NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS
We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the Company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.
We provide electric generation, transmission and distribution services to approximately
708,000
customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly-owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
We prepare our consolidated financial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America. Our consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation.
Use of Management’s Estimates
When we prepare our consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities, at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.
Regulatory Accounting
We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 4, “Rate Matters and Regulation,” for additional information regarding our regulatory assets and liabilities.
Cash and Cash Equivalents
We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.
Fuel Inventory and Supplies
We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately.
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As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Fuel inventory
|
$
|
94,039
|
|
|
$
|
107,086
|
|
|
Supplies
|
199,523
|
|
|
193,039
|
|
|
Fuel inventory and supplies
|
$
|
293,562
|
|
|
$
|
300,125
|
|
Property, Plant and Equipment
We record the value of property, plant and equipment, including that of VIEs, at cost. For plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:
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Year Ended December 31,
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2017
|
|
2016
|
|
2015
|
|
|
(Dollars In Thousands)
|
|
Borrowed funds
|
$
|
5,605
|
|
|
$
|
9,964
|
|
|
$
|
3,505
|
|
|
Equity funds
|
1,996
|
|
|
11,630
|
|
|
2,075
|
|
|
Total
|
$
|
7,601
|
|
|
$
|
21,594
|
|
|
$
|
5,580
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|
|
Average AFUDC Rates
|
2.3
|
%
|
|
4.2
|
%
|
|
2.7
|
%
|
We charge maintenance costs and replacements of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.
Depreciation
We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated
2.5%
in
2017
,
2.4%
in
2016
and
2.5%
in
2015
.
Depreciable lives of property, plant and equipment are as follows.
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Years
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|
Fossil fuel generating facilities
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|
6
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to
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78
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|
Nuclear fuel generating facility
|
|
55
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to
|
71
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|
Wind generating facilities
|
|
19
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to
|
20
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|
Transmission facilities
|
|
15
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to
|
67
|
|
Distribution facilities
|
|
22
|
to
|
68
|
|
Other
|
|
5
|
to
|
30
|
Nuclear Fuel
We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication. We reflect this at original cost and amortize such amounts to fuel expense based on the quantity of heat consumed during the generation of electricity as measured in millions of British thermal units. The accumulated amortization of nuclear fuel in the reactor was
$72.2 million
as of
December 31, 2017
, and
$40.0 million
as of
December 31, 2016
. The cost of nuclear fuel charged to fuel and purchased power expense was
$32.2 million
in
2017
,
$26.8 million
in
2016
and
$27.3 million
in
2015
.
Cash Surrender Value of Life Insurance
We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.
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As of December 31,
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2017
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2016
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(In Thousands)
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|
Cash surrender value of policies
|
$
|
1,320,695
|
|
|
$
|
1,267,349
|
|
|
Borrowings against policies
|
(1,189,212
|
)
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|
(1,137,360
|
)
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|
Corporate-owned life insurance, net
|
$
|
131,483
|
|
|
$
|
129,989
|
|
We record as income increases in cash surrender value and death benefits. We offset against policy income the interest expense that we incur on policy loans. Income from death benefits is highly variable from period to period.
Revenue Recognition
We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.
Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of
$76.7 million
as of
December 31, 2017
, and
$74.4 million
as of
December 31, 2016
within accounts receivable.
Allowance for Doubtful Accounts
We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management’s judgment.
Income Taxes
We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred income tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize future tax benefits to the extent that realization of such benefits is more likely than not. With the passage of the Tax Cuts and Jobs Act (TCJA) in December 2017, we were required to remeasure deferred income tax assets and liabilities at the lower 21% corporate tax rate and defer the amount of excess deferred taxes previously collected from our customers to a regulatory liability, the majority of which will be amortized to income over a period generally corresponding to the life of our plant assets. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.
We record deferred income tax assets to the extent capital losses, net operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred income tax asset.
The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 11, “Taxes,” for additional detail on our accounting for income taxes.
Sales Tax
We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect sales tax in our consolidated statements of income.
Earnings Per Share
We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS).
To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our forward sale agreements, if any, and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.
The following table reconciles our basic and diluted EPS from net income.
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Year Ended December 31,
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2017
|
|
2016
|
|
2015
|
|
|
(Dollars In Thousands, Except Per Share Amounts)
|
|
Net income
|
$
|
336,552
|
|
|
$
|
361,200
|
|
|
$
|
301,796
|
|
|
Less: Net income attributable to noncontrolling interests
|
12,632
|
|
|
14,623
|
|
|
9,867
|
|
|
Net income attributable to Westar Energy, Inc.
|
323,920
|
|
|
346,577
|
|
|
291,929
|
|
|
Less: Net income allocated to RSUs
|
584
|
|
|
714
|
|
|
646
|
|
|
Net income allocated to common stock
|
$
|
323,336
|
|
|
$
|
345,863
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|
|
$
|
291,283
|
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|
|
|
|
|
|
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|
Weighted average equivalent common shares outstanding – basic
|
142,463,831
|
|
|
142,067,558
|
|
|
137,957,515
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|
Effect of dilutive securities:
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|
|
|
|
|
RSUs
|
96,363
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|
|
407,123
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|
|
299,198
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|
Forward sale agreements
|
—
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|
|
—
|
|
|
1,021,510
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|
Weighted average equivalent common shares outstanding – diluted (a)
|
142,560,194
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|
|
142,474,681
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|
|
139,278,223
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Earnings per common share, basic
|
$
|
2.27
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|
|
$
|
2.43
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|
|
$
|
2.11
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|
Earnings per common share, diluted
|
$
|
2.27
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|
|
$
|
2.43
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|
|
$
|
2.09
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_______________
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(a)
|
For the years ended December 31,
2017
,
2016
and
2015
, we had
no
antidilutive securities.
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Supplemental Cash Flow Information
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Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
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(In Thousands)
|
|
CASH PAID FOR (RECEIVED FROM):
|
|
|
|
|
|
|
Interest on financing activities, net of amount capitalized
|
$
|
153,905
|
|
|
$
|
139,029
|
|
|
$
|
161,484
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|
Interest on financing activities of VIEs
|
3,061
|
|
|
5,846
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|
|
10,430
|
|
|
Income taxes, net of refunds
|
(12,736
|
)
|
|
13,103
|
|
|
(410
|
)
|
|
NON-CASH INVESTING TRANSACTIONS:
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|
|
|
|
|
|
Property, plant and equipment additions
|
158,780
|
|
|
151,474
|
|
|
105,169
|
|
|
Deconsolidation of property, plant and equipment of VIE
|
(72,901
|
)
|
|
—
|
|
|
—
|
|
|
NON-CASH FINANCING TRANSACTIONS:
|
|
|
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|
|
Issuance of stock for compensation and reinvested dividends
|
5,089
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|
|
9,685
|
|
|
10,453
|
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|
Deconsolidation of VIE
|
(83,096
|
)
|
|
—
|
|
|
—
|
|
|
Assets acquired through capital leases
|
4,842
|
|
|
2,744
|
|
|
3,130
|
|
New Accounting Guidance
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) 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. We adopted the guidance as of January 1, 2018, without a material impact on our 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 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 will result in a reclassification of cash proceeds from the settlement of COLI policies from cash inflows from operating activities to cash inflows from investing activities. In addition, cash payments for premiums on COLI policies will be reclassified from cash outflows used in operating activities to cash outflows used in investing activities.
In November 2016, the FASB issued ASU No. 2016-18, which requires that the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents be explained in the statement of cash flows. The guidance requires a retrospective transition method. This guidance is effective for fiscal years beginning after December 15, 2017. We adopted the guidance effective January 1, 2018, without a material impact on our consolidated statement of cash flows.
Stock-based Compensation
In March 2016, the FASB issued ASU No. 2016-09 as part of its simplification initiative. The areas for simplification involve several aspects of the accounting for stock-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We adopted the guidance effective January 1, 2016.
Prior to the adoption of ASU 2016-09, if the tax deduction for a stock-based payment award exceeded the compensation cost recorded for financial reporting, the additional tax benefit was recognized in additional paid-in capital and referred to as an excess tax benefit. Tax deficiencies were recognized either as an offset to the accumulated excess tax benefits, if any, or as reduction of income. The issuance of this ASU reflects the FASB’s decision that all prospective excess tax benefits and tax deficiencies should be recognized as income tax benefits or expense, respectively. Prior to the adoption of the ASU, additional paid-in-capital was not recognized to the extent that an excess tax benefit had not be realized (e.g., due to a carryforward of a net operating loss). Under the ASU, all excess tax benefits previously unrecognized because the related tax deduction had not reduced taxes payable are recognized on a modified retrospective basis as a cumulative-effect adjustment to retained earnings as of the date of adoption. Upon adoption, we recorded a
$3.3 million
cumulative effect adjustment to retained earnings for excess tax benefits that had not previously been recognized as well as a
$3.3 million
increase in deferred tax assets.
Further, the issuance of this ASU reflects the FASB’s decision that cash flows related to excess tax benefits should be classified as cash flows from operating activities on the consolidated statements of cash flows. Upon adoption, we have retrospectively presented cash flows from operating activities on the accompanying consolidated statements of cash flows for the year ended December 31, 2015, as
$1.3 million
higher than as previously reported. We have retrospectively presented cash flows used in financing activities as
$1.3 million
higher for the year ended December 31, 2015, than as previously reported.
Leases
In February 2016, the FASB issued ASU No. 2016-02, which requires a lessee to recognize right-of-use assets and lease liabilities, initially measured at present value of the lease payments, on its balance sheet for leases with terms longer than 12 months. Leases are to be classified as either financing or operating leases, with that classification affecting the pattern of expense recognition in the income statement. Accounting for leases by lessors is largely unchanged. The 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 pole attachments, 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 - Credit Losses
In June 2016, the FASB issued ASU No. 2016-13, which requires financial assets measured at amortized cost be presented at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis. The measurement of expected losses is based upon historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. This guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are evaluating the guidance and have not yet determined the impact on our consolidated financial statements.
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 will not have a material impact to our consolidated financial statements and, as a result, we recorded no cumulative effect of initially applying the standard.
Tax Cuts and Jobs Act
The SEC issued Staff Accounting Bulletin 118, which addresses the income tax accounting implications of the TCJA. The income tax effects of the TCJA in which the accounting is complete must be reflected in the financial statements. Additionally, provisional amounts in which reasonable estimates of the income tax effects of the TCJA can be determined should be included in the financial statements. Any specific income tax effect of the TCJA for which a reasonable estimate cannot be determined, would not be reported. Specific income tax effects of the TCJA that cannot be determined would continue to follow the provisions from the tax laws that were in effect immediately prior to the TCJA being enacted. We believe the accounting associated with the passage of the TCJA is complete and we have therefore not recorded any provisional amounts in our consolidated financial statements.
3. PENDING MERGER
On May 29, 2016,
we
entered into an agreement and plan of merger with Great Plains Energy Incorporated (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 still to be determined. 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, without prior approval of Great Plains Energy, 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),
Nuclear Regulatory Commission (NRC), KCC,
and Public Service Commission of the State of Missouri (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 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 intervenors entered into a stipulation and agreement to settle certain issues related to the joint application. The stipulation and agreement is subject to review and approval by the MPSC. On September 1, 2017,
we
and Great Plains Energy filed a joint application for approval of the merger with FERC
, and we
expect to receive a final order by the end of February 2018, unless FERC takes action that results in an extension of this date. On September 5, 2017, Wolf Creek filed a request with the NRC to approve an indirect transfer of control of Wolf Creek’s operating license.
We
and Great Plains Energy each gained shareholder approval of the proposed merger on November 21, 2017. Also,
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.
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, such as entering into a definitive acquisition agreement with respect to a superior proposal.
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, such as entering into a definitive acquisition agreement with respect to a superior proposal.
In connection with the merger, we have incurred, and expect to incur additional, merger-related expenses. These expenses are included in our selling, general, and administrative expenses. For the years ended
December 31, 2017
and
2016
, we incurred approximately
$10.8 million
and
$10.2 million
of merger-related expenses. In the event that the merger is consummated, we expect total merger-related expenses will be approximately
$45.0 million
.
See also Note 16, “Legal Proceedings,” for more information on litigation related to the merger.
4. RATE MATTERS AND REGULATION
Regulatory Assets and Regulatory Liabilities
Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers through the price setting process. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.
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|
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|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Regulatory Assets:
|
|
|
|
|
Deferred employee benefit costs
|
$
|
393,890
|
|
|
$
|
381,129
|
|
|
Debt reacquisition costs
|
109,169
|
|
|
115,502
|
|
|
Depreciation
|
60,598
|
|
|
63,171
|
|
|
Asset retirement obligations
|
42,676
|
|
|
35,487
|
|
|
Analog meter unrecovered investment
|
31,545
|
|
|
8,500
|
|
|
Removal costs
|
30,847
|
|
|
—
|
|
|
Treasury yield hedges
|
24,814
|
|
|
25,927
|
|
|
Retail energy cost adjustment
|
20,741
|
|
|
32,451
|
|
|
Ad valorem tax
|
17,389
|
|
|
17,637
|
|
|
Disallowed plant costs
|
15,249
|
|
|
15,453
|
|
|
La Cygne environmental costs
|
13,295
|
|
|
14,370
|
|
|
Energy efficiency program costs
|
8,096
|
|
|
7,097
|
|
|
Wolf Creek outage
|
6,967
|
|
|
20,316
|
|
|
Amounts due from customers for future income taxes, net
|
—
|
|
|
124,020
|
|
|
Other regulatory assets
|
9,623
|
|
|
18,802
|
|
|
Total regulatory assets
|
$
|
784,899
|
|
|
$
|
879,862
|
|
|
|
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
Income taxes, net
|
$
|
845,240
|
|
|
$
|
—
|
|
|
Deferred regulatory gain from sale leaseback
|
64,569
|
|
|
70,065
|
|
|
Nuclear decommissioning
|
55,531
|
|
|
34,094
|
|
|
Pension and other post-retirement benefits costs
|
48,356
|
|
|
37,172
|
|
|
Jurisdictional allowance for funds used during construction
|
31,707
|
|
|
33,119
|
|
|
La Cygne leasehold dismantling costs
|
29,552
|
|
|
27,742
|
|
|
Kansas tax credits
|
16,844
|
|
|
13,142
|
|
|
Purchase power agreement
|
8,823
|
|
|
9,265
|
|
|
Removal costs
|
—
|
|
|
5,663
|
|
|
Other regulatory liabilities
|
4,954
|
|
|
9,191
|
|
|
Total regulatory liabilities
|
$
|
1,105,576
|
|
|
$
|
239,453
|
|
Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.
|
|
|
|
•
|
Deferred employee benefit costs:
Includes
$374.2 million
for pension and post-retirement benefit obligations and
$19.7 million
for actual pension expense in excess of the amount of such expense recognized in setting our prices. The increase in regulatory assets for pension and post-retirement benefit obligations from 2016 to 2017 is attributable primarily to a decrease in the discount rates used to calculate our and Wolf Creek’s pension benefit obligations. During 2018, we will amortize to expense approximately
$33.5 million
of the benefit obligations and approximately
$6.8 million
of the excess pension expense. We are amortizing the excess pension expense over a
five
-year period. We do not earn a return on this asset.
|
|
|
|
|
•
|
Debt reacquisition costs:
Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.
|
|
|
|
|
•
|
Depreciation:
Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.
|
|
|
|
|
•
|
Asset retirement obligations:
Represents amounts associated with our AROs as discussed in Note 15, “Asset Retirement Obligations.” We recover these amounts over the life of the related plant. We do not earn a return on this asset.
|
|
|
|
|
•
|
Analog meter unrecovered investment:
Represents the deferral of unrecovered investment of analog meters retired between October 2015 and the next general rate review. Once these amounts are included in base rates established in our next general rate review, we will amortize these amounts over a
five
-year period and will not earn a return on this asset.
|
|
|
|
|
•
|
Removal costs:
Represents amounts spent, but not yet collected, to dispose of plant assets. This asset will decrease as removal costs are collected in our prices. We do not earn a return on this asset.
|
|
|
|
|
•
|
Treasury yield hedges:
Represents the effective portion of treasury yield hedge transactions. This amount will be amortized to interest expense over the term of the related debt. We do not earn a return on this asset.
|
|
|
|
|
•
|
Retail energy cost adjustment:
We are allowed to adjust our retail prices to reflect changes in the
|
cost of fuel and purchased power needed to serve our customers. This item represents the actual cost
of fuel consumed in producing electricity and the cost of purchased power in excess of the amounts we
have collected from customers. We expect to recover in our prices this shortfall over a
one
-year
period. We do not earn a return on this asset.
|
|
|
|
•
|
Ad valorem tax:
Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a
one
-year period. We do not earn a return on this asset.
|
|
|
|
|
•
|
Disallowed plant costs:
Originally there was a decision to disallow certain costs related to the Wolf Creek plant. Subsequently, in 1987, the KCC revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.
|
|
|
|
|
•
|
La Cygne environmental costs:
Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.
|
|
|
|
|
•
|
Energy efficiency program costs:
We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a
one
-year period. We do not earn a return on this asset.
|
|
|
|
|
•
|
Wolf Creek outage:
We defer the expenses associated with Wolf Creek’s scheduled refueling and maintenance outages and amortize these expenses during the period between planned outages. We do not earn a return on this asset.
|
|
|
|
|
•
|
Amounts due from customers for future income taxes, net:
In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we received them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. We do not earn a return on this net asset.
|
|
|
|
|
•
|
Other regulatory assets:
Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.
|
Below we summarize the nature and period of amortization for each of the regulatory liabilities listed in the table above.
|
|
|
|
•
|
Income taxes, net:
We have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers in earlier periods when corporate income tax rates were higher than current income tax rates under TCJA. Most of this regulatory liability is related to depreciation and will be returned to customers over the life of the applicable property. Also, in accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions, thereby passing on these benefits to customers at the time we received them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset for these amounts, which is offset against the regulatory liability.
|
|
|
|
|
•
|
Deferred regulatory gain from sale leaseback:
Represents the gain KGE recorded on the
1987
sale and leaseback of its
50%
interest in La Cygne unit 2. We amortize the gain over the lease term.
|
|
|
|
|
•
|
Nuclear decommissioning:
We have a legal obligation to decommission Wolf Creek at the end of its useful life. This amount represents the difference between the fair value of the assets held in a decommissioning trust and the amount recorded for the accumulated accretion and depreciation expense associated with our ARO. See Notes 5, 6 and 15, “Financial Instruments and Trading Securities,” “Financial Investments” and “Asset Retirement Obligations,” respectively, for information regarding our nuclear decommissioning trust (NDT) and our ARO.
|
|
|
|
|
•
|
Pension and other post-retirement benefits costs:
Includes
$12.6 million
for pension and post-retirement benefit obligations and
$35.7 million
for pension and post-retirement expense recognized in setting our prices in excess of actual pension and post-retirement expense. During 2018, we will amortize to expense approximately
$0.3 million
of the benefit obligations and approximately
$3.4 million
of the excess pension and post-retirement expense recognized in setting our prices. We will amortize the excess pension and post-retirement expense over a
five
-year period.
|
|
|
|
|
•
|
Jurisdictional allowance for funds used during construction:
This item represents AFUDC that is accrued subsequent to the time the associated construction charges are included in our prices and prior to the time the related assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.
|
|
|
|
|
•
|
La Cygne leasehold dismantling costs:
We are contractually obligated to dismantle a portion of La Cygne unit 2. This item represents amounts collected but not yet spent to dismantle this unit and the obligation will be discharged as we dismantle the unit.
|
|
|
|
|
•
|
Kansas tax credits:
This item represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.
|
|
|
|
|
•
|
Purchase power agreement:
This item represents the amount included in retail electric rates from customers in excess of the costs incurred by us under the purchase power agreement with Westar Generating. We amortize the amount over a
three
-year period.
|
|
|
|
|
•
|
Removal costs:
Represents amounts collected, but not yet spent, to dispose of plant assets. This liability will be discharged as removal costs are incurred.
|
|
|
|
|
•
|
Other regulatory liabilities:
Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.
|
KCC Proceedings
General and Abbreviated Rate Reviews
In February 2018, we filed an 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 retail cost of service; expiring production tax credits from initial wind investments; and an updated depreciation study. This application also includes savings due to the recently passed TCJA, savings achieved from refinancing debt, and savings from the proposed merger with Great Plains Energy. If approved we estimate the new prices will decrease our annual revenues by approximately
$2.0 million
in September 2018, followed by an increase in our annual revenues of
$54.0 million
in February 2019. We expect the KCC to issue an order on our request by September 2018.
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 all regulated electric public utilities that are 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.
In June 2017, the KCC issued an order in our abbreviated rate review allowing us to adjust our prices to include capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. The new prices were effective June 2017 and are expected to increase our annual retail revenues by approximately
$16.4 million
.
In September 2015, the KCC issued an order in our state general rate review allowing us to adjust our prices to include, among other things, additional investment in La Cygne environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately
$78.3 million
.
Environmental Costs
In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future, we will need to seek approval from the KCC for individual projects. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately
$10.8 million
effective in
June 2015
.
Transmission Costs
We make annual filings with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate (TFR) discussed below. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:
|
|
|
|
•
|
$12.7 million
effective in
April 2017
;
|
|
|
|
|
•
|
$7.0 million
effective in
April 2016
; and
|
|
|
|
|
•
|
$7.2 million
effective in
April 2015
.
|
In June 2016, the KCC approved an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the TFR, along with the reduced return on equity (ROE) as described below. The updated prices were retroactively effective April 2016. We began refunding our previously-recorded refund obligation in 2016 and as of December 31, 2016, we had a remaining refund obligation of
$1.3 million
, which is included in current regulatory liabilities on our balance sheet. As of December 31, 2017, we have fully refunded this obligation.
Property Tax Surcharge
We make annual filings with the KCC to adjust our prices to include the cost incurred for property taxes. In October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent four years, the KCC issued orders related to such filings allowing us to adjust our annual retail revenues by approximately:
|
|
|
|
•
|
$0.2 million
decrease effective in
January 2018
;
|
|
|
|
|
•
|
$26.8 million
decrease effective in
January 2017
;
|
|
|
|
|
•
|
$5.0 million
increase effective in
January 2016
; and
|
|
|
|
|
•
|
$4.9 million
increase effective in
January 2015
.
|
FERC Proceedings
In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent four years, we posted our TFR, which was expected to adjust our annual transmission revenues by approximately:
|
|
|
|
•
|
$25.5 million
increase effective in
January 2018
;
|
|
|
|
|
•
|
$29.6 million
increase effective in
January 2017
;
|
|
|
|
|
•
|
$24.0 million
increase effective in
January 2016
; and
|
|
|
|
|
•
|
$4.6 million
decrease effective in
January 2015
.
|
In March 2016, the FERC approved a settlement reducing our base ROE used in determining our TFR. The settlement resulted in an ROE of
10.3%
, which consists of a
9.8%
base ROE plus a
0.5%
incentive ROE for participation in a regional transmission organization (RTO). The updated prices were retroactively effective January 2016. This adjustment also reflected estimated recovery of increased transmission capital expenditures and operating costs. We began refunding our previously recorded refund obligation in 2016 and as of December 31, 2016, we had a remaining refund obligation of
$1.2 million
, which is included in current regulatory liabilities on our balance sheet. As of December 31, 2017, we have fully refunded this obligation.
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 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, 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 December 31, 2017
|
|
As of December 31, 2016
|
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
|
(In Thousands)
|
|
Fixed-rate debt
|
$
|
3,605,000
|
|
|
$
|
3,888,620
|
|
|
$
|
3,430,000
|
|
|
$
|
3,597,441
|
|
|
Fixed-rate debt of VIEs
|
109,967
|
|
|
110,756
|
|
|
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 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
|
|
|
Trading Securities:
|
|
|
|
|
|
|
|
|
|
|
|
Core bond fund
|
|
—
|
|
|
27,324
|
|
|
—
|
|
|
—
|
|
|
27,324
|
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
6,831
|
|
|
—
|
|
|
—
|
|
|
6,831
|
|
|
Cash equivalents
|
|
156
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156
|
|
|
Total Trading Securities
|
|
156
|
|
|
34,155
|
|
|
—
|
|
|
—
|
|
|
34,311
|
|
|
Total Assets Measured at Fair Value
|
|
$
|
266
|
|
|
$
|
233,530
|
|
|
$
|
—
|
|
|
$
|
37,617
|
|
|
$
|
271,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 markets bond fund
|
|
—
|
|
|
14,738
|
|
|
—
|
|
|
—
|
|
|
14,738
|
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
13,484
|
|
|
—
|
|
|
—
|
|
|
13,484
|
|
|
Alternative investments 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 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 December 31, 2017
|
|
As of December 31, 2016
|
|
As of December 31, 2017
|
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Fair Value
|
|
Unfunded
Commitments
|
|
Redemption
Frequency
|
|
Length of
Settlement
|
|
|
(In Thousands)
|
|
|
|
|
|
Nuclear Decommissioning Trust:
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
5,142
|
|
|
$
|
2,808
|
|
|
$
|
5,056
|
|
|
$
|
3,529
|
|
|
(a)
|
|
(a)
|
|
Alternative investments fund (b)
|
21,669
|
|
|
—
|
|
|
18,958
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
|
Real estate securities fund (b)
|
10,806
|
|
|
—
|
|
|
9,946
|
|
|
—
|
|
|
Quarterly
|
|
65 days
|
|
Total
|
$
|
37,617
|
|
|
$
|
2,808
|
|
|
$
|
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. Three funds have begun to make distributions. Our initial investment in the fourth fund occurred in the second quarter of 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.
|
Derivative Instruments
Price Risk
We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.
Interest Rate Risk
We have entered into numerous fixed and variable rate debt obligations. For details, see Note 10, “Long-Term Debt.” We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other financial derivative instruments such as interest rate swaps.
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. These obligations totaled
$27.4 million
and
$26.8 million
as of
December 31, 2017
and
2016
, respectively. For additional information on our benefit obligations, see Note 12, “Employee Benefit Plans.”
As of
December 31, 2017
and
2016
, we measured the fair value of trust assets at
$34.3 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 years ended
December 31, 2017
,
2016
and
2015
, we recorded unrealized gains of
$4.0 million
,
$2.5 million
and
$0.4 million
, respectively, on assets still held.
Available-for-Sale Securities
We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of
December 31, 2017
and
2016
.
Using the specific identification method to determine cost, we realized
no
gain or loss on our available-for-sale securities in
2017
. We realized a loss on our available-for-sale securities of
$1.5 million
and
$0.9 million
in
2016
and
2015
, respectively. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.
The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of
December 31, 2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Unrealized
|
|
|
|
|
|
Security Type
|
|
Cost
|
|
Gain
|
|
Loss
|
|
Fair Value
|
|
Allocation
|
|
|
|
(Dollars In Thousands)
|
|
|
|
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
67,348
|
|
|
$
|
7,187
|
|
|
$
|
(735
|
)
|
|
$
|
73,800
|
|
|
31
|
%
|
|
International equity funds
|
|
36,324
|
|
|
11,584
|
|
|
—
|
|
|
47,908
|
|
|
20
|
%
|
|
Core bond fund
|
|
33,381
|
|
|
—
|
|
|
(131
|
)
|
|
33,250
|
|
|
14
|
%
|
|
High-yield bond fund
|
|
17,989
|
|
|
100
|
|
|
—
|
|
|
18,089
|
|
|
8
|
%
|
|
Emerging markets bond fund
|
|
17,449
|
|
|
—
|
|
|
(104
|
)
|
|
17,345
|
|
|
7
|
%
|
|
Combination debt/equity/other fund
|
|
8,311
|
|
|
5,814
|
|
|
—
|
|
|
14,125
|
|
|
6
|
%
|
|
Alternative investments fund
|
|
15,000
|
|
|
6,669
|
|
|
—
|
|
|
21,669
|
|
|
9
|
%
|
|
Real estate securities fund
|
|
9,500
|
|
|
1,306
|
|
|
—
|
|
|
10,806
|
|
|
5
|
%
|
|
Cash equivalents
|
|
110
|
|
|
—
|
|
|
—
|
|
|
110
|
|
|
<1%
|
|
|
Total
|
|
$
|
205,412
|
|
|
$
|
32,660
|
|
|
$
|
(970
|
)
|
|
$
|
237,102
|
|
|
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 markets bond fund
|
|
16,397
|
|
|
—
|
|
|
(1,659
|
)
|
|
14,738
|
|
|
7
|
%
|
|
Combination debt/equity/other fund
|
|
9,171
|
|
|
4,313
|
|
|
—
|
|
|
13,484
|
|
|
7
|
%
|
|
Alternative investments 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
December 31, 2017
and
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 December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
$
|
1,784
|
|
|
$
|
(362
|
)
|
|
$
|
1,871
|
|
|
$
|
(373
|
)
|
|
$
|
3,655
|
|
|
$
|
(735
|
)
|
|
Core bond fund
|
—
|
|
|
—
|
|
|
33,250
|
|
|
(131
|
)
|
|
33,250
|
|
|
(131
|
)
|
|
Emerging markets bond fund
|
17,345
|
|
|
(104
|
)
|
|
—
|
|
|
—
|
|
|
17,345
|
|
|
(104
|
)
|
|
Total
|
$
|
19,129
|
|
|
$
|
(466
|
)
|
|
$
|
35,121
|
|
|
$
|
(504
|
)
|
|
$
|
54,250
|
|
|
$
|
(970
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 fund
|
27,423
|
|
|
(529
|
)
|
|
—
|
|
|
—
|
|
|
27,423
|
|
|
(529
|
)
|
|
High-yield bond fund
|
—
|
|
|
—
|
|
|
18,188
|
|
|
(170
|
)
|
|
18,188
|
|
|
(170
|
)
|
|
Emerging markets bond fund
|
—
|
|
|
—
|
|
|
14,738
|
|
|
(1,659
|
)
|
|
14,738
|
|
|
(1,659
|
)
|
|
Total
|
$
|
29,211
|
|
|
$
|
(648
|
)
|
|
$
|
40,415
|
|
|
$
|
(2,462
|
)
|
|
$
|
69,626
|
|
|
$
|
(3,110
|
)
|
7. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of our property, plant and equipment balance.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Electric plant in service
|
$
|
12,954,247
|
|
|
$
|
11,986,046
|
|
|
Electric plant acquisition adjustment
|
739,037
|
|
|
802,318
|
|
|
Accumulated depreciation
|
(4,651,748
|
)
|
|
(4,404,977
|
)
|
|
|
9,041,536
|
|
|
8,383,387
|
|
|
Construction work in progress
|
434,927
|
|
|
773,095
|
|
|
Nuclear fuel, net
|
71,426
|
|
|
61,952
|
|
|
Plant to be retired, net (a)
|
5,866
|
|
|
29,925
|
|
|
Net property, plant and equipment
|
$
|
9,553,755
|
|
|
$
|
9,248,359
|
|
_______________
(a) Represents the planned retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology. See Note 4, “Rate Matters and Regulation,” for additional information.
The following is a summary of property, plant and equipment of VIEs.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Electric plant of VIEs
|
$
|
392,100
|
|
|
$
|
497,999
|
|
|
Accumulated depreciation of VIEs
|
(215,821
|
)
|
|
(240,095
|
)
|
|
Net property, plant and equipment of VIEs
|
$
|
176,279
|
|
|
$
|
257,904
|
|
We recorded depreciation expense on property, plant and equipment of
$350.0 million
in
2017
,
$316.7 million
in
2016
and
$287.9 million
in
2015
. Approximately
$8.3 million
,
$9.5 million
and
$9.6 million
of depreciation expense in
2017
,
2016
and
2015
, respectively, was attributable to property, plant and equipment of VIEs.
8. JOINT OWNERSHIP OF UTILITY PLANTS
Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income and each owner responsible for its own financing. Information relative to our ownership interests in these facilities as of
December 31, 2017
, is shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant
|
|
In-Service
Dates
|
|
Investment
|
|
Accumulated
Depreciation
|
|
Construction
Work in Progress
|
|
Net
MW
|
|
Ownership
Percentage
|
|
|
|
|
|
(Dollars in Thousands)
|
|
|
|
|
|
La Cygne unit 1 (a)
|
|
June 1973
|
|
$
|
639,265
|
|
|
$
|
171,749
|
|
|
$
|
29,511
|
|
|
368
|
|
|
50
|
|
JEC unit 1 (a)
|
|
July 1978
|
|
843,945
|
|
|
207,358
|
|
|
1,703
|
|
|
670
|
|
|
92
|
|
JEC unit 2 (a)
|
|
May 1980
|
|
577,590
|
|
|
206,041
|
|
|
2,190
|
|
|
672
|
|
|
92
|
|
JEC unit 3 (a)
|
|
May 1983
|
|
740,467
|
|
|
337,941
|
|
|
17,995
|
|
|
659
|
|
|
92
|
|
Wolf Creek (b)
|
|
Sept. 1985
|
|
1,867,487
|
|
|
819,772
|
|
|
90,184
|
|
|
552
|
|
|
47
|
|
State Line (c)
|
|
June 2001
|
|
112,679
|
|
|
66,858
|
|
|
454
|
|
|
196
|
|
|
40
|
|
Total
|
|
|
|
$
|
4,781,433
|
|
|
$
|
1,809,719
|
|
|
$
|
142,037
|
|
|
3,117
|
|
|
|
_______________
|
|
|
|
(a)
|
Jointly owned with Kansas City Power & Light Company (KCPL). Our
8%
leasehold interest in Jeffrey Energy Center (JEC) is reflected in the net megawatts (MW) and ownership percentage provided above.
|
|
|
|
|
(b)
|
Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
|
(c) Jointly owned with Empire District Electric Company.
We include in operating expenses on our consolidated statements of income our share of operating expenses of the above plants. Our share of fuel expense for the above plants is generally based on the amount of power we take from the respective plants. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.
In addition, we consolidate a VIE that holds our
50%
leasehold interest in La Cygne unit 2, which represents
331
MW of net capacity. The VIE’s investment in the
50%
interest was
$392.1 million
and accumulated depreciation was
$215.8 million
as of
December 31, 2017
. We include these amounts in property, plant and equipment of VIEs, net on our consolidated balance sheets. See Note 18, “Variable Interest Entities,” for additional information about VIEs.
9. SHORT-TERM DEBT
In
December 2017
, Westar Energy extended the term of the
$270.0 million
revolving credit facility to terminate in
February 2019
. So long as there is no default under the facility, Westar Energy may increase the aggregate amount of borrowings under the facility to
$400.0 million
, subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of
December 31, 2017
and
2016
, Westar Energy had
no
borrowed amounts or letters of credit outstanding under this revolving credit facility.
In
September 2015
, Westar Energy extended the term of its
$730.0 million
revolving credit facility to terminate in
September 2019
,
$20.7 million
of which expired in September 2017. As long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to
$1.0 billion
, both subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of
December 31, 2017
,
no
amounts had been borrowed and
$11.8 million
of letters of credit had been issued under this revolving credit facility. As of
December 31, 2016
,
no
amounts had been borrowed and
$12.3 million
of letters of credit had been issued under this revolving credit facility.
Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of
$1.0 billion
.
This program is supported by and cannot exceed the capacity under Westar Energy’s revolving credit facilities. Maturities of commercial paper issuances may not exceed
365
days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes.
Westar Energy had
$275.7 million
and
$366.7 million
of commercial paper issued and outstanding as of
December 31, 2017
and
2016
, respectively.
In addition, total combined borrowings under Westar Energy’s commercial paper program and revolving credit facilities may not exceed
$1.0 billion
at any given time. The weighted average interest rate on short-term borrowings outstanding as of
December 31, 2017
and
2016
, was
1.83%
and
0.96%
, respectively. Additional information regarding our short-term debt is as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
|
(Dollars in Thousands)
|
|
Weighted average short-term debt outstanding
|
$
|
306,245
|
|
|
$
|
284,700
|
|
|
Weighted daily average interest rates, excluding fees
|
1.29
|
%
|
|
0.78
|
%
|
Our interest expense on short-term debt was
$5.2 million
in
2017
,
$3.6 million
in
2016
and
$3.0 million
in
2015
.
10. LONG-TERM DEBT
Outstanding Debt
The following table summarizes our long-term debt outstanding.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Westar Energy
|
|
|
|
|
First mortgage bond series:
|
|
|
|
|
5.15% due 2017
|
$
|
—
|
|
|
$
|
125,000
|
|
|
5.10% due 2020
|
250,000
|
|
|
250,000
|
|
|
3.25% due 2025
|
250,000
|
|
|
250,000
|
|
|
2.55% due 2026
|
350,000
|
|
|
350,000
|
|
|
3.10% due 2027
|
300,000
|
|
|
—
|
|
|
4.125% due 2042
|
550,000
|
|
|
550,000
|
|
|
4.10% due 2043
|
430,000
|
|
|
430,000
|
|
|
4.625% due 2043
|
250,000
|
|
|
250,000
|
|
|
4.25% due 2045
|
300,000
|
|
|
300,000
|
|
|
|
2,680,000
|
|
|
2,505,000
|
|
|
Pollution control bond series:
|
|
|
|
|
Variable due 2032, 1.92% as of December 31, 2017; 1.14% as of December 31, 2016
|
45,000
|
|
|
45,000
|
|
|
Variable due 2032, 1.94% as of December 31, 2017; 1.32% as of December 31, 2016
|
30,500
|
|
|
30,500
|
|
|
|
75,500
|
|
|
75,500
|
|
|
|
|
|
|
|
KGE
|
|
|
|
|
First mortgage bond series:
|
|
|
|
|
6.70% due 2019
|
300,000
|
|
|
300,000
|
|
|
6.15% due 2023
|
50,000
|
|
|
50,000
|
|
|
6.53% due 2037
|
175,000
|
|
|
175,000
|
|
|
6.64% due 2038
|
100,000
|
|
|
100,000
|
|
|
4.30% due 2044
|
250,000
|
|
|
250,000
|
|
|
|
875,000
|
|
|
875,000
|
|
|
Pollution control bond series:
|
|
|
|
|
Variable due 2027, 2.00% as of December 31, 2017; 1.46% as of December 31, 2016
|
21,940
|
|
|
21,940
|
|
|
2.50% due 2031
|
50,000
|
|
|
50,000
|
|
|
Variable due 2032, 2.00% as of December 31, 2017; 1.46% as of December 31, 2016
|
14,500
|
|
|
14,500
|
|
|
Variable due 2032, 2.00% as of December 31, 2017; 1.46% as of December 31, 2016
|
10,000
|
|
|
10,000
|
|
|
|
96,440
|
|
|
96,440
|
|
|
|
|
|
|
|
Total long-term debt
|
3,726,940
|
|
|
3,551,940
|
|
|
Unamortized debt discount (a)
|
(10,925
|
)
|
|
(10,358
|
)
|
|
Unamortized debt issuance expense (a)
|
(28,460
|
)
|
|
(27,912
|
)
|
|
Long-term debt due within one year
|
—
|
|
|
(125,000
|
)
|
|
Long-term debt, net
|
$
|
3,687,555
|
|
|
$
|
3,388,670
|
|
|
|
|
|
|
|
Variable Interest Entities
|
|
|
|
|
5.92% due 2019 (b)
|
$
|
—
|
|
|
$
|
1,157
|
|
|
2.398% due 2021 (b)
|
109,967
|
|
|
136,805
|
|
|
Total long-term debt of variable interest entities
|
109,967
|
|
|
137,962
|
|
|
Unamortized debt premium (a)
|
—
|
|
|
89
|
|
|
Long-term debt of variable interest entities due within one year
|
(28,534
|
)
|
|
(26,842
|
)
|
|
Long-term debt of variable interest entities, net
|
$
|
81,433
|
|
|
$
|
111,209
|
|
_______________
(a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.
(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.
The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds (FMBs) that could be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.
The amount of Westar Energy FMBs authorized by its Mortgage and Deed of Trust, dated
July 1, 1939
, as supplemented, is subject to certain limitations as described below. The amount of KGE FMBs authorized by the KGE Mortgage and Deed of Trust, dated
April 1, 1940
, as supplemented and amended, is limited to a maximum of
$3.5 billion
, unless amended further. FMBs are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. As of
December 31, 2017
, approximately
$929.7 million
principal amount of additional FMBs could be issued under the most restrictive provisions in Westar Energy’s mortgage. As of
December 31, 2017
, approximately
$1.5 billion
principal amount of additional KGE FMBs could be issued under the most restrictive provisions in KGE’s mortgage.
As of
December 31, 2017
, we had
$121.9 million
of variable rate, tax-exempt bonds outstanding.
While the interest rates for these bonds have been low, we continue to monitor the credit markets and evaluate our options with respect to these bonds.
In March 2017, Westar Energy issued
$300.0 million
in principal amount of FMBs bearing a stated interest at
3.10%
maturing April 2027.
In January 2017, Westar Energy retired
$125.0 million
in principal amount of FMBs bearing a stated interest at
5.15%
maturing January 2017.
In June 2016, Westar Energy issued
$350.0 million
in principal amount of FMBs bearing a stated interest at
2.55%
and maturing July 2026. The bonds were issued as “Green Bonds,” and all proceeds from the bonds were used in renewable energy projects, primarily the construction of the Western Plains Wind Farm.
Also in June 2016, KGE redeemed and reissued
$50.0 million
in principal amount pollution control bonds maturing June 2031. The stated rate of the bonds was reduced from
4.85%
to
2.50%
.
In February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a redemption and reissuance of
$162.1 million
in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from
5.647%
to
2.398%
. See Note 18, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.
With the exception of Green Bonds, proceeds from issuances were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.
Maturities
The principal amounts of our long-term debt maturities as of
December 31, 2017
, are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Long-term debt
|
|
Long-term
debt of VIEs
|
|
|
|
(In Thousands)
|
|
2018
|
|
$
|
—
|
|
|
$
|
28,534
|
|
|
2019
|
|
300,000
|
|
|
30,337
|
|
|
2020
|
|
250,000
|
|
|
32,254
|
|
|
2021
|
|
—
|
|
|
18,842
|
|
|
2022
|
|
—
|
|
|
—
|
|
|
Thereafter
|
|
3,176,940
|
|
|
—
|
|
|
Total maturities
|
|
$
|
3,726,940
|
|
|
$
|
109,967
|
|
Interest expense on long-term debt, net of debt AFUDC, was
$151.7 million
in
2017
,
$141.4 million
in
2016
and
$152.7 million
in
2015
. Interest expense on long-term debt of VIEs was
$2.8 million
in
2017
,
$4.2 million
in
2016
and
$9.8 million
in
2015
.
11. TAXES
Income tax expense is comprised of the following components.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
|
Income Tax Expense (Benefit):
|
|
|
|
|
|
|
Current income taxes:
|
|
|
|
|
|
|
Federal
|
$
|
126
|
|
|
$
|
(1,007
|
)
|
|
$
|
327
|
|
|
State
|
359
|
|
|
318
|
|
|
341
|
|
|
Deferred income taxes:
|
|
|
|
|
|
|
Federal
|
122,757
|
|
|
155,230
|
|
|
124,891
|
|
|
State
|
30,675
|
|
|
32,892
|
|
|
29,484
|
|
|
Investment tax credit amortization
|
(2,762
|
)
|
|
(2,893
|
)
|
|
(3,043
|
)
|
|
Income tax expense
|
$
|
151,155
|
|
|
$
|
184,540
|
|
|
$
|
152,000
|
|
The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Deferred tax assets:
|
|
|
|
|
Tax credit carryforward (a)
|
$
|
323,518
|
|
|
$
|
265,750
|
|
|
Income taxes refundable to customers, net
|
230,348
|
|
|
—
|
|
|
Deferred employee benefit costs
|
95,913
|
|
|
137,337
|
|
|
Net operating loss carryforward (b)
|
70,041
|
|
|
86,693
|
|
|
Deferred state income taxes
|
63,838
|
|
|
73,294
|
|
|
Alternative minimum tax carryforward (c)
|
52,187
|
|
|
29,412
|
|
|
Deferred compensation
|
21,600
|
|
|
31,981
|
|
|
Deferred regulatory gain on sale-leaseback
|
17,148
|
|
|
30,868
|
|
|
Accrued liabilities
|
13,193
|
|
|
21,757
|
|
|
La Cygne dismantling costs
|
7,840
|
|
|
10,972
|
|
|
Disallowed costs
|
5,800
|
|
|
9,600
|
|
|
Other
|
45,484
|
|
|
47,200
|
|
|
Total deferred tax assets
|
$
|
946,910
|
|
|
$
|
744,864
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
Plant-related
|
$
|
1,483,276
|
|
|
$
|
1,925,270
|
|
|
Deferred employee benefit costs
|
95,913
|
|
|
137,337
|
|
|
Acquisition premium
|
76,574
|
|
|
147,868
|
|
|
Deferred state income taxes
|
46,940
|
|
|
61,110
|
|
|
Debt reacquisition costs
|
26,539
|
|
|
41,753
|
|
|
Amounts due from customers for future income taxes, net
|
—
|
|
|
124,020
|
|
|
Other
|
33,411
|
|
|
60,282
|
|
|
Total deferred tax liabilities
|
$
|
1,762,653
|
|
|
$
|
2,497,640
|
|
|
|
|
|
|
|
Net deferred income tax liabilities
|
$
|
815,743
|
|
|
$
|
1,752,776
|
|
_______________
|
|
|
|
(a)
|
Based on filed tax returns and amounts expected to be reported in current year tax returns (
December 31, 2017
), we had available federal general business tax credits of
$100.0 million
and state investment tax credits of
$223.5 million
. The federal general business tax credits were primarily generated from production tax credits. These tax credits expire beginning in
2020
and ending in
2037
. The state investment tax credits expire beginning in
2024
and ending in
2033
.
|
|
|
|
|
(b)
|
As of
December 31, 2017
, we had a federal net operating loss carryforward of
$181.1 million
, which is available to offset federal taxable income and a state net operating loss of
$470.4 million
, which is available to offset state taxable income. The federal net operating losses will expire beginning in
2032
and ending in
2036
and the state net operating losses will expire beginning in
2020
and ending in
2027
.
|
|
|
|
|
(c)
|
As of
December 31, 2017
, we had available an alternative minimum tax credit carryforward of
$52.2 million
. This credit is refundable by tax year
2021
, if not fully utilized.
|
The TCJA, which was signed into law in December 2017, significantly reforms the IRC and is generally effective January 1, 2018. The TCJA contains significant changes to federal corporate income taxation, including, in general and among other things, a federal corporate income tax rate decrease from
35%
to
21%
effective for tax years beginning after December 31, 2017, limiting the deduction for net operating losses, eliminating net operating loss carrybacks for losses after 2017 and eliminating our use of bonus depreciation on new capital investments. As a result, we decreased deferred income tax liabilities by approximately
$1.0 billion
and made corresponding adjustments to regulatory assets and regulatory liabilities. In addition, in 2017 we decreased non-regulated net deferred income tax assets by approximately
$12.2 million
and correspondingly recorded an increase in income tax expense, which increased our effective tax rate by
2.5%
.
We have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers in earlier periods when corporate income tax rates were higher than current income tax rates under the TCJA. Most of this regulatory liability is related to depreciation and will be returned to the customer through lower rates over the life of the applicable property. Also, in accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions, thereby passing on these benefits to customers at the time we received them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset for these amounts, which is offset against the regulatory liability. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided.
Our effective income tax rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective income tax rates and the federal statutory income tax rates are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
Statutory federal income tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
|
Effect of:
|
|
|
|
|
|
|
Production tax credits
|
(6.9
|
)
|
|
(1.8
|
)
|
|
(2.1
|
)
|
|
State income taxes
|
4.1
|
|
|
4.0
|
|
|
4.3
|
|
|
COLI policies
|
(3.1
|
)
|
|
(4.2
|
)
|
|
(4.4
|
)
|
|
Federal income tax rate reduction (TCJA)
|
2.5
|
|
|
—
|
|
|
—
|
|
|
Flow through depreciation for plant-related differences
|
2.3
|
|
|
3.1
|
|
|
2.6
|
|
|
Non-controlling interest
|
(0.9
|
)
|
|
(0.9
|
)
|
|
(0.8
|
)
|
|
Share based payments
|
(0.9
|
)
|
|
(0.5
|
)
|
|
(0.1
|
)
|
|
Amortization of federal investment tax credits
|
(0.6
|
)
|
|
(0.5
|
)
|
|
(0.7
|
)
|
|
AFUDC equity
|
(0.2
|
)
|
|
(0.8
|
)
|
|
(0.2
|
)
|
|
Other
|
(0.3
|
)
|
|
0.4
|
|
|
(0.1
|
)
|
|
Effective income tax rate
|
31.0
|
%
|
|
33.8
|
%
|
|
33.5
|
%
|
We file income tax returns in the U.S. federal jurisdiction as well as various state jurisdictions. The income tax returns we file will likely be audited by the Internal Revenue Service (IRS) or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year
2014
and forward.
The unrecognized income tax benefits decreased from
$2.8 million
at
December 31, 2016
, to
$1.7 million
at
December 31, 2017
. The net decrease for unrecognized income tax benefits was primarily attributable to tax positions expected to be taken with respect to potential deductions related to an environmental settlement agreement. We do not expect significant changes in the unrecognized income tax benefits in the next
12
months. A reconciliation of the beginning and ending amounts of unrecognized income tax benefits is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
|
Unrecognized income tax benefits as of January 1
|
$
|
2,766
|
|
|
$
|
2,901
|
|
|
$
|
3,188
|
|
|
Additions based on tax positions related to the current year
|
165
|
|
|
434
|
|
|
410
|
|
|
Additions for tax positions of prior years
|
20
|
|
|
—
|
|
|
—
|
|
|
Reductions for tax positions of prior years
|
(870
|
)
|
|
(1
|
)
|
|
(86
|
)
|
|
Lapse of statute of limitations
|
(361
|
)
|
|
(568
|
)
|
|
(611
|
)
|
|
Unrecognized income tax benefits as of December 31
|
$
|
1,720
|
|
|
$
|
2,766
|
|
|
$
|
2,901
|
|
The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate, were
$1.6 million
,
$2.7 million
and
$2.9 million
(net of tax) as of
December 31, 2017
,
2016
and
2015
, respectively.
Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of
December 31, 2017
and
2016
, we had
$0.1 million
and
no
amounts accrued for interest on our liability related to unrecognized income tax benefits, respectively. We accrued
no
penalties at either
December 31, 2017
or
2016
.
As of
December 31, 2017
and
2016
, we had recorded
$0.4 million
and
$1.5 million
, respectively, for probable assessments of taxes other than income taxes.
12. EMPLOYEE BENEFIT PLANS
Pension and Post-Retirement Benefit Plans
We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. For the majority of our employees, pension benefits are based on years of service and an employee’s compensation during the
60
highest paid consecutive months out of
120
before retirement. Non-union employees hired after
December 31, 2001
, and union employees hired after
December 31, 2011
, are covered by the same defined benefit pension plan; however, their benefits are derived from a cash balance account formula. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain retired executive officers. We have discontinued accruing any future benefits under this non-qualified plan.
The amount we contribute to our pension plan for future periods is not yet known, however, we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.
In addition to providing pension benefits, we provide certain post-retirement health care and life insurance benefits for substantially all retired employees. We accrue and recover in our prices the costs of post-retirement benefits during an employee’s years of service.
As a co-owner of Wolf Creek, KGE is indirectly responsible for
47%
of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. See Note 13, “Wolf Creek Employee Benefit Plans,” for information about Wolf Creek’s benefit plans.
The following tables summarize the status of our pension and post-retirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
As of December 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In Thousands)
|
|
Change in Benefit Obligation:
|
|
|
|
|
|
|
|
|
|
Benefit obligation, beginning of year
|
|
$
|
1,012,024
|
|
|
$
|
965,193
|
|
|
$
|
129,563
|
|
|
$
|
126,284
|
|
|
Service cost
|
|
20,874
|
|
|
18,563
|
|
|
1,084
|
|
|
1,084
|
|
|
Interest cost
|
|
42,482
|
|
|
43,723
|
|
|
5,255
|
|
|
5,571
|
|
|
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
362
|
|
|
395
|
|
|
Benefits paid
|
|
(53,704
|
)
|
|
(63,540
|
)
|
|
(7,614
|
)
|
|
(7,697
|
)
|
|
Actuarial losses
|
|
83,553
|
|
|
51,482
|
|
|
2,899
|
|
|
3,926
|
|
|
Amendments
|
|
—
|
|
|
(3,397
|
)
|
|
—
|
|
|
—
|
|
|
Benefit obligation, end of year (a)
|
|
$
|
1,105,229
|
|
|
$
|
1,012,024
|
|
|
$
|
131,549
|
|
|
$
|
129,563
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Plan Assets:
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets, beginning of year
|
|
$
|
658,474
|
|
|
$
|
653,945
|
|
|
$
|
115,619
|
|
|
$
|
115,416
|
|
|
Actual return on plan assets
|
|
88,030
|
|
|
45,181
|
|
|
15,498
|
|
|
7,274
|
|
|
Employer contributions
|
|
24,300
|
|
|
20,200
|
|
|
—
|
|
|
—
|
|
|
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
327
|
|
|
356
|
|
|
Benefits paid
|
|
(51,472
|
)
|
|
(60,852
|
)
|
|
(7,374
|
)
|
|
(7,427
|
)
|
|
Fair value of plan assets, end of year
|
|
$
|
719,332
|
|
|
$
|
658,474
|
|
|
$
|
124,070
|
|
|
$
|
115,619
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status, end of year
|
|
$
|
(385,897
|
)
|
|
$
|
(353,550
|
)
|
|
$
|
(7,479
|
)
|
|
$
|
(13,944
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in the Balance Sheets Consist of:
|
|
|
|
|
|
|
|
|
|
Current liability
|
|
$
|
(2,223
|
)
|
|
$
|
(2,260
|
)
|
|
$
|
(255
|
)
|
|
$
|
(284
|
)
|
|
Noncurrent liability
|
|
(383,674
|
)
|
|
(351,290
|
)
|
|
(7,224
|
)
|
|
(13,660
|
)
|
|
Net amount recognized
|
|
$
|
(385,897
|
)
|
|
$
|
(353,550
|
)
|
|
$
|
(7,479
|
)
|
|
$
|
(13,944
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in Regulatory Assets (Liabilities) Consist of:
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
|
$
|
299,068
|
|
|
$
|
282,462
|
|
|
$
|
(12,549
|
)
|
|
$
|
(7,603
|
)
|
|
Prior service cost
|
|
3,231
|
|
|
3,913
|
|
|
2,219
|
|
|
2,674
|
|
|
Net amount recognized
|
|
$
|
302,299
|
|
|
$
|
286,375
|
|
|
$
|
(10,330
|
)
|
|
$
|
(4,929
|
)
|
_______________
|
|
|
|
(a)
|
As of December 31, 2017 and 2016, pension benefits include non-qualified benefit obligations of
$27.4 million
and
$26.8 million
, respectively, which are funded by a trust containing assets of
$34.3 million
and
$34.5 million
, respectively, classified as trading securities. The assets in the aforementioned trust are not included in the table above. See Notes 5 and 6, “Financial Instruments and Trading Securities” and “Financial Investments,” respectively, for additional information regarding these amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
As of December 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(Dollars in Thousands)
|
|
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation
|
|
$
|
1,105,229
|
|
|
$
|
1,012,024
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Fair value of plan assets
|
|
719,332
|
|
|
658,474
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
|
|
|
|
|
|
|
|
|
|
Accumulated benefit obligation
|
|
$
|
989,688
|
|
|
$
|
905,661
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Fair value of plan assets
|
|
719,332
|
|
|
658,474
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
|
|
|
|
|
|
|
|
|
|
Accumulated post-retirement benefit obligation
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
131,549
|
|
|
$
|
129,563
|
|
|
Fair value of plan assets
|
|
—
|
|
|
—
|
|
|
124,070
|
|
|
115,619
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
3.73
|
%
|
|
4.25
|
%
|
|
3.68
|
%
|
|
4.15
|
%
|
|
Compensation rate increase
|
|
4.00
|
%
|
|
4.00
|
%
|
|
—
|
|
|
—
|
|
We use a measurement date of
December 31
for our pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The decrease in the discount rates used as of December 31, 2017, increased the pension and post-retirement benefit obligations by approximately
$79.0 million
and
$7.0 million
, respectively.
We amortize prior service cost on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. We amortize the net actuarial gain or loss on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. The KCC allows us to record a regulatory asset or liability to track the cumulative difference between current year pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. We accumulate such regulatory asset or liability between general rate reviews and amortize the accumulated amount as part of resetting our base prices. Following is additional information regarding our pension and post-retirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
|
|
|
(Dollars in Thousands)
|
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
20,874
|
|
|
$
|
18,563
|
|
|
$
|
21,392
|
|
|
$
|
1,084
|
|
|
$
|
1,084
|
|
|
$
|
1,443
|
|
|
Interest cost
|
|
42,482
|
|
|
43,723
|
|
|
43,014
|
|
|
5,255
|
|
|
5,571
|
|
|
5,691
|
|
|
Expected return on plan assets
|
|
(43,039
|
)
|
|
(42,653
|
)
|
|
(40,236
|
)
|
|
(6,873
|
)
|
|
(6,835
|
)
|
|
(6,614
|
)
|
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
682
|
|
|
768
|
|
|
520
|
|
|
455
|
|
|
455
|
|
|
455
|
|
|
Actuarial loss (gain), net
|
|
21,956
|
|
|
20,577
|
|
|
32,131
|
|
|
(780
|
)
|
|
(1,118
|
)
|
|
379
|
|
|
Net periodic cost (benefit) before regulatory adjustment
|
|
42,955
|
|
|
40,978
|
|
|
56,821
|
|
|
(859
|
)
|
|
(843
|
)
|
|
1,354
|
|
|
Regulatory adjustment (a)
|
|
13,425
|
|
|
14,528
|
|
|
6,886
|
|
|
(1,917
|
)
|
|
(1,922
|
)
|
|
4,096
|
|
|
Net periodic cost (benefit)
|
|
$
|
56,380
|
|
|
$
|
55,506
|
|
|
$
|
63,707
|
|
|
$
|
(2,776
|
)
|
|
$
|
(2,765
|
)
|
|
$
|
5,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets and Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year actuarial loss (gain)
|
|
$
|
38,562
|
|
|
$
|
48,954
|
|
|
$
|
(43,459
|
)
|
|
$
|
(5,726
|
)
|
|
$
|
3,486
|
|
|
$
|
(9,576
|
)
|
|
Amortization of actuarial (loss) gain
|
|
(21,956
|
)
|
|
(20,577
|
)
|
|
(32,379
|
)
|
|
780
|
|
|
1,118
|
|
|
(379
|
)
|
|
Current year prior service cost
|
|
—
|
|
|
(3,397
|
)
|
|
5,730
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Amortization of prior service costs
|
|
(682
|
)
|
|
(768
|
)
|
|
(520
|
)
|
|
(455
|
)
|
|
(455
|
)
|
|
(455
|
)
|
|
Other adjustments
|
|
—
|
|
|
—
|
|
|
352
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total recognized in regulatory assets and liabilities
|
|
$
|
15,924
|
|
|
$
|
24,212
|
|
|
$
|
(70,276
|
)
|
|
$
|
(5,401
|
)
|
|
$
|
4,149
|
|
|
$
|
(10,410
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in net periodic cost and regulatory assets and liabilities
|
|
$
|
72,304
|
|
|
$
|
79,718
|
|
|
$
|
(6,569
|
)
|
|
$
|
(8,177
|
)
|
|
$
|
1,384
|
|
|
$
|
(4,960
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
4.25
|
%
|
|
4.60
|
%
|
|
4.17
|
%
|
|
4.15
|
%
|
|
4.51
|
%
|
|
4.10
|
%
|
|
Expected long-term return on plan assets
|
|
6.50
|
%
|
|
6.50
|
%
|
|
6.50
|
%
|
|
6.00
|
%
|
|
6.00
|
%
|
|
6.00
|
%
|
|
Compensation rate increase
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
_______________
|
|
|
|
(a)
|
The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.
|
We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in
2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
Benefits
|
|
Post-retirement
Benefits
|
|
|
(In Thousands)
|
|
Actuarial loss (gain)
|
$
|
25,941
|
|
|
$
|
(539
|
)
|
|
Prior service cost
|
666
|
|
|
455
|
|
|
Total
|
$
|
26,607
|
|
|
$
|
(84
|
)
|
We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. We select assumed projected rates of return for each asset class after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, we develop an overall expected rate of return for the portfolios, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
Plan Assets
We believe we manage pension and post-retirement benefit plan assets in a prudent manner with regard to preserving principal while providing reasonable returns. We have adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of our strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. We delegate the management of our pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by management, which include allowable and/or prohibited investment types. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.
We have established certain prohibited investments for our pension and post-retirement benefit plans. Such prohibited investments include loans to the company or its officers and directors as well as investments in the company’s debt or equity securities, except as may occur indirectly through investments in diversified mutual funds. In addition, to reduce concentration of risk, the pension plan will not invest in any fund that holds more than
25%
of its total assets to be invested in the securities of one or more issuers conducting their principal business activities in the same industry. This restriction does not apply to investments in securities issued or guaranteed by the U.S. government or its agencies.
Target allocations for our pension plan assets are approximately
39%
to debt securities,
39%
to equity securities,
12%
to alternative investments such as real estate securities, hedge funds and private equity investments, and the remaining
10%
to a fund, which provides tactical portfolio overlay by investing in futures related to debt, equity and foreign currency. Our investments in equity include investment funds with underlying investments in domestic and foreign large-, mid- and small-cap companies, derivatives related to such holdings, private equity investments including late-stage venture investments and other investments. Our investments in debt include core and high-yield bonds. Core bonds are comprised of investment funds with underlying investments in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and other debt securities. High-yield bonds include investment funds with underlying investments in non-investment grade debt securities of corporate entities, obligations of foreign governments and their agencies, private debt securities and other debt securities. Real estate securities consist primarily of funds invested in core real estate throughout the U.S. while alternative funds invest in wide ranging investments including equity and debt securities of domestic and foreign corporations, debt securities issued by U.S. and foreign governments and their agencies, structured debt, warrants, exchange-traded funds, derivative instruments, private investment funds and other investments.
Target allocations for our post-retirement benefit plan assets are
65%
to equity securities and
35%
to debt securities. Our investments in equity securities include investment funds with underlying investments primarily in domestic and foreign large-, mid- and small-cap companies. Our investments in debt securities include a core bond fund with underlying investments in investment grade debt securities of domestic and foreign corporate entities, obligations of U.S. and foreign governments and their agencies, private placement securities and other investments.
Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the pension and post-retirement benefits trusts may buy and sell investments resulting in changes within the hierarchy. See Note 5, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.
The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of
December 31, 2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
|
(In Thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
188,850
|
|
|
$
|
—
|
|
|
$
|
23,896
|
|
|
$
|
212,746
|
|
|
International equity fund
|
|
—
|
|
|
98,646
|
|
|
—
|
|
|
—
|
|
|
98,646
|
|
|
Emerging market equity fund
|
|
—
|
|
|
26,804
|
|
|
—
|
|
|
—
|
|
|
26,804
|
|
|
Domestic bond fund
|
|
—
|
|
|
100,687
|
|
|
—
|
|
|
—
|
|
|
100,687
|
|
|
Core bond fund
|
|
—
|
|
|
98,874
|
|
|
—
|
|
|
—
|
|
|
98,874
|
|
|
High-yield bond fund
|
|
—
|
|
|
31,692
|
|
|
—
|
|
|
—
|
|
|
31,692
|
|
|
Emerging market bond fund
|
|
—
|
|
|
25,959
|
|
|
—
|
|
|
—
|
|
|
25,959
|
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
36,167
|
|
|
—
|
|
|
—
|
|
|
36,167
|
|
|
Alternative investment fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48,906
|
|
|
48,906
|
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34,421
|
|
|
34,421
|
|
|
Cash equivalents
|
|
—
|
|
|
4,430
|
|
|
—
|
|
|
—
|
|
|
4,430
|
|
|
Total Assets Measured at Fair Value
|
|
$
|
—
|
|
|
$
|
612,109
|
|
|
$
|
—
|
|
|
$
|
107,223
|
|
|
$
|
719,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
Assets:
|
|
(In Thousands)
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
168,407
|
|
|
$
|
—
|
|
|
$
|
23,580
|
|
|
$
|
191,987
|
|
|
International equity fund
|
|
—
|
|
|
83,738
|
|
|
—
|
|
|
—
|
|
|
83,738
|
|
|
Emerging market equity fund
|
|
—
|
|
|
21,055
|
|
|
—
|
|
|
—
|
|
|
21,055
|
|
|
Domestic bond fund
|
|
—
|
|
|
101,200
|
|
|
—
|
|
|
—
|
|
|
101,200
|
|
|
Core bond fund
|
|
—
|
|
|
86,109
|
|
|
—
|
|
|
—
|
|
|
86,109
|
|
|
High-yield bond fund
|
|
—
|
|
|
30,729
|
|
|
—
|
|
|
—
|
|
|
30,729
|
|
|
Emerging market bond fund
|
|
—
|
|
|
23,584
|
|
|
—
|
|
|
—
|
|
|
23,584
|
|
|
Combination debt/equity/other fund
|
|
—
|
|
|
37,851
|
|
|
—
|
|
|
—
|
|
|
37,851
|
|
|
Alternative investment fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,686
|
|
|
43,686
|
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,390
|
|
|
32,390
|
|
|
Cash equivalents
|
|
—
|
|
|
6,145
|
|
|
—
|
|
|
—
|
|
|
6,145
|
|
|
Total Assets Measured at Fair Value
|
|
$
|
—
|
|
|
$
|
558,818
|
|
|
$
|
—
|
|
|
$
|
99,656
|
|
|
$
|
658,474
|
|
The following table provides the fair value of our post-retirement benefit plan assets and the corresponding level of hierarchy as of
December 31, 2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
|
(In Thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
65,187
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
65,187
|
|
|
International equity fund
|
|
—
|
|
|
16,217
|
|
|
—
|
|
|
—
|
|
|
16,217
|
|
|
Core bond fund
|
|
—
|
|
|
42,083
|
|
|
—
|
|
|
—
|
|
|
42,083
|
|
|
Cash equivalents
|
|
—
|
|
|
583
|
|
|
—
|
|
|
—
|
|
|
583
|
|
|
Total Assets Measured at Fair Value
|
|
$
|
—
|
|
|
$
|
124,070
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
124,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
|
(In Thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
61,055
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
61,055
|
|
|
International equity fund
|
|
—
|
|
|
15,034
|
|
|
—
|
|
|
—
|
|
|
15,034
|
|
|
Core bond fund
|
|
—
|
|
|
38,952
|
|
|
—
|
|
|
—
|
|
|
38,952
|
|
|
Cash equivalents
|
|
—
|
|
|
578
|
|
|
—
|
|
|
—
|
|
|
578
|
|
|
Total Assets Measured at Fair Value
|
|
$
|
—
|
|
|
$
|
115,619
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
115,619
|
|
Cash Flows
The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
|
|
To/(From) Trust
|
|
(From)
Company Assets
|
|
To/(From) Trust
|
|
(From)
Company Assets
|
|
|
|
(In Millions)
|
|
Expected contributions:
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
32.4
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected benefit payments:
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
(57.6
|
)
|
|
$
|
(2.3
|
)
|
|
$
|
(7.9
|
)
|
|
$
|
(0.3
|
)
|
|
2019
|
|
(60.1
|
)
|
|
(2.3
|
)
|
|
(8.0
|
)
|
|
(0.3
|
)
|
|
2020
|
|
(62.8
|
)
|
|
(2.2
|
)
|
|
(8.0
|
)
|
|
(0.2
|
)
|
|
2021
|
|
(65.4
|
)
|
|
(2.2
|
)
|
|
(8.1
|
)
|
|
(0.2
|
)
|
|
2022
|
|
(65.1
|
)
|
|
(2.2
|
)
|
|
(8.1
|
)
|
|
(0.2
|
)
|
|
2023-2027
|
|
(331.5
|
)
|
|
(10.8
|
)
|
|
(38.7
|
)
|
|
(0.9
|
)
|
Savings Plans
We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees’ contributions in cash up to specified maximum limits. Our contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions totaled
$8.3 million
in
2017
,
$8.0 million
in
2016
and
$7.7 million
in
2015
.
Stock-Based Compensation Plans
We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to
8.3 million
shares of common stock may be granted under the LTISA Plan. As of
December 31, 2017
, awards of approximately
5.4 million
shares of common stock had been made under the plan.
All stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as an expense in the consolidated statement of income over the requisite service period. The requisite service periods range from one to four years. However, upon consummation of the merger, all unrecognized compensation costs for outstanding RSU awards will be expensed on our income statement. The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
|
Compensation expense
|
$
|
8,869
|
|
|
$
|
9,237
|
|
|
$
|
8,250
|
|
|
Income tax benefits related to stock-based compensation arrangements
|
3,508
|
|
|
3,653
|
|
|
3,263
|
|
We use RSU awards for our stock-based compensation awards. RSU awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined as nonvested shares and do not include restrictions once the awards have vested.
RSU awards with only service requirements vest solely upon the passage of time. We measure the fair value of these RSU awards based on the market price of the underlying common stock as of the grant date. RSU awards with only service conditions that have a graded vesting schedule are recognized as an expense in the consolidated statement of income on a straight-line basis over the requisite service period for the entire award. Nonforfeitable dividend equivalents, or the rights to receive cash equal to the value of dividends paid on Westar Energy’s common stock, are paid on these RSUs during the vesting period. Nonforfeitable dividend equivalents are recorded directly to retained earnings.
RSU awards with performance measures vest upon expiration of the award term. The number of shares of common stock awarded upon vesting will vary from
0%
to
200%
of the RSU award, with performance tied to our total shareholder return relative to the total shareholder return of our peer group. We measure the fair value of these RSU awards using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of the expected volatility and risk-free interest rates. Expected volatility is based on historical volatility over three years using daily stock price observations. The risk-free interest rate is based on treasury constant maturity yields as reported by the Federal Reserve and the length of the performance period. For the
2017
valuation, inputs for expected volatility ranged from
17.6%
to
22.7%
and the risk-free interest rate was approximately
1.5%
. For the
2016
valuation, inputs for expected volatility ranged from
16.9%
to
22.4%
and the risk-free interest rate was approximately
0.9%
. For these RSU awards, dividend equivalents accumulate over the vesting period and are paid in cash based on the number of shares of common stock awarded upon vesting.
During the years ended
December 31, 2017
,
2016
and
2015
, our RSU activity for awards with only service requirements was as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
|
|
|
(Shares In Thousands)
|
|
Nonvested balance, beginning of year
|
289.4
|
|
|
$
|
40.11
|
|
|
309.9
|
|
|
$
|
35.21
|
|
|
342.2
|
|
|
$
|
31.38
|
|
|
Granted
|
79.8
|
|
|
53.25
|
|
|
99.3
|
|
|
46.35
|
|
|
115.7
|
|
|
39.50
|
|
|
Vested
|
(109.4
|
)
|
|
35.56
|
|
|
(115.9
|
)
|
|
32.33
|
|
|
(115.4
|
)
|
|
28.77
|
|
|
Forfeited
|
(3.8
|
)
|
|
44.08
|
|
|
(3.9
|
)
|
|
40.95
|
|
|
(32.6
|
)
|
|
33.07
|
|
|
Nonvested balance, end of year
|
256.0
|
|
|
46.09
|
|
|
289.4
|
|
|
40.11
|
|
|
309.9
|
|
|
35.21
|
|
Total unrecognized compensation cost related to RSU awards with only service requirements was
$4.7 million
and
$5.0 million
as of
December 31, 2017
and
2016
, respectively. Absent the merger, we expect to recognize these costs over a remaining weighted-average period of
1.7
years. The total fair value of RSUs with only service requirements that vested during the years ended
December 31, 2017
,
2016
and
2015
, was
$6.1 million
,
$5.2 million
and
$4.7 million
, respectively.
During the years ended
December 31, 2017
,
2016
and
2015
, our RSU activity for awards with performance measures was as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
|
|
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
|
|
|
(Shares In Thousands)
|
|
Nonvested balance, beginning of year
|
297.7
|
|
|
$
|
40.79
|
|
|
299.1
|
|
|
$
|
36.00
|
|
|
345.1
|
|
|
$
|
32.31
|
|
|
Granted
|
76.4
|
|
|
37.08
|
|
|
100.9
|
|
|
46.03
|
|
|
94.8
|
|
|
40.26
|
|
|
Vested
|
(106.7
|
)
|
|
36.38
|
|
|
(98.5
|
)
|
|
31.59
|
|
|
(109.0
|
)
|
|
28.99
|
|
|
Forfeited
|
(2.0
|
)
|
|
42.16
|
|
|
(3.8
|
)
|
|
41.57
|
|
|
(31.8
|
)
|
|
34.03
|
|
|
Nonvested balance, end of year
|
265.4
|
|
|
41.48
|
|
|
297.7
|
|
|
40.79
|
|
|
299.1
|
|
|
36.00
|
|
As of
December 31, 2017
and
2016
, total unrecognized compensation cost related to RSU awards with performance measures was
$3.6 million
and
$4.5 million
, respectively. Absent the merger, we expect to recognize these costs over a remaining weighted-average period of
1.6
years. The total fair value of RSUs with performance measures that vested during the years ended
December 31, 2017
,
2016
and
2015
, was
$12.0 million
,
$7.5 million
and
$3.1 million
, respectively.
Another component of the LTISA Plan is the Executive Stock for Compensation program under which, in the past, eligible employees were entitled to receive deferred common stock in lieu of current cash compensation. Although this plan was discontinued in
2001
, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. Plan participants were awarded
124
shares of common stock for dividends in
2017
,
170
shares in
2016
and
296
shares in
2015
. Participants received common stock distributions of
1,325
shares in
2017
,
2,110
shares in
2016
and
2,024
shares in
2015
.
13. WOLF CREEK EMPLOYEE BENEFIT PLANS
Pension and Post-Retirement Benefit Plans
As a co-owner of Wolf Creek, KGE is indirectly responsible for
47%
of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. KGE accrues its
47%
share of Wolf Creek’s cost of pension and post-retirement benefits during the years an employee provides service. The following tables summarize the status of KGE’s
47%
share of the Wolf Creek pension and post-retirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
As of December 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(In Thousands)
|
|
Change in Benefit Obligation:
|
|
|
|
|
|
|
|
|
|
Benefit obligation, beginning of year
|
|
$
|
229,025
|
|
|
$
|
206,418
|
|
|
$
|
7,215
|
|
|
$
|
7,793
|
|
|
Service cost
|
|
7,800
|
|
|
6,748
|
|
|
146
|
|
|
127
|
|
|
Interest cost
|
|
9,900
|
|
|
9,655
|
|
|
280
|
|
|
325
|
|
|
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
1,096
|
|
|
989
|
|
|
Benefits paid
|
|
(8,381
|
)
|
|
(6,974
|
)
|
|
(1,623
|
)
|
|
(1,531
|
)
|
|
Actuarial losses (gains)
|
|
23,423
|
|
|
13,178
|
|
|
(99
|
)
|
|
(488
|
)
|
|
Benefit obligation, end of year
|
|
$
|
261,767
|
|
|
$
|
229,025
|
|
|
$
|
7,015
|
|
|
$
|
7,215
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Plan Assets:
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets, beginning of year
|
|
$
|
138,688
|
|
|
$
|
121,622
|
|
|
$
|
17
|
|
|
$
|
105
|
|
|
Actual return on plan assets
|
|
25,053
|
|
|
8,967
|
|
|
46
|
|
|
(4
|
)
|
|
Employer contributions
|
|
12,047
|
|
|
14,820
|
|
|
466
|
|
|
458
|
|
|
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
1,096
|
|
|
989
|
|
|
Benefits paid
|
|
(8,128
|
)
|
|
(6,721
|
)
|
|
(1,623
|
)
|
|
(1,531
|
)
|
|
Fair value of plan assets, end of year
|
|
$
|
167,660
|
|
|
$
|
138,688
|
|
|
$
|
2
|
|
|
$
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status, end of year
|
|
$
|
(94,107
|
)
|
|
$
|
(90,337
|
)
|
|
$
|
(7,013
|
)
|
|
$
|
(7,198
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in the Balance Sheets Consist of:
|
|
|
|
|
|
|
|
|
|
Current liability
|
|
$
|
(271
|
)
|
|
$
|
(248
|
)
|
|
$
|
(552
|
)
|
|
$
|
(538
|
)
|
|
Noncurrent liability
|
|
(93,836
|
)
|
|
(90,089
|
)
|
|
(6,461
|
)
|
|
(6,660
|
)
|
|
Net amount recognized
|
|
$
|
(94,107
|
)
|
|
$
|
(90,337
|
)
|
|
$
|
(7,013
|
)
|
|
$
|
(7,198
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in Regulatory Assets (Liabilities) Consist of:
|
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
|
$
|
69,895
|
|
|
$
|
66,324
|
|
|
$
|
(748
|
)
|
|
$
|
(654
|
)
|
|
Prior service cost
|
|
391
|
|
|
446
|
|
|
—
|
|
|
—
|
|
|
Net amount recognized
|
|
$
|
70,286
|
|
|
$
|
66,770
|
|
|
$
|
(748
|
)
|
|
$
|
(654
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
As of December 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
(Dollars in Thousands)
|
|
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation
|
|
$
|
261,767
|
|
|
$
|
229,025
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Fair value of plan assets
|
|
167,660
|
|
|
138,688
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
|
|
|
|
|
|
|
|
|
|
Accumulated benefit obligation
|
|
$
|
229,883
|
|
|
$
|
201,963
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Fair value of plan assets
|
|
167,660
|
|
|
138,688
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
|
|
|
|
|
|
|
|
|
|
Accumulated post-retirement benefit obligation
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,015
|
|
|
$
|
7,215
|
|
|
Fair value of plan assets
|
|
—
|
|
|
—
|
|
|
2
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
3.73
|
%
|
|
4.26
|
%
|
|
3.56
|
%
|
|
3.95
|
%
|
|
Compensation rate increase
|
|
4.00
|
%
|
|
4.00
|
%
|
|
—
|
%
|
|
—
|
%
|
Wolf Creek uses a measurement date of
December 31
for its pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The decrease in the discount rates used as of December 31, 2017, increased Wolf Creek’s pension and post-retirement benefit obligations by approximately
$19.5 million
and
$0.2 million
, respectively.
The prior service cost is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain or loss is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. Following is additional information regarding KGE’s
47%
share of the Wolf Creek pension and other post-retirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
|
|
|
(Dollars in Thousands)
|
|
Components of Net Periodic Cost (Benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
7,800
|
|
|
$
|
6,748
|
|
|
$
|
7,595
|
|
|
$
|
146
|
|
|
$
|
127
|
|
|
$
|
138
|
|
|
Interest cost
|
|
9,900
|
|
|
9,655
|
|
|
9,016
|
|
|
280
|
|
|
325
|
|
|
314
|
|
|
Expected return on plan assets
|
|
(10,571
|
)
|
|
(9,722
|
)
|
|
(9,044
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Amortization of unrecognized:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
55
|
|
|
55
|
|
|
57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Actuarial loss (gain), net
|
|
4,979
|
|
|
4,357
|
|
|
5,930
|
|
|
(50
|
)
|
|
(14
|
)
|
|
3
|
|
|
Curtailments, settlements, and special termination benefits
|
|
390
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net periodic cost before regulatory adjustment
|
|
12,553
|
|
|
11,093
|
|
|
13,554
|
|
|
376
|
|
|
438
|
|
|
455
|
|
|
Regulatory adjustment (a)
|
|
1,083
|
|
|
1,886
|
|
|
(1,485
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net periodic cost
|
|
$
|
13,636
|
|
|
$
|
12,979
|
|
|
$
|
12,069
|
|
|
$
|
376
|
|
|
$
|
438
|
|
|
$
|
455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets and Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year actuarial loss (gain)
|
|
$
|
8,550
|
|
|
$
|
13,934
|
|
|
$
|
(2,373
|
)
|
|
$
|
(145
|
)
|
|
$
|
(484
|
)
|
|
$
|
(211
|
)
|
|
Amortization of actuarial (gain) loss
|
|
(4,979
|
)
|
|
(4,357
|
)
|
|
(5,930
|
)
|
|
50
|
|
|
14
|
|
|
(3
|
)
|
|
Amortization of prior service cost
|
|
(55
|
)
|
|
(55
|
)
|
|
(57
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total recognized in regulatory assets and liabilities
|
|
$
|
3,516
|
|
|
$
|
9,522
|
|
|
$
|
(8,360
|
)
|
|
$
|
(95
|
)
|
|
$
|
(470
|
)
|
|
$
|
(214
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in net periodic cost and regulatory assets and liabilities
|
|
$
|
17,152
|
|
|
$
|
22,501
|
|
|
$
|
3,709
|
|
|
$
|
281
|
|
|
$
|
(32
|
)
|
|
$
|
241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
4.26
|
%
|
|
4.61
|
%
|
|
4.20
|
%
|
|
3.95
|
%
|
|
4.27
|
%
|
|
3.89
|
%
|
|
Expected long-term return on plan assets
|
|
7.25
|
%
|
|
7.50
|
%
|
|
7.50
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
Compensation rate increase
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
_______________
|
|
|
|
(a)
|
The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.
|
We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in
2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
Benefits
|
|
Post-retirement
Benefits
|
|
|
(In Thousands)
|
|
Actuarial loss (gain)
|
$
|
6,624
|
|
|
$
|
(58
|
)
|
|
Prior service cost
|
55
|
|
|
—
|
|
|
Total
|
$
|
6,679
|
|
|
$
|
(58
|
)
|
The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolios was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
For measurement purposes, the assumed annual health care cost growth rates were as follows.
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
Health care cost trend rate assumed for next year
|
6.0
|
%
|
|
6.5
|
%
|
|
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)
|
5.0
|
%
|
|
5.0
|
%
|
|
|
|
|
|
|
Year that the rate reaches the ultimate trend rate
|
2020
|
|
|
2020
|
|
The health care cost trend rate affects the projected benefit obligation. A
1%
change in assumed health care cost growth rates would have effects shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
One-Percentage-
Point Increase
|
|
One-Percentage-
Point Decrease
|
|
|
(In Thousands)
|
|
Effect on total of service and interest cost
|
$
|
(9
|
)
|
|
$
|
10
|
|
|
Effect on post-retirement benefit obligation
|
(133
|
)
|
|
142
|
|
Plan Assets
Wolf Creek’s pension and post-retirement plan investment strategy is to manage assets in a prudent manner with regard to preserving principal while providing reasonable returns. It has adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of its strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. Wolf Creek delegates the management of its pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.
The target allocations for Wolf Creek’s pension plan assets are
31%
to international equity securities,
25%
to domestic equity securities,
25%
to debt securities,
10%
to real estate securities,
5%
to commodity investments and
4%
to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies and investment funds with underlying investments similar to those previously mentioned. The investments in debt include core and high-yield bonds. Core bonds include funds invested in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and private debt securities. High-yield bonds include a fund with underlying investments in non-investment grade debt securities of corporate entities, private placements and bank debt. Real estate securities include funds invested in commercial and residential real estate properties while commodity investments include funds invested in commodity-related instruments.
Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the Wolf Creek pension trust may buy and sell investments resulting in changes within the hierarchy. See Note 5, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.
The following table provides the fair value of KGE’s
47%
share of Wolf Creek’s pension plan assets and the corresponding level of hierarchy as of
December 31, 2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
|
(In Thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
43,396
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
43,396
|
|
|
International equity funds
|
|
—
|
|
|
52,485
|
|
|
—
|
|
|
—
|
|
|
52,485
|
|
|
Core bond funds
|
|
—
|
|
|
42,304
|
|
|
—
|
|
|
—
|
|
|
42,304
|
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,415
|
|
|
7,415
|
|
|
Alternative investment fund
|
|
—
|
|
|
16,988
|
|
|
—
|
|
|
4,369
|
|
|
21,357
|
|
|
Cash equivalents
|
|
—
|
|
|
703
|
|
|
—
|
|
|
—
|
|
|
703
|
|
|
Total Assets Measured at Fair Value
|
|
$
|
—
|
|
|
$
|
155,876
|
|
|
$
|
—
|
|
|
$
|
11,784
|
|
|
$
|
167,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
|
|
|
(In Thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity funds
|
|
$
|
—
|
|
|
$
|
34,586
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
34,586
|
|
|
International equity funds
|
|
—
|
|
|
43,269
|
|
|
—
|
|
|
—
|
|
|
43,269
|
|
|
Core bond funds
|
|
—
|
|
|
35,048
|
|
|
—
|
|
|
—
|
|
|
35,048
|
|
|
Real estate securities fund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,948
|
|
|
6,948
|
|
|
Alternative investment fund
|
|
—
|
|
|
14,073
|
|
|
—
|
|
|
4,164
|
|
|
18,237
|
|
|
Cash equivalents
|
|
—
|
|
|
600
|
|
|
—
|
|
|
—
|
|
|
600
|
|
|
Total Assets Measured at Fair Value
|
|
$
|
—
|
|
|
$
|
127,576
|
|
|
$
|
—
|
|
|
$
|
11,112
|
|
|
$
|
138,688
|
|
Cash Flows
The following table shows our expected cash flows for KGE’s
47%
share of Wolf Creek’s pension and post-retirement benefit plans for future years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Cash Flows
|
|
Pension Benefits
|
|
Post-retirement Benefits
|
|
|
|
To/(From) Trust
|
|
(From)
Company Assets
|
|
To/(From) Trust
|
|
(From)
Company Assets
|
|
|
|
(In Millions)
|
|
Expected contributions:
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
8.9
|
|
|
|
|
$
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected benefit payments:
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
(8.0
|
)
|
|
$
|
(0.3
|
)
|
|
$
|
(2.0
|
)
|
|
$
|
—
|
|
|
2019
|
|
(9.0
|
)
|
|
(0.3
|
)
|
|
(2.3
|
)
|
|
—
|
|
|
2020
|
|
(9.9
|
)
|
|
(0.3
|
)
|
|
(2.6
|
)
|
|
—
|
|
|
2021
|
|
(10.8
|
)
|
|
(0.3
|
)
|
|
(2.9
|
)
|
|
—
|
|
|
2022
|
|
(11.7
|
)
|
|
(0.3
|
)
|
|
(3.2
|
)
|
|
—
|
|
|
2023 - 2027
|
|
(70.7
|
)
|
|
(1.9
|
)
|
|
(19.7
|
)
|
|
—
|
|
Savings Plan
Wolf Creek maintains a qualified 401(k) savings plan in which most of its employees participate. Wolf Creek matches employees’ contributions in cash up to specified maximum limits. Wolf Creek’s contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives provided under the plan. KGE’s portion of the expense associated with Wolf Creek’s matching contributions was
$1.4 million
in
2017
,
$1.6 million
in
2016
and
$1.6 million
in
2015
.
14. COMMITMENTS AND CONTINGENCIES
Purchase Orders and Contracts
As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under “—Fuel and Purchased Power Commitments.” These commitments relate to purchase obligations issued and outstanding at year-end.
The yearly detail of the aggregate amount of required payments as of
December 31, 2017
, was as follows.
|
|
|
|
|
|
|
|
|
Committed
Amount
|
|
|
(In Thousands)
|
|
2018
|
$
|
257,544
|
|
|
2019
|
17,787
|
|
|
2020
|
4,842
|
|
|
Thereafter
|
3,172
|
|
|
Total amount committed
|
$
|
283,345
|
|
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.
Federal Clean Air Act
We must comply with the federal Clean Air Act (CAA), state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (SO
2
), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.
Emissions from our generating facilities, including PM, SO
2
and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze.
Sulfur Dioxide and Nitrogen Oxide
Through the combustion of fossil fuels at our generating facilities, we emit SO
2
and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits, we could be subject to fines and penalties. In order to meet SO
2
and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.
We are subject to the SO
2
allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its SO
2
emissions for that year. In 2017, we had adequate SO
2
allowances to meet generation and we expect to have enough to cover emissions under this program in 2018.
Cross-State Air Pollution Update Rule
In September 2016, the 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 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 consolidated financial results.
National Ambient Air Quality Standards
Under the federal 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 PM, ozone, nitrogen dioxide (NO
2
) (a precursor to ozone), CO and 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 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, EPA designated all counties in the State of Kansas as attainment/unclassifiable. 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 will determine whether to reconsider all or a portion of the rule. In December 2017, environmental groups filed suit against the EPA for failure to make all the required area designations by an October 2017 deadline. Also in December 2017, the EPA issued a notice of availability of their intent to issue the remainder of the area designations by April 2018. This will not affect the area designations for Kansas issued in November 2017.
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 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 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 greenhouse gas (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.
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 is 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 or not they will issue a replacement rule. The EPA is soliciting comments on the legal interpretations contained in this rulemaking.
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 are due to the EPA in February 2018.
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 (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 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 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 early 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 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. The EPA has stated its intent to propose a rule in early 2018 to modify portions of the 2015 rulemaking. 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.
See Note 15, “Asset Retirement Obligations,” for additional information.
SPP Revenue Crediting
We are a member
of the Southwest Power Pool, Inc. (SPP) RTO, which coordinates the operation of a multi-state interconnected transmission system. In 2016, the SPP completed a process of allocating revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are generation interconnection or transmission service projects that benefit SPP members and that are paid for directly by a sponsor without customer support. The SPP determined sponsors are entitled to revenue credits for previously completed upgrades, and members are obligated to pay for revenue credits attributable to these historical upgrades.
As a result, in November 2016
we paid the SPP
$7.6 million
related to revenue credits attributable to historical upgrades from March 2008 to August 2016. The SPP issued revised allocations and we received a small refund in November 2017.
Nuclear Decommissioning
Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with NRC requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every
three
years.
The KCC reviews nuclear decommissioning plans in
two
phases. Phase
one
is the approval of the updated nuclear decommissioning study including the estimated costs to decommission the plant. Phase
two
involves the review and approval of a funding schedule prepared by the owner of the plant detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.
In
2017
, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately
$380.0 million
. This amount compares to the prior site study estimate of
$360.0 million
. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.
We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through
2045
. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated financial results would be materially affected if we were not allowed to recover in our prices the full amount of the funding requirement.
We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately
$5.8 million
in
2017
,
$5.0 million
in
2016
and
$2.8 million
in
2015
. We record our investment in the NDT fund at fair value, which approximated
$237.1 million
and
$200.1 million
as of
December 31, 2017
and
2016
, respectively.
Storage of Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision.
Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. 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, we received
$0.8 million
of the settlement representing reimbursement of costs incurred through 2015 for project planning. Wolf Creek submitted a settlement claim to the DOE in August 2017 for costs incurred between January 2016 and June 2017, with our share of the claim being approximately
$0.5 million
. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.
Nuclear Insurance
We maintain nuclear liability, property and accidental outage insurance for Wolf Creek. These policies contain certain industry standard terms, conditions and exclusions, including, but not limited to, ordinary wear and tear and war. An industry aggregate limit of
$3.2 billion
for nuclear events (
$1.8 billion
of non-nuclear events) plus any reinsurance, indemnity or any other source recoverable by Nuclear Electric Insurance Limited (NEIL), our property and accidental outage insurance provider, exists for acts of terrorism affecting Wolf Creek or any other NEIL insured plant within
12
months from the date of the first act. In addition, we are required to participate in industry-wide retrospective assessment programs as discussed below.
Nuclear Liability Insurance
Pursuant to the Price-Anderson Act, we insure against public nuclear liability claims resulting from nuclear incidents to the required limit of public liability, which is approximately
$13.4 billion
. This limit of liability consists of the maximum available commercial insurance of
$450.0 million
and the remaining
$13.0 billion
is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to
$127.3 million
(our share is
$59.8 million
), payable at no more than
$19.0 million
(our share is
$8.9 million
) per incident per year per reactor for any commercial U.S. nuclear reactor qualifying incident. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in
2018
. In addition, Congress could impose additional revenue-raising measures to pay claims.
Nuclear Property and Accidental Outage Insurance
The owners of Wolf Creek carry decontamination liability, nuclear property damage and premature nuclear decommissioning liability insurance for Wolf Creek totaling approximately
$2.8 billion
. Insurance coverage for non-nuclear property damage accidents total approximately
$2.3 billion
. In the event of an extraordinary nuclear accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or, if certain requirements are met, including decommissioning the plant, toward a shortfall in the NDT fund. The owners also carry additional insurance with NEIL to help cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately
$37.4 million
(our share is
$17.6 million
).
Nuclear Insurance Considerations
Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in our prices, would have a material effect on our consolidated financial results.
Fuel and Purchased Power Commitments
To supply a portion of the fuel requirements for our power plants, the owners of Wolf Creek have entered into various contracts to obtain nuclear fuel and we have entered into various contracts to obtain coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. As of
December 31, 2017
, our share of Wolf Creek’s nuclear fuel commitments was approximately
$13.4 million
for uranium concentrates expiring in
2024
,
$1.9 million
for conversion expiring in
2024
,
$83.2 million
for uranium hexafluoride expiring in
2024
,
$69.9 million
for enrichment expiring in
2027
and
$31.4 million
for fabrication expiring in
2025
.
As of
December 31, 2017
, our coal and coal transportation contract commitments under the remaining terms of the contracts were approximately
$489.7 million
. The contracts are for plants that we operate and expire at various times through
2020
.
As of
December 31, 2017
, our natural gas transportation contract commitments under the remaining terms of the contracts were approximately
$92.6 million
. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through
2030
.
We have power purchase agreements with the owners of
nine
separate wind generation facilities with installed design capabilities of approximately
1,328
MW expiring in
2028
through
2036
. Each of the agreements provide for our receipt and purchase of energy produced at a fixed price per unit of output. We estimate that our annual cost of energy purchased from these wind generation facilities will be approximately
$140.0 million
.
15. ASSET RETIREMENT OBLIGATIONS
Legal Liability
We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of the ARO is capitalized and depreciated over the remaining life of the asset. We estimate our AROs based on the fair value of the AROs we incurred at the time the related long-lived assets were either acquired, placed in service or when regulations establishing the obligation became effective. The recording of AROs for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.
We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (KGE’s
47%
share), retire our wind generation facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds, close ash landfills and dispose of polychlorinated biphenyl (PCB)-contaminated oil. ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement may be conditional on a future event that may or may not be within the control of the entity. In determining our AROs, we make assumptions regarding probable future disposal costs. A change in these assumptions could have significant impact on the AROs reflected on our consolidated balance sheet.
The following table summarizes our legal AROs included on our consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Beginning balance
|
$
|
323,951
|
|
|
$
|
275,285
|
|
|
Increase in ARO liabilities
|
13,471
|
|
|
—
|
|
|
Liabilities settled
|
(16,026
|
)
|
|
(5,372
|
)
|
|
Accretion expense
|
16,940
|
|
|
14,165
|
|
|
Revision to nuclear decommissioning ARO liability
|
19,377
|
|
|
—
|
|
|
Revisions in estimated cash flows
|
47,405
|
|
|
39,873
|
|
|
Ending balance
|
$
|
405,118
|
|
|
$
|
323,951
|
|
|
Less: amount included in other current liabilities
|
25,129
|
|
|
—
|
|
|
Long-term AROs
|
$
|
379,989
|
|
|
$
|
323,951
|
|
Wolf Creek filed a nuclear decommissioning cost study with the KCC in 2017. As a result of the study, we recorded a
$19.4 million
increase in our ARO to reflect revisions to the estimated costs to decommission Wolf Creek. In addition, we increased our AROs for asbestos by
$28.8 million
and recorded a new ARO liability of approximately
$13.5 million
related to Western Plains Wind Farm. In 2016, we increased our ARO by
$39.9 million
to recognize costs associated with closure and post-closure of ash disposal ponds in response to the EPAs rule to regulate CCRs. See Note 14, “Commitments and Contingencies - Regulation of Coal Combustion Residuals,” for additional information on the CCR rule.
We have an obligation to retire our wind generation facilities and remove the foundations. The ARO related to our owned wind generation facilities was determined based upon the date each wind generation facility was constructed.
The initial retirement obligation related to asbestos disposal was recorded in
1990
, the date when the EPA published the “National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule.”
We operate, as permitted by the state of Kansas, ash landfills and ash disposal ponds at several of our power plants. The retirement obligations for the ash landfills and ash disposal ponds were determined based upon the date each landfill was originally placed in service.
PCB-contaminated oil is contained within company electrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regulations that originally became effective in
1978
.
Non-Legal Liability - Cost of Removal
We collect in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of
December 31, 2017
, we had
$30.8 million
in amounts spent, but not yet collected, for removal costs classified as a regulatory asset. As of
December 31, 2016
, we had
$5.7 million
in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.
16. LEGAL PROCEEDINGS
We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Notes 4 and 14, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information.
Pending Merger
Following the announcement of the original merger agreement in May 2016, two putative class action petitions (which were consolidated and superseded by a consolidated class action petition) and one putative derivative petition challenging the original merger were filed in the District Court of Shawnee County, Kansas. In September 2016, the plaintiffs in both actions agreed in principle to dismiss the actions in exchange for our agreement to make supplemental disclosures to shareholders in connection with the original merger agreement and grant waivers of the prohibition on requesting a waiver of the standstill provisions in the confidentiality and standstill agreements executed by the bidders that participated in a sale process that was conducted as part of the original merger agreement. As described below, after the announcement of the revised merger agreement, the plaintiffs in the consolidated putative class action moved to amend their petition, and the plaintiff in the putative derivative case refiled his petition.
The consolidated putative class action petition, originally filed July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, Case No. 2016-CV-000457. This petition named as defendants Westar Energy, the members of our board of directors and Great Plains Energy.
On September 25, 2017, the lead plaintiff filed a motion for leave to amend her class action petition and attached an amended petition. The petition as amended now includes an additional plaintiff. The petition challenges the revised proposed merger and alleges a claim of breach of fiduciary duty against our board of directors and a claim of aiding and abetting that alleged breach against us and Great Plains Energy. The lawsuit seeks injunctive relief declaring the action maintainable as a class action and certifying that the plaintiffs are the class representatives; preliminarily and permanently enjoining the defendants from closing the merger unless we implement a procedure to obtain a merger agreement providing fair and reasonable terms and consideration to the plaintiffs and the class; rescinding the merger agreement or granting the plaintiffs and the class rescissory damages; directing our board of directors to account to the plaintiffs and the class for damages suffered as a result of the alleged breach of fiduciary duty; awarding the plaintiffs reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper. The petition alleges inadequacies in our joint proxy statement concerning the revised proposed transaction and the degree to which our board of directors solicited or considered offers from prior bidders after the proposed original merger was denied by the KCC, and claims that the consideration our stockholders stand to receive in connection with the revised proposed transaction is unfair. Plaintiffs have added two new defendants, Monarch Energy Holding, Inc. and King Energy, Inc., whom they allege aided and abetted our board of directors in breaching their fiduciary duties.
On October 18, 2017, the putative derivative petition, captioned Braunstein v. Chandler et al., Case No. 2017-CV-000692, was re-filed in the District Court of Shawnee County, Kansas. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy, and subsidiaries of Great Plains Energy, with Westar Energy named as a nominal defendant. The petition asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with actions taken after the KCC rejected the proposed original merger. It also asserts that Great Plains Energy and subsidiaries of Great Plains Energy aided and abetted such breaches of fiduciary duties. The petition alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that members of our board of directors committed waste by not collecting termination fees that may have been payable following the KCC’s rejection of the original merger agreement. The petition seeks, among other remedies, an order enjoining the merger on the terms proposed and directing that the director defendants exercise their fiduciary duties to obtain a transaction, which is in the best interests of us and our shareholders, a declaration that the proposed merger was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, rescission of the merger agreement if consummated, the imposition of a constructive trust in favor of the plaintiff, on behalf of us, upon any benefits improperly received by the named defendants as a result of their wrongful conduct, and an award for costs, including attorneys’ fees and experts’ fees.
In addition, on September 21, 2017, a putative class action lawsuit was filed in the United States District Court for the District of Kansas, captioned David Pill v. Westar Energy, Inc. et al, Civil Action No. 17-4086. The federal class action complaint challenges the merger and alleges violations of sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as amended (Exchange Act). The complaint seeks an order declaring that the action is maintainable as a class action and
certifying that the plaintiff is the class representative; preliminarily and permanently enjoining defendants from consummating the mergers or, if consummated, setting them aside and awarding rescissory damages; directing the defendants to file a registration statement on Form S-4 that corrects alleged misstatements; directing our board of directors to account to plaintiff and the class for their damages; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other further relief as the court deems proper.
On October 6, 2017, another putative class action lawsuit was filed in the United States District Court for the District of Kansas, captioned Robert L. Reese v. Westar Energy, Inc. et al, Civil Action No. 2:17-cv-02584. This federal class action complaint challenges the proposed merger and alleges violations of sections 14(a) and 20(a) of the Exchange Act. The complaint seeks an order enjoining the board and other parties from proceeding with, consummating, or closing the merger or, if consummated, setting it aside and awarding rescissory damages; directing the board to disseminate a registration statement that corrects alleged misstatements and includes all material facts the plaintiff asserts are missing; declaring that the defendants violated sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9; awarding reasonable costs and disbursements of the action, including reasonable attorneys’ fees and expert fees; and granting other equitable relief as the court deems proper.
On November 16, 2017, the parties in each of the actions independently agreed to withdraw requests for injunctive relief and otherwise agreed in principle to dismissing the actions with prejudice and to providing releases, in exchange for the supplemental disclosures that we filed in a Form 8-K on November 16, 2017. These agreements do not constitute any admission by any of the defendants as to the merits of any claims. In the future, the parties will prepare and present to the court for approval Stipulations of Settlement that will, if accepted by the court, settle the actions in their entirety. The outcome of litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation.
17. COMMON STOCK
General
Westar Energy’s Restated Articles of Incorporation, as amended, provide for
275.0 million
authorized shares of common stock. As of
December 31, 2017
and
2016
, Westar Energy had issued
142.1 million
shares and
141.8 million
shares, respectively.
Westar Energy has a direct stock purchase plan (DSPP). Shares of common stock sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During
2017
and
2016
, Westar Energy issued
0.4 million
shares through the DSPP and other stock-based plans operated under the long-term incentive and share award plan. As of
December 31, 2017
and
2016
, a total of
0.9 million
shares and
1.0 million
shares, respectively, were available under the DSPP registration statement.
Issuances
In
March 2013
, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank. Both agreements expired in March 2016. The maximum amount that Westar Energy could have offered and sold under the master agreement was the lesser of an aggregate of
$500.0 million
or approximately
25.0 million
shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy could have offered and sold shares of its common stock from time to time. The agent received a commission equal to
1%
of the sales price of all shares sold under the agreements. In 2015, we settled
9.2 million
shares for a physical settlement of approximately
$254.6 million
.
The forward sale transactions were entered into at market prices; therefore, the forward sale agreements had no initial fair value. Westar Energy did not receive any proceeds from the sale of common stock under the forward sale agreements until transactions were settled. Westar Energy settled the forward sale transactions through physical share settlement and recorded the forward sale agreements within equity. The shares under the forward sale agreements were initially priced when the transactions were entered into and were subject to certain fixed pricing adjustments during the term of the agreements. The net proceeds from the forward sale transactions represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurred.
Westar Energy used the proceeds from the transactions described above to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.
18. VARIABLE INTEREST ENTITIES
In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trust holding our
50%
interest in La Cygne unit 2 is a VIE. The trust holding our 8% interest in Jeffrey Energy Center was a VIE until the expiration of a purchase option in July 2017. We remain the primary beneficiary of the trust holding our 50% interest in La Cygne unit 2.
We assess all entities with which we become involved to determine whether such entities are VIEs and, if so, whether or not we are the primary beneficiary of the entities. We also continuously assess whether we are the primary beneficiary of the VIE with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary.
8%
Interest in Jeffrey Energy Center
Under an agreement that expires in
January 2019
, we lease an
8%
interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the
8%
interest in JEC and lease it to a third party, and does not hold any other assets. We met the requirements to be considered the primary beneficiary of the trust until July 2017, when a contractual option to purchase the 8% interest in the plant covered by the lease expired. Accordingly, we deconsolidated the trust in the third quarter of 2017.
In determining the primary beneficiary of the trust, we concluded at the inception of the lease that the activities of the trust that most significantly impacted its economic performance and that we had the power to direct included (1) the operation and maintenance of the
8%
interest in JEC, (2) our ability to exercise an option that expired in July 2017 to purchase the plant at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We had the potential to receive benefits from the trust that could potentially be significant if the fair value of the
8%
interest in JEC at the end of the agreement was greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also created the potential for us to receive significant benefits.
50%
Interest in La Cygne Unit 2
Under an agreement that expires in
September 2029
, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s
50%
interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the
50%
interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the
50%
interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the
50%
interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount.
Financial Statement Impact
We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIEs described above.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Assets:
|
|
|
|
|
Property, plant and equipment of variable interest entities, net
|
$
|
176,279
|
|
|
$
|
257,904
|
|
|
Regulatory assets (a)
|
—
|
|
|
10,396
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
Current maturities of long-term debt of variable interest entities
|
$
|
28,534
|
|
|
$
|
26,842
|
|
|
Accrued interest (b)
|
659
|
|
|
867
|
|
|
Long-term debt of variable interest entities, net
|
81,433
|
|
|
111,209
|
|
_______________
(a) Included in long-term regulatory assets on our consolidated balance sheets.
(b) Included in accrued interest on our consolidated balance sheets.
All of the liabilities noted in the table above relate to the purchase of the property, plant and equipment. The assets of the VIEs can be used only to settle obligations of the VIEs and the VIEs’ debt holders have no recourse to our general credit. We have not provided financial or other support to the VIEs and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIEs.
19. LEASES
Operating Leases
We lease office buildings, computer equipment, vehicles, railcars and other property and equipment. In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term.
Rental expense and estimated future commitments under operating leases are as follows.
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Total
Operating
Leases
|
|
|
|
(In Thousands)
|
|
Rental expense:
|
|
|
|
2015
|
|
$
|
14,035
|
|
|
2016
|
|
13,563
|
|
|
2017
|
|
15,661
|
|
|
|
|
|
|
Future commitments:
|
|
|
|
2018
|
|
$
|
18,132
|
|
|
2019
|
|
13,263
|
|
|
2020
|
|
9,411
|
|
|
2021
|
|
7,448
|
|
|
2022
|
|
4,505
|
|
|
Thereafter
|
|
5,900
|
|
|
Total future commitments
|
|
$
|
58,659
|
|
Capital Leases
We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements.
Assets recorded under capital leases are listed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
|
Vehicles
|
$
|
19,679
|
|
|
$
|
15,595
|
|
|
Computer equipment
|
924
|
|
|
1,073
|
|
|
Generation plant
|
40,048
|
|
|
40,048
|
|
|
Accumulated amortization
|
(17,091
|
)
|
|
(13,542
|
)
|
|
Total capital leases
|
$
|
43,560
|
|
|
$
|
43,174
|
|
Capital leases are treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Total Capital
Leases
|
|
|
|
(In Thousands)
|
|
2018
|
|
$
|
6,433
|
|
|
2019
|
|
5,856
|
|
|
2020
|
|
5,213
|
|
|
2021
|
|
4,699
|
|
|
2022
|
|
4,092
|
|
|
Thereafter
|
|
49,811
|
|
|
|
|
76,104
|
|
|
Amounts representing imputed interest
|
|
(27,434
|
)
|
|
Present value of net minimum lease payments under capital leases
|
|
48,670
|
|
|
Less: Current portion
|
|
3,809
|
|
|
Total long-term obligation under capital leases
|
|
$
|
44,861
|
|
20. QUARTERLY RESULTS (UNAUDITED)
Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
(In Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
Revenues (a)
|
$
|
572,574
|
|
|
$
|
609,321
|
|
|
$
|
794,327
|
|
|
$
|
594,781
|
|
|
Net income (a)
|
63,482
|
|
|
76,039
|
|
|
160,724
|
|
|
36,306
|
|
|
Net income attributable to Westar Energy, Inc. (a)
|
59,661
|
|
|
72,065
|
|
|
158,306
|
|
|
33,888
|
|
|
|
|
|
|
|
|
|
|
|
Per Share Data (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
Earnings available
|
$
|
0.42
|
|
|
$
|
0.50
|
|
|
$
|
1.11
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
Earnings available
|
$
|
0.42
|
|
|
$
|
0.50
|
|
|
$
|
1.11
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividend declared per common share
|
$
|
0.40
|
|
|
$
|
0.40
|
|
|
$
|
0.40
|
|
|
$
|
0.40
|
|
|
Market price per common share:
|
|
|
|
|
|
|
|
|
High
|
$
|
56.60
|
|
|
$
|
55.12
|
|
|
$
|
53.49
|
|
|
$
|
57.32
|
|
|
Low
|
$
|
52.16
|
|
|
$
|
50.35
|
|
|
$
|
49.20
|
|
|
$
|
49.95
|
|
_______________
|
|
|
|
(a)
|
Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
(In Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
Revenues (a)
|
$
|
569,450
|
|
|
$
|
621,448
|
|
|
$
|
764,654
|
|
|
$
|
606,535
|
|
|
Net income (a)
|
68,708
|
|
|
76,144
|
|
|
158,553
|
|
|
57,795
|
|
|
Net income attributable to Westar Energy, Inc. (a)
|
65,585
|
|
|
72,340
|
|
|
154,720
|
|
|
53,932
|
|
|
|
|
|
|
|
|
|
|
|
Per Share Data (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
Earnings available
|
$
|
0.46
|
|
|
$
|
0.51
|
|
|
$
|
1.09
|
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
Earnings available
|
$
|
0.46
|
|
|
$
|
0.51
|
|
|
$
|
1.08
|
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividend declared per common share
|
$
|
0.38
|
|
|
$
|
0.38
|
|
|
$
|
0.38
|
|
|
$
|
0.38
|
|
|
Market price per common share:
|
|
|
|
|
|
|
|
|
High
|
$
|
50.38
|
|
|
$
|
57.25
|
|
|
$
|
56.95
|
|
|
$
|
57.50
|
|
|
Low
|
$
|
40.01
|
|
|
$
|
48.92
|
|
|
$
|
52.52
|
|
|
$
|
54.41
|
|
_______________
|
|
|
|
(a)
|
Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.
|