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
710,000
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 a variable interest entity (VIE) 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
2017
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 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, 2018
, 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
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As of
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March 31, 2018
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|
December 31, 2017
|
|
(In Thousands)
|
Fuel inventory
|
$
|
89,125
|
|
|
$
|
94,039
|
|
Supplies
|
197,706
|
|
|
199,523
|
|
Fuel inventory and supplies
|
$
|
286,831
|
|
|
$
|
293,562
|
|
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:
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Three Months Ended March 31,
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|
2018
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|
2017
|
|
(Dollars In Thousands)
|
Borrowed funds
|
$
|
1,403
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|
|
$
|
1,853
|
|
Equity funds
|
1,097
|
|
|
775
|
|
Total
|
$
|
2,500
|
|
|
$
|
2,628
|
|
Average AFUDC Rates
|
3.6
|
%
|
|
2.2
|
%
|
Earnings Per Share
We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS).
To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our 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,
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2018
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2017
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(Dollars In Thousands, Except Per Share Amounts)
|
Net income
|
$
|
62,904
|
|
|
$
|
63,482
|
|
Less: Net income attributable to noncontrolling interests
|
2,419
|
|
|
3,821
|
|
Net income attributable to Westar Energy, Inc.
|
60,485
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|
59,661
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|
Less: Net income allocated to RSUs
|
104
|
|
|
108
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|
Net income allocated to common stock
|
$
|
60,381
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|
$
|
59,553
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Weighted average equivalent common shares outstanding – basic
|
142,635,490
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|
142,436,622
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Effect of dilutive securities:
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RSUs
|
16,090
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|
|
258,984
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Weighted average equivalent common shares outstanding – diluted (a)
|
142,651,580
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|
|
142,695,606
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Earnings per common share, basic
|
$
|
0.42
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|
$
|
0.42
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|
Earnings per common share, diluted
|
$
|
0.42
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|
$
|
0.42
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_______________
(a)
We had
no
antidilutive securities for the
three months ended
March 31, 2018
and
2017
.
Supplemental Cash Flow Information
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Three Months Ended March 31,
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2018
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2017
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(In Thousands)
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CASH PAID FOR (RECEIVED FROM):
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Interest on financing activities, net of amount capitalized
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$
|
33,043
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$
|
35,644
|
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Interest on financing activities of VIEs
|
1,319
|
|
|
1,696
|
|
Income taxes, net of refunds
|
(231
|
)
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|
(13,000
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)
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NON-CASH INVESTING TRANSACTIONS:
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|
Property, plant and equipment additions
|
29,790
|
|
|
97,196
|
|
NON-CASH FINANCING TRANSACTIONS:
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|
|
|
Issuance of stock for compensation and reinvested dividends
|
149
|
|
|
2,349
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Assets acquired through capital leases
|
48
|
|
|
293
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|
Revenue Recognition
Revenue is recognized primarily at the time we deliver electricity or provide transmission service to customers. The time of delivery of electricity is generally when our obligation to provide service is satisfied. Sales tax and franchise fees that we collect concurrent with revenue-producing activities are excluded from revenue. For more information on revenue recognition, see Note 4, “Revenue.”
We determine the amount of electricity delivered to customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue. Our unbilled revenue estimate is affected by factors including energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of
$68.2 million
and
$76.7 million
as of March 31, 2018, and December 31, 2017, respectively.
Allowance for Doubtful Accounts
We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management’s judgment. For the three months ended March 31, 2018 and 2017, we recorded bad debt expense related to contracts with customers of
$4.0 million
and
$3.2 million
, respectively.
New Accounting Pronouncements
We prepare our condensed 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) and the Securities and Exchange Commission (SEC) issued the following new accounting guidance that may affect our accounting and/or disclosure.
Compensation - Retirement Benefits
In March 2017, the FASB issued Accounting Standard Update (ASU) 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 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 applied on a retrospective basis. The guidance permits and we elected upon adoption to use a practical expedient that allows us to use the amounts disclosed in Note 8, “Pension and Post-Retirement Benefit Plans,” for applying the retrospective presentation of the 2017 condensed consolidated statement of income. As a result, we retrospectively decreased operating, maintenance, and administrative expense by
$5.0 million
and increased other expense by
$5.0 million
for the
three months ended
March 31, 2017
. The new standard is effective for annual periods beginning after December 15, 2017. We adopted the guidance for the Westar Energy pension and post-retirement benefit plans as of January 1, 2018, without a material impact on our condensed consolidated financial statements.
Statement of Cash Flows
In August 2016, the FASB issued 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. Retrospective application is required. We adopted the guidance effective January 1, 2018, which resulted in retrospective reclassification of cash proceeds of
$1.3 million
from the settlement of COLI policies from cash inflows from operating activities to cash inflows from investing activities for the
three months ended
March 31, 2017
.
In addition, cash payments of
$0.9 million
for premiums on COLI policies were reclassified from cash outflows used in operating activities to cash outflows used in investing activities for the same period.
In November 2016, the FASB issued ASU No. 2016-18, which requires that statement of cash flows explain the change for the period of restricted cash and restricted cash equivalents along with cash and cash equivalents. The guidance requires a retrospective transition method and is effective for fiscal years beginning after December 15, 2017. We adopted the guidance effective January 1, 2018. As a result, we adjusted amounts previously reported for cash and cash equivalents to include restricted cash which resulted in an increase to beginning and ending cash, cash equivalents and restricted cash of
$0.1 million
for the
three months ended
March 31, 2017
.
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 criteria used to determine lease classification will remain substantially the same, but will be more subjective under the new guidance. 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. In 2016, we started evaluating our current leases to assess the initial impact on our consolidated financial results. We continue to evaluate the guidance and believe application of the guidance will result in an increase to our assets and liabilities on our consolidated balance sheet, with minimal impact to our consolidated statement of income. We also continue to monitor unresolved industry issues, including renewables and power purchase agreements, and will analyze the related impact. The standard permits an entity to elect a practical expedient for existing or expired contracts to forgo reassessing leases to determine whether each is in scope of the new standard and to forgo reassessing lease classification. We expect to elect this practical expedient upon implementation.
Financial Instruments
In January 2016, the FASB issued ASU No. 2016-01, which generally requires equity investments to be measured at fair value with changes in fair value recognized in net income. Under the new standard, equity securities are no longer to be classified as available-for-sale or trading securities. The guidance requires a modified retrospective transition method. This guidance is effective for fiscal years beginning after December 15, 2017; accordingly, we adopted the new standard on
January 1, 2018
,
without a material impact on our condensed 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; accordingly, we adopted the new standard on January 1, 2018. The standard permits the use of either the retrospective application or modified retrospective method. We elected to use the modified retrospective method, which requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. Adoption of the standard did not have a material impact to our condensed consolidated financial statements and, as a result, we recorded no cumulative effect of initially applying the standard. For more information on revenue recognition, see Note 4, “Revenue.”
3. PENDING MERGER
On May 29, 2016,
we
entered into an agreement and plan of merger with Great Plains Energy
that provided for the acquisition of
us
by Great Plains Energy. On April 19, 2017, the Kansas Corporation Commission (KCC) rejected the prior transaction.
On July 9, 2017, we entered into an amended and restated agreement and plan of merger with Great Plains Energy that provides for a merger of equals between the two companies. Upon closing, each issued and outstanding share of our common stock will be converted into
one
share of common stock of a new holding company with a final name yet to be publicly announced. Upon closing, each issued and outstanding share of Great Plains Energy common stock will be converted into
0.5981
shares of common stock of the new holding company. Following completion of the merger, our shareholders are expected to own approximately
52.5%
of the new holding company and Great Plains Energy’s shareholders are expected to own approximately
47.5%
of the new holding company.
The merger agreement includes certain restrictions and limitations on our ability to declare dividend payments. The merger agreement limits our quarterly dividends declared to
$0.40
per share.
The closing of the merger is subject to conditions including receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the NRC, the KCC, and the Missouri Public Service Commission (MPSC) (provided that such approvals do not result in a material adverse effect on Great Plains Energy or us, after giving effect to the merger, measured on the size and scale of Westar Energy and its subsidiaries, taken as a whole); effectiveness of the registration statement for the shares of the new holding company’s common stock to be issued to our shareholders and Great Plains Energy’s shareholders upon consummation of the merger and approval of the listing of such shares on the New York Stock Exchange; the receipt of tax opinions by us and Great Plains Energy that the merger will be treated as a non-taxable event for U.S. federal income tax purposes; there being no shares of Great Plains Energy preference stock outstanding; and Great Plains Energy having not less than
$1.25 billion
in cash or cash equivalents on its balance sheet. The closing of the merger is also subject to other standard conditions, such as accuracy of representations and warranties, compliance with covenants and the absence of a material adverse effect on either company.
The merger agreement, which contains customary representations, warranties, and covenants, may be terminated by either party if the merger has not occurred by July 10, 2018. The termination date may be extended six months in order to obtain regulatory approvals.
On August 25, 2017,
we
and Great Plains Energy filed a joint application with the KCC requesting approval of the merger. The KCC subsequently approved a procedural schedule that provides for a KCC order on the proposed merger by June 5, 2018, although under Kansas law the KCC has until June 21, 2018, to issue the order. On March 7, 2018,
we
, Great Plains Energy, the KCC staff, the Citizens’ Utility Ratepayer Board (CURB), and certain other intervenors entered into a non-unanimous settlement agreement to settle issues related to the joint application. The settlement agreement is subject to review and approval by the KCC. Components of the settlement agreement are summarized below. The settlement agreement, if approved, is expected to impact our 2018 rate review.
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•
|
$23.0 million
of bill credits in 2018 to our retail customers, which will reduce 2018 revenues by a corresponding amount
|
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|
•
|
An additional
$8.6 million
of annual bill credits to our retail customers between 2019 and 2022
|
|
|
•
|
Reduction of our annual revenues by
$22.5 million
for estimated merger-related savings to be reflected in our 2018 rate review
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|
•
|
An annual earnings review and sharing program that will allow for sharing of earnings with customers if actual earnings are above a certain level, after recovery of the annual bill credits
|
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|
•
|
A return on equity recommendation of
9.3%
in our 2018 rate review
|
|
|
•
|
Limitation on debt capitalization (excluding short-term debt and debt due within
one
year) of
65%
at the consolidated holding company and
60%
at the utility operating companies
|
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|
•
|
A
five
-year prohibition against changing base rates, which could be reduced to
three
years if the ROE ordered by the KCC in the 2018 rate review is set lower than
9.3%
|
|
|
•
|
The recovery of
$23.2 million
of transition costs to be included in our prices over a
10
-year period
|
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|
•
|
We will forgo the ability to offset tax reform benefits with demonstrated under-earnings
|
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|
•
|
An annual quality of service performance reporting requirement
|
The settlement agreement also contains items that, if approved, are expected to impact the 2018 rate review for Kansas City Power & Light Company, a utility subsidiary of Great Plains Energy that operates in Kansas and Missouri.
On August 31, 2017,
we
and Great Plains Energy applied for approval of the merger from the MPSC. On January 12, 2018,
we
, Great Plains Energy, the MPSC staff and certain other intervenors entered into a non-unanimous stipulation and agreement to settle issues related to the joint application. On March 8, 2018, the stipulation and agreement with MPSC staff was amended to include additional intervenors. The stipulation and agreement is subject to review and approval by the MPSC.
We
and Great Plains Energy each gained shareholder approval of the proposed merger on November 21, 2017.
We
and Great Plains Energy received early termination of the statutory waiting period under the Hart-Scott-Rodino Antitrust Improvements Act on December 12, 2017.
We
and Great Plains Energy received FERC approval of the merger on February 28, 2018. On March 12, 2018, Wolf Creek received approval from the NRC for an indirect transfer of control of Wolf Creek’s operating license. On March 19, 2018, we and Great Plains Energy received Federal Communications Commission consent for various license transfers that are deemed to occur with the merger.
The amended and restated merger agreement provides that Great Plains Energy may be required to pay us a termination fee of
$190.0 million
if the agreement is terminated due to (i) failure to receive regulatory approval prior to July 10, 2018, subject to an extension of up to six months, (ii) a non-appealable regulatory order enjoining the merger or (iii) Great Plains Energy’s failure to close after all conditions precedent to closing have been satisfied. In addition, we may be required to pay Great Plains Energy a termination fee of
$190.0 million
if the agreement is terminated by us under certain circumstances. Similarly, Great Plains Energy may be required to pay us a termination fee of
$190.0 million
if the agreement is terminated by Great Plains Energy under certain circumstances.
In connection with the merger, we have incurred, and expect to incur additional, merger-related expenses. These expenses are included in our operating, maintenance and administrative expenses. During the
three months ended
March 31, 2018
and
2017
, we incurred approximately
$0.4 million
of merger-related expenses. In the event that the merger is consummated, we estimate merger-related expenses for investment banking, legal, and other professional services will be approximately
$45.0 million
. In addition, we expect to incur an estimated
$40.0 million
of expenses for accelerated stock-based compensation, voluntary severance plan payments and payments pursuant to change in control agreements.
See also Note 11, “Legal Proceedings,” for more information on litigation related to the merger.
4. REVENUE
Kansas law gives the KCC general regulatory authority over our retail prices, extensions and abandonments of service and facilities, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale electricity sales, including prices and the transmission of electric power. Regulatory authorities have established various methods permitting adjustments to our prices for the recovery of costs, including the cost of invested capital. For portions of our cost of service, regulators allow us to adjust our prices periodically through the application of formulas that track changes in our costs, which reduces the time between making expenditures or investments and reflecting them in the prices we charge customers. However, for the remaining portions of our cost of service, we must file a general rate review, which lengthens the period of time between when we make and recover expenditures and a return on our investments. See Note 5, “Rate Matters and Regulation,” for information regarding our rate proceedings with the KCC and FERC and potential related refund obligations.
We categorize revenue based on class of customer as discussed below.
Retail Revenue
We are the sole supplier of retail electricity within our service territory. We operate facilities necessary to generate, transmit and distribute electricity to our customers. We are required to provide electricity to customers in our service territory as requested by customers. Revenue is recognized over time as we satisfy our obligation, generally corresponding to the amount of electricity that we deliver to our customers.
This method of recognizing revenue corresponds directly to the amount that we have the right to invoice our customers each month.
Retail revenue is impacted by things such as weather, rate regulation, fuel costs, technology, customer behavior, the economy and competitive forces. Changing weather affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential and commercial customers, and to a lesser extent, industrial customers. Mild weather reduces customer demand.
We further classify retail customers as residential, commercial, industrial and other customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification. Other retail sales of electricity include lighting for public streets and highways.
Wholesale Revenue
We sell electricity and capacity (the ability to demand delivery of a maximum amount of electricity) at wholesale to electric cooperatives, municipalities, other electric utilities and RTOs,
the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. We recognize revenue as we deliver the electricity and capacity that corresponds directly to the amount of consideration we expect to invoice. Revenues from these sales reduce retail electricity prices either annually through a formula or when base rates are determined at the time of a general rate review. Our wholesale revenues are impacted by, among other factors, demand, costs and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather. Our long-term contracts for wholesale capacity include variable transaction prices mostly based on peak demand for electricity and capacity of certain generating units. Terms on our long-term contracts for wholesale capacity expire between
2019
and
2039
.
Transmission Revenue
We provide transmission service to the Southwest Power Pool, Inc. (SPP) by allowing it access to our transmission network. As new transmission lines are constructed, they are included in the transmission network available to the SPP. In exchange for providing access, the SPP pays us consideration determined by a formula rate approved by FERC, which includes the cost to construct and maintain the transmission lines and a return on our investment.
The price for access to our transmission network is updated annually based on projected costs. Projections are updated to actual costs and the difference is included in subsequent year’s prices. We recognize revenue over time as we provide transmission service and as we have the right to invoice the SPP.
Other Revenue from Contracts with Customers
Other revenue derived from contracts with customers includes fees we earn for services provided to third parties and revenues earned by permitting other utilities to attach equipment to our utility poles. We recognize revenue when obligations under the terms of a contract with a customer are satisfied.
The following table categorizes our revenue by class of customer.
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|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
|
(In Thousands)
|
REVENUES:
|
|
|
|
Residential
|
$
|
180,285
|
|
|
$
|
169,290
|
|
Commercial
|
155,403
|
|
|
149,552
|
|
Industrial
|
93,460
|
|
|
94,589
|
|
Other retail
|
4,253
|
|
|
5,042
|
|
Total Retail Revenues
|
433,401
|
|
|
418,473
|
|
Wholesale
|
94,209
|
|
|
83,925
|
|
Transmission
|
71,926
|
|
|
70,729
|
|
Other
|
1,781
|
|
|
1,611
|
|
Total Revenue from Contracts with Customers
|
601,317
|
|
|
574,738
|
|
Other
|
(1,113
|
)
|
|
(2,164
|
)
|
Total Revenues
|
$
|
600,204
|
|
|
$
|
572,574
|
|
5. RATE MATTERS AND REGULATION
KCC Proceedings
In March 2018, the KCC issued an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2018 and are expected to increase our annual retail revenues by approximately
$31.5 million
.
In February 2018, we
filed a rate application with the KCC to update our prices to include, among other things, costs associated with the completion of Western Plains Wind Farm, expiration of wholesale contracts currently reflected in retail prices as offsets to our retail cost of service, expiration of the
10
-year period for production tax credits from our initial wind investments and an updated depreciation study. This rate application also includes savings due to the recently passed federal Tax Cuts and Jobs Act (TCJA), savings achieved from refinancing debt and a portion of the savings from the proposed merger with Great Plains Energy. If our rate application were to be approved, we estimate the new prices would decrease our annual revenues by approximately
$2.0 million
in September 2018, followed by an increase in our annual revenues of approximately
$54.0 million
in February 2019. However, we, Great Plains Energy, the KCC staff, CURB and certain other intervenors entered into a non-unanimous settlement agreement related to our merger application, which includes commitments from certain parties to the settlement agreement to accept specific merger-contingent conditions or take particular positions in our rate review. See Note 3, “Pending Merger,” for additional information. If our rate application is approved with the merger-contingent conditions related to a
9.3%
ROE and the limited amount of merger-related savings and transition costs included in our prices, then we estimate the new prices would decrease our annual revenues by approximately
$37.0 million
in September 2018, as compared to the approximately
$2.0 million
reduction originally requested. This reduction would be followed by an increase in our annual revenues of approximately
$54.0 million
in February 2019, as previously stated above. Our revenues would be further reduced due to the payment of bill credits in 2018 through 2022 as discussed in Note 3, “Pending Merger.”
In January 2018, the KCC issued an order to investigate the effect of the TCJA on regulated utilities. The KCC stated the passage of the TCJA has the potential to significantly reduce the cost of service for utilities, and it may impact the regulatory assets and liabilities of Kansas utilities. Therefore, beginning in January 2018, the KCC directed each regulated electric public utility that is taxable at the corporate level to accrue monthly, in a deferred revenue account, the portion of its revenue representing the difference between: (1) the cost of service as approved by the KCC in its most recent rate review; and (2) the cost of service that would have resulted had the provision for federal corporate income taxes been based upon the corporate tax rate approved in the TCJA. The KCC also gave notice to taxable utilities operating in Kansas that the portion of their regulated revenue stream that reflects higher corporate tax rates should be considered interim and subject to refund, with interest. When the KCC’s evaluation of the impact of the TCJA is complete, if it is determined that a retail price decrease is proper and would have been proper as of the effective date of the TCJA, these amounts will be returned to customers. We believe it is probable that we will be required to return these amounts to customers. Therefore, we have recorded a
$15.1 million
regulatory liability as of March 31, 2018, and a corresponding decrease in revenues for the three months ended March 31, 2018.
In December 2017, 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 2018 and are expected to decrease our annual retail revenues by approximately
$0.2 million
.
FERC Proceedings
Our TFR that includes projected 2018 transmission capital expenditures and operating costs was effective in January 2018 and was expected to increase our annual transmission revenues by approximately
$25.5 million
. However, due to the passage of the TCJA, we
requested permission from FERC to retroactively reflect the reduction in the federal corporate income tax rate in our
2018 prices. In April 2018, FERC granted our
request and accordingly, we
have recorded a
$3.9 million
regulatory liability as of March 31, 2018. This updated rate will provide the basis for a new request with the KCC to retroactively adjust our
retail prices to include updated transmission costs as discussed above. We estimate the revised TFR will increase 2018 revenues by
$2.3 million
when compared to 2017.
6. FINANCIAL INSTRUMENTS AND INVESTMENTS
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 that 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 and, 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 condensed 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, 2018
|
|
As of December 31, 2017
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
(In Thousands)
|
Fixed-rate debt
|
$
|
3,605,000
|
|
|
$
|
3,759,785
|
|
|
$
|
3,605,000
|
|
|
$
|
3,888,620
|
|
Fixed-rate debt of VIEs
|
81,433
|
|
|
80,557
|
|
|
109,967
|
|
|
110,756
|
|
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, 2018
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
(In Thousands)
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
68,449
|
|
|
$
|
—
|
|
|
$
|
5,323
|
|
|
$
|
73,772
|
|
International equity funds
|
|
—
|
|
|
45,130
|
|
|
—
|
|
|
—
|
|
|
45,130
|
|
Core bond fund
|
|
—
|
|
|
37,492
|
|
|
—
|
|
|
—
|
|
|
37,492
|
|
High-yield bond fund
|
|
—
|
|
|
19,713
|
|
|
—
|
|
|
—
|
|
|
19,713
|
|
Emerging markets bond fund
|
|
—
|
|
|
17,337
|
|
|
—
|
|
|
—
|
|
|
17,337
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
13,973
|
|
|
—
|
|
|
—
|
|
|
13,973
|
|
Alternative investments fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,521
|
|
|
22,521
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,024
|
|
|
11,024
|
|
Cash equivalents
|
|
191
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
191
|
|
Total Nuclear Decommissioning Trust
|
|
191
|
|
|
202,094
|
|
|
—
|
|
|
38,868
|
|
|
241,153
|
|
Rabbi Trust:
|
|
|
|
|
|
|
|
|
|
|
Core bond fund
|
|
—
|
|
|
25,670
|
|
|
—
|
|
|
—
|
|
|
25,670
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
6,418
|
|
|
—
|
|
|
—
|
|
|
6,418
|
|
Cash equivalents
|
|
156
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156
|
|
Total Rabbi Trust
|
|
156
|
|
|
32,088
|
|
|
—
|
|
|
—
|
|
|
32,244
|
|
Total Assets Measured at Fair Value
|
|
$
|
347
|
|
|
$
|
234,182
|
|
|
$
|
—
|
|
|
$
|
38,868
|
|
|
$
|
273,397
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
(In Thousands)
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
68,658
|
|
|
$
|
—
|
|
|
$
|
5,142
|
|
|
$
|
73,800
|
|
International equity funds
|
|
—
|
|
|
47,908
|
|
|
—
|
|
|
—
|
|
|
47,908
|
|
Core bond fund
|
|
—
|
|
|
33,250
|
|
|
—
|
|
|
—
|
|
|
33,250
|
|
High-yield bond fund
|
|
—
|
|
|
18,089
|
|
|
—
|
|
|
—
|
|
|
18,089
|
|
Emerging markets bond fund
|
|
—
|
|
|
17,345
|
|
|
—
|
|
|
—
|
|
|
17,345
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
14,125
|
|
|
—
|
|
|
—
|
|
|
14,125
|
|
Alternative investments fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,669
|
|
|
21,669
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,806
|
|
|
10,806
|
|
Cash equivalents
|
|
110
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
110
|
|
Total Nuclear Decommissioning Trust
|
|
110
|
|
|
199,375
|
|
|
—
|
|
|
37,617
|
|
|
237,102
|
|
Rabbi Trust:
|
|
|
|
|
|
|
|
|
|
|
Core bond fund
|
|
—
|
|
|
27,324
|
|
|
—
|
|
|
—
|
|
|
27,324
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
6,831
|
|
|
—
|
|
|
—
|
|
|
6,831
|
|
Cash equivalents
|
|
156
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156
|
|
Total Rabbi Trust
|
|
156
|
|
|
34,155
|
|
|
—
|
|
|
—
|
|
|
34,311
|
|
Total Assets Measured at Fair Value
|
|
$
|
266
|
|
|
$
|
233,530
|
|
|
$
|
—
|
|
|
$
|
37,617
|
|
|
$
|
271,413
|
|
We hold equity and debt investments that we classify as securities in a trust for the purpose of funding the decommissioning of Wolf Creek and maintain a Rabbi trust to manage funds for the benefit of certain retired executive officers. We record net realized and unrealized gains and losses on the Nuclear Decommissioning Trust (NDT) in regulatory liabilities on our condensed consolidated balance sheets. We include net realized and unrealized gains or losses on the Rabbi trust in investment earnings on our condensed consolidated statements of income. For the
three months ended
March 31, 2018
and
2017
, we recorded net unrealized losses of
$0.1 million
and net unrealized gains of
$9.0 million
, respectively, on the NDT assets still held as of
March 31, 2018
and net unrealized losses of
$0.4 million
and net unrealized gains of
$1.4 million
, respectively, on the Rabbi trust assets still held as of
March 31, 2018
Some of our investments in the 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, 2018
|
|
As of December 31, 2017
|
|
As of March 31, 2018
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Redemption
Frequency
|
|
Length of
Settlement
|
|
(In Thousands)
|
|
|
|
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
5,323
|
|
|
$
|
2,508
|
|
|
$
|
5,142
|
|
|
$
|
2,808
|
|
|
(a)
|
|
(a)
|
Alternative investments fund (b)
|
22,521
|
|
|
—
|
|
|
21,669
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
Real estate securities fund (b)
|
11,024
|
|
|
—
|
|
|
10,806
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
Total
|
$
|
38,868
|
|
|
$
|
2,508
|
|
|
$
|
37,617
|
|
|
$
|
2,808
|
|
|
|
|
|
_______________
|
|
(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. Three funds have begun to make distributions. Our initial investment in the fourth fund occurred in 2016.
This fund’s term 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 condensed 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 and diversifying maturity dates. We may also use other financial derivative instruments such as entering into treasury yield hedge transactions and interest rate swaps.
7. TAXES
We recorded income tax expense of
$9.2 million
with an effective income tax rate of
13%
for the
three months ended
March 31, 2018
, and income tax expense of
$20.9 million
with an effective income tax rate of
25%
for the same period of
2017
. The decrease in the effective income tax rate for the
three months ended
March 31, 2018
, was due primarily to the TCJA, which was signed into law in December 2017 and decreased the federal corporate income tax rate from
35%
to
21%
.
As of
March 31, 2018
, and
December 31, 2017
, our unrecognized income tax benefits totaled
$1.7 million
. We do not expect significant changes in our unrecognized income tax benefits in the next
12
months.
As of
March 31, 2018
, and
December 31, 2017
, we had
no
amounts and
$0.1 million
, respectively, accrued for interest related to our unrecognized income tax benefits. We accrued
no
penalties at either
March 31, 2018
, or
December 31, 2017
.
As of
March 31, 2018
, and
December 31, 2017
, we had recorded
$0.5 million
and
$0.4 million
, respectively, for probable assessments of taxes other than income taxes.
8. 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,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
5,826
|
|
|
$
|
5,218
|
|
|
$
|
279
|
|
|
$
|
271
|
|
Interest cost (a)
|
|
10,207
|
|
|
10,621
|
|
|
1,183
|
|
|
1,314
|
|
Expected return on plan assets (a)
|
|
(11,091
|
)
|
|
(10,760
|
)
|
|
(1,728
|
)
|
|
(1,718
|
)
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs (a)
|
|
166
|
|
|
171
|
|
|
114
|
|
|
114
|
|
Actuarial loss (gain), net (a)
|
|
6,485
|
|
|
5,489
|
|
|
(135
|
)
|
|
(195
|
)
|
Net periodic cost (benefit) before regulatory adjustment
|
|
11,593
|
|
|
10,739
|
|
|
(287
|
)
|
|
(214
|
)
|
Regulatory adjustment (b)
|
|
2,849
|
|
|
3,288
|
|
|
(434
|
)
|
|
(478
|
)
|
Net periodic cost (benefit)
|
|
$
|
14,442
|
|
|
$
|
14,027
|
|
|
$
|
(721
|
)
|
|
$
|
(692
|
)
|
_______________
|
|
(a)
|
The components of net periodic benefit cost other than service cost are included in the line item other expense in the condensed consolidated statements of income.
|
|
|
(b)
|
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, 2018
and
2017
, we contributed
$12.5 million
and
$7.0 million
, respectively, to the Westar Energy pension trust.
9. 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,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(In Thousands)
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
2,220
|
|
|
$
|
1,950
|
|
|
$
|
36
|
|
|
$
|
37
|
|
Interest cost
|
|
2,478
|
|
|
2,475
|
|
|
61
|
|
|
70
|
|
Expected return on plan assets
|
|
(2,891
|
)
|
|
(2,643
|
)
|
|
—
|
|
|
—
|
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
14
|
|
|
14
|
|
|
—
|
|
|
—
|
|
Actuarial loss (gain), net
|
|
1,656
|
|
|
1,245
|
|
|
(14
|
)
|
|
(13
|
)
|
Net periodic cost before regulatory adjustment
|
|
3,477
|
|
|
3,041
|
|
|
83
|
|
|
94
|
|
Regulatory adjustment (a)
|
|
(49
|
)
|
|
247
|
|
|
—
|
|
|
—
|
|
Net periodic cost
|
|
$
|
3,428
|
|
|
$
|
3,288
|
|
|
$
|
83
|
|
|
$
|
94
|
|
_______________
|
|
(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, 2018
and
2017
, we did not fund Wolf Creek’s pension plan.
10. 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 condensed 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 nitrogen oxides 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
revised the existing ozone season allowance budgets for Missouri and Oklahoma and
established 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 but the rule remains in effect. We do not believe this rule will have a material impact on our operations and condensed consolidated financial results.
National Ambient Air Quality Standards
Under the 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, nitrogen dioxide (NO
2
) (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 attainment/unclassifiable. In November 2017, the EPA designated all counties in the State of Kansas as attainment/unclassifiable. We do not believe this will have a material impact on our condensed 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 attainment/unclassifiable with the standard. We do not believe this will have a material impact on our operations or condensed 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 these criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable. 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 that governs the next round of the designations. Also in January 2017, KDHE recommended the EPA change the designation of the area surrounding the facility from unclassifiable to attainment/unclassifiable. In August 2017, the EPA indicated they would address this area redesignation request in a separate action. 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 condensed 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 condensed 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 Megawatt hour (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 us, in the D.C. Circuit. The CPP was stayed by the Supreme Court in February 2016 and, accordingly, is not currently being implemented by the states.
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. Also in April 2017, the EPA published a notice in the Federal Register that it was initiating administrative reviews of the CPP and the GHG NSPS.
In October 2017, the EPA issued a proposed rule to repeal the CPP. The proposed rule indicates the CPP exceeds EPA’s authority and the EPA has not determined whether they will issue a replacement rule. The EPA is soliciting comments on the legal interpretations contained in this rulemaking. Comments were due in April 2018.
In December 2017, the EPA issued an advance notice of proposed rulemaking. This proposed rulemaking was issued by the EPA because it is considering the possibility of changing certain aspects of the CPP and the EPA is soliciting feedback on specific areas that could be changed. Comments on these proposed areas of change were due to the EPA in February 2018.
Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or condensed 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 (ELG) 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 the EPA’s review. In September 2017, the EPA finalized a rule to postpone the compliance dates for the new, more stringent, effluent limitations and pretreatment standards for bottom ash transport water and flue gas desulfurization wastewater. These compliance dates have been postponed for two years while the EPA completes its administrative reconsideration of the ELG rule. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or condensed 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 or cooling lakes that can be classified as closed cycle cooling. We do not expect the impact from this rule 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 February 2018, the EPA and the U.S. Corps of Engineers finalized a rule adding an applicability date to the 2015 rule, which makes the implementation date of the rule February 2020. In July 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a proposed rule that would, if implemented, reinstate the definition of WOTUS that existed prior to the June 2015 expansion of the definition. Final action on the proposed rule is expected in 2018. 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 condensed 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 and 2018. The Water Infrastructure Improvements for the Nation Act allows states to achieve delegated authority for CCR rules from the EPA. This has the potential to impact compliance options. Electric generation industry participants requested and the EPA has granted a request to reconsider portions of the final CCR regulation. In March 2018, the EPA proposed the Phase I CCR Remand Rule in order to modify portions of the 2015 rulemaking. This rule, should it become final, could introduce additional flexibility in CCR compliance. 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 condensed consolidated financial results could be material.
Storage of Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision.
Wolf Creek has elected to build a dry cask storage facility to expand its existing on-site spent nuclear fuel storage, which is expected to provide additional capacity prior to 2025. Wolf Creek has finalized a settlement agreement through 2019 with the DOE for reimbursement of costs to construct this facility that would not have otherwise been incurred had the DOE begun accepting spent nuclear fuel. As a co-owner of Wolf Creek, in 2017 we received
$0.8 million
of the settlement representing reimbursement of costs incurred through 2015 for project planning, and in March 2018 we received
$0.5 million
for costs incurred between January 2016 and June 2017. We expect the majority of the remaining cost to construct the dry cask storage facility that would not have otherwise been incurred will be reimbursed by the DOE. 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.
TCJA Refund Liability
In January 2018, the KCC issued an order to investigate the effect of the TCJA on regulated utilities and directed Kansas utilities to record a liability for the difference between the cost of service as approved in its most recent rate review and the cost of service that would have resulted had the provision for federal corporate income taxes been based upon the rate approved in the TCJA. We believe it is probable that we will be required to return these amounts to customers. We also believe it is probable that we will be required to return amounts to our transmission customers. See Note 5, “Rate Matters and Regulation,” for additional information.