Document and Entity Information
Document and Entity Information Document - shares | 6 Months Ended | |
Jun. 30, 2017 | Aug. 02, 2017 | |
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | WR | |
Entity Registrant Name | WESTAR ENERGY INC /KS | |
Entity Central Index Key | 54,507 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 142,093,420 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 | |
Income Taxes Receivable, Current | $ 0 | $ 13,000 | |
CURRENT ASSETS: | |||
Cash and cash equivalents | 3,210 | 3,066 | |
Accounts receivable, net of allowance for doubtful accounts of $4,503 and $4,596, respectively | 274,426 | 288,579 | |
Fuel inventory and supplies | 302,696 | 300,125 | |
Prepaid expenses | 19,077 | 16,528 | |
Regulatory assets | 110,179 | 117,383 | |
Other | 30,638 | 29,701 | |
Total Current Assets | 740,226 | 768,382 | |
Property, plant and equipment, net | 9,406,054 | 9,248,359 | |
OTHER ASSETS: | |||
Regulatory assets | 750,888 | 762,479 | |
Nuclear decommissioning trust | 220,031 | 200,122 | |
Other | 226,214 | 249,828 | |
Total Other Assets | 1,197,133 | 1,212,429 | |
TOTAL ASSETS | 11,596,150 | 11,487,074 | |
CURRENT LIABILITIES: | |||
Current maturities of long-term debt | 0 | 125,000 | |
Short-term debt | 329,200 | 366,700 | |
Accounts payable | 139,628 | 220,522 | |
Accrued dividends | 53,743 | 52,885 | |
Accrued taxes | 89,742 | 85,729 | |
Accrued interest | [1] | 45,124 | 72,519 |
Regulatory liabilities | 11,903 | 15,760 | |
Other | 76,294 | 81,236 | |
Total Current Liabilities | 774,172 | 1,047,193 | |
LONG-TERM LIABILITIES: | |||
Long-term debt, net | 3,686,180 | 3,388,670 | |
Deferred income taxes | 1,794,177 | 1,752,776 | |
Unamortized investment tax credits | 209,283 | 210,654 | |
Regulatory liabilities | 230,355 | 223,693 | |
Accrued employee benefits | 511,073 | 512,412 | |
Asset Retirement Obligations, Noncurrent | 368,233 | 323,951 | |
Other | 85,145 | 83,326 | |
Total Long-Term Liabilities | 6,967,099 | 6,606,691 | |
COMMITMENTS AND CONTINGENCIES (See Notes 10 and 11) | |||
Westar Energy, Inc. Shareholders' Equity: | |||
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 129,272,835 shares and 128,254,229 shares, respective to each date | 710,467 | 708,956 | |
Paid-in capital | 2,019,815 | 2,018,317 | |
Retained earnings | 1,095,247 | 1,078,602 | |
Total Westar Energy, Inc. Shareholders' Equity | 3,825,529 | 3,805,875 | |
Noncontrolling Interests | 29,350 | 27,315 | |
Total Equity | 3,854,879 | 3,833,190 | |
TOTAL LIABILITIES AND EQUITY | 11,596,150 | 11,487,074 | |
Variable Interest Entity [Member] | |||
CURRENT ASSETS: | |||
Property, plant and equipment, net | 252,737 | 257,904 | |
CURRENT LIABILITIES: | |||
Current maturities of long-term debt | 28,538 | 26,842 | |
Accrued interest | [1] | 706 | 867 |
LONG-TERM LIABILITIES: | |||
Long-term debt, net | $ 82,653 | $ 111,209 | |
[1] | Included in accrued interest on our condensed consolidated balance sheets. |
Consolidated Balance Sheets Par
Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
CURRENT ASSETS: | ||
Allowance for doubtful accounts | $ 5,697 | $ 6,667 |
Westar Energy, Inc. Shareholders' Equity: | ||
Common stock, par value | $ 5 | $ 5 |
Common stock, shares authorized | 275,000,000 | 275,000,000 |
Common stock, shares issued | 142,093,387 | 141,791,153 |
Common stock, shares outstanding | 142,093,387 | 141,791,153 |
Consolidated Statements Of Inco
Consolidated Statements Of Income - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
REVENUES | $ 609,321 | $ 621,448 | $ 1,181,895 | $ 1,190,898 |
OPERATING EXPENSES: | ||||
Fuel and purchased power | 111,790 | 118,630 | 225,645 | 218,688 |
Network Transmission Cost | 61,763 | 55,227 | 122,437 | 115,987 |
Operating and maintenance | 87,158 | 85,619 | 168,356 | 163,377 |
Depreciation and amortization | 94,029 | 84,226 | 182,655 | 167,866 |
Selling, general and administrative | 57,579 | 75,724 | 116,735 | 132,179 |
Taxes, Miscellaneous | 41,890 | 48,407 | 84,606 | 97,375 |
Total Operating Expenses | 454,209 | 467,833 | 900,434 | 895,472 |
INCOME FROM OPERATIONS | 155,112 | 153,615 | 281,461 | 295,426 |
OTHER INCOME (EXPENSE): | ||||
Investment earnings (losses) | 2,636 | 2,280 | 5,790 | 4,296 |
Other income | 523 | 3,382 | 1,823 | 12,860 |
Other expense | (2,647) | (2,908) | (7,963) | (8,451) |
Total Other Income | 512 | 2,754 | (350) | 8,705 |
Interest expense | 43,679 | 39,683 | 84,774 | 80,114 |
INCOME BEFORE INCOME TAXES | 111,945 | 116,686 | 196,337 | 224,017 |
Income tax expense | 35,906 | 40,542 | 56,816 | 79,165 |
NET INCOME | 76,039 | 76,144 | 139,521 | 144,852 |
Less: Net income attributable to noncontrolling interests | 3,974 | 3,804 | 7,795 | 6,927 |
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC. | $ 72,065 | $ 72,340 | $ 131,726 | $ 137,925 |
Earnings Per Share [Abstract] | ||||
Earnings Per Share, Basic | $ 0.50 | $ 0.51 | $ 0.92 | $ 0.97 |
Earnings Per Share, Diluted | $ 0.50 | $ 0.51 | $ 0.92 | $ 0.97 |
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING | ||||
Weighted Average Number of Shares Outstanding , Basic | 142,465,749 | 142,033,842 | 142,451,266 | 142,013,344 |
Weighted Average Number of Shares Outstanding, Diluted | 142,596,356 | 142,497,335 | 142,579,255 | 142,361,347 |
DIVIDENDS DECLARED PER COMMON SHARE | $ 0.40 | $ 0.38 | $ 0.80 | $ 0.76 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: | ||
Net income | $ 139,521 | $ 144,852 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 182,655 | 167,866 |
Amortization of nuclear fuel | 15,948 | 16,831 |
Amortization of deferred regulatory gain from sale leaseback | (2,748) | (2,748) |
Amortization of corporate-owned life insurance | 8,920 | 8,819 |
Non-cash compensation | 4,613 | 4,778 |
Net deferred income taxes and credits | 53,852 | 75,334 |
Allowance for equity funds used during construction | (773) | (5,247) |
Changes in working capital items: | ||
Accounts receivable | 14,154 | (40,555) |
Fuel inventory and supplies | (2,262) | 2,140 |
Prepaid expenses and other | 39,167 | 7,126 |
Accounts payable | (20,012) | (21,364) |
Accrued taxes | 11,019 | 16,272 |
Other current liabilities | (103,316) | (62,434) |
Changes in other assets | 14,891 | 1,848 |
Changes in other liabilities | 7,695 | 15,163 |
Cash Flows from Operating Activities | 363,324 | 328,681 |
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: | ||
Additions to property, plant and equipment | (383,627) | (503,631) |
Purchase of securities - trusts | (12,140) | (39,603) |
Sale of securities - trusts | 13,538 | 41,201 |
Investment in corporate-owned life insurance | 13,875 | 14,648 |
Proceeds from investment in corporate-owned life insurance | 185 | 24,171 |
Investment in affiliated company | 0 | (655) |
Other investing activities | (3,199) | (2,798) |
Cash Flows used in Investing Activities | (399,118) | (495,963) |
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: | ||
Short-term debt, net | (37,632) | (73,300) |
Proceeds from long-term debt | (296,296) | (396,577) |
Retirements of long-term debt | (125,000) | (50,000) |
Repayment of capital leases | (1,663) | (401) |
Borrowings against cash surrender value of corporate-owned life insurance | 52,302 | 54,910 |
Repayment of borrowings against cash surrender value of corporate-owned life insurance | 0 | (22,921) |
Issuance of common stock | 659 | 1,354 |
Distributions to shareholders of noncontrolling interests | (5,760) | (2,551) |
Cash dividends paid | (109,418) | (101,137) |
Other financing activities | (7,006) | (4,960) |
Cash Flows from Financing Activities | 35,938 | 169,264 |
NET CHANGE IN CASH AND CASH EQUIVALENTS | 144 | 1,982 |
CASH AND CASH EQUIVALENTS: | ||
Beginning of period | 3,066 | 3,231 |
End of period | 3,210 | 5,213 |
Variable Interest Entity [Member] | ||
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: | ||
Proceeds from long-term debt | 0 | (162,048) |
Retirements of long-term debt | $ (26,840) | $ (190,355) |
Consolidated Statements Of Chan
Consolidated Statements Of Changes In Equity - USD ($) | Total | Common Stock [Member] | Paid-In Capital [Member] | Retained Earnings [Member] | Noncontrolling Interests [Member] |
Beginning Balance at Dec. 31, 2015 | $ 3,671,963,000 | $ 706,767,000 | $ 2,004,124,000 | $ 945,830,000 | $ 15,242,000 |
Beginning Balance (Shares) at Dec. 31, 2015 | 141,353,426 | ||||
Net income | 144,852,000 | $ 0 | 0 | 137,925,000 | 6,927,000 |
Issuance of stock | 1,354,000 | $ 143,000 | 1,211,000 | 0 | 0 |
Issuance of stock (shares) | 28,674 | ||||
Issuance Of Stock For Compensation And Reinvested Dividends, Shares | 308,917 | ||||
Issuance Of Stock For Compensation And Reinvested Dividends | 4,941,000 | $ 1,545,000 | 3,396,000 | ||
Tax withholding related to stock compensation | (4,960,000) | (4,960,000) | |||
Dividends on common stock | (108,894,000) | 0 | 0 | (108,894,000) | 0 |
Stock compensation expense | 4,720,000 | 4,720,000 | |||
Distributions to shareholders of noncontrolling interests | (2,551,000) | (2,551,000) | |||
Ending Balance at Jun. 30, 2016 | 3,714,751,000 | $ 708,455,000 | 2,008,491,000 | 978,187,000 | 19,618,000 |
Ending Balance (Shares) at Jun. 30, 2016 | 141,691,017 | ||||
Beginning Balance at Dec. 31, 2016 | 3,833,190,000 | $ 708,956,000 | 2,018,317,000 | 1,078,602,000 | 27,315,000 |
Beginning Balance (Shares) at Dec. 31, 2016 | 141,791,153 | ||||
Net income | 139,521,000 | $ 0 | 0 | 131,726,000 | 7,795,000 |
Issuance of stock | 659,000 | $ 60,000 | 599,000 | 0 | 0 |
Issuance of stock (shares) | 12,131 | ||||
Issuance Of Stock For Compensation And Reinvested Dividends, Shares | 290,103 | ||||
Issuance Of Stock For Compensation And Reinvested Dividends | 4,801,000 | $ 1,451,000 | 3,350,000 | ||
Tax withholding related to stock compensation | (7,006,000) | (7,006,000) | |||
Dividends on common stock | (115,081,000) | 0 | 0 | (115,081,000) | 0 |
Stock compensation expense | 4,555,000 | 4,555,000 | |||
Deconsolidation of variable interest entity | (5,760,000) | (5,760,000) | |||
Distributions to shareholders of noncontrolling interests | (5,760,000) | ||||
Ending Balance at Jun. 30, 2017 | $ 3,854,879,000 | $ 710,467,000 | $ 2,019,815,000 | 1,095,247,000 | $ 29,350,000 |
Ending Balance (Shares) at Jun. 30, 2017 | 142,093,387 | ||||
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets | $ 3,326,000 |
Consolidated Statements Of Cha7
Consolidated Statements Of Changes in Equity Parenthetical (Parentheticals) - $ / shares | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
DIVIDENDS DECLARED PER COMMON SHARE | $ 0.40 | $ 0.38 | $ 0.80 | $ 0.76 |
Description Of Business
Description Of Business | 6 Months Ended |
Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description Of Business | DESCRIPTION OF BUSINESS We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to “the Company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924 , alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 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. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included. The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2016 Form 10-K. Use of Management’s Estimates When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2017 , are not necessarily indicative of the results to be expected for the full year. Fuel Inventory and Supplies We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately. As of As of June 30, 2017 December 31, 2016 (In Thousands) Fuel inventory $ 106,764 $ 107,086 Supplies 195,932 193,039 Fuel inventory and supplies $ 302,696 $ 300,125 Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying condensed consolidated statements of income as follows. Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (Dollars In Thousands) Borrowed funds $ 895 $ 2,338 $ 2,748 $ 4,347 Equity funds — 2,783 773 5,247 Total $ 895 $ 5,121 $ 3,521 $ 9,594 Average AFUDC Rates 1.5 % 4.2 % 2.0 % 4.6 % Earnings Per Share We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS). To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method. The following table reconciles our basic and diluted EPS from net income. Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (Dollars In Thousands, Except Per Share Amounts) Net income $ 76,039 $ 76,144 $ 139,521 $ 144,852 Less: Net income attributable to noncontrolling interests 3,974 3,804 7,795 6,927 Net income attributable to Westar Energy, Inc. 72,065 72,340 131,726 137,925 Less: Net income allocated to RSUs 130 156 237 290 Net income allocated to common stock $ 71,935 $ 72,184 $ 131,489 $ 137,635 Weighted average equivalent common shares outstanding – basic 142,465,749 142,033,842 142,451,266 142,013,344 Effect of dilutive securities: RSUs 130,607 463,493 127,989 348,003 Weighted average equivalent common shares outstanding – diluted (a) 142,596,356 142,497,335 142,579,255 142,361,347 Earnings per common share, basic $ 0.50 $ 0.51 $ 0.92 $ 0.97 Earnings per common share, diluted $ 0.50 $ 0.51 $ 0.92 $ 0.97 _______________ (a) We had no antidilutive securities for the three and six months ended June 30, 2017 and 2016 . Supplemental Cash Flow Information Six Months Ended June 30, 2017 2016 (In Thousands) CASH PAID FOR (RECEIVED FROM): Interest on financing activities, net of amount capitalized $ 76,024 $ 70,697 Interest on financing activities of VIEs 1,696 4,150 Income taxes, net of refunds (12,685 ) (77 ) NON-CASH INVESTING TRANSACTIONS: Property, plant and equipment additions 89,899 71,830 NON-CASH FINANCING TRANSACTIONS: Issuance of stock for compensation and reinvested dividends 4,801 4,941 Assets acquired through capital leases 3,054 392 New Accounting Pronouncements We prepare our condensed consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements that may affect our accounting and/or disclosure. Compensation - Retirement Benefits In March 2017, the FASB issued Accounting Standard Update No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is to be applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is to be applied on a retrospective basis. The new standard is effective for annual periods beginning after December 15, 2017. We are evaluating the guidance and do not expect it to have a material impact on our condensed consolidated financial statements. Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or modified retrospective method. We will 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. We continue to analyze the impact of the new revenue standard and related ASUs. We completed initial revenue contract assessments. In summary, material revenue streams were identified and representative contract/transaction types were sampled. We also continue to monitor unresolved industry issues, including items related to contributions in aid of construction, collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. We are finalizing our changes to revenue-related disclosure and ensuring we have effective internal controls over financial reporting. Based upon our completed assessments, we do not expect the impact on our condensed consolidated financial statements to be material. |
Pending Merger Pending Merger (
Pending Merger Pending Merger (Notes) | 6 Months Ended |
Jun. 30, 2017 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | PENDING MERGER On May 29, 2016, we entered into an agreement and plan of merger with Great Plains Energy that provided for the acquisition of Westar by Great Plains Energy. On April 19, 2017, the Kansas Corporation Commission (KCC) denied our and Great Plains Energy’s merger application. 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 closing of the merger is subject to conditions including, among others, approval of our shareholders representing a majority of the outstanding shares of our common stock; approval of Great Plains Energy’s shareholders representing two-thirds of the outstanding shares of Great Plains Energy common stock; clearance under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act); receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the NRC, the KCC, and the Missouri Public Service Commission (MPSC) (provided that such approvals do not result in a material adverse effect on Great Plains Energy or us, after giving effect to the merger, measured on the size and scale of Westar 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. Either party may terminate the amended and restated merger agreement if the merger is not consummated by July 10, 2018 , subject to an extension of up to six months. Either party may also terminate the agreement if our shareholders or Great Plains Energy’s shareholders do not approve the merger or an order that prohibits the merger becomes final and non-appealable. There are also termination rights for both parties in certain cases if the other party’s board of directors changes its recommendation to its shareholders regarding approval of the merger, or the other party accepts an alternative, superior offer. 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 or by Great Plains Energy as a result of our board of directors changing its recommendation of the merger prior to our shareholder approval having been obtained. 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 or by us as a result of Great Plains Energy’s board of directors changing its recommendation of the merger prior to its shareholder approval having been obtained. Additionally, if the agreement is terminated by either Great Plains Energy or us as a result of Great Plains Energy’s shareholders not approving the agreement, Great Plains Energy may be required to pay us a termination fee of $80.0 million . 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. During 2016, we incurred approximately $10.2 million of merger-related expenses. During the three and six months ended June 30, 2017 , we incurred approximately $0.3 million and $0.7 million , respectively, of merger-related expenses. We incurred approximately $7.5 million in additional merger-related expenses in July 2017, with the balance of expenses to be incurred through the closing of the merger. In the event that the merger is consummated, we expect total merger-related expenses will be approximately $45.0 million . See also Note 13, “Legal Proceedings,” for more information on litigation related to the merger. |
Rate Matters And Regulation
Rate Matters And Regulation | 6 Months Ended |
Jun. 30, 2017 | |
Regulated Operations [Abstract] | |
Rate Matters And Regulation | RATE MATTERS AND REGULATION KCC Proceedings In October 2016, we filed an abbreviated rate review with the KCC to update our prices to include capital costs related to La Cygne Generating Station (La Cygne) environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015. In May 2017, we entered into a settlement agreement with the major parties to the rate review. In June 2017, the agreement was approved by the KCC. The new prices were effective June 2017 and are expected to increase our annual retail revenues by approximately $16.4 million . In March 2017, the KCC issued an order allowing us to adjust our retail prices to include updated transmission costs as reflected in the transmission formula rate (TFR). The new prices were effective in April 2017 and are expected to increase our annual retail revenues by approximately $12.7 million . In December 2016, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2017 and are expected to decrease our annual retail revenues by approximately $26.8 million . FERC Proceedings Our TFR that includes projected 2017 transmission capital expenditures and operating costs was effective in January 2017 and is expected to increase our annual transmission revenues by approximately $29.6 million . This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as discussed above. |
Financial Instruments and Risk
Financial Instruments and Risk Management | 6 Months Ended |
Jun. 30, 2017 | |
Financial And Derivative Instruments and Trading Securities [Abstract] | |
Financial And Derivative Instruments And Trading Securities | 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 condensed consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed-rate debt, a level 2 measurement, based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value. We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our fixed-rate debt. As of June 30, 2017 As of December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In Thousands) Fixed-rate debt $ 3,605,000 $ 3,846,301 $ 3,430,000 $ 3,597,441 Fixed-rate debt of VIEs 111,122 111,850 137,962 139,733 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 June 30, 2017 Level 1 Level 2 Level 3 NAV Total (In Thousands) Nuclear Decommissioning Trust: Domestic equity funds $ — $ 61,322 $ — $ 5,048 $ 66,370 International equity funds — 42,888 — — 42,888 Core bond fund — 32,378 — — 32,378 High-yield bond fund — 17,377 — — 17,377 Emerging markets bond fund — 16,873 — — 16,873 Combination debt/equity/other fund — 13,048 — — 13,048 Alternative investments fund — — — 20,584 20,584 Real estate securities fund — — — 10,380 10,380 Cash equivalents 133 — — — 133 Total Nuclear Decommissioning Trust 133 183,886 — 36,012 220,031 Trading Securities: Domestic equity funds — 17,523 — — 17,523 International equity fund — 4,361 — — 4,361 Core bond fund — 11,739 — — 11,739 Total Trading Securities — 33,623 — — 33,623 Total Assets Measured at Fair Value $ 133 $ 217,509 $ — $ 36,012 $ 253,654 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 Nuclear Decommissioning Trust (NDT) are measured at NAV and do not have readily determinable fair values. These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations, these investments may have redemption restrictions. The following table provides additional information on these investments. As of June 30, 2017 As of December 31, 2016 As of June 30, 2017 Fair Value Unfunded Commitments Fair Value Unfunded Commitments Redemption Frequency Length of Settlement (In Thousands) Nuclear Decommissioning Trust: Domestic equity funds $ 5,048 $ 3,129 $ 5,056 $ 3,529 (a) (a) Alternative investments fund (b) 20,584 — 18,958 — Quarterly 65 days Real estate securities fund (b) 10,380 — 9,946 — Quarterly 65 days Total $ 36,012 $ 3,129 $ 33,960 $ 3,529 _______________ (a) This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in 2013. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods. (b) There is a holdback on final redemptions. Price Risk We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and condensed consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes. Interest Rate Risk We have entered into numerous fixed and variable rate debt obligations. We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other financial derivative instruments such as interest rate swaps. |
Financial Investments
Financial Investments | 6 Months Ended |
Jun. 30, 2017 | |
Investments [Abstract] | |
Financial Investments | FINANCIAL INVESTMENTS We report our investments in equity and debt securities at fair value and use the specific identification method to determine their realized gains and losses. We classify these investments as either trading securities or available-for-sale securities as described below. Trading Securities We hold equity and debt investments that we classify as trading securities in a trust used to fund certain retirement benefit obligations. As of June 30, 2017 , and December 31, 2016 , we measured the fair value of trust assets at $33.6 million and $34.5 million , respectively. We include unrealized gains or losses on these securities in investment earnings on our condensed consolidated statements of income. For the three and six months ended June 30, 2017 , we recorded an unrealized gain of $1.1 million and $2.5 million , respectively, on assets still held in the trust. For the three and six months ended June 30, 2016 , we recorded an unrealized gain of $0.6 million and $1.1 million , respectively, on assets still held in the trust. Available-for-Sale Securities We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of June 30, 2017 , and December 31, 2016 . Using the specific identification method to determine cost, we realized a $0.2 million gain during the three months ended June 30, 2017 , and a gain of $0.1 million during the six months ended June 30, 2017 . We realized a gain of $0.1 million for the three months ended June 30, 2016 , and a loss of $1.4 million for the six months ended June 30, 2016 . We record net realized and unrealized gains and losses in regulatory liabilities on our condensed consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers. The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of June 30, 2017 , and December 31, 2016 . Gross Unrealized Security Type Cost Gain Loss Fair Value Allocation (Dollars In Thousands) As of June 30, 2017: Domestic equity funds $ 54,563 $ 12,260 $ (453 ) $ 66,370 30 % International equity funds 35,664 7,224 — 42,888 19 % Core bond fund 32,542 — (164 ) 32,378 15 % High-yield bond fund 17,060 317 — 17,377 8 % Emerging markets bond fund 17,047 — (174 ) 16,873 8 % Combination debt/equity/other fund 7,980 5,068 — 13,048 6 % Alternative investments fund 15,000 5,584 — 20,584 9 % Real estate securities fund 9,500 880 — 10,380 5 % Cash equivalents 133 — — 133 <1% Total $ 189,489 $ 31,333 $ (791 ) $ 220,031 100 % 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 June 30, 2017 , and December 31, 2016 . Less than 12 Months 12 Months or Greater Total Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses (In Thousands) As of June 30, 2017: Domestic equity funds $ 3,780 $ (453 ) $ — $ — $ 3,780 $ (453 ) Core bond fund 32,378 (164 ) — — 32,378 (164 ) Emerging markets bond fund — — 16,873 (174 ) 16,873 (174 ) Total $ 36,158 $ (617 ) $ 16,873 $ (174 ) $ 53,031 $ (791 ) 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 ) |
Debt Financing
Debt Financing | 6 Months Ended |
Jun. 30, 2017 | |
Long-term Debt, Unclassified [Abstract] | |
Debt Financing | DEBT FINANCING In January 2017, Westar Energy retired $125.0 million in principal amount of first mortgage bonds (FMBs) bearing a stated interest at 5.15% maturing January 2017. In March 2017, Westar Energy issued $300.0 million in principal amount of FMBs bearing a stated interest at 3.10% and maturing April 2027. |
Taxes
Taxes | 6 Months Ended |
Jun. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Taxes | TAXES We recorded income tax expense of $35.9 million with an effective income tax rate of 32% f or the three months ended June 30, 2017 , and income tax expense of $40.5 million with an effective income tax rate of 35% for the same period of 2016 . The decrease in the effective income tax rate for the three months ended June 30, 2017 , was due primarily to increases in tax benefits from production tax credits, largely from placing the Western Plains Wind Farm in service. We recorded income tax expense of $56.8 million with an effective income tax rate of 29% for the six months ended June 30, 2017 , and income tax expense of $79.2 million with an effective income tax rate of 35% for the same period of 2016 . The decrease in the effective income tax rate for the six months ended June 30, 2017 , was due primarily to a decrease in income before income taxes and increases in tax benefits from production tax credits, largely from placing the Western Plains Wind Farm in service. As of June 30, 2017 , and December 31, 2016 , our unrecognized income tax benefits totaled $2.8 million . We do not expect significant changes in our unrecognized income tax benefits in the next 12 months. As of June 30, 2017 , we had $0.1 million accrued for interest related to our unrecognized income tax benefits compared to no amount as of December 31, 2016 . We accrued no penalties at either June 30, 2017 , or December 31, 2016 . As of June 30, 2017 , and December 31, 2016 , we had recorded $0.1 million and $1.5 million , respectively, for probable assessments of taxes other than income taxes. |
Pension and Post-Retirement Ben
Pension and Post-Retirement Benefit Plans | 6 Months Ended |
Jun. 30, 2017 | |
Retirement Benefits [Abstract] | |
Pension And Post-Retirement Benefit Plans | PENSION AND POST-RETIREMENT BENEFIT PLANS The following tables summarize the net periodic costs for our pension and post-retirement benefit plans prior to the effects of capitalization. Pension Benefits Post-retirement Benefits Three Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 5,218 $ 4,633 $ 271 $ 271 Interest cost 10,621 10,921 1,314 1,393 Expected return on plan assets (10,760 ) (10,663 ) (1,718 ) (1,708 ) Amortization of unrecognized: Prior service costs 171 174 114 114 Actuarial loss (gain), net 5,489 5,146 (195 ) (280 ) Net periodic cost (benefit) before regulatory adjustment 10,739 10,211 (214 ) (210 ) Regulatory adjustment (a) 3,288 3,306 (478 ) (486 ) Net periodic cost (benefit) $ 14,027 $ 13,517 $ (692 ) $ (696 ) _______________ (a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices. Pension Benefits Post-retirement Benefits Six Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 10,437 $ 9,297 $ 542 $ 542 Interest cost 21,242 21,880 2,627 2,786 Expected return on plan assets (21,520 ) (21,326 ) (3,436 ) (3,417 ) Amortization of unrecognized: Prior service costs 341 420 228 228 Actuarial loss (gain), net 10,978 10,534 (390 ) (560 ) Net periodic cost (benefit) before regulatory adjustment 21,478 20,805 (429 ) (421 ) Regulatory adjustment (a) 6,576 6,613 (956 ) (972 ) Net periodic cost (benefit) $ 28,054 $ 27,418 $ (1,385 ) $ (1,393 ) _______________ (a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices. During the six months ended June 30, 2017 and 2016 , we contributed $13.1 million and $11.2 million , respectively, to the Westar Energy pension trust. |
Wolf Creek Pension and Post-Ret
Wolf Creek Pension and Post-Retirement Benefit Plans | 6 Months Ended |
Jun. 30, 2017 | |
Defined Benefit Plan [Abstract] | |
Wolf Creek Pension And Post-Retirement Benefit Plans | WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. The following tables summarize the net periodic costs for KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans prior to the effects of capitalization. Pension Benefits Post-retirement Benefits Three Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 1,950 $ 1,687 $ 37 $ 32 Interest cost 2,475 2,414 70 82 Expected return on plan assets (2,643 ) (2,430 ) — — Amortization of unrecognized: Prior service costs 14 14 — — Actuarial loss (gain), net 1,245 1,089 (13 ) (4 ) Net periodic cost before regulatory adjustment 3,041 2,774 94 110 Regulatory adjustment (a) 247 483 — — Net periodic cost $ 3,288 $ 3,257 $ 94 $ 110 _______________ (a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices. Pension Benefits Post-retirement Benefits Six Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 3,900 $ 3,374 $ 73 $ 64 Interest cost 4,950 4,828 140 163 Expected return on plan assets (5,286 ) (4,861 ) — — Amortization of unrecognized: Prior service costs 28 28 — — Actuarial loss (gain), net 2,490 2,178 (25 ) (8 ) Net periodic cost before regulatory adjustment 6,082 5,547 188 219 Regulatory adjustment (a) 494 966 — — Net periodic cost $ 6,576 $ 6,513 $ 188 $ 219 _______________ (a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices. During the six months ended June 30, 2017 , we did not fund Wolf Creek’s pension plan. During the six months ended June 30, 2016, we funded $3.2 million of Wolf Creek’s pension plan contributions. |
Commitments And Contingencies
Commitments And Contingencies | 6 Months Ended |
Jun. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments And Contingencies | COMMITMENTS AND CONTINGENCIES Environmental Matters Set forth below are descriptions of contingencies related to environmental matters that may impact us or our financial results. Our assessment of these contingencies, which are based on federal and state statutes and regulations, and regulatory agency and judicial interpretations and actions, has evolved over time. There are a variety of final and proposed laws and regulations that could have a material adverse effect on our operations and condensed consolidated financial results. Due in part to the complex nature of environmental laws and regulations, we are unable to assess the impact of potential changes that may develop with respect to the environmental contingencies described below. Cross-State Air Pollution Update Rule In September 2016, the Environmental Protection Agency (EPA) finalized the Cross-State Air Pollution Update Rule. The final rule addresses interstate transport of nitrogen oxide (NOx) emissions in 22 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the final rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. Various states and others are challenging the rule in the U.S. Court of Appeals for the D.C. Circuit. We do not believe this rule will have a material impact on our operations and condensed consolidated financial results. National Ambient Air Quality Standards Under the federal Clean Air Act (CAA), the EPA sets NAAQS for certain emissions known as the “criteria pollutants” considered harmful to public health and the environment, including two classes of particulate matter (PM), ozone, NOx (a precursor to ozone), carbon monoxide and sulfur dioxide (SO 2 ), which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 ppb to 70 ppb. In September 2016, the Kansas Department of Health & Environment (KDHE) recommended to the EPA that they designate eight counties in the state of Kansas as in attainment with the standard, and each remaining county in Kansas as in attainment/unclassifiable. The EPA is required to make attainment/nonattainment designations for the revised standards by October 2017, with an option to extend this deadline by one year. If the EPA agrees with the recommended designations for the state of Kansas, we do not believe this will have a material impact on our condensed 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 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We do not believe this will have a material impact on our operations or condensed consolidated financial results. In 2010, the EPA revised the NAAQS for SO 2 . In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO 2 emissions criteria for certain electric generating plants that, if met, required the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants. Tecumseh Energy Center is our only generating station that meets this criteria. In June 2016, the EPA accepted the State of Kansas recommendation to designate the areas surrounding the facility as unclassifiable, completing the second round of the designation process. In addition, in January 2017, KDHE formally recommended to the EPA a 2,000 ton per year limit for Tecumseh Energy Center Unit 7 in order to satisfy the requirements of the 1-hour SO 2 Data Requirements Rule that governs the next round of the designations. By agreeing to the 2,000 ton per year limitation, no further characterization of the area surrounding the plant is required. We continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and condensed consolidated financial results. If areas surrounding our facilities are designated in the future as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and condensed consolidated financial results. Greenhouse Gases Burning coal and other fossil fuels releases carbon dioxide (CO 2 ) and other gases referred to as GHG. Various regulations under the federal CAA limit CO 2 and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions. In October 2015, the EPA published a rule establishing new source performance standards (NSPS) for GHGs that limit CO 2 emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per 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 February 2016, after the U.S. Court of Appeals for the D.C. Circuit denied requests to stay the CPP, the U.S. Supreme Court issued an order granting a stay of the rule pending resolution of the legal challenges. In September 2016, oral arguments were heard before an en banc panel of D.C. Circuit judges and a decision on the legal challenges is pending. In March 2017, President Trump signed an Executive Order instructing the EPA to immediately review the CPP and GHG NSPS, and “if appropriate . . . as soon as practicable . . . publish for notice and comment proposed rules suspending, revising or rescinding those rules.” On the same day the Executive Order was signed, the EPA filed motions with the D.C. Circuit asking the court to hold the challenges to the CPP and the GHG NSPS in abeyance while the EPA completes its administrative review of the rules and issues any forthcoming rulemakings. In April 2017, the court issued orders to hold the cases in abeyance for 60 days and requested briefing on whether the cases should be remanded to the EPA or continue to be held in abeyance. In May 2017, all parties in the case filed supplemental briefs stating their positions regarding remanding the rule back to the EPA or continuing to hold the case in abeyance. Also in April 2017, the EPA published in the Federal Register a notice of withdrawal of the proposed CPP federal plan, proposed model trading rules and proposed Clean Energy Incentive Program design details, in light of the Executive Order and the agency’s review of the CPP. Also in April 2017, the EPA published a notice in the Federal Register that it is initiating administrative reviews of the CPP and the GHG NSPS in light of the Executive Order. Due to the future uncertainty of the CPP, we cannot determine the impact on our operations or condensed consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material. Water We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes effluent limitations guidelines (ELGs) and standards for wastewater discharges, including limits on the amount of toxic metals and other pollutants that can be discharged. Implementation timelines for these requirements vary from 2019 to 2023. In April 2017, the EPA announced it is reconsidering the ELG rule and court challenges have been placed in abeyance pending the EPA’s review. In June 2017, the EPA proposed a rule to postpone the compliance dates for the new, more stringent, effluent limitations and pretreatment standards for each of the following waste streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater. These compliance dates would be postponed until the EPA completes its administrative reconsideration of the ELG rule. We are evaluating the final rule and related developments and cannot predict the resulting impact on our operations or condensed consolidated financial results, but believe costs to comply could be material if the rule is implemented in its current or substantially similar form. In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule’s impact on those two plants and cannot predict the resulting impact on our operations or condensed consolidated financial results, but we do not expect it to be material. In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States (WOTUS) for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states and others have filed lawsuits challenging the WOTUS rule in district courts and courts of appeals across the country. The appellate court challenges have been consolidated in the U.S. Court of Appeals for the Sixth Circuit and, in October 2015, the Sixth Circuit issued an order that temporarily stays implementation of the WOTUS rule nationwide pending the outcome of the various legal challenges. In 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. We are currently evaluating the WOTUS rule and related developments. We do not believe the rule, if upheld and implemented in its current or substantially similar form, will have a material impact on our operations or condensed consolidated financial results. Regulation of Coal Combustion Residuals In the course of operating our coal generation plants, we produce coal combustion residuals (CCRs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCRs in April 2015, which we believe will require additional CCR handling, processing and storage equipment and closure of certain ash disposal ponds. Impacts to operations will be dependent on the development of groundwater monitoring of CCR units being completed in 2017. 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. We have recorded an ARO for our current estimate for closure of ash disposal ponds but we may be required to record additional AROs in the future due to changes in existing CCR regulations, changes in interpretation of existing CCR regulations or changes in the timing or cost to close ash disposal ponds. If additional AROs are necessary, we believe the impact on our operations or condensed consolidated financial results could be material. 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. In 2017, the SPP notified us that it would be issuing revised allocations. Due to the complexity of the allocation process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and the complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate whether the amount we previously paid will change. If the SPP’s revised calculation allocates additional charges to us, we believe that most of the additional charges will be recovered from our customers in future prices. Storage of Spent Nuclear Fuel In 2010, the Department of Energy (DOE) filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision. Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. 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 began 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. We plan to apply for reimbursement of additional costs incurred after 2015. 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. |
Asset Retirement Obligations (N
Asset Retirement Obligations (Notes) | 6 Months Ended |
Jun. 30, 2017 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligation Disclosure [Text Block] | ASSET RETIREMENT OBLIGATIONS In 2017, we recorded a new ARO liability of approximately $13.5 million corresponding to placing Western Plains Wind Farm in service. In addition, we revised our AROs by $34.7 million relating to asbestos removal, CCR and other owned windfarms. See Note 11, “Commitments and Contingencies - Regulation of Coal Combustion Residuals,” for additional information related to the CCR rule. The change in the balance of our ARO liability from December 31, 2016, through June 30, 2017, is summarized in the following table. (In Thousands) Balance as of December 31, 2016 $ 323,951 Increase in ARO liabilities 13,471 Liabilities settled (1,431 ) Accretion expense 8,077 Revisions in estimated cash flows 34,713 Balance as of June 30, 2017 378,781 Balance included in other current liabilities (10,548 ) Long-term AROs $ 368,233 |
Legal Proceedings
Legal Proceedings | 6 Months Ended |
Jun. 30, 2017 | |
Legal Proceedings [Abstract] | |
Legal Proceedings | 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 condensed consolidated financial results. See Note 4, “Rate Matters and Regulation,” and Note 11, “Commitments and Contingencies,” for additional information. Pending Merger Following the announcement of the original merger agreement, two putative class action complaints (which were consolidated and superseded by a consolidated complaint) and one putative derivative complaint challenging the merger were filed in the District Court of Shawnee County, Kansas. The consolidated putative class action complaint, filed on July 25, 2016, is captioned In re Westar Energy, Inc. Stockholder Litigation, Case No. 2016-CV-000457. This complaint names as defendants Westar Energy, the members of our board of directors and Great Plains Energy. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the original merger. It also asserts that Westar Energy and Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that (i) the original merger consideration deprived our shareholders of fair consideration for their shares, (ii) the original merger agreement contained deal protection provisions that unfairly favored Great Plains Energy and discouraged third parties from submitting potentially superior proposals, (iii) the disclosures were misleading and/or omitted material information necessary for our shareholders to make an informed decision whether to vote in favor of the original merger and (iv) if the original merger were to have been consummated, certain of our directors and officers may have received significant benefits. The complaint seeks, among other remedies, (i) injunctive relief enjoining the original merger, (ii) rescission of the original merger agreement or rescissory damages, (iii) a directive to members of our board of directors to account for all damages caused by them as a result of their breaches of their fiduciary duties and (iv) an award for costs and disbursements, including attorneys’ fees and experts’ fees. The putative derivative complaint, filed on July 5, 2016, and as amended on August 25, 2016, is captioned Braunstein v. Chandler et al., Case No. 2016-CV-000502. This putative derivative action names as defendants the members of our board of directors, Great Plains Energy and a subsidiary of Great Plains Energy, with Westar Energy named as a nominal defendant. The complaint asserts that the members of our board of directors breached their fiduciary duties to our shareholders in connection with the original merger. It also asserts that Great Plains Energy and a subsidiary of Great Plains Energy aided and abetted such breaches of fiduciary duties. The complaint alleges, among other things, that the members of our board of directors failed to obtain the best possible price for our shareholders in the original merger because of a flawed process that discouraged third parties from submitting potentially superior proposals, and that the disclosures are false or misleading due to the omission of certain information. The complaint seeks, among other remedies, (i) a direction that the director defendants exercise their fiduciary duties to obtain a transaction which is in the best interests of us and our shareholders, (ii) a declaration that the original merger was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable, (iii) rescission of the original merger agreement, (iv) 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, (v) award for costs, including attorneys’ fees and experts’ fees, and (vi) the imposition of an injunction against the defendants and others from consummating the original merger on the terms proposed. On September 21, 2016, the parties in the consolidated putative class action and the putative derivative complaint 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, the parties in the putative derivative complaint agreed that we would make supplemental disclosures to the shareholders, which disclosures were made in a Form 8-K filed on September 21, 2016, and the parties in the consolidated putative class action agreed that we would (i) make the disclosures in the Form 8-K filed on September 21, 2016, and (ii) 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 the our sale process. These agreements do not constitute any admission by any of the defendants as to the merits of any claims. The September 2016 agreement in principle may be null and void as a result of entering into the amended and restated merger agreement in July 2017. The outcome of litigation is inherently uncertain, and we cannot predict how existing litigation will progress, or whether additional claims may result from the amended and restated merger agreement. 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. |
Variable Interest Entities
Variable Interest Entities | 6 Months Ended |
Jun. 30, 2017 | |
Variable Interest Entities [Abstract] | |
Variable Interest Entities | VARIABLE INTEREST ENTITIES In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in Jeffrey Energy Center (JEC) and our 50% interest in La Cygne unit 2 are VIEs. Upon the expiration of a purchase option in July 2017, we are no longer the primary beneficiary of the trust holding our 8% interest in JEC. 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 VIEs with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary. 8% Interest in Jeffrey Energy Center Under an agreement that expires in January 2019 , we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We 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 will deconsolidate the trust in the third quarter. In determining the primary beneficiary of the trust, we had concluded 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 condensed consolidated balance sheets related to the VIEs described above. As of As of June 30, 2017 December 31, 2016 (In Thousands) Assets: Property, plant and equipment of variable interest entities, net $ 252,737 $ 257,904 Regulatory assets (a) 11,155 10,396 Liabilities: Current maturities of long-term debt of variable interest entities $ 28,538 $ 26,842 Accrued interest (b) 706 867 Long-term debt of variable interest entities, net 82,653 111,209 _______________ (a) Included in long-term regulatory assets on our condensed consolidated balance sheets. (b) Included in accrued interest on our condensed 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. |
Summary Of Significant Accoun22
Summary Of Significant Accounting Policies (Policy) | 6 Months Ended |
Jun. 30, 2017 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Pronouncements We prepare our condensed consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements that may affect our accounting and/or disclosure. Compensation - Retirement Benefits In March 2017, the FASB issued Accounting Standard Update No. 2017-07, which requires employers to disaggregate the service cost component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are included in each income statement line item. The standard requires employers to report the service cost component in the same line item as other compensation costs and to report the other components of net periodic benefit costs (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) separately and outside a subtotal of operating income. Of the components of net periodic benefit cost, only the service cost component will be eligible for capitalization as property, plant and equipment, which is to be applied prospectively. The other components of net periodic benefit costs that are no longer eligible for capitalization as property, plant and equipment will be recorded as a regulatory asset. The guidance changing the presentation in the statements of income is to be applied on a retrospective basis. The new standard is effective for annual periods beginning after December 15, 2017. We are evaluating the guidance and do not expect it to have a material impact on our condensed consolidated financial statements. Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. Subsequent ASUs have been released providing modifications and clarifications to ASU No. 2014-09. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. This guidance is effective for fiscal years beginning after December 15, 2017. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or modified retrospective method. We will 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. We continue to analyze the impact of the new revenue standard and related ASUs. We completed initial revenue contract assessments. In summary, material revenue streams were identified and representative contract/transaction types were sampled. We also continue to monitor unresolved industry issues, including items related to contributions in aid of construction, collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. We are finalizing our changes to revenue-related disclosure and ensuring we have effective internal controls over financial reporting. Based upon our completed assessments, we do not expect the impact on our condensed consolidated financial statements to be material. |
Principles Of Consolidation | Principles of Consolidation We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) for the United States of America have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of the condensed consolidated financial statements, have been included. |
Use Of Management's Estimates | Use of Management’s Estimates When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2017 , are not necessarily indicative of the results to be expected for the full year. |
Fuel Inventory And Supplies | Fuel Inventory and Supplies We state fuel inventory and supplies at average cost. |
Allowance For Funds Used During Construction | Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost |
Earnings Per Share | Earnings Per Share We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS). To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method. |
Summary Of Significant Accoun23
Summary Of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Utility Inventory | Following are the balances for fuel inventory and supplies stated separately. As of As of June 30, 2017 December 31, 2016 (In Thousands) Fuel inventory $ 106,764 $ 107,086 Supplies 195,932 193,039 Fuel inventory and supplies $ 302,696 $ 300,125 |
Allowance For Funds Used During Construction | We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying condensed consolidated statements of income as follows. Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (Dollars In Thousands) Borrowed funds $ 895 $ 2,338 $ 2,748 $ 4,347 Equity funds — 2,783 773 5,247 Total $ 895 $ 5,121 $ 3,521 $ 9,594 Average AFUDC Rates 1.5 % 4.2 % 2.0 % 4.6 % |
Reconciliation Of Basic And Diluted EPS | The following table reconciles our basic and diluted EPS from net income. Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (Dollars In Thousands, Except Per Share Amounts) Net income $ 76,039 $ 76,144 $ 139,521 $ 144,852 Less: Net income attributable to noncontrolling interests 3,974 3,804 7,795 6,927 Net income attributable to Westar Energy, Inc. 72,065 72,340 131,726 137,925 Less: Net income allocated to RSUs 130 156 237 290 Net income allocated to common stock $ 71,935 $ 72,184 $ 131,489 $ 137,635 Weighted average equivalent common shares outstanding – basic 142,465,749 142,033,842 142,451,266 142,013,344 Effect of dilutive securities: RSUs 130,607 463,493 127,989 348,003 Weighted average equivalent common shares outstanding – diluted (a) 142,596,356 142,497,335 142,579,255 142,361,347 Earnings per common share, basic $ 0.50 $ 0.51 $ 0.92 $ 0.97 Earnings per common share, diluted $ 0.50 $ 0.51 $ 0.92 $ 0.97 _______________ (a) We had no antidilutive securities for the three and six months ended June 30, 2017 and 2016 . |
Supplemental Cash Flow Information | Six Months Ended June 30, 2017 2016 (In Thousands) CASH PAID FOR (RECEIVED FROM): Interest on financing activities, net of amount capitalized $ 76,024 $ 70,697 Interest on financing activities of VIEs 1,696 4,150 Income taxes, net of refunds (12,685 ) (77 ) NON-CASH INVESTING TRANSACTIONS: Property, plant and equipment additions 89,899 71,830 NON-CASH FINANCING TRANSACTIONS: Issuance of stock for compensation and reinvested dividends 4,801 4,941 Assets acquired through capital leases 3,054 392 |
Financial Instruments and Ris24
Financial Instruments and Risk Management (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Financial And Derivative Instruments and Trading Securities [Abstract] | |
Carrying Values And Fair Values Of Financial Instruments | The following table provides the carrying values and measured fair values of our fixed-rate debt. As of June 30, 2017 As of December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In Thousands) Fixed-rate debt $ 3,605,000 $ 3,846,301 $ 3,430,000 $ 3,597,441 Fixed-rate debt of VIEs 111,122 111,850 137,962 139,733 |
Fair Value Of Assets And Liabilities | The following table provides the amounts and their corresponding level of hierarchy for our assets that are measured at fair value. As of June 30, 2017 Level 1 Level 2 Level 3 NAV Total (In Thousands) Nuclear Decommissioning Trust: Domestic equity funds $ — $ 61,322 $ — $ 5,048 $ 66,370 International equity funds — 42,888 — — 42,888 Core bond fund — 32,378 — — 32,378 High-yield bond fund — 17,377 — — 17,377 Emerging markets bond fund — 16,873 — — 16,873 Combination debt/equity/other fund — 13,048 — — 13,048 Alternative investments fund — — — 20,584 20,584 Real estate securities fund — — — 10,380 10,380 Cash equivalents 133 — — — 133 Total Nuclear Decommissioning Trust 133 183,886 — 36,012 220,031 Trading Securities: Domestic equity funds — 17,523 — — 17,523 International equity fund — 4,361 — — 4,361 Core bond fund — 11,739 — — 11,739 Total Trading Securities — 33,623 — — 33,623 Total Assets Measured at Fair Value $ 133 $ 217,509 $ — $ 36,012 $ 253,654 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 |
Unrealized Gains And Losses On Fair Value Assets And Liabilities | |
Investments In Financial Instruments | The following table provides additional information on these investments. As of June 30, 2017 As of December 31, 2016 As of June 30, 2017 Fair Value Unfunded Commitments Fair Value Unfunded Commitments Redemption Frequency Length of Settlement (In Thousands) Nuclear Decommissioning Trust: Domestic equity funds $ 5,048 $ 3,129 $ 5,056 $ 3,529 (a) (a) Alternative investments fund (b) 20,584 — 18,958 — Quarterly 65 days Real estate securities fund (b) 10,380 — 9,946 — Quarterly 65 days Total $ 36,012 $ 3,129 $ 33,960 $ 3,529 _______________ (a) This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in 2013. Our initial investment in the fourth fund occurred in the second quarter of 2016. The term of the third and fourth fund is 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods. (b) There is a holdback on final redemptions. |
Financial Investments (Tables)
Financial Investments (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Investments [Abstract] | |
Cost And Fair Value Of Investments | The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of June 30, 2017 , and December 31, 2016 . Gross Unrealized Security Type Cost Gain Loss Fair Value Allocation (Dollars In Thousands) As of June 30, 2017: Domestic equity funds $ 54,563 $ 12,260 $ (453 ) $ 66,370 30 % International equity funds 35,664 7,224 — 42,888 19 % Core bond fund 32,542 — (164 ) 32,378 15 % High-yield bond fund 17,060 317 — 17,377 8 % Emerging markets bond fund 17,047 — (174 ) 16,873 8 % Combination debt/equity/other fund 7,980 5,068 — 13,048 6 % Alternative investments fund 15,000 5,584 — 20,584 9 % Real estate securities fund 9,500 880 — 10,380 5 % Cash equivalents 133 — — 133 <1% Total $ 189,489 $ 31,333 $ (791 ) $ 220,031 100 % 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 % |
Fair Value And Gross Unrealized Losses Of Available-For-Sale Securities | June 30, 2017 , and December 31, 2016 . Less than 12 Months 12 Months or Greater Total Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses (In Thousands) As of June 30, 2017: Domestic equity funds $ 3,780 $ (453 ) $ — $ — $ 3,780 $ (453 ) Core bond fund 32,378 (164 ) — — 32,378 (164 ) Emerging markets bond fund — — 16,873 (174 ) 16,873 (174 ) Total $ 36,158 $ (617 ) $ 16,873 $ (174 ) $ 53,031 $ (791 ) 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 ) |
Pension and Post-Retirement B26
Pension and Post-Retirement Benefit Plans (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Net Periodic Benefit Costs [Table Text Block] | The following tables summarize the net periodic costs for our pension and post-retirement benefit plans prior to the effects of capitalization. Pension Benefits Post-retirement Benefits Three Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 5,218 $ 4,633 $ 271 $ 271 Interest cost 10,621 10,921 1,314 1,393 Expected return on plan assets (10,760 ) (10,663 ) (1,718 ) (1,708 ) Amortization of unrecognized: Prior service costs 171 174 114 114 Actuarial loss (gain), net 5,489 5,146 (195 ) (280 ) Net periodic cost (benefit) before regulatory adjustment 10,739 10,211 (214 ) (210 ) Regulatory adjustment (a) 3,288 3,306 (478 ) (486 ) Net periodic cost (benefit) $ 14,027 $ 13,517 $ (692 ) $ (696 ) _______________ (a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices. Pension Benefits Post-retirement Benefits Six Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 10,437 $ 9,297 $ 542 $ 542 Interest cost 21,242 21,880 2,627 2,786 Expected return on plan assets (21,520 ) (21,326 ) (3,436 ) (3,417 ) Amortization of unrecognized: Prior service costs 341 420 228 228 Actuarial loss (gain), net 10,978 10,534 (390 ) (560 ) Net periodic cost (benefit) before regulatory adjustment 21,478 20,805 (429 ) (421 ) Regulatory adjustment (a) 6,576 6,613 (956 ) (972 ) Net periodic cost (benefit) $ 28,054 $ 27,418 $ (1,385 ) $ (1,393 ) _______________ (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. |
Wolf Creek Pension and Post-R27
Wolf Creek Pension and Post-Retirement Benefit Plans (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Wolf Creek Pension And Post-Retirement Benefit Plans [Line Items] | |
Schedule of Net Periodic Benefit Costs [Table Text Block] | The following tables summarize the net periodic costs for our pension and post-retirement benefit plans prior to the effects of capitalization. Pension Benefits Post-retirement Benefits Three Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 5,218 $ 4,633 $ 271 $ 271 Interest cost 10,621 10,921 1,314 1,393 Expected return on plan assets (10,760 ) (10,663 ) (1,718 ) (1,708 ) Amortization of unrecognized: Prior service costs 171 174 114 114 Actuarial loss (gain), net 5,489 5,146 (195 ) (280 ) Net periodic cost (benefit) before regulatory adjustment 10,739 10,211 (214 ) (210 ) Regulatory adjustment (a) 3,288 3,306 (478 ) (486 ) Net periodic cost (benefit) $ 14,027 $ 13,517 $ (692 ) $ (696 ) _______________ (a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices. Pension Benefits Post-retirement Benefits Six Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 10,437 $ 9,297 $ 542 $ 542 Interest cost 21,242 21,880 2,627 2,786 Expected return on plan assets (21,520 ) (21,326 ) (3,436 ) (3,417 ) Amortization of unrecognized: Prior service costs 341 420 228 228 Actuarial loss (gain), net 10,978 10,534 (390 ) (560 ) Net periodic cost (benefit) before regulatory adjustment 21,478 20,805 (429 ) (421 ) Regulatory adjustment (a) 6,576 6,613 (956 ) (972 ) Net periodic cost (benefit) $ 28,054 $ 27,418 $ (1,385 ) $ (1,393 ) _______________ (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. |
Wolf Creek [Member] | |
Wolf Creek Pension And Post-Retirement Benefit Plans [Line Items] | |
Schedule of Net Periodic Benefit Costs [Table Text Block] | The following tables summarize the net periodic costs for KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans prior to the effects of capitalization. Pension Benefits Post-retirement Benefits Three Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 1,950 $ 1,687 $ 37 $ 32 Interest cost 2,475 2,414 70 82 Expected return on plan assets (2,643 ) (2,430 ) — — Amortization of unrecognized: Prior service costs 14 14 — — Actuarial loss (gain), net 1,245 1,089 (13 ) (4 ) Net periodic cost before regulatory adjustment 3,041 2,774 94 110 Regulatory adjustment (a) 247 483 — — Net periodic cost $ 3,288 $ 3,257 $ 94 $ 110 _______________ (a) The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices. Pension Benefits Post-retirement Benefits Six Months Ended June 30, 2017 2016 2017 2016 (In Thousands) Components of Net Periodic Cost (Benefit): Service cost $ 3,900 $ 3,374 $ 73 $ 64 Interest cost 4,950 4,828 140 163 Expected return on plan assets (5,286 ) (4,861 ) — — Amortization of unrecognized: Prior service costs 28 28 — — Actuarial loss (gain), net 2,490 2,178 (25 ) (8 ) Net periodic cost before regulatory adjustment 6,082 5,547 188 219 Regulatory adjustment (a) 494 966 — — Net periodic cost $ 6,576 $ 6,513 $ 188 $ 219 _______________ (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. |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Variable Interest Entities [Abstract] | |
Assets And Liabilities of VIEs | We have recorded the following assets and liabilities on our condensed consolidated balance sheets related to the VIEs described above. As of As of June 30, 2017 December 31, 2016 (In Thousands) Assets: Property, plant and equipment of variable interest entities, net $ 252,737 $ 257,904 Regulatory assets (a) 11,155 10,396 Liabilities: Current maturities of long-term debt of variable interest entities $ 28,538 $ 26,842 Accrued interest (b) 706 867 Long-term debt of variable interest entities, net 82,653 111,209 _______________ (a) Included in long-term regulatory assets on our condensed consolidated balance sheets. (b) Included in accrued interest on our condensed consolidated balance sheets. |
Description Of Business (Detail
Description Of Business (Details) | 6 Months Ended |
Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of customers in Kansas | 708,000 |
Summary Of Significant Accoun30
Summary Of Significant Accounting Policies (Fuel Inventory And Supplies) (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
Public Utilities, Inventory [Line Items] | ||
Total | $ 302,696 | $ 300,125 |
Fuel Inventory [Member] | ||
Public Utilities, Inventory [Line Items] | ||
Public Utility Inventory | 106,764 | 107,086 |
Supplies [Member] | ||
Public Utilities, Inventory [Line Items] | ||
Public Utility Inventory | $ 195,932 | $ 193,039 |
Summary Of Significant Accoun31
Summary Of Significant Accounting Policies (Allowance For Funds Used During Construction) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Accounting Policies [Abstract] | ||||
Borrowed funds | $ (895) | $ (2,338) | $ (2,748) | $ (4,347) |
Equity funds | 0 | 2,783 | 773 | 5,247 |
Total | $ 895 | $ 5,121 | $ 3,521 | $ 9,594 |
Average AFUDC rates | 1.50% | 4.20% | 2.00% | 4.60% |
Summary Of Significant Accoun32
Summary Of Significant Accounting Policies (Reconciliation Of Basic And Diluted EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Accounting Policies [Abstract] | ||||
Participating Securities, Distributed and Undistributed Earnings (Loss), Basic | $ 130 | $ 156 | $ 237 | $ 290 |
Net income allocated to common stock | $ 71,935 | $ 72,184 | $ 131,489 | $ 137,635 |
Weighted Average Number of Shares Outstanding , Basic | 142,465,749 | 142,033,842 | 142,451,266 | 142,013,344 |
RSUs | 130,607 | 463,493 | 127,989 | 348,003 |
Weighted average equivalent common shares outstanding - diluted | 142,596,356 | 142,497,335 | 142,579,255 | 142,361,347 |
Earnings Per Share, Basic | $ 0.50 | $ 0.51 | $ 0.92 | $ 0.97 |
Earnings Per Share, Diluted | $ 0.50 | $ 0.51 | $ 0.92 | $ 0.97 |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive securities | 0 |
Summary Of Significant Accoun33
Summary Of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
Cash Paid For (Received From) | ||
Interest on financing activities | $ 76,024 | $ 70,697 |
Income taxes, net of refunds | (12,685) | (77) |
Noncash Investing and Financing Transactions | ||
Property, plant and equipment | 89,899 | 71,830 |
Issuance of common stock for reinvested dividends and compensation plans | 4,801 | 4,941 |
Deconsolidation of VIE | (5,760) | |
Assets acquired through capital leases | 3,054 | 392 |
Variable Interest Entity, Primary Beneficiary [Member] | ||
Cash Paid For (Received From) | ||
Interest on financing activities | $ 1,696 | $ 4,150 |
Summary Of Significant Accoun34
Summary Of Significant Accounting Policies New Accounting Pronouncements (Details) | 3 Months Ended |
Jun. 30, 2016 | |
Item Effected [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Description | 3,326 |
Pending Merger Pending Merger35
Pending Merger Pending Merger (Narrative) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | |
Jul. 31, 2017 | Jun. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2016 | Jul. 09, 2017 | |
Westar Energy [Member] | Subsequent Event [Member] | |||||
Business Combination [Line Items] | |||||
Business Combination, Share Conversion Ratio | 1 | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 52.50% | ||||
Westar Energy [Member] | Subsequent Event [Member] | Westar Energy breaches agreement and enters into acquisition proposal within 12 months of termination, paid to Great Plains Energy [Member] [Domain] | |||||
Business Combination [Line Items] | |||||
Business Combination Merger Contract Termination Fee | $ 190 | ||||
Great Plains Energy, Inc. Merger [Member] | |||||
Business Combination [Line Items] | |||||
Business Combination, Acquisition Related Costs | $ 0.3 | $ 0.7 | $ 10.2 | ||
Business Combination, Expected Acquisition Related Costs | $ 45 | ||||
Great Plains Energy, Inc. Merger [Member] | Subsequent Event [Member] | |||||
Business Combination [Line Items] | |||||
Business Combination, Share Conversion Ratio | 0.5981 | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 47.50% | ||||
Cash | $ 1,250 | ||||
Business Combination, Expected Acquisition Related Costs | $ 7.5 | ||||
Great Plains Energy, Inc. Merger [Member] | Subsequent Event [Member] | End date occurred and Great Plains Energy enters into acquisition proposal within 12 months of termination, paid to Westar Energy [Member] [Domain] | |||||
Business Combination [Line Items] | |||||
Business Combination Merger Contract Termination Fee | 190 | ||||
Great Plains Energy, Inc. Merger [Member] | Subsequent Event [Member] | Great Plains Energy breaches merger agreement and enters into acquisition proposal within 12 months of termination [Member] [Domain] | |||||
Business Combination [Line Items] | |||||
Business Combination Merger Contract Termination Fee | 190 | ||||
Great Plains Energy, Inc. Merger [Member] | Subsequent Event [Member] | Great Plains shareholder no vote, paid to Westar Energy [Domain] | |||||
Business Combination [Line Items] | |||||
Business Combination Merger Contract Termination Fee | $ 80 |
Rate Matters And Regulation (Na
Rate Matters And Regulation (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | |||
Jun. 30, 2017 | Apr. 30, 2017 | Jan. 31, 2017 | Dec. 31, 2016 | |
Kansas Corporation Commission [Member] | Electric Transmission [Member] | ||||
Regulatory Proceedings [Line Items] | ||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 16.4 | |||
Kansas Corporation Commission [Member] | Kansas Corporation Commission [Member] | ||||
Regulatory Proceedings [Line Items] | ||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 12.7 | |||
Kansas Corporation Commission [Member] | Ad Valorem Tax [Member] | ||||
Regulatory Proceedings [Line Items] | ||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 26.8 | |||
Federal Energy Regulatory Commission [Member] | Electric Transmission [Member] | ||||
Regulatory Proceedings [Line Items] | ||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 29.6 |
Financial Instruments and Ris37
Financial Instruments and Risk Management (Carrying Values And Fair Values Of Financial Instruments) (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
Fixed Rate Debt Member | ||
Debt Instrument [Line Items] | ||
Carrying Value | $ 3,605,000 | $ 3,430,000 |
Fair Value | 3,846,301 | 3,597,441 |
Fixed Rate Debt Of Variable Interest Entities Member | ||
Debt Instrument [Line Items] | ||
Carrying Value | 111,122 | 137,962 |
Fair Value | $ 111,850 | $ 139,733 |
Financial Instruments and Ris38
Financial Instruments and Risk Management (Fair Value Of Assets And Liabilities) (Details) - USD ($) $ in Thousands | 6 Months Ended | ||
Jun. 30, 2017 | Dec. 31, 2016 | ||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction Period | [1] | 15 years | |
Nuclear decommissioning trust assets | $ 220,031 | $ 200,122 | |
Trading securities | 33,623 | 34,491 | |
Total assets measured at fair value | 253,654 | 234,613 | |
Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 133 | 73 | |
Trading securities | 0 | 156 | |
Total assets measured at fair value | 133 | 229 | |
Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 183,886 | 166,089 | |
Trading securities | 33,623 | 34,335 | |
Total assets measured at fair value | 217,509 | 200,424 | |
Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
Total assets measured at fair value | 0 | 0 | |
Domestic Equity [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 66,370 | 61,368 | |
Trading securities | 17,523 | 18,364 | |
Domestic Equity [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
Domestic Equity [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 61,322 | 56,312 | |
Trading securities | 17,523 | 18,364 | |
Domestic Equity [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
International Equity [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 42,888 | 35,944 | |
Trading securities | 4,361 | 4,467 | |
International Equity [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
International Equity [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 42,888 | 35,944 | |
Trading securities | 4,361 | 4,467 | |
International Equity [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
Core Bonds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 32,378 | 27,423 | |
Trading securities | 11,739 | 11,504 | |
Core Bonds [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
Core Bonds [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 32,378 | 27,423 | |
Trading securities | 11,739 | 11,504 | |
Core Bonds [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
High-Yield Bonds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 17,377 | 18,188 | |
High-Yield Bonds [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
High-Yield Bonds [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 17,377 | 18,188 | |
High-Yield Bonds [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Emerging Market Bonds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 16,873 | 14,738 | |
Emerging Market Bonds [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Emerging Market Bonds [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 16,873 | 14,738 | |
Emerging Market Bonds [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Combination Debt Equity And Other Fund [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 13,048 | ||
Combination Debt Equity And Other Fund [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | ||
Combination Debt Equity And Other Fund [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 13,048 | ||
Combination Debt Equity And Other Fund [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | ||
Combination Debt and Equity Fund [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 13,484 | ||
Combination Debt and Equity Fund [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | ||
Combination Debt and Equity Fund [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 13,484 | ||
Combination Debt and Equity Fund [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | ||
Alternative Funds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 20,584 | 18,958 | |
Alternative Funds [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Alternative Funds [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Alternative Funds [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Real Estate Securities [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 10,380 | 9,946 | |
Real Estate Securities [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Real Estate Securities [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Real Estate Securities [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Cash Equivalents [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 133 | 73 | |
Trading securities | 156 | ||
Cash Equivalents [Member] | Level 1 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 133 | 73 | |
Trading securities | 156 | ||
Cash Equivalents [Member] | Level 2 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | ||
Cash Equivalents [Member] | Level 3 [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | ||
fair value, inputs, net asset value [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 36,012 | 33,960 | |
Trading securities | 0 | 0 | |
Total assets measured at fair value | 36,012 | 33,960 | |
fair value, inputs, net asset value [Member] | Domestic Equity [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 5,048 | 5,056 | |
Trading securities | 0 | 0 | |
fair value, inputs, net asset value [Member] | International Equity [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
fair value, inputs, net asset value [Member] | Core Bonds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
Trading securities | 0 | 0 | |
fair value, inputs, net asset value [Member] | High-Yield Bonds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
fair value, inputs, net asset value [Member] | Emerging Market Bonds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | 0 | |
fair value, inputs, net asset value [Member] | Combination Debt Equity And Other Fund [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | ||
fair value, inputs, net asset value [Member] | Combination Debt and Equity Fund [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 0 | ||
fair value, inputs, net asset value [Member] | Alternative Funds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 20,584 | 18,958 | |
fair value, inputs, net asset value [Member] | Real Estate Securities [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 10,380 | 9,946 | |
fair value, inputs, net asset value [Member] | Cash Equivalents [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | $ 0 | 0 | |
Trading securities | $ 0 | ||
[1] | subject to the general partner’s right to extend the term for up to three additional one-year periods. |
Financial Instruments and Ris39
Financial Instruments and Risk Management (Investments In Financial Instruments) (Details) - USD ($) $ in Thousands | 6 Months Ended | ||
Jun. 30, 2017 | Dec. 31, 2016 | ||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | $ 220,031 | $ 200,122 | |
Trading securities | 33,623 | 34,491 | |
Total | 253,654 | 234,613 | |
Fair Value [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 36,012 | 33,960 | |
Decommissioning Trust Assets [Member] | Fair Value [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Unfunded commitments | 3,129 | 3,529 | |
Domestic Equity [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 66,370 | 61,368 | |
Trading securities | 17,523 | 18,364 | |
Domestic Equity [Member] | Fair Value [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | [1] | 5,048 | 5,056 |
Unfunded commitments | 3,129 | 3,529 | |
Alternative Funds [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 20,584 | 18,958 | |
Alternative Funds [Member] | Fair Value [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 20,584 | 18,958 | |
Unfunded commitments | $ 0 | 0 | |
Investment redemption frequency | Quarterly | ||
Investment redemption length of settlement | [2] | 65 days | |
Real Estate Securities [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | $ 10,380 | 9,946 | |
Real Estate Securities [Member] | Fair Value [Member] | |||
Financial and Derivative Instruments and Trading Securities [Line Items] | |||
Nuclear decommissioning trust assets | 10,380 | 9,946 | |
Unfunded commitments | $ 0 | $ 0 | |
Investment redemption frequency | Quarterly | ||
Investment redemption length of settlement | 65 days | ||
[1] | This investment is in four long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated, which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in 2013. Our initial investment in the fourth fund occurred in the second quarter of 2016. | ||
[2] | There is a holdback on final redemptions. |
Financial Investments (Narrativ
Financial Investments (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Schedule of Available-for-sale Securities [Line Items] | |||||
Trading securities | $ 33,623 | $ 33,623 | $ 34,491 | ||
Unrealized gains losses | 1,100 | $ 600 | 2,500 | $ 1,100 | |
Realized gains on available-for-sale-securities | $ (200) | $ 100 | $ 100 | $ 1,400 |
Financial Investments (Cost And
Financial Investments (Cost And Fair Value Of Investments) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Schedule of Available-for-sale Securities [Line Items] | |||||
Trading Securities, Change in Unrealized Holding Gain (Loss) | $ 1,100 | $ 600 | $ 2,500 | $ 1,100 | |
Trading securities | 33,623 | 33,623 | $ 34,491 | ||
Cost | 189,489 | 189,489 | 184,145 | ||
Available-for-sale Securities, Gross Unrealized Gain | 31,333 | 31,333 | 19,087 | ||
Available-for-sale Securities, Gross Unrealized Loss | (791) | (791) | (3,110) | ||
Available-for-sale Securities | $ 220,031 | $ 220,031 | $ 200,122 | ||
Allocation | 100.00% | 100.00% | 100.00% | ||
Domestic Equity [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Trading securities | $ 17,523 | $ 17,523 | $ 18,364 | ||
Cost | 54,563 | 54,563 | 53,192 | ||
Available-for-sale Securities, Gross Unrealized Gain | 12,260 | 12,260 | 8,295 | ||
Available-for-sale Securities, Gross Unrealized Loss | (453) | (453) | (119) | ||
Available-for-sale Securities | $ 66,370 | $ 66,370 | $ 61,368 | ||
Allocation | 30.00% | 30.00% | 31.00% | ||
International Equity [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Trading securities | $ 4,361 | $ 4,361 | $ 4,467 | ||
Cost | 35,664 | 35,664 | 34,502 | ||
Available-for-sale Securities, Gross Unrealized Gain | 7,224 | 7,224 | 2,075 | ||
Available-for-sale Securities, Gross Unrealized Loss | 0 | 0 | (633) | ||
Available-for-sale Securities | $ 42,888 | $ 42,888 | $ 35,944 | ||
Allocation | 19.00% | 19.00% | 18.00% | ||
Core Bonds [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Trading securities | $ 11,739 | $ 11,739 | $ 11,504 | ||
Cost | 32,542 | 32,542 | 27,952 | ||
Available-for-sale Securities, Gross Unrealized Gain | 0 | 0 | 0 | ||
Available-for-sale Securities, Gross Unrealized Loss | (164) | (164) | (529) | ||
Available-for-sale Securities | $ 32,378 | $ 32,378 | $ 27,423 | ||
Allocation | 15.00% | 15.00% | 14.00% | ||
High-Yield Bonds [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Cost | $ 17,060 | $ 17,060 | $ 18,358 | ||
Available-for-sale Securities, Gross Unrealized Gain | 317 | 317 | 0 | ||
Available-for-sale Securities, Gross Unrealized Loss | 0 | 0 | (170) | ||
Available-for-sale Securities | $ 17,377 | $ 17,377 | $ 18,188 | ||
Allocation | 8.00% | 8.00% | 9.00% | ||
Emerging Market Bonds [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Cost | $ 17,047 | $ 17,047 | $ 16,397 | ||
Available-for-sale Securities, Gross Unrealized Gain | 0 | 0 | 0 | ||
Available-for-sale Securities, Gross Unrealized Loss | (174) | (174) | (1,659) | ||
Available-for-sale Securities | $ 16,873 | $ 16,873 | $ 14,738 | ||
Allocation | 8.00% | 8.00% | 7.00% | ||
Combination Debt Equity And Other Fund [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Cost | $ 7,980 | $ 7,980 | |||
Available-for-sale Securities, Gross Unrealized Gain | 5,068 | 5,068 | |||
Available-for-sale Securities, Gross Unrealized Loss | 0 | 0 | |||
Available-for-sale Securities | $ 13,048 | $ 13,048 | |||
Allocation | 6.00% | 6.00% | |||
Combination Debt and Equity Fund [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Cost | $ 9,171 | ||||
Available-for-sale Securities, Gross Unrealized Gain | 4,313 | ||||
Available-for-sale Securities, Gross Unrealized Loss | 0 | ||||
Available-for-sale Securities | $ 13,484 | ||||
Allocation | 7.00% | ||||
Alternative Funds [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Cost | $ 15,000 | $ 15,000 | $ 15,000 | ||
Available-for-sale Securities, Gross Unrealized Gain | 5,584 | 5,584 | 3,958 | ||
Available-for-sale Securities, Gross Unrealized Loss | 0 | 0 | 0 | ||
Available-for-sale Securities | $ 20,584 | $ 20,584 | $ 18,958 | ||
Allocation | 9.00% | 9.00% | 9.00% | ||
Real Estate Securities [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Cost | $ 9,500 | $ 9,500 | $ 9,500 | ||
Available-for-sale Securities, Gross Unrealized Gain | 880 | 880 | 446 | ||
Available-for-sale Securities, Gross Unrealized Loss | 0 | 0 | 0 | ||
Available-for-sale Securities | $ 10,380 | $ 10,380 | $ 9,946 | ||
Allocation | 5.00% | 5.00% | 5.00% | ||
Cash Equivalents [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Trading securities | $ 156 | ||||
Cost | $ 133 | $ 133 | 73 | ||
Available-for-sale Securities, Gross Unrealized Gain | 0 | 0 | 0 | ||
Available-for-sale Securities, Gross Unrealized Loss | 0 | 0 | 0 | ||
Available-for-sale Securities | $ 133 | $ 133 | $ 73 |
Financial Investments (Fair Val
Financial Investments (Fair Value And The Gross Unrealized Losses Of the Available-For-Sale Securities) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Schedule of Available-for-sale Securities [Line Items] | |||||
Trading Securities, Change in Unrealized Holding Gain (Loss) | $ 1,100 | $ 600 | $ 2,500 | $ 1,100 | |
Fair Value, Less than 12 Months | 36,158 | 36,158 | $ 29,211 | ||
Gross Unrealized Losses, Less than 12 Months | (617) | (617) | (648) | ||
Fair Value, 12 Months or Greater | 16,873 | 16,873 | 40,415 | ||
Gross Unrealized Losses, 12 Months or Greater | (174) | (174) | (2,462) | ||
Fair Value, Total | 53,031 | 53,031 | 69,626 | ||
Gross Unrealized Losses, Total | (791) | (791) | (3,110) | ||
Domestic Equity [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value, Less than 12 Months | 3,780 | 3,780 | 1,788 | ||
Gross Unrealized Losses, Less than 12 Months | (453) | (453) | (119) | ||
Fair Value, 12 Months or Greater | 0 | 0 | 0 | ||
Gross Unrealized Losses, 12 Months or Greater | 0 | 0 | 0 | ||
Fair Value, Total | 3,780 | 3,780 | 1,788 | ||
Gross Unrealized Losses, Total | (453) | (453) | (119) | ||
International Equity [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value, Less than 12 Months | 0 | ||||
Gross Unrealized Losses, Less than 12 Months | 0 | ||||
Fair Value, 12 Months or Greater | 7,489 | ||||
Gross Unrealized Losses, 12 Months or Greater | (633) | ||||
Fair Value, Total | 7,489 | ||||
Gross Unrealized Losses, Total | (633) | ||||
Core Bonds [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value, Less than 12 Months | 32,378 | 32,378 | 27,423 | ||
Gross Unrealized Losses, Less than 12 Months | (164) | (164) | (529) | ||
Fair Value, 12 Months or Greater | 0 | 0 | 0 | ||
Gross Unrealized Losses, 12 Months or Greater | 0 | 0 | 0 | ||
Fair Value, Total | 32,378 | 32,378 | 27,423 | ||
Gross Unrealized Losses, Total | (164) | (164) | (529) | ||
High-Yield Bonds [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value, Less than 12 Months | 0 | ||||
Gross Unrealized Losses, Less than 12 Months | 0 | ||||
Fair Value, 12 Months or Greater | 18,188 | ||||
Gross Unrealized Losses, 12 Months or Greater | (170) | ||||
Fair Value, Total | 18,188 | ||||
Gross Unrealized Losses, Total | (170) | ||||
Emerging Market Bonds [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value, Less than 12 Months | 0 | 0 | 0 | ||
Gross Unrealized Losses, Less than 12 Months | 0 | 0 | 0 | ||
Fair Value, 12 Months or Greater | 16,873 | 16,873 | 14,738 | ||
Gross Unrealized Losses, 12 Months or Greater | (174) | (174) | (1,659) | ||
Fair Value, Total | 16,873 | 16,873 | 14,738 | ||
Gross Unrealized Losses, Total | $ (174) | $ (174) | $ (1,659) |
Debt Financing (Narrative) (Det
Debt Financing (Narrative) (Details) - Westar Energy [Member] - Secured Debt [Member] - USD ($) $ in Millions | 1 Months Ended | |
Jan. 31, 2017 | Mar. 06, 2017 | |
Debt Instrument Two [Member] | ||
Debt Instrument [Line Items] | ||
Repayments of Debt | $ 125 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.15% | |
Debt Instrument 8930 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | $ 300 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.10% |
Taxes Taxes (Narrative) (Detail
Taxes Taxes (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Income Tax Contingency [Line Items] | |||||
Income tax expense | $ 35,906 | $ 40,542 | $ 56,816 | $ 79,165 | |
Effective income tax rate | 32.00% | 35.00% | 29.00% | 35.00% | |
Liability for unrecognized income tax benefits | $ 2,800 | ||||
Interest on liability related to unrecognized income tax benefits | $ 100 | $ 100 | 0 | ||
Penalties accrued for unrecognized income tax benefits | 0 | 0 | 0 | ||
Accrual for taxes other than income taxes | $ 100 | $ 100 | $ 1,500 |
Pension and Post-Retirement B45
Pension and Post-Retirement Benefit Plans (Net Periodic Costs And Pension Contributions) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |||||
Components of Net Periodic Cost (Benefit): | ||||||||
Payment for Pension Benefits | $ 13,100 | $ 11,200 | ||||||
Pension Benefits [Member] | ||||||||
Components of Net Periodic Cost (Benefit): | ||||||||
Service cost | $ 5,218 | $ 4,633 | 10,437 | 9,297 | ||||
Interest cost | 10,621 | 10,921 | 21,242 | 21,880 | ||||
Expected return on plan assets | (10,760) | (10,663) | (21,520) | (21,326) | ||||
Prior service costs | 171 | 174 | 341 | 420 | ||||
Actuarial loss, net | 5,489 | 5,146 | 10,978 | 10,534 | ||||
Net periodic cost before regulatory adjustment | 10,739 | 10,211 | 21,478 | 20,805 | ||||
Regulatory adjustment | 3,288 | [1] | 3,306 | [1] | 6,576 | [2] | 6,613 | [2] |
Net periodic cost | 14,027 | 13,517 | 28,054 | 27,418 | ||||
Post-Retirement Benefits [Member] | ||||||||
Components of Net Periodic Cost (Benefit): | ||||||||
Service cost | 271 | 271 | 542 | 542 | ||||
Interest cost | 1,314 | 1,393 | 2,627 | 2,786 | ||||
Expected return on plan assets | (1,718) | (1,708) | (3,436) | (3,417) | ||||
Prior service costs | 114 | 114 | 228 | 228 | ||||
Actuarial loss, net | (195) | (280) | (390) | (560) | ||||
Net periodic cost before regulatory adjustment | (214) | (210) | (429) | (421) | ||||
Regulatory adjustment | (478) | [1] | (486) | [1] | (956) | [2] | (972) | [2] |
Net periodic cost | $ (692) | $ (696) | $ (1,385) | $ (1,393) | ||||
[1] | 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. | |||||||
[2] | (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. |
Wolf Creek Pension and Post-R46
Wolf Creek Pension and Post-Retirement Benefit Plans Wolf Creek Pension and Post-Retirement Benefit Plans (Net Periodic Costs and Pension Contributions) (Details) - USD ($) | 3 Months Ended | 6 Months Ended | ||||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |||||
Components of Net Periodic Cost (Benefit): | ||||||||
Payment for Pension Benefits | $ 13,100,000 | $ 11,200,000 | ||||||
Wolf Creek [Member] | ||||||||
Components of Net Periodic Cost (Benefit): | ||||||||
Payment for Pension Benefits | $ 0 | 3,200,000 | ||||||
KGE Member | ||||||||
Subsidiary Interest in Defined Benefit Plans | 47.00% | |||||||
Pension Benefits [Member] | ||||||||
Components of Net Periodic Cost (Benefit): | ||||||||
Service cost | $ 5,218,000 | $ 4,633,000 | $ 10,437,000 | 9,297,000 | ||||
Interest cost | 10,621,000 | 10,921,000 | 21,242,000 | 21,880,000 | ||||
Expected return on plan assets | (10,760,000) | (10,663,000) | (21,520,000) | (21,326,000) | ||||
Prior service costs | 171,000 | 174,000 | 341,000 | 420,000 | ||||
Actuarial loss, net | 5,489,000 | 5,146,000 | 10,978,000 | 10,534,000 | ||||
Net periodic cost before regulatory adjustment | 10,739,000 | 10,211,000 | 21,478,000 | 20,805,000 | ||||
Regulatory adjustment | 3,288,000 | [1] | 3,306,000 | [1] | 6,576,000 | [2] | 6,613,000 | [2] |
Net periodic cost | 14,027,000 | 13,517,000 | 28,054,000 | 27,418,000 | ||||
Pension Benefits [Member] | Wolf Creek [Member] | ||||||||
Components of Net Periodic Cost (Benefit): | ||||||||
Service cost | 1,950,000 | 1,687,000 | 3,900,000 | 3,374,000 | ||||
Interest cost | 2,475,000 | 2,414,000 | 4,950,000 | 4,828,000 | ||||
Expected return on plan assets | (2,643,000) | (2,430,000) | (5,286,000) | (4,861,000) | ||||
Prior service costs | 14,000 | 14,000 | 28,000 | 28,000 | ||||
Actuarial loss, net | 1,245,000 | 1,089,000 | 2,490,000 | 2,178,000 | ||||
Net periodic cost before regulatory adjustment | 3,041,000 | 2,774,000 | 6,082,000 | 5,547,000 | ||||
Regulatory adjustment | 247,000 | [3] | 483,000 | [3] | 494,000 | [4] | 966,000 | [4] |
Net periodic cost | 3,288,000 | 3,257,000 | 6,576,000 | 6,513,000 | ||||
Post-Retirement Benefits [Member] | ||||||||
Components of Net Periodic Cost (Benefit): | ||||||||
Service cost | 271,000 | 271,000 | 542,000 | 542,000 | ||||
Interest cost | 1,314,000 | 1,393,000 | 2,627,000 | 2,786,000 | ||||
Expected return on plan assets | (1,718,000) | (1,708,000) | (3,436,000) | (3,417,000) | ||||
Prior service costs | 114,000 | 114,000 | 228,000 | 228,000 | ||||
Actuarial loss, net | (195,000) | (280,000) | (390,000) | (560,000) | ||||
Net periodic cost before regulatory adjustment | (214,000) | (210,000) | (429,000) | (421,000) | ||||
Regulatory adjustment | (478,000) | [1] | (486,000) | [1] | (956,000) | [2] | (972,000) | [2] |
Net periodic cost | (692,000) | (696,000) | (1,385,000) | (1,393,000) | ||||
Post-Retirement Benefits [Member] | Wolf Creek [Member] | ||||||||
Components of Net Periodic Cost (Benefit): | ||||||||
Service cost | 37,000 | 32,000 | 73,000 | 64,000 | ||||
Interest cost | 70,000 | 82,000 | 140,000 | 163,000 | ||||
Expected return on plan assets | 0 | 0 | 0 | 0 | ||||
Prior service costs | 0 | 0 | 0 | 0 | ||||
Actuarial loss, net | (13,000) | (4,000) | (25,000) | (8,000) | ||||
Net periodic cost before regulatory adjustment | 94,000 | 110,000 | 188,000 | 219,000 | ||||
Regulatory adjustment | 0 | [3] | 0 | [3] | 0 | [4] | 0 | [4] |
Net periodic cost | $ 94,000 | $ 110,000 | $ 188,000 | $ 219,000 | ||||
[1] | 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. | |||||||
[2] | (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. | |||||||
[3] | (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. | |||||||
[4] | 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. |
Commitments And Contingencies C
Commitments And Contingencies Commitments And Contingencies (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | |
Nov. 30, 2016 | Jun. 02, 2017 | |
Loss Contingencies [Line Items] | ||
Loss Contingency Accrual, Payments | $ 7.6 | |
Settlement Assets, Current | $ 0.8 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligation, Liabilities Settled | $ (1,431) | |
Asset Retirement Obligation, Accretion Expense | 8,077 | |
Asset Retirement Obligation, Revision of Estimate | 34,713 | |
Asset Retirement Obligation, Liabilities Incurred | 13,471 | |
Asset Retirement Obligation | 378,781 | $ 323,951 |
Asset Retirement Obligation, Current | (10,548) | |
Asset Retirement Obligations, Noncurrent | $ 368,233 | $ 323,951 |
Variable Interest Entities (Nar
Variable Interest Entities (Narrative) (Details) | 6 Months Ended |
Jun. 30, 2017USD ($) | |
Variable Interest Entity [Line Items] | |
Variable Interest Entity, Initial Consolidation, Gain (Loss) | $ 0 |
Jeffrey Energy Center [Member] | |
Variable Interest Entity [Line Items] | |
Variable interest entity percentage of asset held | 8.00% |
Agreement expiration date | Jan. 1, 2019 |
La Cygne Generating Station [Member] | |
Variable Interest Entity [Line Items] | |
Variable interest entity percentage of asset held | 50.00% |
Agreement expiration date | Sep. 1, 2029 |
Variable Interest Entities (Ass
Variable Interest Entities (Assets And Liabilities In Relation To VIEs) (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 | |
Variable Interest Entity [Line Items] | |||
Property, plant and equipment, net | $ 9,406,054 | $ 9,248,359 | |
Current maturities of long-term debt | 0 | 125,000 | |
Accrued interest | [1] | 45,124 | 72,519 |
Long-term debt, net | 3,686,180 | 3,388,670 | |
Variable Interest Entity, Primary Beneficiary [Member] | |||
Variable Interest Entity [Line Items] | |||
Property, plant and equipment, net | 252,737 | 257,904 | |
Regulatory assets | [2] | 11,155 | 10,396 |
Current maturities of long-term debt | 28,538 | 26,842 | |
Accrued interest | [1] | 706 | 867 |
Long-term debt, net | $ 82,653 | $ 111,209 | |
[1] | Included in accrued interest on our condensed consolidated balance sheets. | ||
[2] | Included in long-term regulatory assets on our condensed consolidated balance sheets. |