Exhibit 99.3

WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)

(Unaudited)

 

		As of June 30, 2016				As of December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	5,213			$	3,231
Accounts receivable, net of allowance for doubtful accounts of $5,093 and $5,294, respectively			298,841				258,286
Fuel inventory and supplies			299,465				301,294
Prepaid expenses			17,994				16,864
Regulatory assets			87,256				109,606
Other			33,099				27,860
Total Current Assets			741,868				717,141
PROPERTY, PLANT AND EQUIPMENT, NET			8,800,698				8,524,902
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET			263,072				268,239
OTHER ASSETS:
Regulatory assets			734,844				751,312
Nuclear decommissioning trust			189,179				184,057
Other			241,081				260,015
Total Other Assets			1,165,104				1,195,384
TOTAL ASSETS		$	10,970,742			$	10,705,666
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt		$	125,000			$	—
Current maturities of long-term debt of variable interest entities			26,842				28,309
Short-term debt			177,000				250,300
Accounts payable			178,374				220,969
Accrued dividends			52,767				49,829
Accrued taxes			95,084				83,773
Accrued interest			41,969				71,426
Regulatory liabilities			33,634				25,697
Other			90,841				106,632
Total Current Liabilities			821,511				836,935
LONG-TERM LIABILITIES:
Long-term debt, net			3,387,696				3,163,950
Long-term debt of variable interest entities, net			111,230				138,097
Deferred income taxes			1,655,825				1,591,430
Unamortized investment tax credits			208,318				209,763
Regulatory liabilities			247,916				267,114
Accrued employee benefits			455,923				462,304
Asset retirement obligations			280,507				275,285
Other			87,065				88,825
Total Long-Term Liabilities			6,434,480				6,196,768
COMMITMENTS AND CONTINGENCIES (See Notes 4, 11 and 12)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,691,017 shares and 141,353,426 shares, respective to each date			708,455				706,767
Paid-in capital			2,008,491				2,004,124
Retained earnings			978,187				945,830
Total Westar Energy, Inc. Shareholders’ Equity			3,695,133				3,656,721
Noncontrolling Interests			19,618				15,242
Total Equity			3,714,751				3,671,963
TOTAL LIABILITIES AND EQUITY		$	10,970,742			$	10,705,666

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

 

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

		Three Months Ended June 30,
		2016				2015
REVENUES		$	621,448			$	589,563
OPERATING EXPENSES:
Fuel and purchased power			118,630				140,080
SPP network transmission costs			55,227				57,352
Operating and maintenance			85,619				82,739
Depreciation and amortization			84,226				76,759
Selling, general and administrative			75,724				63,663
Taxes other than income tax			48,407				37,494
Total Operating Expenses			467,833				458,087
INCOME FROM OPERATIONS			153,615				131,476
OTHER INCOME (EXPENSE):
Investment earnings			2,280				1,634
Other income			3,382				15,121
Other expense			(2,908	)			(2,633	)
Total Other Income			2,754				14,122
Interest expense			39,683				45,516
INCOME BEFORE INCOME TAXES			116,686				100,082
Income tax expense			40,542				33,839
NET INCOME			76,144				66,243
Less: Net income attributable to noncontrolling interests			3,804				2,533
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.		$	72,340			$	63,710
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share		$	0.51			$	0.47
Diluted earnings per common share		$	0.51			$	0.46
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic			142,033,842				135,939,197
Diluted			142,497,335				137,412,152
DIVIDENDS DECLARED PER COMMON SHARE		$	0.38			$	0.36

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

 

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

		Six Months Ended June 30,
		2016				2015
REVENUES		$	1,190,898			$	1,180,370
OPERATING EXPENSES:
Fuel and purchased power			218,688				295,561
SPP network transmission costs			115,987				114,164
Operating and maintenance			163,377				167,819
Depreciation and amortization			167,866				151,345
Selling, general and administrative			132,179				119,082
Taxes other than income tax			97,375				75,365
Total Operating Expenses			895,472				923,336
INCOME FROM OPERATIONS			295,426				257,034
OTHER INCOME (EXPENSE):
Investment earnings			4,296				4,113
Other income			12,860				17,935
Other expense			(8,451	)			(8,345	)
Total Other Income			8,705				13,703
Interest expense			80,114				89,814
INCOME BEFORE INCOME TAXES			224,017				180,923
Income tax expense			79,165				61,517
NET INCOME			144,852				119,406
Less: Net income attributable to noncontrolling interests			6,927				4,716
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.		$	137,925			$	114,690
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2):
Basic earnings per common share		$	0.97			$	0.85
Diluted earnings per common share		$	0.97			$	0.84
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING:
Basic			142,013,344				134,177,136
Diluted			142,361,347				136,329,603
DIVIDENDS DECLARED PER COMMON SHARE		$	0.76			$	0.72

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

 

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 

		Six Months Ended June 30,
		2016				2015
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income		$	144,852			$	119,406
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			167,866				151,345
Amortization of nuclear fuel			16,831				10,085
Amortization of deferred regulatory gain from sale leaseback			(2,748	)			(2,748	)
Amortization of corporate-owned life insurance			8,819				9,042
Non-cash compensation			4,778				4,241
Net deferred income taxes and credits			75,334				54,740
Allowance for equity funds used during construction			(5,247	)			(2,041	)
Changes in working capital items:
Accounts receivable			(40,555	)			998
Fuel inventory and supplies			2,140				(31,307	)
Prepaid expenses and other			7,126				(40,195	)
Accounts payable			(21,364	)			(2,873	)
Accrued taxes			16,272				16,893
Other current liabilities			(62,434	)			(65,908	)
Changes in other assets			1,848				(9,712	)
Changes in other liabilities			15,163				21,046
Cash Flows from Operating Activities			328,681				233,012
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment			(503,631	)			(334,905	)
Purchase of securities - trusts			(39,603	)			(9,980	)
Sale of securities - trusts			41,201				10,263
Investment in corporate-owned life insurance			(14,648	)			(14,845	)
Proceeds from investment in corporate-owned life insurance			24,171				1,192
Investment in affiliated company			(655	)			—
Other investing activities			(2,798	)			(653	)
Cash Flows used in Investing Activities			(495,963	)			(348,928	)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net			(73,300	)			49,500
Proceeds from long-term debt			396,577				—
Proceeds from long-term debt of variable interest entities			162,048				—
Retirements of long-term debt			(50,000	)			(125,000	)
Retirements of long-term debt of variable interest entities			(190,355	)			(27,925	)
Repayment of capital leases			(401	)			(1,721	)
Borrowings against cash surrender value of corporate-owned life insurance			54,910				56,622
Repayment of borrowings against cash surrender value of corporate-owned life insurance			(22,921	)			(899	)
Issuance of common stock			1,354				256,394
Distributions to shareholders of noncontrolling interests			(2,551	)			(1,076	)
Cash dividends paid			(101,137	)			(89,035	)
Other financing activities			(4,960	)			(3,234	)
Cash Flows from Financing Activities			169,264				113,626
NET CHANGE IN CASH AND CASH EQUIVALENTS			1,982				(2,290	)
CASH AND CASH EQUIVALENTS:
Beginning of period			3,231				4,556
End of period		$	5,213			$	2,266

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

 

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WESTAR ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 

		Westar Energy, Inc. Shareholders
		Common stock shares				Common stock				Paid-in capital				Retained earnings				Non-controlling interests				Total equity
Balance as of December 31, 2014			131,687,454			$	658,437			$	1,781,120			$	855,299			$	6,451			$	3,301,307
Net income			—				—				—				114,690				4,716				119,406
Issuance of stock			9,208,267				46,041				210,353				—				—				256,394
Issuance of stock for compensation and reinvested dividends			282,897				1,415				4,117				—				—				5,532
Tax withholding related to stock compensation			—				—				(3,234	)			—				—				(3,234	)
Dividends declared on common stock ($0.72 per share)			—				—				—				(99,169	)			—				(99,169	)
Stock compensation expense			—				—				4,196				—				—				4,196
Tax benefit on stock compensation			—				—				1,178				—				—				1,178
Distributions to shareholders of noncontrolling interests			—				—				—				—				(1,076	)			(1,076	)
Other			—				—				(69	)			—				(1	)			(70	)
Balance as of June 30, 2015			141,178,618			$	705,893			$	1,997,661			$	870,820			$	10,090			$	3,584,464
Balance as of December 31, 2015			141,353,426			$	706,767			$	2,004,124			$	945,830			$	15,242			$	3,671,963
Net income			—				—				—				137,925				6,927				144,852
Issuance of stock			28,674				143				1,211				—				—				1,354
Issuance of stock for compensation and reinvested dividends			308,917				1,545				3,396				—				—				4,941
Tax withholding related to stock compensation			—				—				(4,960	)			—				—				(4,960	)
Dividends declared on common stock ($0.76 per share)			—				—				—				(108,894	)			—				(108,894	)
Stock compensation expense			—				—				4,720				—				—				4,720
Distribution to shareholders of noncontrolling interests			—				—				—				—				(2,551	)			(2,551	)
Cumulative effect of accounting change - stock compensation			—				—				—				3,326				—				3,326
Balance as of June 30, 2016			141,691,017			$	708,455			$	2,008,491			$	978,187			$	19,618			$	3,714,751

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

 

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WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

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

We provide electric generation, transmission and distribution services to approximately 704,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed 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. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2015 Form 10-K.

Use of Management’s Estimates

When we prepare our condensed 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 condensed 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 (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of the results to be expected for the full year.

 

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Fuel Inventory and Supplies

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

 

		As of June 30, 2016				As of December 31, 2015
		(In Thousands)
Fuel inventory		$	107,397			$	113,438
Supplies			192,068				187,856
Fuel inventory and supplies		$	299,465			$	301,294

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. 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:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2016				2015				2016				2015
		(Dollars In Thousands)
Borrowed funds		$	2,338			$	552			$	4,347			$	2,581
Equity funds			2,783				90				5,247				2,041
Total		$	5,121			$	642			$	9,594			$	4,622
Average AFUDC Rates			4.2	%			1.2	%			4.6	%			3.2	%

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.

 

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

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2016				2015				2016				2015
		(Dollars In Thousands, Except Per Share Amounts)
Net income		$	76,144			$	66,243			$	144,852			$	119,406
Less: Net income attributable to noncontrolling interests			3,804				2,533				6,927				4,716
Net income attributable to Westar Energy, Inc.			72,340				63,710				137,925				114,690
Less: Net income allocated to RSUs			156				141				290				257
Net income allocated to common stock		$	72,184			$	63,569			$	137,635			$	114,433
Weighted average equivalent common shares outstanding – basic			142,033,842				135,939,197				142,013,344				134,177,136
Effect of dilutive securities:
RSUs			463,493				121,234				348,003				127,999
Forward sale agreements			—				1,351,721				—				2,024,468
Weighted average equivalent common shares outstanding – diluted (a)			142,497,335				137,412,152				142,361,347				136,329,603
Earnings per common share, basic		$	0.51			$	0.47			$	0.97			$	0.85
Earnings per common share, diluted		$	0.51			$	0.46			$	0.97			$	0.84

 

(a)	We had no antidilutive securities for the three and six months ended June 30, 2016 and 2015.

Supplemental Cash Flow Information

 

		Six Months Ended June 30,
		2016				2015
		(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized		$	70,697			$	82,297
Interest on financing activities of VIEs			4,150				5,651
Income taxes, net of refunds			(77	)			126
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions			71,830				66,861
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends			4,941				5,532
Assets acquired through capital leases			392				1,102

 

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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.

Leases

In February 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-02 which requires lessees to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either financing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The guidance requires a modified retrospective approach for all leases existing at the earliest period presented, or entered into by the date of initial adoption, with certain practical expedients permitted. We are evaluating the guidance and believe application of the guidance will result in an increase to our assets and liabilities on our consolidated financial statements.

Stock-based Compensation

In March 2016, the FASB issued ASU No. 2016-09 as part of its simplification initiative. The areas for simplification involve several aspects of the accounting for stock-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to adopt effective January 1, 2016.

Prior to the adoption of ASU 2016-09, if the tax deduction for a stock-based payment award exceeded the compensation cost recorded for financial reporting, the additional tax benefit was recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB’s decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits and expense. Upon initial adoption, we recorded a $3.3 million cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized.

Further, the issuance of this ASU reflects the FASB’s decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities on the accompanying condensed consolidated statements of cash flows for the six months ended June 30, 2015, as $1.2 million higher than as previously reported, and cash flows from financing activities as $1.2 million lower than as previously reported.

Financial Instruments

In May 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize certain investments measured at net asset value (NAV) per share within the fair value hierarchy. The guidance is effective for fiscal years beginning after December 15, 2015. We have adopted this guidance as of January 1, 2016. The adoption was limited to disclosure and does not have a material impact on our consolidated financial statements. See Note 5, “Financial Instruments and Trading Securities.”

Revenue Recognition

In May 2014, the FASB 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 are continuing to analyze the new standard and 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.

 

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3. PENDING MERGER

On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy, a Missouri corporation, providing for the merger of a wholly-owned subsidiary of Great Plains Energy with and into Westar Energy, with Westar Energy surviving as a wholly-owned subsidiary of Great Plains Energy. At the closing of the merger, our shareholders will receive cash and shares of Great Plains Energy. Each issued and outstanding share of our common stock, other than certain restricted shares, will be canceled and automatically converted into $51.00 in cash, without interest, and a number of shares of Great Plains Energy common stock equal to an exchange ratio that may vary between 0.2709 and 0.3148, based upon the volume-weighted average share price of Great Plains Energy common stock on the New York Stock Exchange for the 20 consecutive full trading days ending on (and including) the third trading day immediately prior to the closing date of the transaction. Based on the closing price per share of Great Plains Energy common stock on the trading day prior to announcement of the merger, our shareholders would receive an implied $60.00 for each share of Westar Energy common stock.

The closing of the merger is subject to customary conditions including, among others, approval by our shareholders and the shareholders of Great Plains Energy and receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger.

On July 14, 2016, Great Plains Energy filed a registration statement on Form S-4 with the SEC. The registration statement includes a preliminary proxy statement that, once finalized, will be sent to our shareholders in connection with the special meeting of our shareholders to be held to vote to approve the merger.

The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If Great Plains Energy terminates the merger agreement because our board of directors changes its recommendation, if we terminate the merger agreement to enter into an acquisition agreement with a superior proposal, or if our shareholders vote and do not give approval and we enter into an acquisition proposal within 12 months of termination of the merger agreement, we must pay Great Plains Energy a termination fee of $280.0 million.

If the merger agreement is terminated under other circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of $380.0 million. If we terminate the merger agreement because the Great Plains Energy board of directors changes its recommendation, Great Plains Energy must pay us a termination fee of $180.0 million. If either party terminates the merger agreement because the end date occurred or Great Plains Energy shareholders’ approval was not acquired, and it has either been publicly disclosed that Great Plains Energy has entered into an alternative acquisition proposal, or an acquisition proposal was entered into within 12 months after the termination of the merger agreement, Great Plains Energy must pay us a termination fee of $180.0 million. If Great Plains Energy shareholders’ meeting was held and completed, but approval was not obtained, and the termination fee described above is not payable by Great Plains Energy, Great Plains Energy must pay us a termination fee of $80.0 million.

In connection with this transaction, we have incurred merger-related expenses. During the three months ended June 30, 2016, we incurred approximately $7.8 million of merger-related expenses, which is included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately $30.0 million, with the majority of the expense to coincide with the closing of the merger.

We are currently involved in litigation relating to the merger. See Note 11, “Commitments and Contingencies,” and Note 12, “Legal Proceedings,” for more information on legal matters.

4. RATE MATTERS AND REGULATION

KCC Proceedings

In December 2015, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2016 and are expected to increase our annual retail revenues by approximately $5.0 million.

In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR), along with the reduced return on equity (ROE) as described below. The

 

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updated prices were retroactively effective April 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $7.0 million. As of June 30, 2016, we have recorded a regulatory liability of $4.0 million for our estimated refund obligation from the refund effective date of April 2016 through June 2016.

FERC Proceedings

In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement results in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO.

The updated prices were retroactively effective January 2016 and the estimated revenue impact for 2016, as compared to 2015, is expected to be an increase of approximately $24.0 million. This increase also reflects estimated recovery of increased transmission capital expenditures and operating costs. We have begun refunding our previously recorded refund obligation during the three months ended June 30, 2016. As of June 30, 2016, we have a remaining refund obligation of $8.1 million which is included in current regulatory liabilities on our balance sheet.

5. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

GAAP establishes a hierarchical framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy levels. In addition, we measure certain investments that do not have a readily determinable fair value at NAV, which are not included in the fair value hierarchy. Further explanation of these levels and NAV is summarized below.

 

•

Level 1 - Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on public exchanges.

 

•

Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically liquid investments in funds which have a readily determinable fair value calculated using daily NAVs, other financial instruments that are comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or other financial instruments priced with models using highly observable inputs.

 

•

Level 3 - Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation.

 

•

Net Asset Value - Investments that do not have a readily determinable fair value are measured at NAV. These investments do not consider the observability of inputs, therefore, they are not included within the fair value hierarchy. We include in this category investments in private equity, real estate and alternative investment funds. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments.

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

 

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

 

		As of June 30, 2016								As of December 31, 2015
		Carrying Value				Fair Value				Carrying Value				Fair Value
		(In Thousands)
Fixed-rate debt		$	3,430,000			$	3,865,914			$	3,080,000			$	3,259,533
Fixed-rate debt of VIEs			137,963				154,097				166,271				179,030

 

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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 June 30, 2016		Level 1				Level 2				Level 3				NAV				Total
		(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds			—			$	50,856			$	—			$	5,944			$	56,800
International equity funds			—				34,560				—				—				34,560
Core bond fund			—				27,509				—				—				27,509
High-yield bond fund			—				16,557				—				—				16,557
Emerging markets bond fund			—				15,342				—				—				15,342
Combination debt/equity/other funds			—				12,277				—				—				12,277
Alternative investments fund			—				—				—				16,386				16,386
Real estate securities fund			—				—				—				9,500				9,500
Cash equivalents			248				—				—				—				248
Total Nuclear Decommissioning Trust			248				157,101				—				31,830				189,179
Trading Securities:
Domestic equity funds			—				17,782				—				—				17,782
International equity fund			—				4,220				—				—				4,220
Core bond fund			—				11,935				—				—				11,935
Cash equivalents			156				—				—				—				156
Total Trading Securities			156				33,937				—				—				34,093
Total Assets Measured at Fair Value		$	404			$	191,038			$	—			$	31,830			$	223,272
As of December 31, 2015		Level 1				Level 2				Level 3				NAV				Total
		(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds		$	—			$	50,872			$	—			$	6,050			$	56,922
International equity funds			—				33,595				—				—				33,595
Core bond fund			—				25,976				—				—				25,976
High-yield bond fund			—				15,288				—				—				15,288
Emerging markets bond fund			—				13,584				—				—				13,584
Combination debt/equity/other funds			—				11,343				—				—				11,343
Alternative investments 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

 

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Some of our investments in the Nuclear Decommissioning Trust (NDT) are measured at NAV and do not have readily determinable fair values. These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations, these investments may have redemption restrictions. The following table provides additional information on these investments.

 

		As of June 30, 2016								As of December 31, 2015								As of June 30, 2016
		Fair Value				Unfunded Commitments				Fair Value				Unfunded Commitments				Redemption Frequency				Length of Settlement
						(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds		$	5,944			$	3,689			$	6,050			$	1,948				(a)				(a)
Alternative investments fund (b)			16,386				—				16,439				—				Quarterly				65 days
Real estate securities fund (b)			9,500				—				10,823				—				Quarterly				65 days
Total		$	31,830			$	3,689			$	33,312			$	1,948

 

(a)

This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.

(b)	There is a holdback on final redemptions.

Price Risk

We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to 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. 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.

6. FINANCIAL INVESTMENTS

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

Trading Securities

We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of June 30, 2016, and December 31, 2015, we measured the fair value of trust assets at $34.1 million and $33.9 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the three months ended June 30, 2016, we recorded an unrealized gain of $0.6 million on assets still held. For the six months ended June 30, 2016, we recorded an unrealized gain of $1.1 million on assets still held. For the three months ended June 30, 2015, we recorded no unrealized gain or loss on assets still held. For the six months ended June 30, 2015, we recorded an unrealized gain of $0.7 million on assets still held.

 

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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 June 30, 2016, and December 31, 2015.

Using the specific identification method to determine cost, we realized a gain of $0.1 million during the three months ended June 30, 2016, and a loss of $1.4 million during the six months ended June 30, 2016. We realized a loss of $0.6 million for the three months ended June 30, 2015, and a loss of $0.5 million for the six months ended June 30, 2015. 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 June 30, 2016, and December 31, 2015.

 

						Gross Unrealized
Security Type		Cost				Gain				Loss				Fair Value				Allocation
						(Dollars In Thousands)
As of June 30, 2016:
Domestic equity funds		$	49,844			$	6,965			$	(9	)		$	56,800				30	%
International equity funds			33,935				1,201				(576	)			34,560				18	%
Core bond fund			26,882				627				—				27,509				15	%
High-yield bond fund			17,405				—				(848	)			16,557				9	%
Emerging market bond fund			16,145				—				(803	)			15,342				8	%
Combination debt/equity/other funds			9,003				3,274				—				12,277				6	%
Alternative investment fund			15,000				1,386				—				16,386				9	%
Real estate securities fund			9,500				—				—				9,500				5	%
Cash equivalents			248				—				—				248				<1	%
Total		$	177,962			$	13,453			$	(2,236	)		$	189,179				100	%
As of December 31, 2015:
Domestic equity funds		$	49,488			$	7,436			$	(2	)		$	56,922				32	%
International equity funds			33,458				1,372				(1,235	)			33,595				18	%
Core bond fund			26,397				—				(421	)			25,976				14	%
High-yield bond fund			17,047				—				(1,759	)			15,288				8	%
Emerging market bond fund			16,306				—				(2,722	)			13,584				7	%
Combination debt/equity/other funds			8,239				3,104				—				11,343				6	%
Alternative investment fund			15,000				1,439				—				16,439				9	%
Real estate securities fund			11,026				—				(203	)			10,823				6	%
Cash equivalents			87				—				—				87				<1	%
Total		$	177,048			$	13,351			$	(6,342	)		$	184,057				100	%

 

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The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of June 30, 2016, and December 31, 2015.

 

		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 June 30, 2016:
Domestic equity funds		$	861			$	(9	)		$	—			$	—			$	861			$	(9	)
International equity funds			—				—				7,426				(576	)			7,426				(576	)
High-yield bond fund			—				—				16,557				(848	)			16,557				(848	)
Emerging market bond fund			—				—				15,342				(803	)			15,342				(803	)
Total		$	861			$	(9	)		$	39,325			$	(2,227	)		$	40,186			$	(2,236	)
As of December 31, 2015:
Domestic equity funds		$	—			$	—			$	668			$	(2	)		$	668			$	(2	)
International equity funds			—				—				6,717				(1,235	)			6,717				(1,235	)
Core bond funds			25,976				(421	)			—				—				25,976				(421	)
High-yield bond fund			15,288				(1,759	)			—				—				15,288				(1,759	)
Emerging market bond fund			—				—				13,584				(2,722	)			13,584				(2,722	)
Real estate securities fund			—				—				10,823				(203	)			10,823				(203	)
Total		$	41,264			$	(2,180	)		$	31,792			$	(4,162	)		$	73,056			$	(6,342	)

7. DEBT FINANCING

In June 2016, Westar Energy issued $350.0 million in principal amount of first mortgage bonds bearing a stated interest at 2.55% and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds will be used for renewable energy projects, primarily the construction of the Western Plains Wind Farm.

Also in June 2016, KGE refunded $50.0 million in principal amount of pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from 4.85% to 2.50%.

In February 2016, KGE, as lessee to the La Cygne Generating Station (La Cygne) sale-leaseback, effected a refunding of $162.1 million in outstanding bonds maturing in March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 13, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

8. TAXES

We recorded income tax expense of $40.5 million with an effective income tax rate of 35% for the three months ended June 30, 2016, and income tax expense of $33.8 million with an effective income tax rate of 34% for the same period of 2015. We recorded income tax expense of $79.2 million with an effective income tax rate of 35% for the six months ended June 30, 2016, and income tax expense of $61.5 million with an effective income tax rate of 34% for the same period of 2015. The increase in the effective income tax rate for the three and six months ended June 30, 2016, was due primarily to an increase in income before income taxes.

As of June 30, 2016, and December 31, 2015, our unrecognized income tax benefits totaled $3.0 million and $2.9 million, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next 12 months.

 

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As of June 30, 2016, and December 31, 2015, we had no amounts accrued for interest related to our unrecognized income tax benefits. We accrued no penalties at either June 30, 2016, or December 31, 2015.

As of June 30, 2016, and December 31, 2015, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

9. PENSION AND POST-RETIREMENT BENEFIT PLANS

The following tables summarize the net periodic costs for our pension and post-retirement benefit plans prior to the effects of capitalization.

 

		Pension Benefits								Post-retirement Benefits
Three Months Ended June 30,		2016				2015				2016				2015
		(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost		$	4,633			$	5,348			$	271			$	361
Interest cost			10,921				10,753				1,393				1,422
Expected return on plan assets			(10,663	)			(10,059	)			(1,708	)			(1,654	)
Amortization of unrecognized:
Prior service costs			174				130				114				114
Actuarial loss (gain), net			5,146				8,053				(280	)			95
Net periodic cost (benefit) before regulatory adjustment			10,211				14,225				(210	)			338
Regulatory adjustment (a)			3,306				1,534				(486	)			1,013
Net periodic cost (benefit)		$	13,517			$	15,759			$	(696	)		$	1,351

 

(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.

 

		Pension Benefits								Post-retirement Benefits
Six Months Ended June 30,		2016				2015				2016				2015
		(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost		$	9,297			$	10,696			$	542			$	722
Interest cost			21,880				21,507				2,786				2,845
Expected return on plan assets			(21,326	)			(20,118	)			(3,417	)			(3,307	)
Amortization of unrecognized:
Prior service costs			420				260				228				227
Actuarial loss (gain), net			10,534				15,714				(560	)			190
Net periodic cost (benefit) before regulatory adjustment			20,805				28,059				(421	)			677
Regulatory adjustment (a)			6,613				3,332				(972	)			2,026
Net periodic cost (benefit)		$	27,418			$	31,391			$	(1,393	)		$	2,703

 

(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.

During the six months ended June 30, 2016 and 2015, we contributed $11.2 million and $19.4 million, respectively, to the Westar Energy pension trust.

 

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10. WOLF CREEK 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. The following tables summarize the net periodic costs for KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans prior to the effects of capitalization.

 

		Pension Benefits								Post-retirement Benefits
Three Months Ended June 30,		2016				2015				2016				2015
		(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost		$	1,687			$	1,899			$	32			$	34
Interest cost			2,414				2,254				82				79
Expected return on plan assets			(2,430	)			(2,261	)			—				—
Amortization of unrecognized:
Prior service costs			14				14				—				—
Actuarial loss (gain), net			1,089				1,482				(4	)			1
Net periodic cost before regulatory adjustment			2,774				3,388				110				114
Regulatory adjustment (a)			483				(304	)			—				—
Net periodic cost		$	3,257			$	3,084			$	110			$	114

 

(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.

 

		Pension Benefits								Post-retirement Benefits
Six Months Ended June 30,		2016				2015				2016				2015
		(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost		$	3,374			$	3,797			$	64			$	69
Interest cost			4,828				4,508				163				157
Expected return on plan assets			(4,861	)			(4,522	)			—				—
Amortization of unrecognized:
Prior service costs			28				28				—				—
Actuarial loss (gain), net			2,178				2,965				(8	)			1
Net periodic cost before regulatory adjustment			5,547				6,776				219				227
Regulatory adjustment (a)			966				(608	)			—				—
Net periodic cost		$	6,513			$	6,168			$	219			$	227

 

(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.

During the six months ended June 30, 2016 and 2015, we funded $3.2 million and $2.5 million of Wolf Creek’s pension plan contributions, respectively.

 

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11. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Cross-State Air Pollution Rule

In November 2015, the Environmental Protection Agency (EPA) proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of nitrogen oxides (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 Clean Air Act (CAA), the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, NOx (a precursor to ozone), carbon monoxide (CO) and sulfur dioxide (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 do not believe this will have a material impact on our operations or consolidated financial results.

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. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in June 2016, Kansas Department of Health and Environment (KDHE) recommended a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO₂ Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We are working with KDHE to determine the impact of this proposed designation. 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 in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

Burning coal and other fossil fuels releases carbon dioxide (CO₂) and other gases referred to as GHG. 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.

 

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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 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. 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. In May 2016, the U.S. Court of Appeals for the D.C. Circuit decided to forego the normal three judge panel to review the CPP and to conduct the review en banc. At the same time, the Court scheduled oral arguments for September 2016. In June 2016, the EPA issued a proposed rule formalizing the details of the CPP’s Clean Energy Incentive Program. 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.

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. It is believed the stay will last into 2017. We are currently evaluating the final rule. We do not believe the rule will 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 believe the impact on our operations or consolidated financial results could be material.

 

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SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. The SPP has 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, but it could be material.

Storage of Spent Nuclear Fuel

In 2010, the Department of Energy (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.

FERC Proceedings

See Note 4, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a settlement of a complaint that was filed by the KCC against us with the FERC under Section 206 of the Federal Power Act.

Department of Justice Proceedings

At any time before or after the merger, the Department of Justice (DOJ) or the Federal Trade Commission could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the merger or seeking divestiture of substantial assets of Great Plains Energy, the Company or their respective subsidiaries. Private parties and state attorneys general may also bring an action under the antitrust laws under certain circumstances. On June 23, 2016, the DOJ sent a letter to us and Great Plains Energy informing the parties that it had opened an investigation into the proposed transaction and requested that the parties provide on a voluntary basis certain documents and information. We and Great Plains Energy intend to fully cooperate with the DOJ in its investigation. Based upon an examination of information available relating to the businesses in which the companies are engaged, we and Great Plains Energy believe that the merger will receive the necessary antitrust clearance. However, there can be no assurance that a challenge to the merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.

12. 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 Note 4, “Rate Matters and Regulation,” and Note 11, “Commitments and Contingencies,” for additional information.

 

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Pending Merger

Following the announcement of the merger agreement, two putative class action complaints and one putative derivative action complaint challenging the merger were filed on behalf of purported Westar Energy shareholders in the District Court of Shawnee County, Kansas.

The first complaint, filed on June 13, 2016, is captioned Smith v. Westar Energy, Inc., et al., Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that we and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration undervalues Westar Energy, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourages third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, our CEO will reap significant personal financial gain. The complaint seeks, among other remedies, a declaration that the action may be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement (to the extent already implemented), a directive to the members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

The second complaint, filed on June 14, 2016, is captioned Miller v. Westar Energy, Inc., et al., Case No. 2016-CV-000458. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the merger consideration deprives our shareholders of fair consideration for their shares, that the merger agreement contains deal protection provisions that unfairly favor Great Plains Energy and discourage third parties from submitting potentially superior proposals, and that if the proposed transaction is consummated, certain of our directors and officers stand to receive significant benefits. The complaint seeks, among other remedies, an order to permit the action to be maintained as a class action, injunctive relief enjoining the merger, rescission of the merger agreement, a directive to defendants to account for all damages caused by them as a result of their breaches of their fiduciary duties, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper.

Counsel for plaintiffs in the Smith matter and the Miller matter have filed an unopposed motion for consolidation and appointment of lead counsel. The defendants believe that the claims asserted against them in both class action lawsuits are without merit and intend to vigorously defend against such claims.

The third complaint, filed on July 5, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action is brought on behalf of our shareholders and names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as the nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the proposed merger, and that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals. The complaint seeks, among other remedies, an order to permit the action to be maintained as a derivative action, enjoining direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, a declaration that the proposed transaction was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement (to the extent already implemented), imposing a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and award for costs, including attorneys’ fees and experts’ fees, and further equitable relief as the court may deem just and proper. The defendants intend to seek dismissal of this complaint at the appropriate time.

 

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13. 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 Jeffrey Energy Center (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 7, “Debt Financing,” for additional information.

 

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Financial Statement Impact

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

 

		As of June 30, 2016				As of December 31, 2015
		(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net		$	263,072			$	268,239
Regulatory assets (a)			9,758				9,088
Liabilities:
Current maturities of long-term debt of variable interest entities		$	26,842			$	28,309
Accrued interest (b)			867				2,457
Long-term debt of variable interest entities, net			111,230				138,097

 

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

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

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

 

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