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 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 nine months ended
September 30, 2016
, are not necessarily indicative of the results to be expected for the full year.
Fuel Inventory and Supplies
We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately.
|
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As of
|
|
As of
|
|
September 30, 2016
|
|
December 31, 2015
|
|
(In Thousands)
|
Fuel inventory
|
$
|
95,936
|
|
|
$
|
113,438
|
|
Supplies
|
194,144
|
|
|
187,856
|
|
Fuel inventory and supplies
|
$
|
290,080
|
|
|
$
|
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:
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|
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|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Dollars In Thousands)
|
Borrowed funds
|
$
|
2,537
|
|
|
$
|
466
|
|
|
$
|
6,884
|
|
|
$
|
3,047
|
|
Equity funds
|
2,647
|
|
|
—
|
|
|
7,894
|
|
|
2,034
|
|
Total
|
$
|
5,184
|
|
|
$
|
466
|
|
|
$
|
14,778
|
|
|
$
|
5,081
|
|
Average AFUDC Rates
|
3.6
|
%
|
|
1.0
|
%
|
|
4.2
|
%
|
|
2.8
|
%
|
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.
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Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Dollars In Thousands, Except Per Share Amounts)
|
Net income
|
$
|
158,553
|
|
|
$
|
140,564
|
|
|
$
|
303,405
|
|
|
$
|
259,970
|
|
Less: Net income attributable to noncontrolling interests
|
3,833
|
|
|
2,561
|
|
|
10,760
|
|
|
7,277
|
|
Net income attributable to Westar Energy, Inc.
|
154,720
|
|
|
138,003
|
|
|
292,645
|
|
|
252,693
|
|
Less: Net income allocated to RSUs
|
325
|
|
|
304
|
|
|
605
|
|
|
563
|
|
Net income allocated to common stock
|
$
|
154,395
|
|
|
$
|
137,699
|
|
|
$
|
292,040
|
|
|
$
|
252,130
|
|
|
|
|
|
|
|
|
|
Weighted average equivalent common shares outstanding – basic
|
142,090,706
|
|
|
141,622,697
|
|
|
142,039,320
|
|
|
136,686,263
|
|
Effect of dilutive securities:
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|
|
|
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|
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|
RSUs
|
487,239
|
|
|
215,481
|
|
|
373,869
|
|
|
197,373
|
|
Forward sale agreements
|
—
|
|
|
—
|
|
|
—
|
|
|
1,297,949
|
|
Weighted average equivalent common shares outstanding – diluted (a)
|
142,577,945
|
|
|
141,838,178
|
|
|
142,413,189
|
|
|
138,181,585
|
|
|
|
|
|
|
|
|
|
Earnings per common share, basic
|
$
|
1.09
|
|
|
$
|
0.97
|
|
|
$
|
2.06
|
|
|
$
|
1.84
|
|
Earnings per common share, diluted
|
$
|
1.08
|
|
|
$
|
0.97
|
|
|
$
|
2.05
|
|
|
$
|
1.82
|
|
_______________
(a) We had
no
antidilutive securities for the
three and nine months ended
September 30, 2016
and
2015
.
Supplemental Cash Flow Information
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Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
(In Thousands)
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CASH PAID FOR:
|
|
|
|
Interest on financing activities, net of amount capitalized
|
$
|
100,828
|
|
|
$
|
119,173
|
|
Interest on financing activities of VIEs
|
5,846
|
|
|
10,430
|
|
Income taxes, net of refunds
|
13,004
|
|
|
126
|
|
NON-CASH INVESTING TRANSACTIONS:
|
|
|
|
Property, plant and equipment additions
|
94,007
|
|
|
60,155
|
|
NON-CASH FINANCING TRANSACTIONS:
|
|
|
|
Issuance of stock for compensation and reinvested dividends
|
7,315
|
|
|
8,008
|
|
Assets acquired through capital leases
|
1,310
|
|
|
2,246
|
|
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.
Statement of Cash Flows
In August 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-15, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Among other clarifications, the guidance requires that cash proceeds received from the settlement of corporate-owned life insurance (COLI) policies be classified as cash inflows from investing activities and that cash payments for premiums on COLI policies may be classified as cash outflows for investing activities, operating activities or a combination of both. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. Retrospective application is required. We are evaluating the guidance and do not expect it to have a material impact on our consolidated financial statements.
Stock-based Compensation
In March 2016, the FASB 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 nine months ended September 30, 2015, as
$1.2 million
higher than as previously reported, and cash flows used in financing activities as
$1.2 million
higher than as previously reported.
Leases
In February 2016, the FASB issued ASU No. 2016-02, which requires a lessee to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either 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.
Financial Instruments - Credit Losses
In June 2016, the FASB issued ASU No. 2016-13, which requires financial assets measured at amortized cost be presented at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis. The measurement of expected losses is based upon historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. This guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are evaluating the guidance and have not yet determined the impact on our consolidated financial statements.
Financial Instruments - Net Asset Value
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.
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, receipt of required regulatory approvals. On June 28, 2016, we and Great Plains Energy filed a joint application with the Kansas Corporation Commission (KCC) requesting approval of the merger. Unless otherwise agreed to by the applicants, Kansas law imposes a
300
-day time limit on the KCC’s review of the joint application. On September 27, 2016, the KCC issued an order setting a procedural schedule for the application, with a KCC order date of April 24, 2017. On October 18, 2016, the KCC issued an order stating that, if the KCC staff or other interested parties believe that the joint application does not adequately address the standards by which public utility mergers should be evaluated in Kansas, KCC staff or other interested parties should file for relief, including the potential dismissal of the joint application.
In addition, the Public Service Commission of the State of Missouri (Missouri Commission) opened an investigation to determine whether it has jurisdiction over the merger and on August 3, 2016, issued its order closing the investigation. On October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the Missouri Commission seeking to have the Missouri Commission assert jurisdiction over the merger, and various parties have intervened in these complaints. On October 12, 2016, and on October 26, 2016, the Missouri Commission staff and the Office of the Public Counsel (OPC), respectively, announced that each had entered into a Stipulation and Agreement with Great Plains Energy that, among other things, provided that Missouri Commission staff and the OPC would not file a complaint, or support another complaint, to assert that the Missouri Commission has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the Missouri Commission, and the Missouri Commission has not ruled on the related consumer complaints. If the Missouri Commission rejects the Stipulation and Agreement, or rules in favor of the consumer complaints, and determines that the Missouri Commission has jurisdiction over the merger, approval of the Missouri Commission also will be required in order to consummate the merger.
On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger. On July 22, 2016, Wolf Creek filed a request with the NRC to approve an indirect transfer of control of Wolf Creek’s operating license.
On September 26, 2016, we and Great Plains Energy filed the antitrust notifications required under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) to complete the merger. We and Great Plains Energy received early termination of the statutory waiting period under the HSR Act on October 21, 2016.
Also on September 26, 2016, the proposed merger was approved by our shareholders. Concurrently, shareholders of Great Plains Energy approved various matters necessary for Great Plains Energy to complete the merger.
The merger agreement, which contains customary representations, warranties and covenants, may be terminated by either party if the merger has not occurred by May 31, 2017. The termination date may be extended six months in order to obtain regulatory approvals. If the merger agreement is terminated under these circumstances, including the failure to obtain regulatory approvals, Great Plains Energy must pay us a termination fee of
$380.0 million
.
The merger agreement also provides for certain other termination rights for both us and Great Plains Energy. If (a) the merger agreement is terminated by either party because the end date occurred, or by us because Great Plains Energy is in breach of the merger agreement and (b) prior to such termination, an alternative acquisition proposal is made to Great Plains Energy or its board of directors or has been publicly disclosed and not withdrawn and within 12 months after termination of the merger agreement Great Plains Energy enters into an acquisition proposal, Great Plains Energy must pay us a termination fee of
$180.0 million
. In addition, if either party terminates the merger agreement because the end date occurred, or if Great Plains Energy terminates the merger agreement because we are in breach of the merger agreement, and (a) prior to such termination, an alternative acquisition proposal is made to us or our board of directors or is publicly disclosed and not withdrawn, and (b)
within 12 months after termination of the merger agreement, we enter into a definitive agreement or consummate a transaction with respect to an acquisition proposal, we must pay Great Plains Energy a termination fee of
$280.0 million
.
In connection with this transaction, we have incurred merger-related expenses. During the three and nine months ended September 30, 2016, we incurred approximately
$1.9 million
and
$9.8 million
, respectively, of merger-related expenses, which are included in our selling, general, and administrative expenses. We expect total merger-related expenses will be approximately
$30.0 million
, with the majority of the expenses to coincide with the closing of the merger.
We are currently involved in litigation relating to the merger. See Note 11, “Commitments and Contingencies - Department of Justice Proceedings,” and Note 12, “Legal Proceedings,” for more information on legal matters.
4. RATE MATTERS AND REGULATION
KCC Proceedings
In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne Generating Station (La Cygne) environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. If approved, we estimate that the new prices will increase our annual retail revenues by approximately
$17.4 million
. The KCC is required to issue an order on our request within 240 days of our filing, which is in June 2017.
In 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 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
. We have begun refunding our previously recorded refund obligation and as of September 30, 2016, we have a remaining refund obligation of
$2.7 million
, which is included in current regulatory liabilities on our balance sheet.
FERC Proceedings
Our TFR that includes projected 2017 transmission capital expenditures and operating costs will become effective in January 2017 and is expected to increase our annual transmission revenues by approximately
$29.6 million
.
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 and as of September 30, 2016, we have a remaining refund obligation of
$4.6 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.
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.
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|
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|
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|
|
|
|
|
|
|
|
As of September 30, 2016
|
|
As of December 31, 2015
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
(In Thousands)
|
Fixed-rate debt
|
$
|
3,430,000
|
|
|
$
|
3,850,563
|
|
|
$
|
3,080,000
|
|
|
$
|
3,259,533
|
|
Fixed-rate debt of VIEs
|
137,962
|
|
|
150,877
|
|
|
166,271
|
|
|
179,030
|
|
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 September 30, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
(In Thousands)
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
53,950
|
|
|
$
|
—
|
|
|
$
|
5,171
|
|
|
$
|
59,121
|
|
International equity funds
|
|
—
|
|
|
37,357
|
|
|
—
|
|
|
—
|
|
|
37,357
|
|
Core bond fund
|
|
—
|
|
|
27,985
|
|
|
—
|
|
|
—
|
|
|
27,985
|
|
High-yield bond fund
|
|
—
|
|
|
17,686
|
|
|
—
|
|
|
—
|
|
|
17,686
|
|
Emerging markets bond fund
|
|
—
|
|
|
16,007
|
|
|
—
|
|
|
—
|
|
|
16,007
|
|
Combination debt/equity/other funds
|
|
—
|
|
|
12,816
|
|
|
—
|
|
|
—
|
|
|
12,816
|
|
Alternative investments fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,886
|
|
|
17,886
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,737
|
|
|
9,737
|
|
Cash equivalents
|
|
201
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
201
|
|
Total Nuclear Decommissioning Trust
|
|
201
|
|
|
165,801
|
|
|
—
|
|
|
32,794
|
|
|
198,796
|
|
Trading Securities:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
—
|
|
|
18,004
|
|
|
—
|
|
|
—
|
|
|
18,004
|
|
International equity fund
|
|
—
|
|
|
4,482
|
|
|
—
|
|
|
—
|
|
|
4,482
|
|
Core bond fund
|
|
—
|
|
|
12,009
|
|
|
—
|
|
|
—
|
|
|
12,009
|
|
Total Trading Securities
|
|
—
|
|
|
34,495
|
|
|
—
|
|
|
—
|
|
|
34,495
|
|
Total Assets Measured at Fair Value
|
|
$
|
201
|
|
|
$
|
200,296
|
|
|
$
|
—
|
|
|
$
|
32,794
|
|
|
$
|
233,291
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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 September 30, 2016
|
|
As of December 31, 2015
|
|
As of September 30, 2016
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Redemption
Frequency
|
|
Length of
Settlement
|
|
(In Thousands)
|
|
|
|
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
5,171
|
|
|
$
|
3,689
|
|
|
$
|
6,050
|
|
|
$
|
1,948
|
|
|
(a)
|
|
(a)
|
Alternative investments fund (b)
|
17,886
|
|
|
—
|
|
|
16,439
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
Real estate securities fund (b)
|
9,737
|
|
|
—
|
|
|
10,823
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
Total
|
$
|
32,794
|
|
|
$
|
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
September 30, 2016
, and
December 31, 2015
, we measured the fair value of trust assets at
$34.5 million
and
$33.9 million
, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the
three and nine months ended
September 30, 2016
, we recorded an unrealized gain of
$1.0 million
and
$2.2 million
, respectively, on assets still held. For the
three and nine months ended
September 30, 2015
, we recorded an unrealized loss of
$1.5 million
and
$0.8 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
September 30, 2016
, and
December 31, 2015
.
Using the specific identification method to determine cost, we realized
no
gains or losses during the
three months ended
September 30, 2016
, and
a loss of
$1.5 million
during the
nine months ended
September 30, 2016
. We realized a loss of
$0.5 million
for the
three months ended
September 30, 2015
, and a loss of
$1.0 million
for the
nine months ended
September 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
September 30, 2016
, and
December 31, 2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Unrealized
|
|
|
|
|
Security Type
|
|
Cost
|
|
Gain
|
|
Loss
|
|
Fair Value
|
|
Allocation
|
|
|
(Dollars In Thousands)
|
|
|
As of September 30, 2016:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
50,397
|
|
|
$
|
8,861
|
|
|
$
|
(137
|
)
|
|
$
|
59,121
|
|
|
30
|
%
|
International equity funds
|
|
34,199
|
|
|
3,262
|
|
|
(104
|
)
|
|
37,357
|
|
|
19
|
%
|
Core bond fund
|
|
27,280
|
|
|
705
|
|
|
—
|
|
|
27,985
|
|
|
14
|
%
|
High-yield bond fund
|
|
17,805
|
|
|
—
|
|
|
(119
|
)
|
|
17,686
|
|
|
9
|
%
|
Emerging market bond fund
|
|
16,242
|
|
|
—
|
|
|
(235
|
)
|
|
16,007
|
|
|
8
|
%
|
Combination debt/equity/other funds
|
|
9,088
|
|
|
3,728
|
|
|
—
|
|
|
12,816
|
|
|
6
|
%
|
Alternative investment fund
|
|
15,000
|
|
|
2,886
|
|
|
—
|
|
|
17,886
|
|
|
9
|
%
|
Real estate securities fund
|
|
9,500
|
|
|
237
|
|
|
—
|
|
|
9,737
|
|
|
5
|
%
|
Cash equivalents
|
|
201
|
|
|
—
|
|
|
—
|
|
|
201
|
|
|
<1%
|
|
Total
|
|
$
|
179,712
|
|
|
$
|
19,679
|
|
|
$
|
(595
|
)
|
|
$
|
198,796
|
|
|
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
|
%
|
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
September 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 September 30, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
1,710
|
|
|
$
|
(137
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,710
|
|
|
$
|
(137
|
)
|
International equity funds
|
—
|
|
|
—
|
|
|
7,954
|
|
|
(104
|
)
|
|
7,954
|
|
|
(104
|
)
|
High-yield bond fund
|
—
|
|
|
—
|
|
|
17,686
|
|
|
(119
|
)
|
|
17,686
|
|
|
(119
|
)
|
Emerging market bond fund
|
—
|
|
|
—
|
|
|
16,007
|
|
|
(235
|
)
|
|
16,007
|
|
|
(235
|
)
|
Total
|
$
|
1,710
|
|
|
$
|
(137
|
)
|
|
$
|
41,647
|
|
|
$
|
(458
|
)
|
|
$
|
43,357
|
|
|
$
|
(595
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
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 redeemed and reissued
$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 sale-leaseback, effected a redemption and reissuance 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
$81.2 million
with an effective income tax rate of
34%
for the
three months ended
September 30, 2016
, and income tax expense of
$66.3 million
with an effective income tax rate of
32%
for the same period of
2015
. We recorded income tax expense of
$160.4 million
with an effective income tax rate of
35%
for the
nine months ended
September 30, 2016
, and income tax expense of
$127.8 million
with an effective income tax rate of
33%
for the same period of
2015
. The increase in the effective income tax rate for the three and nine months ended
September 30, 2016
, was due primarily to an increase in income before income taxes.
As of
September 30, 2016
, and
December 31, 2015
, our unrecognized income tax benefits totaled
$2.2 million
and
$2.9 million
, respectively. We do not expect significant changes in our unrecognized income tax benefits in the next
12
months.
As of
September 30, 2016
, we had
$0.1 million
accrued for interest related to our unrecognized income tax benefits compared to
no
amount as of
December 31, 2015
. We accrued
no
penalties at either
September 30, 2016
, or
December 31, 2015
.
As of
September 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 September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
4,633
|
|
|
$
|
5,348
|
|
|
$
|
271
|
|
|
$
|
361
|
|
Interest cost
|
|
10,922
|
|
|
10,753
|
|
|
1,392
|
|
|
1,422
|
|
Expected return on plan assets
|
|
(10,664
|
)
|
|
(10,059
|
)
|
|
(1,708
|
)
|
|
(1,654
|
)
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
174
|
|
|
130
|
|
|
113
|
|
|
114
|
|
Actuarial loss (gain), net
|
|
5,146
|
|
|
8,033
|
|
|
(279
|
)
|
|
95
|
|
Net periodic cost (benefit) before regulatory adjustment
|
|
10,211
|
|
|
14,205
|
|
|
(211
|
)
|
|
338
|
|
Regulatory adjustment (a)
|
|
3,306
|
|
|
1,548
|
|
|
(486
|
)
|
|
1,013
|
|
Net periodic cost (benefit)
|
|
$
|
13,517
|
|
|
$
|
15,753
|
|
|
$
|
(697
|
)
|
|
$
|
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
|
Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
13,930
|
|
|
$
|
16,044
|
|
|
$
|
813
|
|
|
$
|
1,082
|
|
Interest cost
|
|
32,802
|
|
|
32,261
|
|
|
4,178
|
|
|
4,268
|
|
Expected return on plan assets
|
|
(31,990
|
)
|
|
(31,177
|
)
|
|
(5,125
|
)
|
|
(4,961
|
)
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
594
|
|
|
390
|
|
|
341
|
|
|
342
|
|
Actuarial loss (gain), net
|
|
15,680
|
|
|
23,746
|
|
|
(839
|
)
|
|
284
|
|
Net periodic cost (benefit) before regulatory adjustment
|
|
31,016
|
|
|
41,264
|
|
|
(632
|
)
|
|
1,015
|
|
Regulatory adjustment (a)
|
|
9,919
|
|
|
4,880
|
|
|
(1,458
|
)
|
|
3,038
|
|
Net periodic cost (benefit)
|
|
$
|
40,935
|
|
|
$
|
46,144
|
|
|
$
|
(2,090
|
)
|
|
$
|
4,053
|
|
_______________
|
|
(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
nine months ended
September 30, 2016
and
2015
, we contributed
$15.7 million
and
$29.7 million
, respectively, to the Westar Energy pension trust.
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 September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
1,687
|
|
|
$
|
1,899
|
|
|
$
|
31
|
|
|
$
|
34
|
|
Interest cost
|
|
2,413
|
|
|
2,254
|
|
|
81
|
|
|
79
|
|
Expected return on plan assets
|
|
(2,431
|
)
|
|
(2,261
|
)
|
|
—
|
|
|
—
|
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
14
|
|
|
14
|
|
|
—
|
|
|
—
|
|
Actuarial loss (gain), net
|
|
1,090
|
|
|
1,482
|
|
|
(3
|
)
|
|
1
|
|
Net periodic cost before regulatory adjustment
|
|
2,773
|
|
|
3,388
|
|
|
109
|
|
|
114
|
|
Regulatory adjustment (a)
|
|
483
|
|
|
(304
|
)
|
|
—
|
|
|
—
|
|
Net periodic cost
|
|
$
|
3,256
|
|
|
$
|
3,084
|
|
|
$
|
109
|
|
|
$
|
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
|
Nine Months Ended September 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
5,061
|
|
|
$
|
5,696
|
|
|
$
|
95
|
|
|
$
|
103
|
|
Interest cost
|
|
7,241
|
|
|
6,761
|
|
|
244
|
|
|
236
|
|
Expected return on plan assets
|
|
(7,292
|
)
|
|
(6,783
|
)
|
|
—
|
|
|
—
|
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
42
|
|
|
43
|
|
|
—
|
|
|
—
|
|
Actuarial loss (gain), net
|
|
3,268
|
|
|
4,448
|
|
|
(11
|
)
|
|
2
|
|
Net periodic cost before regulatory adjustment
|
|
8,320
|
|
|
10,165
|
|
|
328
|
|
|
341
|
|
Regulatory adjustment (a)
|
|
1,449
|
|
|
(912
|
)
|
|
—
|
|
|
—
|
|
Net periodic cost
|
|
$
|
9,769
|
|
|
$
|
9,253
|
|
|
$
|
328
|
|
|
$
|
341
|
|
_______________
|
|
(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
nine months ended
September 30, 2016
and
2015
, we funded
$14.6 million
and
$4.5 million
of Wolf Creek’s pension plan contributions, respectively.
11. COMMITMENTS AND CONTINGENCIES
Environmental Matters
Cross-State Air Pollution Update Rule
In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxides (NOx) emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final 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 final rule on our operations, however, based on our initial analysis we do not believe this rule will 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 (SO
2
), which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.
In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. In September 2016, the Kansas Department of Health and Environment (KDHE) recommended to the EPA that they designate the state of Kansas as in attainment or in attainment/unclassifiable with the standard. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. If the EPA agrees with an attainment or attainment/unclassifiable designation for the state of Kansas, we do not believe this will have a material impact on our consolidated 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 SO
2
. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO
2
emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in June 2016, 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 SO
2
Data Requirements Rule which governs the next round of the designations. By agreeing to the ton per year limitation, no further characterization of the area surrounding the plant is required. We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated 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 (CO
2
) and other gases referred to as GHG. Various regulations under the federal CAA limit CO
2
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 CO
2
emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour depending on various characteristics of the units. Also in October 2015, the EPA published a rule establishing guidelines for states to regulate CO
2
emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our Company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015. In February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before the U.S. Court of Appeals for the D.C. Circuit to review the CPP and to conduct the review en banc. Despite the stay, 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 cost to comply with the CPP could be material.
Water
We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual 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.
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 has determined sponsors are entitled to revenue credits for previously completed upgrades, and members will be obligated to pay for revenue credits attributable to these historical upgrades.
As a result, we expect to pay the SPP in November 2016 approximately
$7.0 million
related to revenue credits attributable to historical upgrades. As of September 30, 2016, we have recorded a corresponding liability for our obligation to the SPP for the period of March 2008 to August 2016. Most of the related charges will be recovered from our customers in future prices.
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.
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 cooperated with the DOJ in its investigation, and on October 21, 2016, we were notified that the DOJ closed the investigation.