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
701,000
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 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
2016
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 (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the
three months ended
March 31, 2017
, 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.
|
|
|
|
|
|
|
|
|
|
As of
|
|
As of
|
|
March 31, 2017
|
|
December 31, 2016
|
|
(In Thousands)
|
Fuel inventory
|
$
|
115,921
|
|
|
$
|
107,086
|
|
Supplies
|
194,940
|
|
|
193,039
|
|
Fuel inventory and supplies
|
$
|
310,861
|
|
|
$
|
300,125
|
|
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 condensed consolidated statements of income as follows:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
|
(Dollars In Thousands)
|
Borrowed funds
|
$
|
1,853
|
|
|
$
|
2,008
|
|
Equity funds
|
775
|
|
|
2,464
|
|
Total
|
$
|
2,628
|
|
|
$
|
4,472
|
|
Average AFUDC Rates
|
2.2
|
%
|
|
5.2
|
%
|
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 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 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 March 31,
|
|
2017
|
|
2016
|
|
(Dollars In Thousands, Except Per Share Amounts)
|
Net income
|
$
|
63,482
|
|
|
$
|
68,708
|
|
Less: Net income attributable to noncontrolling interests
|
3,821
|
|
|
3,123
|
|
Net income attributable to Westar Energy, Inc.
|
59,661
|
|
|
65,585
|
|
Less: Net income allocated to RSUs
|
108
|
|
|
135
|
|
Net income allocated to common stock
|
$
|
59,553
|
|
|
$
|
65,450
|
|
|
|
|
|
Weighted average equivalent common shares outstanding – basic
|
142,436,622
|
|
|
141,992,846
|
|
Effect of dilutive securities:
|
|
|
|
RSUs
|
258,984
|
|
|
318,382
|
|
Weighted average equivalent common shares outstanding – diluted (a)
|
142,695,606
|
|
|
142,311,228
|
|
|
|
|
|
Earnings per common share, basic
|
$
|
0.42
|
|
|
$
|
0.46
|
|
Earnings per common share, diluted
|
$
|
0.42
|
|
|
$
|
0.46
|
|
_______________
(a)
We had
no
antidilutive securities for the
three months ended
March 31, 2017
and
2016
.
Supplemental Cash Flow Information
|
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|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2017
|
|
2016
|
|
(In Thousands)
|
CASH PAID FOR (RECEIVED FROM):
|
|
|
|
Interest on financing activities, net of amount capitalized
|
$
|
35,644
|
|
|
$
|
30,415
|
|
Interest on financing activities of VIEs
|
1,696
|
|
|
4,150
|
|
Income taxes, net of refunds
|
(13,000
|
)
|
|
(383
|
)
|
NON-CASH INVESTING TRANSACTIONS:
|
|
|
|
Property, plant and equipment additions
|
97,196
|
|
|
130,532
|
|
NON-CASH FINANCING TRANSACTIONS:
|
|
|
|
Issuance of stock for compensation and reinvested dividends
|
2,349
|
|
|
2,405
|
|
Assets acquired through capital leases
|
293
|
|
|
180
|
|
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 that may affect our accounting and/or disclosure.
Compensation - Retirement Benefits
In March 2017, the FASB issued Accounting Standard Update No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is to be applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is to be applied on a retrospective basis. The new standard is effective for annual periods beginning after December 15, 2017. We are evaluating the guidance and do not expect it to have a material impact on our consolidated financial statements.
Revenue Recognition
In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. 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. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method. We continue to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. In summary, material revenue streams were identified and representative contract/transaction types were sampled. We also continue to monitor unresolved industry issues, including items related to contributions in aid of construction, collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. Based upon our completed assessments, we do not expect the impact on our consolidated financial statements to be material.
3. PENDING MERGER
On May 29, 2016, we entered into an agreement and plan of merger (merger) with Great Plains Energy, 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 merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement, without prior approval of Great Plains Energy, limits our quarterly dividends declared in 2017 to
$0.40
per share, which represents an annualized increase of
$0.08
per share, consistent with last year’s dividend increase.
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. On April 19, 2017, the KCC rejected the merger application citing, among other concerns, an excessive purchase price, Great Plains Energy’s capital structure, quantifiable and demonstrable customer benefits and staffing levels in our service territory. On May 4, 2017, we and Great Plains Energy filed with the KCC a petition for reconsideration of the KCC’s order and to set the matter for further proceedings so that we and Great Plains Energy may work together to determine whether it is feasible to develop a revised transaction that addresses the KCC’s concerns. Under applicable Kansas regulations, the KCC has 30 days following the filing of the petition for reconsideration to either deny or grant the petition. If we and Great Plains Energy agree on a revised transaction, then we and Great Plains Energy would expect to file the revised proposal and a supplemental application with the KCC.
In addition, there are two open dockets in Missouri related to the merger. In the first docket, Great Plains Energy sought approval from the Public Service Commission of the State of Missouri (MPSC) to waive certain affiliate transaction rules following the closing of the merger. In this docket, on October 12, 2016, and on October 26, 2016, the MPSC staff and the Office of Public Counsel (OPC), respectively, announced that each had entered into a Stipulation and Agreement with Great Plains Energy that, among other things, provided that MPSC staff and the OPC would not file a complaint, or support another complaint, to assert that the MPSC has jurisdiction over the merger. The Stipulation and Agreements are subject to approval by the MPSC. Regarding the second docket, on October 11, 2016, a consumer group filed complaints against us and Great Plains Energy with the MPSC seeking to have the MPSC assert jurisdiction over the merger, and various parties have intervened in these complaints. The MPSC dismissed the complaint against us on December 6, 2016, but on February 22, 2017, the MPSC ordered that Great Plains Energy was required to obtain MPSC approval prior to consummation of the merger. On February 23, 2017, Great Plains Energy filed an application with the MPSC seeking approval of the merger. The merger application docket was consolidated with the affiliate transaction waiver docket. Several parties filed testimony and the evidentiary hearing was held in April 2017. On April 20, 2017, after the KCC’s order rejecting the merger was issued, Great Plains Energy filed a motion to suspend the briefing schedule in the MPSC merger docket, effectively suspending that proceeding indefinitely until Great Plains Energy takes further action in the docket.
On July 11, 2016, we and Great Plains filed a joint application with the Federal Energy Regulatory Commission (FERC) requesting approval of the merger. Approval of the merger application requires action by the FERC commissioners because it is a contested application. The Federal Power Act (FPA) requires a quorum of three or more commissioners to act on a contested application. Following the resignation of the FERC Chairman effective February 3, 2017, the FERC commission is comprised only of two commissioners and is therefore unable to act on the application. A new commissioner must be appointed by the President of the United States, with the advice and consent of the United States Senate, before FERC will be able to act on the application. If the FERC commissioners do not issue an order on the application within
180
days after the application was deemed complete because of the lack of a quorum, approval of the application may be deemed granted by operation of law, unless an order is issued extending the time for review. On May 3, 2017, the FERC staff extended the time period for a review of the application until November 1, 2017. We are unable to predict when FERC will regain a quorum or how the change in commissioners will impact the review of the application.
On April 7, 2017, the NRC approved Wolf Creek’s request of an indirect transfer of control of Wolf Creek’s operating license. The transfer will not be completed until receipt of all required regulatory approvals and written notification is made to the NRC.
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. Under the HSR Act, a new statutory waiting period will start one year from the date on which an existing waiting period expires, or October 21, 2017. Accordingly, if the merger has not closed prior to October 21, 2017, we and Great Plains Energy will need to re-file the necessary HSR Act notifications.
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 months ended March 31, 2017, we incurred approximately
$0.4 million
of merger-related expenses, which are included in our selling, general,
and administrative expenses. In the event the merger is consummated, we expect total merger-related expenses will be approximately
$30.0 million
, with the majority of the expense to be paid upon closing.
See also Note 12, “Legal Proceedings,” for more information on litigation related to the merger.
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. In May 2017, we reached an agreement with the major parties to the rate review. If the agreement is approved by the KCC, we estimate that the new prices will increase our annual retail revenues by approximately
$16.4 million
. We expect the KCC to issue an order on our request in June 2017.
In March 2017, the KCC issued an order allowing us to adjust our retail prices, subject to refund, to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2017 and are expected to increase our annual retail revenues by approximately
$12.7 million
.
In December 2016, 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 2017 and are expected to decrease our annual retail revenues by approximately
$26.8 million
.
FERC Proceedings
Our TFR that includes projected 2017 transmission capital expenditures and operating costs was effective in January 2017 and is expected to increase our annual transmission revenues by approximately
$29.6 million
. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as discussed above.
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 net asset value (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
|
that do not have a readily determinable fair value. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2017
|
|
As of December 31, 2016
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
(In Thousands)
|
Fixed-rate debt
|
$
|
3,605,000
|
|
|
$
|
3,756,244
|
|
|
$
|
3,430,000
|
|
|
$
|
3,597,441
|
|
Fixed-rate debt of VIEs
|
111,122
|
|
|
111,513
|
|
|
137,962
|
|
|
139,733
|
|
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 March 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
(In Thousands)
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
59,559
|
|
|
$
|
—
|
|
|
$
|
4,894
|
|
|
$
|
64,453
|
|
International equity funds
|
|
—
|
|
|
40,287
|
|
|
—
|
|
|
—
|
|
|
40,287
|
|
Core bond fund
|
|
—
|
|
|
27,912
|
|
|
—
|
|
|
—
|
|
|
27,912
|
|
High-yield bond fund
|
|
—
|
|
|
18,836
|
|
|
—
|
|
|
—
|
|
|
18,836
|
|
Emerging market bond fund
|
|
—
|
|
|
16,275
|
|
|
—
|
|
|
—
|
|
|
16,275
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
14,608
|
|
|
—
|
|
|
—
|
|
|
14,608
|
|
Alternative investment fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,107
|
|
|
20,107
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,170
|
|
|
10,170
|
|
Cash equivalents
|
|
172
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
172
|
|
Total Nuclear Decommissioning Trust
|
|
172
|
|
|
177,477
|
|
|
—
|
|
|
35,171
|
|
|
212,820
|
|
Trading Securities:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
—
|
|
|
17,165
|
|
|
—
|
|
|
—
|
|
|
17,165
|
|
International equity fund
|
|
—
|
|
|
4,287
|
|
|
—
|
|
|
—
|
|
|
4,287
|
|
Core bond fund
|
|
—
|
|
|
11,584
|
|
|
—
|
|
|
—
|
|
|
11,584
|
|
Total Trading Securities
|
|
—
|
|
|
33,036
|
|
|
—
|
|
|
—
|
|
|
33,036
|
|
Total Assets Measured at Fair Value
|
|
$
|
172
|
|
|
$
|
210,513
|
|
|
$
|
—
|
|
|
$
|
35,171
|
|
|
$
|
245,856
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
(In Thousands)
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
56,312
|
|
|
$
|
—
|
|
|
$
|
5,056
|
|
|
$
|
61,368
|
|
International equity funds
|
|
—
|
|
|
35,944
|
|
|
—
|
|
|
—
|
|
|
35,944
|
|
Core bond fund
|
|
—
|
|
|
27,423
|
|
|
—
|
|
|
—
|
|
|
27,423
|
|
High-yield bond fund
|
|
—
|
|
|
18,188
|
|
|
—
|
|
|
—
|
|
|
18,188
|
|
Emerging market bond fund
|
|
—
|
|
|
14,738
|
|
|
—
|
|
|
—
|
|
|
14,738
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
13,484
|
|
|
—
|
|
|
—
|
|
|
13,484
|
|
Alternative investment fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,958
|
|
|
18,958
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,946
|
|
|
9,946
|
|
Cash equivalents
|
|
73
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
73
|
|
Total Nuclear Decommissioning Trust
|
|
73
|
|
|
166,089
|
|
|
—
|
|
|
33,960
|
|
|
200,122
|
|
Trading Securities:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
—
|
|
|
18,364
|
|
|
—
|
|
|
—
|
|
|
18,364
|
|
International equity fund
|
|
—
|
|
|
4,467
|
|
|
—
|
|
|
—
|
|
|
4,467
|
|
Core bond fund
|
|
—
|
|
|
11,504
|
|
|
—
|
|
|
—
|
|
|
11,504
|
|
Cash equivalents
|
|
156
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156
|
|
Total Trading Securities
|
|
156
|
|
|
34,335
|
|
|
—
|
|
|
—
|
|
|
34,491
|
|
Total Assets Measured at Fair Value
|
|
$
|
229
|
|
|
$
|
200,424
|
|
|
$
|
—
|
|
|
$
|
33,960
|
|
|
$
|
234,613
|
|
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 March 31, 2017
|
|
As of December 31, 2016
|
|
As of March 31, 2017
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Redemption
Frequency
|
|
Length of
Settlement
|
|
(In Thousands)
|
|
|
|
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
4,894
|
|
|
$
|
3,349
|
|
|
$
|
5,056
|
|
|
$
|
3,529
|
|
|
(a)
|
|
(a)
|
Alternative investment fund (b)
|
20,107
|
|
|
—
|
|
|
18,958
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
Real estate securities fund (b)
|
10,170
|
|
|
—
|
|
|
9,946
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
Total Nuclear Decommissioning Trust
|
$
|
35,171
|
|
|
$
|
3,349
|
|
|
$
|
33,960
|
|
|
$
|
3,529
|
|
|
|
|
|
_______________
|
|
(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 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
March 31, 2017
, and
December 31, 2016
, we measured the fair value of trust assets at
$33.0 million
and
$34.5 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
March 31, 2017
and
2016
, we recorded unrealized gains of
$1.4 million
and
$0.5 million
, respectively, on the 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
March 31, 2017
, and
December 31, 2016
.
Using the specific identification method to determine cost, we realized
no
gains or losses on our available-for-sale securities during the
three months ended
March 31, 2017
, and a loss of
$1.6 million
during the
three months ended
March 31, 2016
. 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
March 31, 2017
, and
December 31, 2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Unrealized
|
|
|
|
|
Security Type
|
|
Cost
|
|
Gain
|
|
Loss
|
|
Fair Value
|
|
Allocation
|
|
|
(Dollars In Thousands)
|
|
|
As of March 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
54,038
|
|
|
$
|
10,725
|
|
|
$
|
(310
|
)
|
|
$
|
64,453
|
|
|
30
|
%
|
International equity funds
|
|
35,520
|
|
|
4,767
|
|
|
—
|
|
|
40,287
|
|
|
19
|
%
|
Core bond fund
|
|
28,360
|
|
|
—
|
|
|
(448
|
)
|
|
27,912
|
|
|
13
|
%
|
High-yield bond fund
|
|
18,782
|
|
|
54
|
|
|
—
|
|
|
18,836
|
|
|
9
|
%
|
Emerging market bond fund
|
|
16,997
|
|
|
—
|
|
|
(722
|
)
|
|
16,275
|
|
|
8
|
%
|
Combination debt/equity/other fund
|
|
9,476
|
|
|
5,132
|
|
|
—
|
|
|
14,608
|
|
|
7
|
%
|
Alternative investment fund
|
|
15,000
|
|
|
5,107
|
|
|
—
|
|
|
20,107
|
|
|
9
|
%
|
Real estate securities fund
|
|
9,500
|
|
|
670
|
|
|
—
|
|
|
10,170
|
|
|
5
|
%
|
Cash equivalents
|
|
172
|
|
|
—
|
|
|
—
|
|
|
172
|
|
|
<1%
|
|
Total
|
|
$
|
187,845
|
|
|
$
|
26,455
|
|
|
$
|
(1,480
|
)
|
|
$
|
212,820
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
53,192
|
|
|
$
|
8,295
|
|
|
$
|
(119
|
)
|
|
$
|
61,368
|
|
|
31
|
%
|
International equity funds
|
|
34,502
|
|
|
2,075
|
|
|
(633
|
)
|
|
35,944
|
|
|
18
|
%
|
Core bond fund
|
|
27,952
|
|
|
—
|
|
|
(529
|
)
|
|
27,423
|
|
|
14
|
%
|
High-yield bond fund
|
|
18,358
|
|
|
—
|
|
|
(170
|
)
|
|
18,188
|
|
|
9
|
%
|
Emerging market bond fund
|
|
16,397
|
|
|
—
|
|
|
(1,659
|
)
|
|
14,738
|
|
|
7
|
%
|
Combination debt/equity/other fund
|
|
9,171
|
|
|
4,313
|
|
|
—
|
|
|
13,484
|
|
|
7
|
%
|
Alternative investment fund
|
|
15,000
|
|
|
3,958
|
|
|
—
|
|
|
18,958
|
|
|
9
|
%
|
Real estate securities fund
|
|
9,500
|
|
|
446
|
|
|
—
|
|
|
9,946
|
|
|
5
|
%
|
Cash equivalents
|
|
73
|
|
|
—
|
|
|
—
|
|
|
73
|
|
|
<1%
|
|
Total
|
|
$
|
184,145
|
|
|
$
|
19,087
|
|
|
$
|
(3,110
|
)
|
|
$
|
200,122
|
|
|
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
March 31, 2017
, and
December 31, 2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 March 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
4,894
|
|
|
$
|
(310
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,894
|
|
|
$
|
(310
|
)
|
Core bonds
|
27,912
|
|
|
(448
|
)
|
|
—
|
|
|
—
|
|
|
27,912
|
|
|
(448
|
)
|
Emerging market bond fund
|
—
|
|
|
—
|
|
|
16,275
|
|
|
(722
|
)
|
|
16,275
|
|
|
(722
|
)
|
Total
|
$
|
32,806
|
|
|
$
|
(758
|
)
|
|
$
|
16,275
|
|
|
$
|
(722
|
)
|
|
$
|
49,081
|
|
|
$
|
(1,480
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
1,788
|
|
|
$
|
(119
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,788
|
|
|
$
|
(119
|
)
|
International equity funds
|
—
|
|
|
—
|
|
|
7,489
|
|
|
(633
|
)
|
|
7,489
|
|
|
(633
|
)
|
Core bond funds
|
27,423
|
|
|
(529
|
)
|
|
—
|
|
|
—
|
|
|
27,423
|
|
|
(529
|
)
|
High-yield bond fund
|
—
|
|
|
—
|
|
|
18,188
|
|
|
(170
|
)
|
|
18,188
|
|
|
(170
|
)
|
Emerging market bond fund
|
—
|
|
|
—
|
|
|
14,738
|
|
|
(1,659
|
)
|
|
14,738
|
|
|
(1,659
|
)
|
Total
|
$
|
29,211
|
|
|
$
|
(648
|
)
|
|
$
|
40,415
|
|
|
$
|
(2,462
|
)
|
|
$
|
69,626
|
|
|
$
|
(3,110
|
)
|
7. DEBT FINANCING
In January 2017, Westar Energy retired
$125.0 million
in principal amount of first mortgage bonds (FMBs) bearing a stated interest at
5.15%
maturing January 2017.
In March 2017, Westar Energy issued
$300.0 million
in principal amount of FMBs bearing a stated interest at
3.10%
and maturing April 2027.
8. TAXES
We recorded income tax expense of
$20.9 million
with an effective income tax rate of
25%
for the
three months ended
March 31, 2017
, and income tax expense of
$38.6 million
with an effective income tax rate of
36%
for the same period of
2016
. The decrease in the effective income tax rate for the
three months ended
March 31, 2017
, was due primarily to a decrease in income before income taxes and increases in tax benefits from production tax credits and stock-based compensation.
As of
March 31, 2017
, and
December 31, 2016
, our unrecognized income tax benefits totaled
$2.8 million
. We do not expect significant changes in our unrecognized income tax benefits in the next
12
months.
As of
March 31, 2017
, and
December 31, 2016
, we had
no
amounts accrued for interest related to our unrecognized income tax benefits. We accrued
no
penalties at either
March 31, 2017
, or
December 31, 2016
.
As of
March 31, 2017
, and
December 31, 2016
, we had recorded
$1.5 million
for probable assessments of taxes other than income taxes.
9. PENSION AND POST-RETIREMENT BENEFIT PLANS
The following table summarizes 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 March 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
5,218
|
|
|
$
|
4,664
|
|
|
$
|
271
|
|
|
$
|
271
|
|
Interest cost
|
|
10,621
|
|
|
10,959
|
|
|
1,314
|
|
|
1,393
|
|
Expected return on plan assets
|
|
(10,760
|
)
|
|
(10,663
|
)
|
|
(1,718
|
)
|
|
(1,709
|
)
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
171
|
|
|
246
|
|
|
114
|
|
|
114
|
|
Actuarial loss (gain), net
|
|
5,489
|
|
|
5,388
|
|
|
(195
|
)
|
|
(280
|
)
|
Net periodic cost (benefit) before regulatory adjustment
|
|
10,739
|
|
|
10,594
|
|
|
(214
|
)
|
|
(211
|
)
|
Regulatory adjustment (a)
|
|
3,288
|
|
|
3,306
|
|
|
(478
|
)
|
|
(486
|
)
|
Net periodic cost (benefit)
|
|
$
|
14,027
|
|
|
$
|
13,900
|
|
|
$
|
(692
|
)
|
|
$
|
(697
|
)
|
_______________
|
|
(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
three months ended
March 31, 2017
and
2016
, we contributed
$7.0 million
and
$6.8 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 table summarizes 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 March 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
1,950
|
|
|
$
|
1,687
|
|
|
$
|
37
|
|
|
$
|
32
|
|
Interest cost
|
|
2,475
|
|
|
2,414
|
|
|
70
|
|
|
81
|
|
Expected return on plan assets
|
|
(2,643
|
)
|
|
(2,431
|
)
|
|
—
|
|
|
—
|
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
14
|
|
|
14
|
|
|
—
|
|
|
—
|
|
Actuarial loss (gain), net
|
|
1,245
|
|
|
1,089
|
|
|
(13
|
)
|
|
(4
|
)
|
Net periodic cost before regulatory adjustment
|
|
3,041
|
|
|
2,773
|
|
|
94
|
|
|
109
|
|
Regulatory adjustment (a)
|
|
247
|
|
|
483
|
|
|
—
|
|
|
—
|
|
Net periodic cost
|
|
$
|
3,288
|
|
|
$
|
3,256
|
|
|
$
|
94
|
|
|
$
|
109
|
|
_______________
|
|
(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
three months ended
March 31, 2017
, we did not fund Wolf Creek’s pension plan. During the
three months ended
March 31,
2016
, we funded
$1.6 million
of Wolf Creek’s pension plan contributions.
11. COMMITMENTS AND CONTINGENCIES
Environmental Matters
Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and consolidated financial results. Due in part to the complex nature of environmental laws and regulations, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below.
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 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. Various states and others are challenging the rule in the U.S. Court of Appeals for the D.C. Circuit. 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 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 ppb to 70 ppb. In September 2016, the Kansas Department of Health & Environment
(KDHE)
recommended to the EPA that they designate eight counties in the state of Kansas as in attainment with the standard, and each remaining county in Kansas as in attainment/unclassifiable. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. If the EPA agrees with the recommended designations for the state of Kansas, we do not believe this will have a material impact on our consolidated financial results.
Various states and others are challenging the revised 2015 ozone NAAQS in the D.C. Circuit. In April 2017, at the request of the EPA the court issued an order holding the case in abeyance because the new administration is planning to review the 2015 ozone NAAQS and determine whether to reconsider all or a portion of the rule.
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 January 2017, KDHE formally recommended to the EPA 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 2,000 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 (NSPS) for GHGs that limit CO
2
emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per MWh depending on various characteristics of the units. Legal challenges to the GHG NSPS have been filed in the D.C. Circuit by various states and industry members. 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 D.C. Circuit. 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 an en banc panel of D.C. Circuit judges and a decision on the legal challenges is pending.
In March 2017, President Trump signed an Executive Order instructing the EPA to immediately review the CPP and GHG NSPS, and “if appropriate . . . as soon as practicable . . . publish for notice and comment proposed rules suspending, revising or rescinding those rules.” On the same day the Executive Order was signed, the EPA filed motions with the D.C. Circuit asking the court to hold the challenges to the CPP and the GHG NSPS in abeyance while the EPA completes its administrative review of the rules and issues any forthcoming rulemakings. In April 2017, the court issued orders to hold the cases in abeyance for 60 days and requested briefing on whether the cases should be remanded to the EPA or continue to be held in abeyance.
Also in April 2017, the EPA published in the Federal Register a notice of withdrawal of the proposed CPP federal plan, proposed model trading rules and proposed Clean Energy Incentive Program design details, in light of the Executive Order and the agency’s review of the CPP. Also in April 2017, the EPA published a notice in the Federal Register that it is initiating administrative reviews of the CPP and the GHG NSPS in light of the Executive Order.
Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, 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 effluent limitations guidelines (ELGs) and standards for wastewater discharges, including limits on the amount of toxic metals and other pollutants that can be discharged. Implementation timelines for these requirements vary from 2019 to 2023. In April 2017, the EPA announced it is reconsidering the ELG rule and court challenges have been placed in abeyance pending EPA’s review. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material if the rule is implemented in its current or substantially similar form.
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 Generating Station (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 (WOTUS) 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 and others have filed lawsuits challenging the WOTUS rule in district courts and courts of appeals across the country. The appellate court challenges have been consolidated in the U.S. Court of Appeals for the Sixth Circuit and, in October 2015, the Sixth Circuit issued an order that temporarily stays implementation of the WOTUS rule nationwide pending the outcome of the various legal challenges. In March 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a notice of intent to review and rescind or revise the WOTUS rule, as required by an Executive Order signed in February 2017. We are currently evaluating the WOTUS rule and related developments. We do not believe the rule, if upheld and implemented in its current or substantially similar form, will have a material impact on our operations or consolidated financial results.
Regulation of Coal Combustion Residuals
In the course of operating our coal generation plants, we produce coal combustion residuals (CCRs), 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 CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017. We have recorded an ARO for our current estimate for closure of ash disposal ponds but we may be required to record additional AROs in the future due to changes in existing CCR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or consolidated financial results 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. Wolf Creek is in discussions with the DOE to determine which of its incremental costs may be reimbursable. 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.