retired, net (a)		33,785			—

Net property, plant and equipment	$	8,524,902		$	8,162,908

(a)	Represents the retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.


	As of December 31,
	2015			2014
	(In Thousands)
Electric plant of VIEs	$	497,999		$	497,999
Accumulated depreciation of VIEs		(229,760	)		(219,426	)

Net property, plant and equipment of VIEs	$	268,239		$	278,573

We recorded depreciation expense on property, plant and equipment of $287.9 million in 2015, $263.8 million in 2014 and $249.9 million in 2013. Approximately $9.6 million, $9.7 million and $9.7 million of depreciation expense in 2015, 2014 and 2013, respectively, was attributable to property, plant and equipment of VIEs.

7. JOINT OWNERSHIP OF UTILITY PLANTS

Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income and each owner responsible for its own financing. Information relative to our ownership interests in these facilities as of December 31, 2015, is shown in the table below.


Plant	In-Service Dates		Investment		Accumulated Depreciation		Construction Work in Progress		Net MW		Ownership Percentage
			(Dollars in Thousands)
La Cygne unit 1 (a)		June 1973	$	602,599	$	152,737	$	22,461		368		50
JEC unit 1 (a)		July 1978		816,051		188,649		800		670		92
JEC unit 2 (a)		May 1980		546,955		200,286		10,112		651		92
JEC unit 3 (a)		May 1983		715,624		325,599		18,959		654		92
Wolf Creek (b)		Sept. 1985		1,880,243		817,353		72,864		551		47
State Line (c)		June 2001		111,451		57,828		263		196		40

Total			$	4,672,923	$	1,742,452	$	125,459		3,090

(a)	Jointly owned with Kansas City Power & Light Company (KCPL). Our 8% leasehold interest in Jeffrey Energy Center (JEC) that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.

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

(c)	Jointly owned with Empire District Electric Company.

We include in operating expenses on our consolidated statements of income our share of operating expenses of the above plants. Our share of fuel expense for the above plants is generally based on the amount of power we take from the respective plants. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.

In addition, we also consolidate a VIE that holds our 50% leasehold interest in La Cygne unit 2, which represents 331 MW of net capacity. The VIE’s investment in the 50% interest was $392.1 million and accumulated depreciation was $201.6 million as of December 31, 2015. We include these amounts in property, plant and equipment of VIEs, net on our consolidated balance sheets. See Note 17, “Variable Interest Entities,” for additional information about VIEs.

8. SHORT-TERM DEBT

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 by KGE 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 of December 31, 2015 and 2014, was 0.77% and 0.52%, respectively. Additional information regarding our short-term debt is as follows.


	Year Ended December 31,
	2015			2014
	(Dollars in Thousands)
Weighted average short-term debt outstanding	$	350,380		$	232,336
Weighted daily average interest rates, excluding fees		0.48	%		0.30	%

Our interest expense on short-term debt was $3.0 million in 2015, $2.0 million in 2014 and $2.4 million in 2013.

9. LONG-TERM DEBT

Outstanding Debt

The following table summarizes our long-term debt outstanding.


	As of December 31,
	2015			2014
	(In Thousands)
Westar Energy
First mortgage bond series:
5.15% due 2017	$	125,000		$	125,000
8.625% due 2018		—			300,000
5.10% due 2020		250,000			250,000
3.25% due 2025		250,000			—
5.95% due 2035		—			125,000
5.875% due 2036		—			150,000
4.125% due 2042		550,000			550,000
4.10% due 2043		430,000			430,000
4.625% due 2043		250,000			250,000
4.25% due 2045		300,000			—

		2,155,000			2,180,000

Pollution control bond series:
Variable due 2032, 0.02% as of December 31, 2015; 0.06% as of December 31, 2014		45,000			45,000
Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014		30,500			30,500

		75,500			75,500

KGE
First mortgage bond series:
6.70% due 2019		300,000			300,000
6.15% due 2023		50,000			50,000
6.53% due 2037		175,000			175,000
6.64% due 2038		100,000			100,000
4.30% due 2044		250,000			250,000

		875,000			875,000

Pollution control bond series:
Variable due 2027, 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 due 2032, 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		3,201,940			3,226,940
Unamortized debt discount (a)		(10,374	)		(11,401	)
Unamortized debt issuance expense (a)		(27,616	)		(28,459	)

Long-term debt, net	$	3,163,950		$	3,187,080

Variable Interest Entities
5.92% due 2019 (b)	$	4,223		$	8,413
5.647% due 2021 (b)		162,048			185,791

Total long-term debt of variable interest entities		166,271			194,204
Unamortized debt premium (a)		135			294
Long-term debt of variable interest entities due within one year		(28,309	)		(27,933	)

Long-term debt of variable interest entities, net	$	138,097		$	166,565

(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)	KGE has entered into an agreement to refund this debt in June 2016.

The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

The amount of Westar Energy first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is subject to certain limitations as described below. The amount of KGE first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented and amended, is limited to a maximum of $3.5 billion, unless amended further. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. As of December 31, 2015, approximately $851.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy’s mortgage. As of December 31, 2015, approximately $1.5 billion principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in KGE’s mortgage.

As of December 31, 2015, we had $121.9 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 17, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

In November 2015, Westar Energy issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 3.25% and maturing December 2025. Concurrently, Westar Energy issued $300.0 million in principal amount of first mortgage bonds bearing stated interest at 4.25% and maturing December 2045.

Also in November 2015, Westar Energy redeemed $300.0 million in principal amount of first mortgage bonds bearing stated interest at 8.625% maturing in December 2018 for $360.9 million which included a call premium. The call premium was recorded as a regulatory asset and is being amortized over the term of the new bonds.

In August 2015, Westar Energy redeemed $150.0 million in principal amount of first mortgage bonds bearing stated interest at 5.875% and maturing July 2036.

In January 2015, Westar Energy redeemed $125.0 million in principal amount of first mortgage bonds bearing stated interest at 5.95% and maturing January 2035.

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%.

In May 2014, Westar Energy issued $180.0 million in principal amount of first mortgage bonds bearing stated interest at 4.10% and maturing April 2043. These bonds constitute a further issuance of a series of bonds initially issued in March 2013 in a principal amount of $250.0 million.

Proceeds from issuances were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.

Maturities

The principal amounts of our long-term debt maturities as of December 31, 2015, are as follows.


Year	Long-term debt		Long-term debt of VIEs
	(In Thousands)
2016	$	—	$	28,309
2017		125,000		26,842
2018		—		28,538
2019		300,000		31,485
2020		250,000		32,254
Thereafter		2,526,940		18,843

Total maturities	$	3,201,940	$	166,271

Interest expense on long-term debt, net of debt AFUDC, was $152.7 million in 2015, $158.8 million in 2014 and $154.9 million in 2013. Interest expense on long-term debt of VIEs was $9.8 million in 2015, $11.4 million in 2014 and $13.0 million in 2013.

10. TAXES

Income tax expense is comprised of the following components.


	Year Ended December 31,
	2015			2014			2013
	(In Thousands)
Income Tax Expense (Benefit):
Current income taxes:
Federal	$	327		$	416		$	135
State		341			(597	)		279
Deferred income taxes:
Federal		124,891			124,923			102,030
State		29,484			29,657			24,443
Investment tax credit amortization		(3,043	)		(3,129	)		(3,166	)

Income tax expense	$	152,000		$	151,270		$	123,721

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


	As of December 31,
	2015		2014
	(In Thousands)
Deferred tax assets:
Tax credit carryforward (a)	$	266,963	$	257,827
Net operating loss carryforward (b)		129,232		179,285
Deferred employee benefit costs		122,757		158,102
Deferred state income taxes		67,307		66,557
Deferred regulatory gain on sale-leaseback		33,287		35,706
Deferred compensation		27,266		29,315
Alternative minimum tax carryforward (c)		26,725		24,114
Accrued liabilities		21,115		23,048
Disallowed costs		10,211		10,829
LaCygne dismantling cost		10,018		9,064
Capital loss carryforward (d)		1,668		1,981
Other		41,319		27,689

Total gross deferred tax assets		757,868		823,517

Less: Valuation allowance (e)		1,668		1,981

Deferred tax assets	$	756,200	$	821,536

Deferred tax liabilities:
Accelerated depreciation	$	1,787,457	$	1,664,367
Acquisition premium		155,881		163,894
Amounts due from customers for future income taxes, net		144,120		153,984
Deferred employee benefit costs		122,757		158,102
Deferred state income taxes		59,787		59,170
Debt reacquisition costs		42,314		20,102
Pension expense tracker		12,051		14,187
Storm costs		—		15,713
Other		23,263		17,868

Total deferred tax liabilities	$	2,347,630	$	2,267,387

Net deferred income tax liabilities	$	1,591,430	$	1,445,851

(a)

Based on filed tax returns and amounts expected to be reported in current year tax returns (December 31, 2015), we had available federal general business tax credits of $80.9 million and state investment tax credits of $186.1 million. The federal general business tax credits were primarily generated from production tax credits. These tax credits expire beginning in 2020 and ending in 2035. The state investment tax credits expire beginning in 2017 and ending in 2031.

(b)	As of December 31, 2015, we had a federal net operating loss carryforward of $326.5 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2031 and ending in 2034.

(c)	As of December 31, 2015, we had available an alternative minimum tax credit carryforward of $26.7 million, which has an unlimited carryforward period.

(d)	As of December 31, 2015, we had an unused capital loss carryforward of $4.2 million that is available to offset future capital gains. The capital losses will expire in 2016.

(e)	As we do not expect to realize any significant capital gains in the future, we have established a valuation allowance of $1.7 million. The total valuation allowance related to the deferred tax assets was $1.7 million as of December 31, 2015, and $2.0 million as of December 31, 2014.

In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers at corporate income tax rates higher than current income tax rates. The price reduction will occur as the temporary differences resulting in the excess deferred income tax liabilities reverse. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. The net deferred income tax liability related to these temporary differences is classified above as amounts due from customers for future income taxes, net.

Our effective income tax rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective income tax rates and the federal statutory income tax rates are as follows.


	Year Ended December 31,
	2015			2014			2013
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Effect of:
COLI policies		(4.4	)		(4.0	)		(5.4	)
State income taxes		4.3			4.0			3.8
Flow through depreciation for plant-related differences		2.6			2.0			2.2
Production tax credits		(2.1	)		(2.1	)		(2.3	)
Amortization of federal investment tax credits		(0.7	)		(0.7	)		(0.7	)
AFUDC equity		(0.2	)		(1.3	)		(1.2	)
Capital loss utilization carryforward		(0.1	)		(0.3	)		(1.1	)
Liability for unrecognized income tax benefits		—			(0.2	)		0.1
Other		(0.9	)		(0.5	)		(1.3	)

Effective income tax rate		33.5	%		31.9	%		29.1	%

We file income tax returns in the U.S. federal jurisdiction as well as various state jurisdictions. The income tax returns we file will likely be audited by the Internal Revenue Service or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year 2012 and forward.

The unrecognized income tax benefits decreased from $3.2 million at December 31, 2014, to $2.9 million at December 31, 2015. The decrease for unrecognized income tax benefits was largely attributable to tax positions expected to be taken with respect to potential deductions related to an environmental settlement agreement in a tax period for which the statute of limitations has closed. We do not expect significant changes in the unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amounts of unrecognized income tax benefits is as follows:


	2015			2014			2013
	(In Thousands)
Unrecognized income tax benefits as of January 1	$	3,188		$	1,703		$	1,219
Additions based on tax positions related to the current year		410			872			224
Additions for tax positions of prior years		—			813			325
Reductions for tax positions of prior years		(86	)		(200	)		(65	)
Lapse of statute of limitations		(611	)		—			—
Settlements		—			—			—

Unrecognized income tax benefits as of December 31	$	2,901		$	3,188		$	1,703

The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate, were $2.9 million, $3.2 million and $2.4 million (net of tax) as of December 31, 2015, 2014 and 2013, 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 2014.

As of December 31, 2015 and 2014, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

11. EMPLOYEE BENEFIT PLANS

Pension and Post-Retirement Benefit Plans

We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. For the majority of our employees, pension benefits are based on years of service and an employee’s compensation during the 60 highest paid consecutive months out of 120 before retirement. Non-union employees hired after December 31, 2001, and union employees hired after December 31, 2011, are covered by the same defined benefit pension plan; however, their benefits are derived from a cash balance account formula. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain retired executive officers. We have discontinued accruing any future benefits under this non-qualified plan.

The amount we contribute to our pension plan for future periods is not yet known, however, we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.

In addition to providing pension benefits, we provide certain post-retirement health care and life insurance benefits for substantially all retired employees. We accrue and recover in our prices the costs of post-retirement benefits during an employee’s years of service. In 2014 and prior years, our retirees were covered under a health insurance policy. In January 2015, we began giving our retirees a fixed annual allowance, which provides them the flexibility to obtain health coverage in the marketplace that is tailored to their needs.

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. See Note 12, “Wolf Creek Employee Benefit Plans,” for information about Wolf Creek’s benefit plans.

The following tables summarize the status of our 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	$	1,030,645		$	823,780		$	141,516		$	133,061
Service cost		21,392			16,218			1,443			1,381
Interest cost		43,014			41,600			5,691			6,351
Plan participants’ contributions		—			—			582			4,232
Benefits paid		(44,945	)		(39,225	)		(6,549	)		(12,184	)
Actuarial (gains) losses		(90,644	)		188,272			(16,399	)		16,509
Amendments		5,731			—			—			(7,834	)

Benefit obligation, end of year (a)	$	965,193		$	1,030,645		$	126,284		$	141,516

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	661,141		$	609,817		$	121,349		$	121,766
Actual return on plan assets		(6,948	)		61,291			(208	)		7,189
Employer contributions		41,000			26,400			—			—
Plan participants’ contributions		—			—			534			4,074
Benefits paid		(41,248	)		(36,367	)		(6,259	)		(11,680	)

Fair value of plan assets, end of year	$	653,945		$	661,141		$	115,416		$	121,349

Funded status, end of year	$	(311,248	)	$	(369,504	)	$	(10,868	)	$	(20,167	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(2,745	)	$	(2,716	)	$	(344	)	$	(246	)
Noncurrent liability		(308,503	)		(366,788	)		(10,524	)		(19,921	)

Net amount recognized	$	(311,248	)	$	(369,504	)	$	(10,868	)	$	(20,167	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	254,085		$	329,572		$	(12,208	)	$	(2,253	)
Prior service cost		8,078			2,867			3,130			3,585

Net amount recognized	$	262,163		$	332,439		$	(9,078	)	$	1,332

(a)

As of December 31, 2015 and 2014, pension benefits include non-qualified benefit obligations of $27.4 million and $29.8 million, respectively, which are funded by a trust containing assets of $33.9 million and $35.5 million, respectively, classified as trading securities. The assets in the aforementioned trust are not included in the table above. See Notes 4 and 5, “Financial Instruments and Trading Securities” and “Financial Investments,” respectively, for additional information regarding these amounts.


	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	$	965,193		$	1,030,645		$	—		$	—
Fair value of plan assets		653,945			661,141			—			—
Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	864,263		$	914,800			—			—
Fair value of plan assets		653,945			661,141			—			—
Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation		—			—		$	126,284		$	141,516
Fair value of plan assets		—			—			115,416			121,349
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate		4.60	%		4.17	%		4.51	%		4.10	%
Compensation rate increase		4.00	%		4.00	%		—			—

We use a measurement date of December 31 for our pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The increase in the discount rates used as of December 31, 2015, decreased the pension and post-retirement benefit obligations by approximately $59.6 million and $5.8 million, respectively.

We utilize 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 of life expectancies based on additional years of actual mortality experience. We adopted a modified version of the revised mortality table as of December 31, 2015, resulting in a decrease to the pension and post-retirement benefit obligations by approximately $27.3 million and $1.8 million, respectively.

We amortize prior service cost on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. We amortize the net actuarial gain or loss on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. The KCC allows us to record a regulatory asset or liability to track the cumulative difference between current year pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. We accumulate such regulatory asset or liability between general rate reviews and amortize the accumulated amount as part of resetting our base prices. Following is additional information regarding our pension and post-retirement benefit plans.


	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2015			2014			2013			2015			2014			2013
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	21,392		$	16,218		$	21,420		$	1,443		$	1,381		$	2,028
Interest cost		43,014			41,600			38,520			5,691			6,351			6,007
Expected return on plan assets		(40,236	)		(36,438	)		(33,405	)		(6,614	)		(6,576	)		(6,691	)
Amortization of unrecognized:
Transition obligation, net		—			—			—			—			—			325
Prior service costs		520			526			601			455			2,524			2,524
Actuarial loss (gain), net		32,131			19,362			33,914			379			(742	)		1,125

Net periodic cost before regulatory adjustment		56,821			41,268			61,050			1,354			2,938			5,318
Regulatory adjustment (a)		6,886			15,479			3,693			4,096			4,499			2,922

Net periodic cost	$	63,707		$	56,747		$	64,743		$	5,450		$	7,437		$	8,240

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain) loss	$	(43,459	)	$	162,569		$	(163,086	)	$	(9,576	)	$	15,896		$	(30,201	)
Amortization of actuarial (loss) gain		(32,379	)		(19,362	)		(33,914	)		(379	)		742			(1,125	)
Current year prior service cost		5,730			—			—			—			(7,834	)		—
Amortization of prior service costs		(520	)		(526	)		(601	)		(455	)		(2,524	)		(2,525	)
Amortization of transition obligation		—			—			—			—			—			(325	)
Other adjustments		352			—			—			—			—			—

Total recognized in regulatory assets	$	(70,276	)	$	142,681		$	(197,601	)	$	(10,410	)	$	6,280		$	(34,176	)

Total recognized in net periodic cost and regulatory assets	$	(6,569	)	$	199,428		$	(132,858	)	$	(4,960	)	$	13,717		$	(25,936	)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
Discount rate		4.17	%		5.07	%		4.13	%		4.10	%		4.88	%		3.99	%
Expected long-term return on plan assets		6.50	%		6.50	%		6.50	%		6.00	%		6.00	%		6.00	%
Compensation rate increase		4.00	%		4.00	%		4.00	%		4.00	%		4.00	%		4.00	%

(a)	The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.


	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	20,559	$	(1,118	)
Prior service cost		987		455

Total	$	21,546	$	(663	)

We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. We select assumed projected rates of return for each asset class after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, we develop an overall expected rate of return for the portfolios, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

Plan Assets

We believe we manage pension and post-retirement benefit plan assets in a prudent manner with regard to preserving principal while providing reasonable returns. We have adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of our strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. We delegate the management of our pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by management, which include allowable and/or prohibited investment types. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

We have established certain prohibited investments for our pension and post-retirement benefit plans. Such prohibited investments include loans to the company or its officers and directors as well as investments in the company’s debt or equity securities, except as may occur indirectly through investments in diversified mutual funds. In addition, to reduce concentration of risk, the pension plan will not invest in any fund that holds more than 25% of its total assets to be invested in the securities of one or more issuers conducting their principal business activities in the same industry. This restriction does not apply to investments in securities issued or guaranteed by the U.S. government or its agencies.

Target allocations for our pension plan assets are approximately 39% to debt securities, 39% to equity securities, 12% to alternative investments such as real estate securities, hedge funds and private equity investments, and the remaining 10% to a fund which provides tactical portfolio overlay by investing in debt and equity securities. Our investments in equity include investment funds with underlying investments in domestic and foreign large-, mid- and small-cap companies, derivatives related to such holdings, private equity investments including late-stage venture investments and other investments. Our investments in debt include core and high-yield bonds. Core bonds are comprised of investment funds with underlying investments in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and other debt securities. High-yield bonds include investment funds with underlying investments in non-investment grade debt securities of corporate entities, obligations of foreign governments and their agencies, private debt securities and other debt securities. Real estate securities consist primarily of funds invested in core real estate throughout the U.S. while alternative funds invest in wide ranging investments including equity and debt securities of domestic and foreign corporations, debt securities issued by U.S. and foreign governments and their agencies, structured debt, warrants, exchange-traded funds, derivative instruments, private investment funds and other investments.

Target allocations for our post-retirement benefit plan assets are 65% to equity securities and 35% to debt securities. Our investments in equity securities include investment funds with underlying investments primarily in domestic and foreign large-, mid- and small-cap companies. Our investments in debt securities include a core bond fund with underlying investments in investment grade debt securities of domestic and foreign corporate entities, obligations of U.S. and foreign governments and their agencies, private placement securities and other investments.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the pension and post-retirement benefits trusts may buy and sell investments resulting in changes within the hierarchy. See Note 4, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.

All level 2 pension investments are held in investment funds that are measured at fair value using daily net asset values as reported by the trustee, invested directly in long-term U.S. Treasury securities. We also maintain certain level 3 investments in private equity, alternative investments and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at fair value utilizing both market- and income-based models, public company comparables, investment cost or the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. The underlying real estate investments are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.


As of December 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	165,506	$	25,277	$	190,783
International equity fund		—		75,453		—		75,453
Emerging market equity fund		—		20,798		—		20,798
Domestic bond fund		—		105,279		—		105,279
Core bond funds		—		99,726		—		99,726
High-yield bond fund		—		28,288		—		28,288
Emerging market bond fund		—		23,019		—		23,019
Combination debt/equity/other fund		—		36,151		—		36,151
Alternative investment funds		—		—		39,557		39,557
Real estate securities fund		—		—		30,173		30,173
Cash equivalents		—		4,718		—		4,718

Total Assets Measured at Fair Value	$	—	$	558,938	$	95,007	$	653,945


As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	160,574	$	23,996	$	184,570
International equity fund		—		82,604		—		82,604
Core bond funds		—		224,740		—		224,740
High-yield bond fund		—		20,412		—		20,412
Emerging market bond fund		—		14,685		—		14,685
Combination debt/equity/other fund		—		61,632		—		61,632
Alternative investment funds		—		—		41,141		41,141
Real estate securities fund		—		—		26,439		26,439
Cash equivalents		—		4,918		—		4,918

Total Assets Measured at Fair Value	$	—	$	569,565	$	91,576	$	661,141

The following table provides a reconciliation of pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2015 and 2014.


	Domestic Equity Funds			Alternative Investment Funds			Real Estate Securities Fund			Total
	(In Thousands)
Balance as of December 31, 2014	$	23,996		$	41,141		$	26,439		$	91,576
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date		934			(1,584	)		3,944			3,294
Relating to assets sold during the period		2,755			—			60			2,815
Purchases, issuances and settlements, net		(2,408	)		—			(270	)		(2,678	)

Balance as of December 31, 2015	$	25,277		$	39,557		$	30,173		$	95,007

Balance as of December 31, 2013	$	22,488		$	39,171		$	24,022		$	85,681
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date		(154	)		1,970			2,630			4,446
Relating to assets sold during the period		1,365			—			29			1,394
Purchases, issuances and settlements, net		297			—			(242	)		55

Balance as of December 31, 2014	$	23,996		$	41,141		$	26,439		$	91,576

The following table provides the fair value of our post-retirement benefit plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.


As of December 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	59,946	$	—	$	59,946
International equity fund		—		14,419		—		14,419
Core bond funds		—		40,475		—		40,475
Cash equivalents		—		576		—		576

Total Assets Measured at Fair Value	$	—	$	115,416	$	—	$	115,416


As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	63,600	$	—	$	63,600
International equity fund		—		14,783		—		14,783
Core bond funds		—		42,390		—		42,390
Cash equivalents		—		576		—		576

Total Assets Measured at Fair Value	$	—	$	121,349	$	—	$	121,349

Cash Flows

The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.


	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2016	$	28.0					$	—
Expected benefit payments:
2016	$	(54.0	)	$	(2.8	)	$	(7.4	)	$	(0.4	)
2017		(55.0	)		(2.8	)		(7.7	)		(0.3	)
2018		(57.4	)		(2.7	)		(7.9	)		(0.3	)
2019		(59.3	)		(2.7	)		(8.1	)		(0.3	)
2020		(61.4	)		(2.7	)		(8.3	)		(0.3	)
2021-2025		(318.3	)		(12.6	)		(41.2	)		(1.1	)

Savings Plans

We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees’ contributions in cash up to specified maximum limits. Our contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions totaled $7.7 million in 2015, $7.0 million in 2014 and $6.9 million in 2013.

Stock-Based Compensation Plans

We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to 8.25 million shares of common stock may be granted under the LTISA Plan. As of December 31, 2015, awards of approximately 5.0 million shares of common stock had been made under the plan.

All stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as an expense in the consolidated statement of income over the requisite service period. The requisite service periods range from one to ten years. The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.


	Year Ended December 31,
	2015		2014		2013
	(In Thousands)
Compensation expense	$	8,250	$	7,193	$	8,121
Income tax benefits related to stock-based compensation arrangements		3,263		2,845		3,212

We use RSU awards for our stock-based compensation awards. RSU awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined as nonvested shares and do not include restrictions once the awards have vested.

RSU awards with only service requirements vest solely upon the passage of time. We measure the fair value of these RSU awards based on the market price of the underlying common stock as of the grant date. RSU awards with only service conditions that have a graded vesting schedule are recognized as an expense in the consolidated statement of income on a straight-line basis over the requisite service period for the entire award. Nonforfeitable dividend equivalents, or the rights to receive cash equal to the value of dividends paid on Westar Energy’s common stock, are paid on these RSUs during the vesting period.

RSU awards with performance measures vest upon expiration of the award term. The number of shares of common stock awarded upon vesting will vary from 0% to 200% of the RSU award, with performance tied to our total shareholder return relative to the total shareholder return of our peer group. We measure the fair value of these RSU awards using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of the expected volatility and risk-free interest rates. Expected volatility is based on historical volatility over three years using daily stock price observations. The risk-free interest rate is based on treasury constant maturity yields as reported by the Federal Reserve and the length of the performance period. For the 2015 valuation, inputs for expected volatility ranged from 14.6% to 19.1% and the risk-free interest rate was approximately 1.0%. For the 2014 valuation, inputs for expected volatility ranged from 15.2% to 23.3% and the risk-free interest rate was approximately 0.3%. For these RSU awards, dividend equivalents accumulate over the vesting period and are paid in cash based on the number of shares of common stock awarded upon vesting.

During the years ended December 31, 2015, 2014 and 2013, our RSU activity for awards with only service requirements was as follows.


	As of December 31,
	2015					2014					2013
	Shares			Weighted- Average Grant Date Fair Value		Shares			Weighted- Average Grant Date Fair Value		Shares			Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year		342.2		$	31.38		352.5		$	28.38		351.1		$	25.47
Granted		115.7			39.50		131.5			34.53		139.6			31.06
Vested		(115.4	)		28.77		(118.2	)		26.19		(125.5	)		23.22
Forfeited		(32.6	)		33.07		(23.6	)		30.00		(12.7	)		28.35

Nonvested balance, end of year		309.9			35.21		342.2			31.38		352.5			28.38

Total unrecognized compensation cost related to RSU awards with only service requirements was $4.5 million and $4.4 million as of December 31, 2015 and 2014, respectively. We expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value of RSUs with only service requirements that vested during the years ended December 31, 2015, 2014 and 2013, was $4.7 million, $3.9 million and $3.7 million, respectively.

During the years ended December 31, 2015, 2014 and 2013, our RSU activity for awards with performance measures was as follows.


	As of December 31,
	2015					2014					2013
	Shares			Weighted- Average Grant Date Fair Value		Shares			Weighted- Average Grant Date Fair Value		Shares			Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year		345.1		$	32.31		350.1		$	30.35		340.1		$	29.20
Granted		94.8			40.26		126.1			35.97		134.4			31.54
Vested		(109.0	)		28.99		(108.2	)		30.56		(112.5	)		28.29
Forfeited		(31.8	)		34.03		(22.9	)		30.70		(11.9	)		30.45

Nonvested balance, end of year		299.1			36.00		345.1			32.31		350.1			30.35

As of December 31, 2015 and 2014, total unrecognized compensation cost related to RSU awards with performance measures was $4.0 million and $3.8 million, respectively. We expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value of RSUs with performance measures that vested during the years ended December 31, 2015, 2014 and 2013, was $3.1 million, $0.5 million and $2.3 million, respectively.

Another component of the LTISA Plan is the Executive Stock for Compensation program under which, in the past, eligible employees were entitled to receive deferred common stock in lieu of current cash compensation. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. Plan participants were awarded 296 shares of common stock for dividends in 2015, 403 shares in 2014 and 551 shares in 2013. Participants received common stock distributions of 2,024 shares in 2015, 1,944 shares in 2014 and 3,456 shares in 2013.

Income tax benefits resulting from income tax deductions in excess of the related compensation cost recognized in the financial statements is classified as cash flows from financing activities in the consolidated statements of cash flows.

12. WOLF CREEK EMPLOYEE BENEFIT PLANS

Pension and Post-retirement Benefit Plans

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. KGE accrues its 47% share of Wolf Creek’s cost of pension and post-retirement benefits during the years an employee provides service. The following tables summarize the status of KGE’s 47% 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 Recognized in the Balance Sheets Consist of:
Current liability	$	(247	)	$	(247	)	$	(597	)	$	(575	)
Noncurrent liability		(84,549	)		(85,413	)		(7,091	)		(7,659	)

Net amount recognized	$	(84,796	)	$	(85,660	)	$	(7,688	)	$	(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


	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 of life 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.

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 KGE’s 47% share of the Wolf Creek pension and other post-retirement benefit plans.


	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2015			2014			2013			2015			2014			2013
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	7,595		$	5,695		$	6,835		$	138		$	173		$	206
Interest cost		9,016			8,469			7,562			314			464			413
Expected return on plan assets		(9,044	)		(8,084	)		(7,373	)		—			—			—
Amortization of unrecognized:
Prior service costs		57			58			58			—			—			—
Actuarial loss, net		5,930			2,987			5,421			3			165			265

Net periodic cost before regulatory adjustment		13,554			9,125			12,503			455			802			884
Regulatory adjustment (a)		(1,485	)		2,328			(641	)		—			—			—

Net periodic cost	$	12,069		$	11,453		$	11,862		$	455		$	802		$	884

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain) loss	$	(2,373	)	$	38,833		$	(29,911	)	$	(211	)	$	(1,881	)	$	(1,303	)
Amortization of actuarial gain		(5,930	)		(2,987	)		(5,421	)		(3	)		(165	)		(265	)
Amortization of prior service cost		(57	)		(58	)		(58	)		—			—			—

Total recognized in regulatory assets	$	(8,360	)	$	35,788		$	(35,390	)	$	(214	)	$	(2,046	)	$	(1,568	)

Total recognized in net periodic cost and regulatory assets	$	3,709		$	47,241		$	(23,528	)	$	241		$	(1,244	)	$	(684	)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate		4.20	%		5.11	%		4.16	%		3.89	%		4.70	%		3.78	%
Expected long-term return on plan assets		7.50	%		7.50	%		7.50	%		—			—			—
Compensation rate increase		4.00	%		4.00	%		4.00	%		—			—			—

(a)	The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.


	Pension Benefits		Post-retirement 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.

For measurement purposes, the assumed annual health care cost growth rates were as follows.


	As of December 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-Percentage- Point Increase			One-Percentage- Point 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 financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. Wolf Creek delegates the management of its pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

The target allocations for Wolf Creek’s pension plan assets are 31% to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies, 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 Trading Securities,” for a description of the hierarchal framework.

The following table provides the fair value of KGE’s 47% share of Wolf Creek’s pension plan assets and the corresponding level of hierarchy as of December 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 of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
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 KGE’s 47% 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 Securities Fund		Alternative Investment 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

Cash Flows

The following table shows our expected cash flows for KGE’s 47% share of Wolf Creek’s pension and post-retirement benefit plans for future years.


Expected Cash Flows	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) 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. KGE’s portion of the expense associated with Wolf Creek’s matching contributions was $1.6 million in 2015, $1.4 million in 2014 and $1.4 million in 2013.

13. COMMITMENTS AND CONTINGENCIES

Purchase Orders and Contracts

As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under “—Fuel, Purchased Power and Transmission Commitments.” These commitments relate to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments as of December 31, 2015, was as follows.


	Committed Amount
	(In Thousands)
2016 (a)	$	757,250
2017		13,199
2018		48,744
Thereafter		31,720

Total amount committed	$	850,913

(a)	Significant portion related to construction commitments.

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 (SO₂), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.

Emissions from our generating facilities, including PM, SO₂ 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 SO₂ 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 SO₂ 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 SO₂ 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 SO₂ emissions for that year. In 2015, we had adequate SO₂ 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 of NOx 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 SO₂, 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 SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ 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. Tecumseh Energy Center is our only generating station that meets this criteria. 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 could have on our operations and consolidated financial results. 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 (CO₂) 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 CO₂ 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 CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour (MWh) depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO₂ 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.

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 $34.4 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 14, “Asset Retirement Obligations,” for additional information.

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 of renewable 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.

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, $2.8 million in 2014 and $2.9 million in 2013. 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 of a cent for each kilowatt-hour of net nuclear generation delivered to customers, was $0.8 million in 2014 and $3.0 million in 2013. We included these costs in fuel and purchased power expense on our consolidated statements of income.

In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. 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.

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 $827.8 million. The contracts are for plants that 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 contracts were approximately $109.6 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2030.

We have power purchase agreements with the owners of nine separate wind generation facilities with installed design capabilities of approximately 1,314 MW expiring in 2028 through 2036. Of the approximately 1,314 MW under contract, approximately 400 MW are associated with agreements pursuant to which generation providers are scheduled to deliver power beginning by early 2017. Each of the agreements provide for our receipt and purchase of energy produced at a fixed price per unit of output. We estimate that our annual cost of energy purchased from these wind generation facilities will be approximately $104.8 million in 2016 and approximately $145.0 million for the next several years thereafter.

We have acquired rights to transmit a total of 206 MW. These agreements providing transmission capacity for 206 MW expire in 2016. As of December 31, 2015, we are committed to spend approximately $7.1 million over the remaining terms of these agreements.

FERC Proceedings

See Note 3, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a pending settlement of a complaint that was filed by the KCC against us with the FERC under Section 206 of the FPA.

14. ASSET RETIREMENT OBLIGATIONS

Legal Liability

We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. The recording of 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 (KGE’s 47% share), retire our wind generation facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl (PCB)-contaminated oil.

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


	As of December 31,
	2015			2014
	(In Thousands)
Beginning ARO	$	230,668		$	160,682
Increase in nuclear decommissioning ARO liability		—			50,683
Increase in other ARO liabilities		34,440			9,580
Liabilities settled		(1,553	)		(593	)
Accretion expense		12,964			10,316
Revisions in estimated cash flows		(1,234	)		—

Ending ARO	$	275,285		$	230,668

In 2015, we recorded an approximately $34.4 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 13, “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 in 2014 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 retirement of our wind generation facilities, disposal of asbestos insulating material at our power plants, the remediation of ash disposal ponds and the disposal of PCB-contaminated oil.

We have an obligation to retire our wind generation facilities and remove the foundations. The ARO related to our owned wind generation facilities was determined based upon the date each wind generation facility was placed into service.

The amount of the retirement obligation related to asbestos disposal was recorded as of 1990, the date when the EPA published the “National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule.”

We operate, as permitted by the state of Kansas, ash landfills at several of our power plants. The retirement obligation for the ash landfills was determined based upon the date each landfill was originally placed in service.

PCB-contaminated oil is contained within company electrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regulations that originally became effective in 1978.

Non-Legal Liability - Cost of Removal

We collect in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of December 31, 2015 and 2014, we had $53.8 million and $88.2 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.

15. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Notes 3 and 13, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information.

16. COMMON STOCK

General

Westar Energy’s Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2015 and 2014, Westar Energy had issued 141.4 million shares and 131.7 million shares, respectively.

Westar Energy has a direct stock purchase plan (DSPP). Shares of common stock sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2015 and 2014, Westar Energy issued 0.5 million shares and 0.5 million shares, respectively, through the DSPP and other stock-based plans operated under the LTISA Plan. As of December 31, 2015 and 2014, a total of 1.2 million shares and 1.6 million shares, respectively, were available under the DSPP registration statement.

Issuances

In September 2013, Westar Energy entered into two forward sale agreements with two banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy’s common stock from third parties and sold them to a group of underwriters for $31.15 per share. Pursuant to over-allotment options granted to the underwriters, the underwriters purchased in October 2013 an additional 0.9 million shares from the banks as forward sellers, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under each agreement.

In March 2013, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank. The maximum amount that Westar Energy may offer and sell under the March 2013 master agreements is the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy may offer and sell shares of its common stock from time to time. In addition, under the terms of the sales agency financing agreement and master forward sale confirmation, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser and the bank will borrow shares of Westar Energy’s common stock from third parties and sell them through its agent. The agent receives a commission equal to 1% of the sales price of all shares sold under the agreements.

In April 2010, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank that was terminated in March 2013. The maximum amount that Westar Energy could offer and sell under the agreements was the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Terms under these agreements were generally similar to the March 2013 agreements described above.

The following table summarizes our common stock activity pursuant to the three forward sale agreements.


	Year Ended December 31,
	2015		2014		2013
Shares that could be settled at beginning of year		9,160,500		12,052,976		1,753,415
Transactions entered		—		—		11,367,673
Transactions settled (a)		9,160,500		2,892,476		1,068,112

Shares that could be settled at end of year		—		9,160,500		12,052,976

(a)	The shares settled during the years ended December 31, 2015, 2014 and 2013, were settled with a physical settlement amount of approximately $254.6 million, $82.9 million and $27.0 million, respectively.

The forward sale transactions were entered into at market prices; therefore, the forward sale agreements had no initial fair value. Westar Energy did not receive any proceeds from the sale of common stock under the forward sale agreements until transactions were settled. Westar Energy settled the forward sale transactions through physical share settlement and recorded the forward sale agreements within equity. The shares under the forward sale agreements were initially priced when the transactions were entered into and were subject to certain fixed pricing adjustments during the term of the agreements. The net proceeds from the forward sale transactions represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurred.

Westar Energy used the proceeds from the transactions described above to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.

17. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in JEC and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.

We assess all entities with which we become involved to determine whether such entities are VIEs and, if so, whether or not we are the primary beneficiary of the entities. We also continuously assess whether we are the primary beneficiary of the VIEs with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary.

8% Interest in Jeffrey Energy Center

Under an agreement that expires in January 2019, we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 8% interest in JEC at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.

50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 9, “Long-term Debt,” for additional information.

Railcars

Under two separate agreements, we leased railcars from unrelated trusts to transport coal to some of our power plants. We consolidated the trusts as VIEs until the agreements expired in November 2014 and May 2013. As a result of deconsolidating the trusts, property, plant and equipment of VIEs, net and noncontrolling interests decreased $7.3 million in 2014 and $14.3 million in 2013.

Financial Statement Impact

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIEs described above.


	As of December 31,
	2015		2014
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	268,239	$	278,573
Regulatory assets (a)		9,088		7,882
Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Accrued interest (b)		2,457		2,961
Long-term debt of variable interest entities, net		138,097		166,565

(a)	Included in long-term regulatory assets on our consolidated balance sheets.

(b)	Included in accrued interest on our consolidated balance sheets.

All of the liabilities noted in the table above relate to the purchase of the property, plant and equipment. The assets of the VIEs can be used only to settle obligations of the VIEs and the VIEs’ debt holders have no recourse to our general credit. We have not provided financial or other support to the VIEs and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIEs.

18. LEASES

Operating Leases

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment. In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term.

Rental expense and estimated future commitments under operating leases are as follows.


Year Ended December 31,	Total Operating Leases
	(In Thousands)
Rental expense:
2013	$	16,484
2014		14,143
2015		14,035
Future commitments:
2016	$	13,550
2017		11,646
2018		10,216
2019		8,815
2020		5,988
Thereafter		8,917

Total future commitments	$	59,132

Capital Leases

We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements.

Assets recorded under capital leases are listed below.


	As of December 31,
	2015			2014
	(In Thousands)
Vehicles	$	17,345		$	18,820
Computer equipment		1,204			1,504
Generation plant		40,048			40,048
Accumulated amortization		(13,477	)		(11,741	)

Total capital leases	$	45,120		$	48,631

Capital leases are treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.


Year Ended December 31,	Total Capital Leases
	(In Thousands)
2016	$	5,812
2017		5,386
2018		5,233
2019		4,645
2020		4,007
Thereafter		56,050

		81,133
Amounts representing imputed interest		(32,271	)

Present value of net minimum lease payments under capital leases		48,862
Less: Current portion		3,815

Total long-term obligation under capital leases	$	45,047

19. QUARTERLY RESULTS (UNAUDITED)

Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.


2015	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)
Revenues (a)	$	590,807	$	589,563	$	732,829	$	545,965
Net income (a)		53,163		66,243		140,564		41,826
Net income attributable to Westar Energy, Inc. (a)		50,980		63,710		138,003		39,235
Per Share Data (a):
Basic:
Earnings available	$	0.38	$	0.47	$	0.97	$	0.28
Diluted:
Earnings available	$	0.38	$	0.46	$	0.97	$	0.28
Cash dividend declared per common share	$	0.36	$	0.36	$	0.36	$	0.36
Market price per common share:
High	$	44.03	$	39.65	$	40.22	$	43.56
Low	$	36.58	$	33.88	$	34.17	$	37.55

(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.


2014	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)
Revenues (a)	$	628,556	$	612,668	$	764,040	$	596,439
Net income (a)		70,970		55,822		149,760		45,773
Net income attributable to Westar Energy, Inc. (a)		68,955		53,473		147,382		43,449
Per Share Data (a):
Basic:
Earnings available	$	0.53	$	0.41	$	1.13	$	0.33
Diluted:
Earnings available	$	0.52	$	0.40	$	1.10	$	0.32
Cash dividend declared per common share	$	0.35	$	0.35	$	0.35	$	0.35
Market price per common share:
High	$	35.33	$	38.24	$	38.23	$	43.15
Low	$	31.67	$	34.51	$	33.76	$	33.73

(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

WESTAR ENERGY, INC.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (a)			Balance at End of Period
	(In Thousands)
Year ended December 31, 2013
Allowances deducted from assets for doubtful accounts	$	4,916	$	7,039	$	(7,359	)	$	4,596
Year ended December 31, 2014
Allowances deducted from assets for doubtful accounts	$	4,596	$	9,752	$	(9,039	)	$	5,309
Year ended December 31, 2015
Allowances deducted from assets for doubtful accounts	$	5,309	$	8,614	$	(8,629	)	$	5,294

(a)	Result from write-offs of accounts receivable.

GREAT PLAINS ENERGY INC - FORM 8-K - EX-99.1 - September 27, 2016

Attached files

GREAT PLAINS ENERGY INC Reports