Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Jan. 31, 2021 | Jun. 30, 2020 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Current Fiscal Year End Date | --12-31 | ||
Document Period End Date | Dec. 31, 2020 | ||
Document Transition Report | false | ||
Entity File Number | 001-31303 | ||
Entity Registrant Name | BLACK HILLS CORPORATION | ||
Entity Incorporation, State or Country Code | SD | ||
Entity Tax Identification Number | 46-0458824 | ||
Entity Address, Address Line One | 7001 Mount Rushmore Road | ||
Entity Address, City or Town | Rapid City | ||
Entity Address, State or Province | SD | ||
Entity Address, Postal Zip Code | 57702 | ||
City Area Code | 605 | ||
Local Phone Number | 721-1700 | ||
Title of 12(b) Security | Common stock of $1.00 par value | ||
Trading Symbol | BKH | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 3,528,768,075 | ||
Entity Common Stock, Shares Outstanding | 62,794,490 | ||
Documents Incorporated by Reference | Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2021 Annual Meeting of Stockholders to be held on April 27, 2021, are incorporated by reference in Part III of this Form 10-K. | ||
Entity Central Index Key | 0001130464 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2020 | ||
Document Fiscal Period Focus | FY |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Revenue: | |||
Revenue | $ 1,696,941 | $ 1,734,900 | $ 1,754,268 |
Operating expenses: | |||
Fuel, purchased power and cost of natural gas sold | 492,404 | 570,829 | 625,610 |
Operations and maintenance | 495,404 | 495,994 | 481,706 |
Depreciation, depletion and amortization | 224,457 | 209,120 | 196,328 |
Taxes - property and production | 56,373 | 52,915 | 51,746 |
Other operating expenses | 0 | 0 | 1,841 |
Total operating expenses | 1,268,638 | 1,328,858 | 1,357,231 |
Operating income | 428,303 | 406,042 | 397,037 |
Other income (expense): | |||
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | (144,931) | (139,291) | (141,616) |
Interest income | 1,461 | 1,632 | 1,641 |
Impairment of investment | (6,859) | (19,741) | 0 |
Other income (expense), net | (2,293) | (5,740) | (1,180) |
Total other income (expense) | (152,622) | (163,140) | (141,155) |
Income before income taxes | 275,681 | 242,902 | 255,882 |
Income tax benefit (expense) | (32,918) | (29,580) | 23,667 |
Income from continuing operations | 242,763 | 213,322 | 279,549 |
Net (loss) from discontinued operations | 0 | 0 | (6,887) |
Net income | 242,763 | 213,322 | 272,662 |
Net income attributable to noncontrolling interest | (15,155) | (14,012) | (14,220) |
Net income available for common stock | 227,608 | 199,310 | 258,442 |
Amounts attributable to common shareholders: | |||
Net income from continuing operations | 227,608 | 199,310 | 265,329 |
Net (loss) from discontinued operations | 0 | 0 | (6,887) |
Net income available for common stock | $ 227,608 | $ 199,310 | $ 258,442 |
Earnings (loss) per share of common stock, Basic - | |||
Earnings from continuing operations, Basic (usd per share) | $ 3.65 | $ 3.29 | $ 4.88 |
(Loss) from discontinued operations, Basic (usd per share) | 0 | 0 | (0.13) |
Total earnings per share of common stock, Basic (usd per share) | 3.65 | 3.29 | 4.75 |
Earnings (loss) per share of common stock, Diluted - | |||
Earnings from continuing operations, Diluted (usd per share) | 3.65 | 3.28 | 4.78 |
(Loss) from discontinued operations, Diluted (usd per share) | 0 | 0 | (0.12) |
Total earnings per share of common stock, Diluted (usd per share) | $ 3.65 | $ 3.28 | $ 4.66 |
Weighted average common shares outstanding: | |||
Basic (in shares) | 62,378 | 60,662 | 54,420 |
Diluted (in shares) | 62,439 | 60,798 | 55,486 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Net income | $ 242,763 | $ 213,322 | $ 272,662 |
Other comprehensive income (loss), net of tax: | |||
Benefit plan liability adjustments - net gain (loss) (net of tax of $191, $1,886 and $(660), respectively) | (1,062) | (6,253) | 2,155 |
Benefit plan liability adjustments - prior service costs (net of tax of $0, $2 and $0 respectively) | 0 | (8) | 0 |
Reclassification adjustment of benefit plan liability - net loss (net of tax of $(958), $434 and $(586), respectively) | 1,429 | 1,179 | 1,901 |
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $23, $19 and $43, respectively) | (80) | (58) | (135) |
Other comprehensive income (loss), net of tax | 3,309 | (3,739) | 7,027 |
Comprehensive income | 246,072 | 209,583 | 279,689 |
Less: comprehensive income attributable to non-controlling interest | (15,155) | (14,012) | (14,220) |
Comprehensive income available for common stock | 230,917 | 195,571 | 265,469 |
Interest rate swaps | |||
Other comprehensive income (loss), net of tax: | |||
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax | 2,564 | 2,185 | 2,252 |
Commodity derivatives | |||
Other comprehensive income (loss), net of tax: | |||
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax | 505 | (362) | 99 |
Net unrealized gains (losses) on commodity derivatives (net of tax of $14, $126 and $(228), respectively) | $ (47) | $ (422) | $ 755 |
Cosolidated Statements of Compr
Cosolidated Statements of Comprehensive Income (parentheticals) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
(Tax) benefit on benefit plan liability adjustments - net gain (loss) | $ 191 | $ 1,886 | $ (660) |
(Tax) benefit on benefit plan liability adjustments - prior service costs | 0 | 2 | 0 |
(Tax) benefit on reclassification adjustment of benefit plan liability - net loss | (958) | 434 | (586) |
(Tax) benefit on reclassification adjustment of benefit plan liability - prior service cost | 23 | 19 | 43 |
Interest Rate Swap | |||
Tax (benefit) on reclassification of net realized (gains) losses on settled/amortized derivatives | (287) | (666) | (599) |
Commodity Contract | |||
Tax (benefit) on reclassification of net realized (gains) losses on settled/amortized derivatives | (96) | 55 | (31) |
(Tax) benefit on net unrealized gains (losses) on commodity derivatives | $ 14 | $ 126 | $ (228) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Current assets: | ||
Cash and cash equivalents | $ 6,356 | $ 9,777 |
Restricted cash and equivalents | 4,383 | 3,881 |
Accounts receivable, net | 265,961 | 255,805 |
Materials, supplies and fuel | 117,400 | 117,172 |
Derivative assets, current | 1,848 | 342 |
Income tax receivable, net | 19,446 | 16,446 |
Regulatory assets, current | 51,676 | 43,282 |
Other current assets | 26,221 | 26,479 |
Total current assets | 493,291 | 473,184 |
Property, plant and equipment | 7,305,530 | 6,784,679 |
Less accumulated depreciation and depletion | (1,285,816) | (1,281,493) |
Total property, plant and equipment, net | 6,019,714 | 5,503,186 |
Other assets: | ||
Goodwill | 1,299,454 | 1,299,454 |
Intangible assets, net | 11,944 | 13,266 |
Regulatory assets, non-current | 226,582 | 228,062 |
Other assets, non-current | 37,801 | 41,305 |
Total other assets, non-current | 1,575,781 | 1,582,087 |
TOTAL ASSETS | 8,088,786 | 7,558,457 |
Current liabilities: | ||
Accounts payable | 183,340 | 193,523 |
Accrued liabilities | 243,612 | 226,767 |
Derivative liabilities, current | 2,044 | 2,254 |
Regulatory liabilities, current | 25,061 | 33,507 |
Notes payable | 234,040 | 349,500 |
Current maturities of long-term debt | 8,436 | 5,743 |
Total current liabilities | 696,533 | 811,294 |
Long-term debt, net of current maturities | 3,528,100 | 3,140,096 |
Deferred credits and other liabilities: | ||
Deferred income tax liabilities, net | 408,624 | 360,719 |
Regulatory liabilities, non-current | 507,659 | 503,145 |
Benefit plan liabilities | 150,556 | 154,472 |
Other deferred credits and other liabilities | 134,667 | 124,662 |
Total deferred credits and other liabilities | 1,201,506 | 1,142,998 |
Commitments, contingencies and guarantees (Note 3) | ||
Stockholders’ equity - | ||
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 62,827,179 and 61,480,658, respectively | 62,827 | 61,481 |
Additional paid-in capital | 1,657,285 | 1,552,788 |
Retained earnings | 870,738 | 778,776 |
Treasury stock at cost - 32,492 and 3,956, respectively | (2,119) | (267) |
Accumulated other comprehensive income (loss) | (27,346) | (30,655) |
Total stockholders’ equity | 2,561,385 | 2,362,123 |
Noncontrolling interest | 101,262 | 101,946 |
Total equity | 2,662,647 | 2,464,069 |
TOTAL LIABILITIES AND TOTAL EQUITY | $ 8,088,786 | $ 7,558,457 |
Common stock, par value (usd per share) | $ 1 | $ 1 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares, issued | 62,827,179 | 61,480,658 |
Treasury stock, shares | 32,492 | 3,956 |
Consolidated Balance Sheets (pa
Consolidated Balance Sheets (parentheticals) - $ / shares | Dec. 31, 2020 | Dec. 31, 2019 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (usd per share) | $ 1 | $ 1 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares, issued | 62,827,179 | 61,480,658 |
Treasury stock, shares | 32,492 | 3,956 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Operating activities: | |||
Net income | $ 242,763 | $ 213,322 | $ 272,662 |
Loss from discontinued operations, net of tax | 0 | 0 | 6,887 |
Income from continuing operations | 242,763 | 213,322 | 279,549 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 224,457 | 209,120 | 196,328 |
Deferred financing cost amortization | 7,883 | 7,838 | 7,845 |
Impairment of investment | 6,859 | 19,741 | 0 |
Stock compensation | 5,373 | 12,095 | 12,390 |
Deferred income taxes | 38,091 | 38,020 | (24,239) |
Employee benefit plans | 11,997 | 12,406 | 14,068 |
Other adjustments, net | 11,669 | 16,485 | 5,836 |
Change in certain operating assets and liabilities: | |||
Materials, supplies and fuel | 2,755 | 2,052 | (2,919) |
Accounts receivable and other current assets | (10,843) | 7,578 | (45,966) |
Accounts payable and other current liabilities | 24,659 | (34,906) | 5,305 |
Regulatory assets - current | (5,047) | 23,619 | 33,608 |
Regulatory liabilities - current | (10,706) | (15,158) | 18,533 |
Contributions to defined benefit pension plans | (12,700) | (12,700) | (12,700) |
Other operating activities, net | 4,653 | 6,001 | 6,689 |
Net cash provided by operating activities of continuing operations | 541,863 | 505,513 | 494,327 |
Net cash provided by (used in) operating activities of discontinued operations | 0 | 0 | (5,516) |
Net cash provided by operating activities | 541,863 | 505,513 | 488,811 |
Investing activities: | |||
Property, plant and equipment additions | (767,404) | (818,376) | (457,524) |
Purchase of investment | 0 | 0 | (24,429) |
Other investing activities | 5,740 | 2,166 | (4,281) |
Net cash (used in) investing activities of continuing operations | (761,664) | (816,210) | (486,234) |
Net cash provided by investing activities of discontinued operations | 0 | 0 | 20,385 |
Net cash (used in) investing activities | (761,664) | (816,210) | (465,849) |
Financing activities: | |||
Dividends paid on common stock | (135,439) | (124,647) | (106,591) |
Common stock issued | 99,278 | 101,358 | 300,834 |
Net (payments) borrowings of short-term debt | (115,460) | 163,880 | (25,680) |
Long-term debt - issuance | 400,000 | 1,100,000 | 700,000 |
Long-term debt - repayments | (8,597) | (905,743) | (854,743) |
Distributions to noncontrolling interests | (15,839) | (17,901) | (19,617) |
Other financing activities | (7,061) | (16,737) | (11,260) |
Net cash provided by (used in) financing activities | 216,882 | 300,210 | (17,057) |
Net change in cash, restricted cash and cash equivalents | (2,919) | (10,487) | 5,905 |
Cash and cash equivalents: | |||
Cash, restricted cash and cash equivalents beginning of year | 13,658 | 24,145 | 18,240 |
Cash, restricted cash and cash equivalents end of year | 10,739 | 13,658 | 24,145 |
Supplemental cash flow information: | |||
Interest (net of amounts capitalized) | (136,549) | (131,774) | (137,965) |
Income taxes | 2,172 | 4,682 | (14,730) |
Accrued property, plant and equipment purchases at December 31 | 72,215 | 91,491 | 69,017 |
Increase in capitalized assets associated with asset retirement obligations | $ 4,774 | $ 5,044 | $ 2,625 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Thousands | Total | Cumulative Effect, Period of Adoption, Adjustment | Common Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest |
Beginning balance (in shares) at Dec. 31, 2017 | 53,579,986 | 39,064 | ||||||
Beginning balance at Dec. 31, 2017 | $ 1,820,206 | $ 53,580 | $ (2,306) | $ 1,150,285 | $ 548,617 | $ (41,202) | $ 111,232 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net income available for common stock | 272,662 | 258,442 | 14,220 | |||||
Other comprehensive income (loss), net of tax | 7,027 | 7,027 | ||||||
Reclassification of certain tax effects from AOCI | 740 | 740 | ||||||
Reclassification to regulatory asset | 6,519 | 6,519 | ||||||
Dividends on common stock | (106,591) | (106,591) | ||||||
Share-based compensation (in shares) | 92,830 | 5,189 | ||||||
Share-based compensation | 7,190 | $ 93 | $ (204) | 7,301 | ||||
Issuance of common stock (in shares) | 6,371,690 | |||||||
Issuance of common stock | 299,000 | $ 6,372 | 292,628 | |||||
Issuance costs | (15) | (15) | ||||||
Dividend reinvestment and stock purchase plan (in shares) | 4,061 | |||||||
Dividend reinvestment and stock purchase plan | 220 | $ 4 | 216 | |||||
Other stock transactions | 82 | 154 | (72) | |||||
Distributions to noncontrolling interest | (19,617) | (19,617) | ||||||
Ending balance (in shares) at Dec. 31, 2018 | 60,048,567 | 44,253 | ||||||
Ending balance at Dec. 31, 2018 | 2,287,423 | $ 60,049 | $ (2,510) | 1,450,569 | 700,396 | (26,916) | 105,835 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net income available for common stock | 213,322 | 199,310 | 14,012 | |||||
Other comprehensive income (loss), net of tax | (3,739) | (3,739) | ||||||
Dividends on common stock | (124,647) | (124,647) | ||||||
Share-based compensation (in shares) | 103,759 | 40,297 | ||||||
Share-based compensation | 7,076 | $ 104 | $ 2,243 | 4,729 | ||||
Issuance of common stock (in shares) | 1,328,332 | |||||||
Issuance of common stock | 100,000 | $ 1,328 | 98,672 | |||||
Issuance costs | (1,182) | (1,182) | ||||||
Other stock transactions | 327 | 327 | ||||||
Distributions to noncontrolling interest | (17,901) | (17,901) | ||||||
Ending balance (in shares) at Dec. 31, 2019 | 61,480,658 | 3,956 | ||||||
Ending balance at Dec. 31, 2019 | 2,464,069 | $ 3,390 | $ 61,481 | $ (267) | 1,552,788 | 778,776 | (30,655) | 101,946 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net income available for common stock | 242,763 | 227,608 | 15,155 | |||||
Other comprehensive income (loss), net of tax | 3,309 | 3,309 | ||||||
Dividends on common stock | (135,439) | (135,439) | ||||||
Share-based compensation (in shares) | 123,578 | 28,536 | ||||||
Share-based compensation | 5,194 | $ 123 | $ (1,852) | 6,923 | ||||
Issuance of common stock (in shares) | 1,222,943 | |||||||
Issuance of common stock | 100,000 | $ 1,223 | 98,777 | |||||
Issuance costs | (1,203) | (1,203) | ||||||
Distributions to noncontrolling interest | (15,839) | (15,839) | ||||||
Ending balance (in shares) at Dec. 31, 2020 | 62,827,179 | 32,492 | ||||||
Ending balance at Dec. 31, 2020 | $ 2,662,647 | $ (207) | $ 62,827 | $ (2,119) | $ 1,657,285 | $ 870,738 | $ (27,346) | $ 101,262 |
Consolidated Statement of Equit
Consolidated Statement of Equity (Parentheticals) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Statement of Stockholders' Equity [Abstract] | |||
Dividends on common stock, Per Share | $ 2.17 | $ 2.05 | $ 1.93 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | $ 2,662,647 | $ 2,464,069 | $ 2,287,423 |
Business Description And Signif
Business Description And Significant Accounting Policies: | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Business Description and Significant Accounting Policies | BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Both of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 18 . On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued operations. Unless otherwise noted, the amounts presented in the accompanying Notes to Consolidated Financial Statements relate to the Company’s continuing operations. Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. COVID-19 Pandemic In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations. The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the year ended December 31, 2020, there were no material adverse impacts on the Company’s results of operations. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 18 . Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generation facility, wind farm or transmission tie. See Note 6 for additional information. Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 14 . Cash and Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash. Accounts Receivable and Allowance for Credit Losses Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal primarily to affiliates or regional utilities. We maintain an allowance for credit losses which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for credit losses to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. Following is a summary of accounts receivable as of December 31 (in thousands): 2020 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net Electric Utilities $ 45,841 $ 32,915 $ (1,269) $ 77,487 Gas Utilities 95,592 93,150 (5,734) 183,008 Power Generation 1,837 — — 1,837 Mining 2,511 — — 2,511 Corporate 1,118 — — 1,118 Total $ 146,899 $ 126,065 $ (7,003) $ 265,961 2019 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net Electric Utilities $ 41,428 $ 33,886 $ (592) $ 74,722 Gas Utilities 97,607 79,616 (1,683) 175,540 Power Generation 2,164 — — 2,164 Mining 2,277 — — 2,277 Corporate 1,271 — (169) 1,102 Total $ 144,747 $ 113,502 $ (2,444) $ 255,805 Changes to allowance for credit losses for the years ended December 31, were as follows (in thousands): Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year 2020 $ 2,444 $ 8,927 (a) $ 4,728 $ (9,096) $ 7,003 2019 $ 3,209 $ 5,795 $ 3,942 $ (10,502) $ 2,444 2018 $ 3,081 $ 6,859 $ 4,092 $ (10,823) $ 3,209 _________________ (a) Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections due to non-payment for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the year ended December 31, 2020 by an incremental $3.3 million. The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 11 . Materials, Supplies and Fuel The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2020 2019 Materials and supplies $ 85,250 $ 82,809 Fuel 1,531 2,425 Natural gas in storage 30,619 31,938 Total materials, supplies and fuel $ 117,400 $ 117,172 Materials and supplies represent parts and supplies for all of our business segments. Fuel represents diesel oil and gas used by our Electric Utilities to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. Investments In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment at that time. During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time. The following table presents the carrying value of our investments (in thousands), which are included in Other assets, non-current on the Consolidated Balance Sheets, as of December 31: 2020 2019 Investment in privately held oil and gas company $ 1,500 $ 8,359 Cash surrender value of life insurance contracts 13,628 13,056 Other investments 682 514 Total investments $ 15,810 $ 21,929 We changed the classification of our investments on the Consolidated Balance Sheets as of December 31, 2019 to conform with current year presentation. The prior year reclassification of $22 million from Investments to Other assets, non-current did not impact previously reported current or total assets. Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our stored natural gas base or Cushion Gas as property, plant and equipment. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs related to our regulated properties that do not have legal retirement obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. The composite depreciation method is applied to regulated utility property. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. See Note 5 for additional information. Asset Retirement Obligations Accounting standards for AROs associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. Additional information is included in Note 7 . Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life are amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, which are also its reportable segments. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies. We believe that goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill amounts have not changed since 2016. As of December 31, 2020 and 2019, Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Goodwill $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Our intangible assets represent contract intangibles, easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2020 2019 2018 Intangible assets, net, beginning balance $ 13,266 $ 14,337 $ 7,559 Additions — — 7,602 Amortization expense (a) (1,322) (1,071) (824) Intangible assets, net, ending balance $ 11,944 $ 13,266 $ 14,337 _________________ (a) Amortization expense for existing intangible assets is expected to be $1.3 million for each year of the next five years. Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2020 2019 Accrued employee compensation, benefits and withholdings $ 77,806 $ 62,837 Accrued property taxes 47,105 44,547 Customer deposits and prepayments 52,185 54,728 Accrued interest 31,520 31,868 Other (none of which is individually significant) 34,996 32,787 Total accrued liabilities $ 243,612 $ 226,767 Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives The wholesale electric energy and natural gas commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2). For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Additional information on fair value measurements is included in Notes 12 and 15 . Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. In addition, certain derivative contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980, Regulated Operations . We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on these designated derivatives is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivative contracts are recognized in earnings. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures. See additional information in Notes 11 , 12 and 13 . Deferred Financing Costs Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities. See additional information in Note 9 . Regulatory Accounting Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates. • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings. If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows. As of December 31, 2020 and 2019, we had total regulatory assets of $278 million and $271 million respectively, and total regulatory liabilities of $533 million and $537 million respectively. See Note 2 for further information. Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax benefit (expense) on the Consolidated Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 17 for additional information. Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans. A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands): 2020 2019 2018 Net income available for common stock $ 227,608 $ 199,310 $ 258,442 Weighted average shares - basic 62,378 60,662 54,420 Dilutive effect of: Equity Units — — 898 Equity compensation 61 136 168 Weighted average shares - diluted 62,439 60,798 55,486 Net income available for common stock, per share - Diluted $ 3.65 $ 3.28 $ 4.66 The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands): 2020 2019 2018 Equity compensation 60 1 16 Anti-dilutive shares excluded from computation of earnings per share 60 1 16 Noncontrolling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidation. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 14 for additional detail on noncontrolling interests. Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation , by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in |
Regulatory Matters_
Regulatory Matters: | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Regulatory Matters | REGULATORY MATTERS We had the following regulatory assets and liabilities as of December 31 (in thousands): 2020 2019 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 39,035 $ 34,088 Deferred gas cost adjustments (a) 3,200 1,540 Gas price derivatives (a) 2,226 3,328 Deferred taxes on AFUDC (b) 7,491 7,790 Employee benefit plans and related deferred taxes (c) 116,598 115,900 Environmental (a) 1,413 1,454 Loss on reacquired debt (a) 22,864 24,777 Renewable energy standard adjustment (a) — 1,622 Deferred taxes on flow-through accounting (c) 47,515 41,220 Decommissioning costs (a) 8,988 10,670 Gas supply contract termination (a) 2,524 8,485 Other regulatory assets (a) 26,404 20,470 Total regulatory assets 278,258 271,344 Less current regulatory assets (51,676) (43,282) Regulatory assets, non-current $ 226,582 $ 228,062 Regulatory liabilities Deferred energy and gas costs (a) $ 13,253 $ 17,278 Employee benefit plan costs and related deferred taxes (c) 40,256 43,349 Cost of removal (a) 172,902 166,727 Excess deferred income taxes (c) 285,259 285,438 Other regulatory liabilities (c) 21,050 23,860 Total regulatory liabilities 532,720 536,652 Less current regulatory liabilities (25,061) (33,507) Regulatory liabilities, non-current $ 507,659 $ 503,145 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. Regulatory assets represent items we expect to recover from customers through probable future rates. Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utilities’ customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state regulatory commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions. The recovery period for these costs is less than a year. Deferred Gas Cost Adjustment s - Our regulated Gas Utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state regulatory commissions. The recovery period for these costs is less than a year. Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2020 are hedged over a maximum forward term of two years. Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Environmental - Environmental costs associated with certain former manufactured gas plant sites. These costs are first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the applicable state regulatory commission and therefore, the recovery period is unknown at this time. Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue. Renewable Energy Standard Adjustment - The renewable energy standard adjustment provides funding for various renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard. These programs include incentives for our Colorado Electric customers to install renewable energy equipment at their location. These project costs and program incentives are recovered over time through the Renewable Energy Standard Adjustment charged on customers’ bills. Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer and result in lower utility rates in the year in which the tax benefits are realized. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes. Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs as a regulatory asset and received approval in 2020 to begin recovering those costs over three years. Gas Supply Contract Termination - As part of our acquisition of SourceGas in 2016, we acquired agreements that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to certain customers in Colorado, Nebraska, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our SourceGas Transaction purchase price allocation. We were granted approval to terminate these agreements from the CPUC, NPSC and WPSC on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Deferred Energy and Gas Costs - Deferred energy and gas costs that have been over-recovered through customer rates and will be returned to customers in future periods. Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense. Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. See Note 17 for additional information. Regulatory Activity TCJA On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018 and 2019, the Company successfully delivered several of these tax benefits from the TCJA to its utility customers. In 2020, regulatory proceedings resolved the last of the Company’s open dockets seeking approval of its TCJA plans. As a result, the Company relieved certain TCJA-related liabilities, which resulted in an increase to net income for the year ended December 31, 2020 of $4.0 million. On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related customer billing credits to its customers. The billing credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, will be delivered to customers in February 2021. These billing credits will be offset by a reduction in income tax expense and will result in a minimal impact to Net income. On Janaury 26, 2021, NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related customer billing credits to its customers. The billing credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, is expected to be delivered to customers in the second quarter of 2021. These billing credits will be offset by a reduction in income tax and and will result in a minimal impact to Net income. Electric Utilities Regulatory Activity South Dakota Electric Settlement On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement agreement to extend the 6-year moratorium period by an additional 3 years to June 30, 2026. Also, as part of the settlement, we withdrew our application for deferred accounting treatment and expensed $5.4 million of development costs in 2019 related to projects we no longer intend to construct. This settlement amends a previous agreement approved by the SDPUC on June 16, 2017, whereby South Dakota Electric would not increase base rates, absent an extraordinary event, for a 6 year moratorium period effective July 1, 2017. The moratorium period also includes suspension of both the TFA and EIA. FERC Formula Rate The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2020 the annual revenue requirement was $27 million and included estimated weighted average capital additions of $33 million for 2019 and 2020 combined. The annual transmission revenue requirement has a true-up mechanism that is recorded in June of each year. Black Hills Wyoming and Wyoming Electric Wygen 1 FERC Filing On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years. Gas Utilities Regulatory Activity Colorado Gas Jurisdictional Consolidation and Rate Reviews On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On January 6, 2021 the CPUC issued an order dismissing the rate rev iew. On January 26, 2021, Colorado Gas filed an application for rehearing, reargument or reconsideration in response to the Commission’s January 6 order. On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety and integrity focused investments in its system over five years. A decision from the CPUC is expected by mid-2021. On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020. RMNG SSIR On October 30, 2020, RMNG filed the tariff adjusting rates to include 2021 projects with an expected capital investment of $33 million under the current SSIR. The new tariff rates went into effect January 1, 2021 and the current approved SSIR expires December 31, 2021. Nebraska Gas Jurisdictional Consolidation and Rate Review On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover significant infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates will be enacted on March 1, 2021, to replace interim rates enacted September 1, 2020. The approval will shift $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism for consolidated utility alignment. Wyoming Gas Jurisdictional Consolidation and Rate Review Wyoming Gas’s new single statewide rate structure became effective March 1, 2020. Wyoming Gas received approval from the WPSC on December 11, 2019, to consolidate the rates, tariffs and services of its four existing gas distribution territories. New rates are expected to generate $13 million in new annual revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability. |
Commitment, Contingencies And G
Commitment, Contingencies And Guarantees: | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments, Contingencies and Guarantees | COMMITMENTS, CONTINGENCIES AND GUARANTEES Power Purchase and Transmission Services Agreements Through our subsidiaries, we have the following significant long-term power purchase contracts and transmission services agreement (TSA) with non-affiliated third-parties: Subsidiary Contract Type Counterparty Fuel Type Quantity (MW) Expiration Date Colorado Electric (a) PPA PRPA Wind 60 May 31, 2030 Colorado Electric PPA PRPA Coal 25 June 30, 2024 South Dakota Electric PPA PacifiCorp Coal 50 December 31, 2023 South Dakota Electric (b) TSA PacifiCorp N/A 50 December 31, 2023 South Dakota Electric PPA PRPA Wind 12 September 30, 2029 South Dakota Electric PPA Fall River Solar, LLC Solar 80 Pending Completion (c) Wyoming Electric (d) PPA Happy Jack Wind 30 September 3, 2028 Wyoming Electric (e) PPA Silver Sage Wind 30 September 30, 2029 _____________ (a) Colorado Electric sells the wind energy purchased under this PPA to City of Colorado Springs as discussed below. (b) This is a firm point-to-point transmission service agreement that provides 50 MW of capacity and energy to be transmitted annually. (c) This agreement relates to a new solar facility currently being constructed and will expire 20 years after construction completion, which is expected by the end of 2022. (d) Under a separate intercompany PSA, Wyoming Electric sells 50% of the facility output to South Dakota Electric. (e) Under a separate intercompany PSA, Wyoming Electric sells 67% of the facility output to South Dakota Electric. Costs under these agreements for the years ended December 31 were as follows (in thousands): Subsidiary Contract Type Counterparty Fuel Type 2020 2019 2018 Colorado Electric PPA PRPA Wind $ 2,791 $ — $ — Colorado Electric PPA PRPA Coal $ 4,524 $ 1,802 $ — South Dakota Electric PPA PacifiCorp Coal $ 5,897 $ 7,477 $ 13,681 South Dakota Electric TSA PacifiCorp N/A $ 1,776 $ 1,741 $ 1,742 South Dakota Electric PPA PRPA Wind $ 715 $ 688 $ 223 Wyoming Electric PPA Happy Jack Wind $ 4,531 $ 3,936 $ 3,884 Wyoming Electric PPA Silver Sage Wind $ 6,203 $ 5,366 $ 5,376 Power Purchase Agreements - Related Parties Wyoming Electric currently has a PPA with Black Hills Wyoming expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On October 15, 2020, the FERC approved a settlement agreement in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I facility. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric through a PPA, which expires in November 2044. Black Hills Electric Generation provides its 14.5 MW share of energy generated from Busch Ranch I to Colorado Electric through a PPA, which expires in October 2037. Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. At the segment level, we recognize the associated revenues, costs and assets on an accrual basis, rather than as a finance lease. See Note 18 for additional information. Purchase Commitments We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract. Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2020, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): Northern Natural Gas - Ventura Northwest Pipeline - Wyoming ONEOK - Oklahoma Southern Star Central Gas Pipeline Panhandle Eastern Pipe Line 2021 3,650,000 1,510,000 5,475,000 113,130 4,680 2022 1,810,000 1,510,000 5,475,000 — — 2023 1,840,000 1,510,000 5,475,000 — — 2024 1,820,000 910,000 5,490,000 — — 2025 — — 4,560,000 — — Thereafter — — — — — Purchases under these contracts totaled $25 million, $6.7 million and $27 million for 2020, 2019 and 2018, respectively. Other Gas Supply Agreements Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044. The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and natural gas transportation and storage agreements (in thousands): Power purchase and transmission services agreements (a) Natural gas transportation and storage agreements 2021 $ 24,452 $ 116,563 2022 $ 11,678 $ 121,819 2023 $ 11,678 $ 100,282 2024 $ 2,738 $ 67,089 2025 $ — $ 50,709 Thereafter $ — $ 167,100 _____________ (a) This schedule does not reflect renewable energy PPA obligations since these agreements vary based on weather conditions. Power Sales Agreements Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties: • On July 1, 2020, Colorado Electric entered into a PSA with the City of Colorado Springs to sell up to 60 MW of wind energy purchased from PRPA under a separate 60 MW PPA discussed above. This PSA with the City of Colorado Springs expires June 30, 2025. • During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023. • South Dakota Electric has an agreement to provide MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023. • During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from its other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which has an initial term through September 3, 2034 and would be renewed annually on September 3 thereafter, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves. • South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires May 31, 2028. The contract terms are from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: Contract Years Total Contract Capacity Contingent Capacity Amounts on Wygen III Contingent Capacity Amounts on Neil Simpson II 2020-2022 15 MW 7 MW 8 MW 2022-2023 15 MW 8 MW 7 MW 2023-2028 10 MW 5 MW 5 MW • South Dakota Electric has an agreement that expires December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals. • Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PSA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit. Environmental Matters We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies. Reclamation Liability For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under our land leases for our wind generation facilities, we are required to reclaim land where we have placed wind turbines. The reclamation liabilities are recorded at the present value of the estimated future cost to reclaim the land. Under its mining permit, WRDC is required to reclaim all land where it has mined reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. See Note 7 for additional information. Manufactured Gas Processing In 2008, we acquired whole and partial liabilities for former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.2 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.4 million regulatory asset for manufactured gas processing sites; see Note 2 for additional information. As of December 31, 2020, we had $2.6 million accrued for remediation of Iowa’s manufactured gas processing site as the landowner. As of December 31, 2020, we had $0.6 million accrued for remediation of Nebraska’s manufactured gas processing site as the land owner. These liabilities are included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties. Legal Proceedings In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements. In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities. Guarantees We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements, which are off-balance sheet commitments, include indemnification for reclamation and surety bonds. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets. We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2020 Expiration Indemnification for subsidiary reclamation/surety bonds $ 53,769 Ongoing |
Revenue_
Revenue: | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | REVENUE Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, Regulated Operations, that provide services to regulated customers under tariff rates, charges, terms and conditions of service and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our Utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. Certain energy sale and purchase transactions with the same counterparty and at the same delivery point are netted to reflect the economic substance of the arrangement. • Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate Electric Utilities, and an affiliate non-regulated Power Generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered. • Other non-regulated services - Our Electric and Gas Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments, for the years ended December 31, 2020, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 610,721 $ 765,922 $ — $ 58,567 $ (31,478) $ 1,403,732 Transportation — 154,581 — — (526) 154,055 Wholesale 17,848 — 103,258 — (97,169) 23,937 Market - off-system sales 24,309 260 — — (8,797) 15,772 Transmission/Other 58,965 43,658 — — (19,315) 83,308 Revenue from contracts with customers 711,843 964,421 103,258 58,567 (157,285) 1,680,804 Other revenues 2,201 10,249 1,789 2,508 (610) 16,137 Total revenues $ 714,044 $ 974,670 $ 105,047 $ 61,075 $ (157,895) $ 1,696,941 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 58,567 $ (31,478) $ 27,089 Services transferred over time 711,843 964,421 103,258 — (125,807) 1,653,715 Revenue from contracts with customers $ 711,843 $ 964,421 $ 103,258 $ 58,567 $ (157,285) $ 1,680,804 Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 605,756 $ 817,840 $ — $ 59,233 $ (32,053) $ 1,450,776 Transportation — 143,390 — — (1,042) 142,348 Wholesale 20,884 — 99,157 — (91,577) 28,464 Market - off-system sales 23,817 691 — — (7,736) 16,772 Transmission/Other 57,104 47,725 — — (16,797) 88,032 Revenue from contracts with customers 707,561 1,009,646 99,157 59,233 (149,205) 1,726,392 Other revenues 5,191 384 2,101 2,396 (1,564) 8,508 Total revenues $ 712,752 $ 1,010,030 $ 101,258 $ 61,629 $ (150,769) $ 1,734,900 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 59,233 $ (32,053) $ 27,180 Services transferred over time 707,561 1,009,646 99,157 — (117,152) 1,699,212 Revenue from contracts with customers $ 707,561 $ 1,009,646 $ 99,157 $ 59,233 $ (149,205) $ 1,726,392 Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 594,329 $ 833,379 $ — $ 65,803 $ (32,194) $ 1,461,317 Transportation — 140,705 — — (1,348) 139,357 Wholesale 33,687 — 90,791 — (84,957) 39,521 Market - off-system sales 24,799 866 — — (8,102) 17,563 Transmission/Other 56,209 49,402 — — (14,827) 90,784 Revenue from contracts with customers 709,024 1,024,352 90,791 65,803 (141,428) 1,748,542 Other revenues 2,427 955 1,660 2,230 (1,546) 5,726 Total revenues $ 711,451 $ 1,025,307 $ 92,451 $ 68,033 $ (142,974) $ 1,754,268 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 65,803 $ (32,194) $ 33,609 Services transferred over time 709,024 1,024,352 90,791 — (109,234) 1,714,933 Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 90,791 $ 65,803 $ (141,428) $ 1,748,542 The majority of our revenue contracts are based on variable quantities delivered. Any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative revenue programs revenue under ASC 980, Regulated Operations . Significant Judgments and Estimates Unbilled Revenue To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month, the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 1 . |
Property, Plant And Equipment_
Property, Plant And Equipment: | 12 Months Ended |
Dec. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2020 2019 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,417,951 40 $ 1,348,049 41 32 46 Electric transmission 517,794 49 483,640 51 44 51 Electric distribution 959,453 46 861,042 47 46 48 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 259,010 28 259,266 28 26 29 Total electric plant in service 3,159,078 2,956,867 Construction work in progress 89,402 102,268 Total electric plant 3,248,480 3,059,135 Less accumulated depreciation (666,669) (670,861) Electric plant net of accumulated depreciation $ 2,581,811 $ 2,388,274 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 10 years remaining. 2020 2019 Lives (in years) Gas Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Gas plant: Production $ 15,603 40 $ 13,000 35 24 46 Gas transmission 578,278 54 516,172 50 22 71 Gas distribution 2,115,082 53 1,857,233 43 45 59 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciable (a) 39,184 N/A 44,443 N/A N/A N/A Storage 55,481 38 46,977 31 24 52 General 438,217 19 437,054 20 12 23 Total gas plant in service 3,245,384 2,918,418 Construction work in progress 67,229 63,080 Total gas plant 3,312,613 2,981,498 Less accumulated depreciation (323,679) (336,721) Gas plant net of accumulated depreciation $ 2,988,934 $ 2,644,777 _____________ (a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 529,927 $ 4,876 $ 534,803 $ (167,787) $ 367,016 31 2 40 Mining $ 186,552 $ 988 $ 187,540 $ (126,537) $ 61,003 14 2 59 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 532,397 $ 2,121 $ 534,518 $ (154,362) $ 380,156 31 2 40 Mining $ 179,198 $ 1,275 $ 180,473 $ (118,585) $ 61,888 13 2 59 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,692 $ 16,402 $ 22,094 $ (1,144) $ 20,950 10 10 22 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,721 $ 23,334 $ 29,055 $ (964) $ 28,091 10 3 30 |
Jointly Owned Facilities_
Jointly Owned Facilities: | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Jointly Owned Facilities | JOINTLY OWNED FACILITIES Our consolidated financial statements include our share of several jointly-owned utility and non-regulated facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities. Wyodak Plant South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves. Transmission Tie South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the Transmission Tie), an AC-DC-AC transmission tie. Basin Electric Power Cooperative owns the remaining ownership percentage. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie. Wygen III South Dakota Electric owns 52% of the Wygen III generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies fuel to Wygen III for the life of the plant. Wygen I Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations. At December 31, 2020, our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation Wyodak Plant $ 116,074 $ 2,249 $ (67,762) $ 50,561 Transmission Tie $ 26,176 $ 509 $ (7,103) $ 19,582 Wygen III $ 142,739 $ 582 $ (24,783) $ 118,538 Wygen I $ 114,975 $ 318 $ (49,459) $ 65,834 Jointly Owned Facilities - Related Party Busch Ranch I Colorado Electric owns 50% of Busch Ranch I while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. Colorado Electric retains responsibility for operations of the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037. Cheyenne Prairie Cheyenne Prairie serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 100.4 MW unit that is jointly-owned by South Dakota Electric (58 MW) and Wyoming Electric (42.4 MW). BHSC is responsible for plant operations. Corriedale Corriedale serves as the dedicated wind energy supply for Renewable Ready customers in South Dakota and Wyoming. The 52.5 MW wind farm is jointly-owned by South Dakota Electric (32.5 MW) and Wyoming Electric (20 MW). BHSC is responsible for operations of the wind farm. |
Asset Retirement Obligations_
Asset Retirement Obligations: | 12 Months Ended |
Dec. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS We have identified legal retirement obligations related to reclamation of mining sites in the Mining segment, removal of fuel tanks, transformers containing polychlorinated biphenyls, and an evaporation pond at our Electric Utilities, wind turbines at our Electric Utilities and Power Generation segments, retirement of gas pipelines at our Gas Utilities and removal of asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these AROs. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment. The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2019 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2020 Electric Utilities (a) $ 9,329 $ 1,217 $ — $ 407 $ — $ 10,953 Gas Utilities (b) 36,085 4,782 (132) 1,539 — 42,274 Power Generation 4,739 — — 206 — 4,945 Mining (c) 14,052 — (185) 617 (1,225) 13,259 Total 64,205 $ 5,999 $ (317) $ 2,769 $ (1,225) $ 71,431 December 31, 2018 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2019 Electric Utilities (d) $ 6,258 $ — $ — $ 385 $ 2,686 $ 9,329 Gas Utilities 34,627 — — 1,458 — 36,085 Power Generation (a) 300 3,445 — 158 836 4,739 Mining (c) 15,615 — (380) 740 (1,923) 14,052 Total $ 56,800 $ 3,445 $ (380) $ 2,741 $ 1,599 $ 64,205 _____________________ (a) Liabilities incurred were related to new wind assets. (b) Liabilities incurred were driven by an increase in gas pipeline miles; which increases our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The Mining Revisions to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process. (d) The Electric Utilities Revisions to Prior Estimates was primarily driven by an increase in the estimated cost to decommission certain regulated wind farm assets. We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time. |
Leases_
Leases: | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Lease | LEASES Lessee We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than 1 year to 35 years, including options to extend that are reasonably certain to be exercised. We have one immaterial finance lease for communication equipment at the WRDC mine. Most of our leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using our applicable subsidiaries’ incremental borrowing rate (weighted-average of 4.24% as of December 31, 2020). Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the accompanying Consolidated Balance Sheets. Lease expense for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease cost Operations and maintenance $ 978 $ 1,456 Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2020 2019 Assets: Operating lease assets Other assets, non-current $ 4,188 $ 4,629 Total lease assets $ 4,188 $ 4,629 Liabilities: Current: Operating leases Accrued liabilities $ 736 $ 1,179 Noncurrent: Operating leases Other deferred credits and other liabilities 3,807 3,821 Total lease liabilities $ 4,543 $ 5,000 Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2020 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,023 $ 1,263 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 161 $ 2,801 Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2020 2019 Weighted average remaining lease term: Operating leases 8 years 8 years Weighted average discount rate: Operating leases 4.24 % 4.27 % As of December 31, 2020, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases 2021 $ 907 2022 804 2023 779 2024 776 2025 529 Thereafter 1,643 Total lease payments $ 5,438 Less imputed interest 895 Present value of lease liabilities $ 4,543 Lessor We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 34 years. Lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease income Revenue $ 2,534 $ 2,306 As of December 31, 2020, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2021 $ 2,383 2022 2,122 2023 2,130 2024 2,074 2025 2,090 Thereafter 58,829 Total lease receivables $ 69,628 |
Lease | LEASES Lessee We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than 1 year to 35 years, including options to extend that are reasonably certain to be exercised. We have one immaterial finance lease for communication equipment at the WRDC mine. Most of our leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using our applicable subsidiaries’ incremental borrowing rate (weighted-average of 4.24% as of December 31, 2020). Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the accompanying Consolidated Balance Sheets. Lease expense for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease cost Operations and maintenance $ 978 $ 1,456 Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2020 2019 Assets: Operating lease assets Other assets, non-current $ 4,188 $ 4,629 Total lease assets $ 4,188 $ 4,629 Liabilities: Current: Operating leases Accrued liabilities $ 736 $ 1,179 Noncurrent: Operating leases Other deferred credits and other liabilities 3,807 3,821 Total lease liabilities $ 4,543 $ 5,000 Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2020 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,023 $ 1,263 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 161 $ 2,801 Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2020 2019 Weighted average remaining lease term: Operating leases 8 years 8 years Weighted average discount rate: Operating leases 4.24 % 4.27 % As of December 31, 2020, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases 2021 $ 907 2022 804 2023 779 2024 776 2025 529 Thereafter 1,643 Total lease payments $ 5,438 Less imputed interest 895 Present value of lease liabilities $ 4,543 Lessor We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 34 years. Lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease income Revenue $ 2,534 $ 2,306 As of December 31, 2020, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2021 $ 2,383 2022 2,122 2023 2,130 2024 2,074 2025 2,090 Thereafter 58,829 Total lease receivables $ 69,628 |
Debt and Credit Facilities_
Debt and Credit Facilities: | 12 Months Ended |
Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |
Debt and Credit Facilities | DEBT AND CREDIT FACILITIES Short-term debt We had the following Notes payable outstanding at the Consolidated Balance Sheets date (in thousands): December 31, 2020 December 31, 2019 Balance Outstanding Letters of Credit (a) Balance Outstanding Letters of Credit (a) Revolving Credit Facility $ — $ 24,730 $ — $ 30,274 CP Program 234,040 — 349,500 — Total $ 234,040 $ 24,730 $ 349,500 $ 30,274 _______________ (a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility. Revolving Credit Facility and CP Program On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, at December 31, 2020. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2020. We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net short-term borrowings (payments) during 2020 were $(115) million. As of December 31, 2020, the weighted average interest rate on short-term borrowings was 0.27%. Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See below for additional details. Long-term debt Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2020 December 31, 2020 December 31, 2019 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 300,000 Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 400,000 Senior unsecured notes, due 2029 October 15, 2029 3.05% 400,000 400,000 Senior unsecured notes, due 2030 June 15, 2030 2.50% 400,000 — Senior unsecured notes due 2033 May 1, 2033 4.35% 400,000 400,000 Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Senior unsecured notes, due 2049 October 15, 2049 3.88% 300,000 300,000 Corporate term loan due 2021 June 7, 2021 2.32% 1,436 7,178 Total Corporate debt 3,026,436 2,632,178 Less unamortized debt discount (7,013) (6,462) Total Corporate debt, net 3,019,423 2,625,716 South Dakota Electric Series 94A Debt, variable rate (a) June 1, 2024 N/A — 2,855 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 Total South Dakota Electric debt 340,000 342,855 Less unamortized debt discount (78) (82) Total South Dakota Electric debt, net 339,922 342,773 Wyoming Electric Industrial development revenue bonds due 2021 (a) (b) September 1, 2021 0.12% 7,000 7,000 Industrial development revenue bonds due 2027 (a) (b) March 1, 2027 0.12% 10,000 10,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 Total Wyoming Electric debt 202,000 202,000 Less unamortized debt discount — — Total Wyoming Electric debt, net 202,000 202,000 Total long-term debt 3,561,345 3,170,489 Less current maturities 8,436 5,743 Less unamortized deferred financing costs (c) 24,809 24,650 Long-term debt, net of current maturities and deferred financing costs $ 3,528,100 $ 3,140,096 _______________ (a) Variable interest rate. (b) A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due March 1, 2027 and the 2009B bonds of $7.0 million due September 1, 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. (c) Includes deferred financing costs associated with our Revolving Credit Facility of $1.0 million and $1.7 million as of December 31, 2020 and December 31, 2019, respectively. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2021 $ 8,436 2022 $ — 2023 $ 525,000 2024 $ — 2025 $ — Thereafter $ 3,035,000 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2020. See below for additional information. Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. Amortization of Deferred Financing Costs Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2020 2020 2019 2018 $ 24,809 $ 3,272 $ 3,242 $ 2,829 Debt Transactions On June 17, 2020, we completed a public debt offering which consisted of $400 million of 2.50% 10-year senior unsecured notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes. On March 24, 2020, South Dakota Electric paid off its $2.9 million, Series 94A variable rate notes due June 1, 2024. These notes were tendered by the sole investor on March 17, 2020. On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following: • Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021; • Retire the $200 million 5.875% senior notes due July 15, 2020; and • Repay a portion of short-term debt. On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan. Debt Covenants Revolving Credit Facility Under our Revolving Credit Facility and term loan agreements we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with our covenants at December 31, 2020 as shown below: As of December 31, 2020 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 59.9% Less than 65% Wyoming Electric Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2020, we were in compliance with these covenants. Dividend Restrictions Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2020: • Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2020, the restricted net assets at our Electric and Gas Utilities were approximately $155 million. |
Stockholders' Equity_
Stockholders' Equity: | 12 Months Ended |
Dec. 31, 2020 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity | STOCKHOLDERS' EQUITY February 2020 Equity Issuance On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the SEC. At-the-Market Equity Offering Program On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. This forward sales option allows us to sell our shares through the ATM program at the current trading price without actually issuing any shares to satisfy the sale until a future date. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August 3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares under the ATM during the twelve months ended December 31, 2020. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM for $99 million, net of $1.2 million in issuance costs. We did not issue any common shares under the ATM during the twelve months ended December 31, 2018. Shareholder Dividend Reinvestment and Stock Purchase Plan We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2020, there were 163,962 shares of unissued stock available for future offering under the DRSPP. Preferred Stock Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding. |
Risk Management And Derivatives
Risk Management And Derivatives: | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management And Derivatives | RISK MANAGEMENT AND DERIVATIVES Market and Credit Risk Disclosures Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1 . Market Risk Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed, but not limited to, the following market risks: • Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and • Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic. Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified. Our credit exposure at December 31, 2020 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. We continue to monitor COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify estimated future financial impacts to the allowance for credit losses. During the year ended December 31, 2020, the potential economic impact of the COVID-19 pandemic was considered in forward looking projections related to write-off and recovery rates, and resulted in increases to the allowance for credit losses and bad debt expense of $3.3 million. See Note 1 for further information. Derivatives and Hedging Activity Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 12 . The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income. We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income. We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from January 2021 through May 2022. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly. The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our utilities are comprised of both short and long positions. We had the following net long positions as of: December 31, 2020 December 31, 2019 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 620,000 3 1,450,000 12 Natural gas options purchased, net 3,160,000 3 3,240,000 3 Natural gas basis swaps purchased 900,000 3 1,290,000 12 Natural gas over-the-counter swaps, net (b) 3,850,000 17 4,600,000 24 Natural gas physical commitments, net (c) 17,513,061 22 13,548,235 12 Electric wholesale contracts (c) 219,000 12 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2020, 914,600 of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP. We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At December 31, 2020, the Company posted $1.5 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets. Derivatives by Balance Sheet Classification As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements that allow us to settle positive and negative positions. The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands): Balance Sheet Location 2020 2019 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 181 $ 1 Noncurrent commodity derivatives Other assets, non-current 43 3 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (108) (490) Noncurrent commodity derivatives Other deferred credits and other liabilities — (29) Total derivatives designated as hedges $ 116 $ (515) Derivatives not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1,667 $ 341 Noncurrent commodity derivatives Other assets, non-current 151 2 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (1,936) (1,764) Noncurrent commodity derivatives Other deferred credits and other liabilities — (63) Total derivatives not designated as hedges $ (118) $ (1,484) Derivatives Designated as Hedge Instruments The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2020, 2019 and 2018. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. 2020 2019 2018 2020 2019 2018 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in OCI Income Statement Location Amount of Gain/(Loss) Reclassified from AOCI into Income (in thousands) (in thousands) Interest rate swaps $ 2,851 $ 2,851 $ 2,851 Interest expense $ (2,851) $ (2,851) $ (2,851) Commodity derivatives 540 (965) 1,113 Fuel, purchased power and cost of natural gas sold (601) 417 (130) Total $ 3,391 $ 1,886 $ 3,964 $ (3,452) $ (2,434) $ (2,981) As of December 31, 2020, $2.8 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. 2020 2019 2018 Derivatives Not Designated as Hedging Instruments Income Statement Location Amount of Gain/(Loss) on Derivatives Recognized in Income (in thousands) Commodity derivatives - Electric Fuel, purchased power and cost of natural gas sold $ 144 $ — $ — Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 1,640 (1,100) 1,101 $ 1,784 $ (1,100) $ 1,101 As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to these financial instruments in our Gas Utilities were $2.2 million and $3.3 million at December 31, 2020 and 2019, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income. |
Fair Value Measurements_
Fair Value Measurements: | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements Derivatives The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of December 31, 2020 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in thousands) Assets: Commodity derivatives - Gas Utilities $ — $ 2,504 $ — $ (1,527) $ 977 Commodity derivatives - Electric Utilities — 1,065 — — 1,065 Total $ — $ 3,569 $ — $ (1,527) $ 2,042 Liabilities: Commodity derivatives - Gas Utilities $ — $ 2,675 $ — $ (1,552) $ 1,123 Commodity derivatives - Electric Utilities $ 921 $ — $ 921 Total $ — $ 3,596 $ — $ (1,552) $ 2,044 _______________ (a) As of December 31, 2020, $1.5 million of our commodity derivative gross assets and $1.6 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements. As of December 31, 2019 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total Assets: Commodity derivatives - Gas Utilities $ — 1,433 $ — $ (1,085) $ 348 Total $ — $ 1,433 $ — $ (1,085) $ 348 Liabilities: Commodity derivatives - Gas Utilities $ — $ 5,254 $ — $ (2,909) $ 2,345 Total $ — $ 5,254 $ — $ (2,909) $ 2,345 _______________ (a) As of December 31, 2019, $1.1 million of our commodity derivative assets and $2.9 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements. Pension and Postretirement Plan Assets A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 15 . Nonrecurring Fair Value Measurement A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 1 . Other Fair Value Measurements The carrying amount of cash and cash equivalents, restricted cash and equivalents, and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets at December 31 (in thousands): 2020 2019 Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current maturities (a) $ 3,536,536 $ 4,208,167 $ 3,145,839 $ 3,479,367 _______________ (a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs. |
Other Comprehensive Income_
Other Comprehensive Income: | 12 Months Ended |
Dec. 31, 2020 | |
Statement of Comprehensive Income [Abstract] | |
Other Comprehensive Income | OTHER COMPREHENSIVE INCOME We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Consolidated Statements of Income Amount Reclassified from AOCI December 31, 2020 December 31, 2019 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,851) $ (2,851) Commodity contracts Fuel, purchased power and cost of natural gas sold (601) 417 (3,452) (2,434) Income tax Income tax benefit (expense) 383 611 Total reclassification adjustments related to cash flow hedges, net of tax $ (3,069) $ (1,823) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 103 $ 77 Actuarial gain (loss) Operations and maintenance (2,387) (745) (2,284) (668) Income tax Income tax benefit (expense) 935 (453) Total reclassification adjustments related to defined benefit plans, net of tax $ (1,349) $ (1,121) Total reclassifications $ (4,418) $ (2,944) Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655) Other comprehensive income (loss) before reclassifications — (47) (1,062) (1,109) Amounts reclassified from AOCI 2,564 505 1,349 4,418 As of December 31, 2020 $ (12,558) $ 2 $ (14,790) $ (27,346) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2018 $ (17,307) $ 328 $ (9,937) $ (26,916) Other comprehensive income (loss) before reclassifications — (422) (6,261) (6,683) Amounts reclassified from AOCI 2,185 (362) 1,121 2,944 As of December 31, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655) |
Variable Interest Entity
Variable Interest Entity | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable Interest Entity | VARIABLE INTEREST ENTITY Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP to a third-party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric. The accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810, Consolidation . The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Net income available for common stock for the years ended December 31, 2020, 2019 and 2018 was reduced by $15 million, $14 million, and $14 million, respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of net income attributable to this noncontrolling interest are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31 (in thousands): 2020 2019 Assets: Current assets $ 13,604 $ 13,350 Property, plant and equipment of variable interest entities, net $ 190,637 $ 193,046 Liabilities: Current liabilities $ 5,318 $ 6,013 |
Employee Benefits Plans_
Employee Benefits Plans: | 12 Months Ended |
Dec. 31, 2020 | |
Retirement Benefits [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Defined Contribution Plans We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company. Defined Benefit Pension Plan We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria. The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments. The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2020, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 28% to 36% return-seeking assets and 64% to 72% liability-hedging assets. Our Pension Plan is funded in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows: 2020 2019 Equity 21% 20% Real estate 3 3 Fixed income 69 71 Cash 3 1 Hedge funds 4 5 Total 100% 100% Supplemental Non-qualified Defined Benefit Plans We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are funded on a cash basis as benefits are paid. Non-pension Defined Benefit Postretirement Healthcare Plan BHC sponsors a retiree healthcare plan (Healthcare Plan) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plan for participating business units are pre-funded via VEBA trusts. Pre-65 retirees as well as a grandfathered group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for post-65 Medicare-eligible retirees is provided through an individual market healthcare exchange. We fund the Healthcare Plan on a cash basis as benefits are paid. The Healthcare Plan provides for partial pre-funding via VEBA trusts. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Iowa and Kansas. We do not pre-fund the Healthcare Plan for those employees outside Arkansas, Iowa and Kansas. Plan Contributions Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands): 2020 2019 Defined Contribution Plan Company retirement contributions $ 10,455 $ 9,714 Company matching contributions $ 15,240 $ 14,558 2020 2019 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 12,700 Non-Pension Defined Benefit Postretirement Healthcare Plan $ 6,058 $ 7,033 Supplemental Non-Qualified Defined Benefit Plans $ 2,674 $ 2,344 We do not have required 2021 contributions and currently do not expect to contribute to our Pension Plan. Fair Value Measurements The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Common Collective Trust - Cash and Cash Equivalents $ — $ 16,810 $ — $ 16,810 $ — $ 16,810 Common Collective Trust - Equity — 100,311 — 100,311 — 100,311 Common Collective Trust - Fixed Income — 324,845 — 324,845 — 324,845 Common Collective Trust - Real Estate — — — — 14,301 14,301 Hedge Funds — — — — 17,454 17,454 Total investments measured at fair value $ — $ 441,966 $ — $ 441,966 $ 31,755 $ 473,721 Pension Plan December 31, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 60 $ — $ 60 $ — $ 60 Common Collective Trust - Cash and Cash Equivalents — 7,054 — 7,054 — 7,054 Common Collective Trust - Equity — 87,106 — 87,106 — 87,106 Common Collective Trust - Fixed Income — 306,275 — 306,275 — 306,275 Common Collective Trust - Real Estate — — — — 14,239 14,239 Hedge Funds — — — — 19,550 19,550 Total investments measured at fair value $ — $ 400,495 $ — $ 400,495 $ 33,789 $ 434,284 _____________ (a) Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,165 $ — $ — $ 8,165 $ 8,165 Total investments measured at fair value $ 8,165 $ — $ — $ 8,165 $ 8,165 Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,305 $ — $ — $ 8,305 $ 8,305 Total investments measured at fair value $ 8,305 $ — $ — $ 8,305 $ 8,305 Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows: Pension Plan Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2. Common Collective Trust-Real Estate Funds : These funds are valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. Some of the funds without participant withdrawal limitations are categorized as Level 2. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance: Common Collective Trust-Real Estate Fund : This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy. Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. 10% of the shares may be redeemed at the end of each month with a 15-day notice and full redemptions are available at the end of each quarter with 60-day notice and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. Non-pension Defined Benefit Postretirement Healthcare Plan Cash and Cash Equivalents: This represents an investment in Northern Institutional Government Assets Portfolio, which is a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, amounts recognized in the Consolidated Balance Sheets, accumulated benefit obligation, and reconciliation of components of the net periodic expense and elements of AOCI (in thousands): Employee Benefit Plan Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Change in benefit obligation: Projected benefit obligation at beginning of year $ 485,376 $ 445,381 $ 54,088 $ 43,010 $ 65,277 $ 60,817 Service cost (a) 5,411 5,383 1,579 4,995 2,056 1,815 Interest cost 13,426 17,374 1,099 1,295 1,649 2,247 Actuarial (gain) loss 47,064 56,384 962 7,132 5,804 5,976 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Plan participants’ contributions — — — — 1,510 1,455 Projected benefit obligation at end of year $ 514,008 $ 485,376 $ 55,054 $ 54,088 $ 70,238 $ 65,277 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised. Fair Value Employee Benefit Plan Assets Defined Benefit Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan (a) As of December 31, 2020 2019 2020 2019 2020 2019 Change in fair value of plan assets: Beginning fair value of plan assets $ 434,284 $ 390,796 $ — $ — $ 8,305 $ 8,162 Investment income (loss) 64,006 69,934 — — 33 260 Employer contributions 12,700 12,700 2,674 2,344 4,374 5,461 Retiree contributions — — — — 1,511 1,455 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Ending fair value of plan assets $ 473,721 $ 434,284 $ — $ — $ 8,165 $ 8,305 ____________________ (a) Assets of VEBA trusts. In 2012, we froze our Pension Plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, recent capital markets volatility driven by the COVID-19 pandemic did not materially affect our unfunded status. Amounts Recognized in the Consolidated Balance Sheets Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Regulatory assets $ 86,677 $ 88,471 $ — $ — $ 16,102 $ 11,670 Current liabilities $ — $ — $ 1,927 $ 1,420 $ 4,931 $ 4,802 Non-current liabilities $ 40,287 $ 51,093 $ 53,127 $ 51,243 $ 57,142 $ 52,136 Regulatory liabilities $ 3,607 $ 3,524 $ — $ — $ 2,140 $ 4,088 Accumulated Benefit Obligation Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Accumulated Benefit Obligation $ 498,815 $ 470,615 $ 54,779 $ 49,241 $ 70,238 $ 65,277 Components of Net Periodic Expense Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan For the years ended December 31, 2020 2019 2018 2020 2019 2018 2020 2019 2018 Service cost (a) $ 5,411 $ 5,383 $ 6,834 $ 1,579 $ 4,995 $ 1,764 $ 2,056 $ 1,815 $ 2,291 Interest cost 13,426 17,374 15,470 1,099 1,295 1,170 1,649 2,247 2,085 Expected return on assets (22,591) (24,401) (24,741) — — — (182) (230) (315) Net amortization of prior service cost — 26 58 2 2 2 (546) (398) (398) Recognized net actuarial loss (gain) 8,372 3,763 8,632 1,702 535 1,000 20 — 216 Net periodic expense $ 4,618 $ 2,145 $ 6,253 $ 4,382 $ 6,827 $ 3,936 $ 2,997 $ 3,434 $ 3,879 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised. For the years ended December 31, 2020, 2019 and 2018, Service costs were recorded in Operations and maintenance expense while non service costs were recorded in Other expense on the Consolidated Statements of Income. Change in Accounting Principle - Pension Accounting Asset Method Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company used a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement. We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a decrease to prior service costs, as recorded in Other income (expense), net, of $0.6 million, an increase in Income tax expense of $0.2 million and an increase to Net income of $0.4 million within the accompanying Consolidated Statements of Income for the year ended December 31, 2020. AOCI Amounts (After-Tax) Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Net (gain) loss $ 5,511 $ 5,322 $ 9,323 $ 9,893 $ 100 $ 90 Prior service cost (gain) — — — 2 (144) (230) Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense $ 5,511 $ 5,322 $ 9,323 $ 9,895 $ (44) $ (140) Assumptions Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine benefit obligations: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate 2.56 % 3.27 % 4.40 % 2.41 % 3.14 % 4.34 % 2.41 % 3.15 % 4.28 % Rate of increase in compensation levels 3.34 % 3.49 % 3.52 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate (a) 3.27 % 4.40 % 3.71 % 3.14 % 4.34 % 3.67 % 3.15 % 4.28 % 3.60 % Expected long-term rate of return on assets (b) 5.25 % 6.00 % 6.25 % N/A N/A N/A 2.35 % 3.00 % 3.93 % Rate of increase in compensation levels 3.49 % 3.52 % 3.43 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 2.56% for the calculation of the 2021 net periodic pension costs. (b) The expected rate of return on plan assets is 4.50% for the calculation of the 2021 net periodic pension cost. The healthcare benefit obligation at December 31 was determined as follows: 2020 2019 Trend Rate - Medical Pre-65 for next year - All Plans 6.10% 6.40% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2027 Post-65 for next year - All Plans 4.92% 4.92% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2029 2028 The following benefit payments to employees, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2021 $ 25,842 $ 1,927 $ 6,108 2022 $ 26,658 $ 1,968 $ 5,965 2023 $ 27,581 $ 2,033 $ 5,725 2024 $ 28,284 $ 2,231 $ 5,532 2025 $ 29,062 $ 2,690 $ 5,244 2026-2030 $ 144,273 $ 13,117 $ 22,872 |
Share-based Compensation Plans_
Share-based Compensation Plans: | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement [Abstract] | |
Share-based Compensation Plans | SHARE-BASED COMPENSATION PLANS Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options, performance shares and performance share units. We had 561,073 shares available to grant at December 31, 2020. Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2020, total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 2 years. Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31 (in thousands): 2020 2019 2018 Stock-based compensation expense $ 5,373 $ 12,095 $ 12,390 Stock Options The Company has not issued any stock options since 2014 and has 5,000 stock options outstanding at December 31, 2020. The amount of stock options granted and related exercise activity are not material to the Company’s consolidated financial statements. Restricted Stock The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant. The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over three years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period. A summary of the status of the restricted stock and restricted stock units at December 31, 2020, was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at January 1, 2020 192 $ 65.66 Granted 116 69.49 Vested (90) 63.30 Forfeited (22) 65.30 Balance at December 31, 2020 196 $ 69.05 The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, were as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2020 $ 69.49 $ 6,722 2019 $ 73.66 $ 8,438 2018 $ 57.31 $ 6,776 As of December 31, 2020, there was $10.3 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.2 years. Performance Share Plan Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.7 million at December 31, 2020 would be reclassified as a liability. Outstanding performance periods at December 31, 2020 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2020 January 1, 2020 - December 31, 2022 36 0% 200% January 1, 2019 January 1, 2019 - December 31, 2021 36 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 49 0% 200% A summary of the status of the Performance Share Plan at December 31, 2020 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2020 (in thousands) (in thousands) Performance Shares balance at beginning of period 67 $ 64.32 67 Granted 19 81.42 19 Forfeited (2) 73.89 (2) Vested (23) 63.52 (23) Performance Shares balance at end of period 61 $ 69.71 61 $ 52.42 _____________________ (a) The grant date fair values for the performance shares granted in 2020, 2019 and 2018 were determined by Monte Carlo simulation using a blended volatility of 18%, 21% and 21%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2020 $ 81.42 December 31, 2019 $ 68.72 December 31, 2018 $ 61.82 Performance plan payouts have been as follows (in thousands): Performance Period Year Paid Stock Issued Cash Paid Total Intrinsic Value January 1, 2017 to December 31, 2019 2020 14 $ 1,100 $ 2,199 January 1, 2016 to December 31, 2018 2019 44 $ 2,860 $ 5,720 January 1, 2015 to December 31, 2017 2018 — — — On January 27, 2021, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2018 through December 31, 2020 performance period was at the 55th percentile of its peer group and confirmed a payout equal to 112.35% of target shares, valued at $3.3 million. The payout was fully accrued at December 31, 2020. As of December 31, 2020, there was $2.0 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.7 years. |
Income Taxes_
Income Taxes: | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES CARES Act On March 27, 2020, President Trump signed the CARES Act, which contained, in part, an allowance for deferral of the employer portion of Social Security employment tax liabilities until 2021 and 2022, as well as a COVID-19 employee retention tax credit of up to $5,000 per eligible employee. Eligible employers are taxpayers experiencing either: (1) a full or partial suspension of business operations stemming from a government COVID-19 related order or (2) a more than 50% drop in gross receipts compared to the corresponding calendar quarter in 2019. This 50% employee retention tax credit applies up to $10,000 in qualified wages paid between March 13, 2020 through December 31, 2020, and is refundable to the extent it exceeds the employer portion of payroll tax liability. Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee did not provide services. However, employees do not need to stop providing all services to the employer for the credit to potentially apply. Additionally, the CARES Act accelerates the amount of alternative minimum tax (“AMT”) credits that can be refunded for the 2018 and 2019 annual tax returns. In 2020, we filed for, and received, a refund of approximately $2.4 million of AMT credit carryforwards under this provision. During the year ended December 31, 2020, we utilized the payroll tax deferral provision which allowed us to defer payment of approximately $10 million of Social Security employment tax liabilities. We are currently reviewing the potential future benefits of the CARES Act related to employee retention tax credits to assess the impact on our financial position, results of operations and cash flows. TCJA On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the federal and state utility commissions, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the year ended December 31, 2018, we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2020, the Company has amortized $13.3 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2020, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. Income Tax Expense (Benefit) Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2020 2019 2018 Current: Federal $ (6,020) $ (8,578) $ 325 State 847 138 247 Current income tax expense (benefit) (5,173) (8,440) 572 Deferred: Federal 35,672 34,551 (25,022) State 2,419 3,469 783 Deferred income tax expense (benefit) 38,091 38,020 (24,239) Income tax expense (benefit) $ 32,918 $ 29,580 $ (23,667) Effective Tax Rates The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2020 2019 2018 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax (net of federal tax effect) 2.4 1.5 2.3 Non-controlling interest (a) (1.2) (1.2) (1.3) Tax credits (b) (c) (9.2) (3.9) (2.0) Flow-through adjustments (d) (1.6) (2.4) (1.6) Jurisdictional consolidation project (e) — — (28.5) Uncertain Tax Benefits 1.5 — — Valuation Allowance 0.7 — — Other tax differences 0.6 (1.6) (0.1) TCJA corporate rate reduction (f) — — 1.6 Amortization of excess deferred income tax expense (g) (2.3) (1.2) (0.7) Effective Tax Rate 11.9 % 12.2 % (9.3) % _________________________ (a) The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (b) The current year increase of PTCs reflect full year production of two wind facilities that were acquired/ placed into service during 2019; Top of Iowa purchased February 2019 and Busch Ranch II with an in-service date of November 2019. Additionally, in November 2020, the Corriedale qualifying wind facility was placed in service. (c) In 2020, the Company completed a research and development study which encompassed tax years from 2013 to 2019. (d) Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. (e) In 2018, the Company restructured certain legal entities from earlier acquisitions, which resulted in additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, and deferred tax benefits of $73 million. (f) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. During the year ended December 31, 2018, we recorded $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. (g) Primarily TCJA - see above. Deferred Tax Assets and Liabilities The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2020 2019 Deferred tax assets: Regulatory liabilities $ 90,535 $ 89,754 State tax credits 23,339 23,261 Federal NOL 96,155 120,624 State NOL 9,914 13,537 Partnership 15,601 14,030 Credit Carryovers 51,445 27,139 Other deferred tax assets 40,143 33,395 Less: Valuation allowance (13,943) (12,063) Total deferred tax assets 313,189 309,677 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (551,137) (533,292) Regulatory assets (28,007) (23,586) Goodwill (30,590) (15,875) State deferred tax liability (73,910) (72,911) Other deferred tax liabilities (38,169) (24,732) Total deferred tax liabilities (721,813) (670,396) Net deferred tax liability $ (408,624) $ (360,719) Net Operating Loss Carryforwards At December 31, 2020, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal NOL Carryforward $ 378,236 2022 to 2037 Federal NOL Carryforward $ 79,644 No expiration State NOL Carryforward (a) $ 173,867 2021 to 2040 _________________________ (a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes. As of December 31, 2020, we had a $1.1 million valuation allowance against the state NOL carryforwards. Our 2020 analysis of the ability to utilize such NOLs resulted in a $0.8 million increase in the valuation allowance reduced by previously reserved expiring NOL of $0.2 million, which results in an increase to tax expense of $0.8 million net of federal income tax and a decrease to the state NOL deferred tax asset of $0.2 million. The valuation allowance adjustment was primarily attributable to statutory rate reduction for years beyond 2020. Unrecognized Tax Benefits The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands): Changes in Uncertain Tax Positions Beginning balance at January 1, 2018 $ 3,263 Additions for prior year tax positions 251 Reductions for prior year tax positions (417) Additions for current year tax positions 486 Settlements — Ending balance at December 31, 2018 3,583 Additions for prior year tax positions 446 Reductions for prior year tax positions (862) Additions for current year tax positions 998 Settlements — Ending balance at December 31, 2019 4,165 Additions for prior year tax positions 3,788 Reductions for prior year tax positions (1,313) Additions for current year tax positions 1,743 Settlements — Ending balance at December 31, 2020 $ 8,383 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $4.3 million. We recognized no interest expense associated with income taxes for the years ended December 31, 2020, December 31, 2019 and December 31, 2018. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2020 and December 31, 2019. The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which filed a separate consolidated tax return from BHC and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. BHC is no longer subject to examination for tax years prior to 2017. As of December 31, 2020, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2021. State tax credits have been generated and are available to offset future state income taxes. At December 31, 2020, we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year ITC $ 23,060 2023 to 2041 Research and development $ 278 No expiration As of December 31, 2020, we had a $12.8 million valuation allowance against the state ITC carryforwards. Our 2020 analysis of the ability to utilize such ITC resulted in a $1.3 million increase in the valuation allowance, which resulted in an increase to tax expense of $1.3 million. The valuation allowance adjustment was primarily attributable to changes in forecasted future state taxable income. |
Business Segment Information_
Business Segment Information: | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting Information, Additional Information [Abstract] | |
Business Segment Information | BUSINESS SEGMENT INFORMATION Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the Chief Operating Decision Maker (CODM) assesses performance. The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results. Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2020 2019 Electric Utilities $ 3,120,928 $ 2,900,983 Gas Utilities 4,376,204 4,032,339 Power Generation 404,220 417,715 Mining 77,085 77,175 Corporate and Other 110,349 130,245 Total assets $ 8,088,786 $ 7,558,457 Capital Expenditures (a) for the years ended December 31, 2020 2019 Electric Utilities $ 271,104 $ 222,911 Gas Utilities 449,209 512,366 Power Generation 9,329 85,346 Mining 8,250 8,430 Corporate and Other 17,500 20,702 Total capital expenditures $ 755,392 $ 849,755 _________________ (a) Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows . Property, Plant and Equipment as of December 31, 2020 2019 Electric Utilities $ 3,248,480 $ 3,059,135 Gas Utilities 3,312,613 2,981,498 Power Generation 534,803 534,518 Mining 187,540 180,473 Corporate and Other 22,094 29,055 Total property, plant and equipment $ 7,305,530 $ 6,784,679 Consolidating Income Statement Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 687,929 $ 959,696 $ 6,090 $ 27,089 $ — $ — $ 1,680,804 Other revenues 2,201 9,962 1,566 2,408 — — 16,137 690,130 969,658 7,656 29,497 — — 1,696,941 Inter-company operating revenue - Contracts with customers 23,914 4,724 97,169 31,478 167 (157,452) — Other revenues — 288 222 100 352,976 (353,586) — 23,914 5,012 97,391 31,578 353,143 (511,038) — Total revenue 714,044 974,670 105,047 61,075 353,143 (511,038) 1,696,941 Fuel, purchased power and cost of natural gas sold 267,045 354,645 8,993 — 83 (138,362) 492,404 Operations and maintenance, including taxes 196,794 303,577 33,695 39,033 284,501 (305,823) 551,777 Depreciation, depletion and amortization 94,150 100,559 20,247 9,235 25,150 (24,884) 224,457 Adjusted operating income (loss) $ 156,055 $ 215,889 $ 42,112 $ 12,807 $ 43,409 $ (41,969) $ 428,303 Interest expense, net (143,470) Impairment of investment (6,859) Other income (expense), net (2,293) Income tax benefit (expense) (32,918) Income from continuing operations 242,763 (Loss) from discontinued operations, net of tax — Net income 242,763 Net income attributable to noncontrolling interest (15,155) Net income available for common stock $ 227,608 Consolidating Income Statement Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 684,445 $ 1,007,187 $ 7,580 $ 27,180 $ — $ — $ 1,726,392 Other revenues 5,191 384 1,859 1,074 — $ — 8,508 689,636 1,007,571 9,439 28,254 — — 1,734,900 Inter-company operating revenue - Contracts with customers 23,116 2,459 91,577 32,053 230 (149,435) — Other revenues — — 242 1,322 343,975 (345,539) — 23,116 2,459 91,819 33,375 344,205 (494,974) — Total revenue 712,752 1,010,030 101,258 61,629 344,205 (494,974) 1,734,900 Fuel, purchased power and cost of natural gas sold 268,297 425,898 9,059 — 268 (132,693) 570,829 Operations and maintenance, including taxes 195,581 301,844 28,429 40,032 286,799 (303,776) 548,909 Depreciation, depletion and amortization 88,577 92,317 18,991 8,970 22,065 (21,800) 209,120 Adjusted operating income (loss) 160,297 189,971 44,779 12,627 35,073 (36,705) 406,042 Interest expense, net (137,659) Impairment of investment (19,741) Other income (expense), net (5,740) Income tax benefit (expense) (29,580) Income from continuing operations 213,322 (Loss) from discontinued operations, net of tax — Net income 213,322 Net income attributable to noncontrolling interest (14,012) Net income available for common stock $ 199,310 Consolidating Income Statement Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 686,272 $ 1,022,828 $ 5,833 $ 33,609 $ — $ — $ 1,748,542 Other revenues 2,427 955 1,413 931 — — 5,726 688,699 1,023,783 7,246 34,540 — — 1,754,268 Inter-company operating revenue - Contracts with customers 22,752 1,524 84,959 32,194 148 (141,577) — Other revenues — — 246 1,299 379,775 (381,320) — 22,752 1,524 85,205 33,493 379,923 (522,897) — Total revenue 711,451 1,025,307 92,451 68,033 379,923 (522,897) 1,754,268 Fuel, purchased power and cost of natural gas sold 283,840 462,153 8,592 — 44 (129,019) 625,610 Operations and maintenance, including taxes 186,175 291,481 25,135 43,728 324,916 (336,142) 535,293 Depreciation, depletion and amortization 85,567 86,434 16,110 7,965 21,161 (20,909) 196,328 Adjusted operating income (loss) 155,869 185,239 42,614 16,340 33,802 (36,827) 397,037 Interest expense, net (139,975) Other income (expense), net (1,180) Income tax benefit (expense) 23,667 Income from continuing operations 279,549 (Loss) from discontinued operations, net of tax (6,887) Net income 272,662 Net income attributable to noncontrolling interest (14,220) Net income available for common stock $ 258,442 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2020 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENT In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. Our Utilities have regulatory mechanisms to recover the increased energy costs from this record-breaking cold weather event. However, given the extraordinary impact of these higher costs to our customers, we expect our regulators to undertake a heightened review. We are engaged with our regulators to identify appropriate recovery periods over which to recover costs associated with this event as we continue to address the impacts to our customers’ bills. As a result of this historic event, our natural gas purchases increased by approximately $600 million compared to forecasted base load for the month of February. This amount is a preliminary estimate through February 24, 2021, and does not include certain pipeline transportation charges that remain subject to settlement and payable in late March 2021. To fund February natural gas purchases and pipeline transportation charges and provide additional liquidity, we entered into a nine-month Credit Agreement on February 24, 2021, that provides for an $800 million unsecured term loan facility. The term loan, which matures on November 23, 2021, has an interest rate based on LIBOR plus 75 basis points, carries no prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We expect to repay a portion of this term loan prior to maturity and refinance the remaining portion in longer-term debt. In the event we are unable to refinance the remaining obligation under the $800 million term loan, we believe it is probable that our current plans to manage liquidity would be sufficient to meet our obligations. Except as described above and the Note 2 disclosures surrounding Colorado Gas’ and Nebraska Gas’ jurisdictional consolidation and rate reviews, there have been no events subsequent to December 31, 2020 which would require recognition in the consolidated financial statements or disclosures. |
Business Description And Sign_2
Business Description And Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Segment Reporting | Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Both of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 18 . On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued operations. Unless otherwise noted, the amounts presented in the accompanying Notes to Consolidated Financial Statements relate to the Company’s continuing operations. |
Use of Estimates and Basis of Presentation | Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. COVID-19 Pandemic In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations. The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the year ended December 31, 2020, there were no material adverse impacts on the Company’s results of operations. |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 18 . Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generation facility, wind farm or transmission tie. See Note 6 for additional information. |
Variable Interest Entities | Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 14 . |
Cash and Cash Equivalents and Restricted Cash | Cash and Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash. |
Accounts Receivable and Allowance for Credit Losses | Accounts Receivable and Allowance for Credit Losses Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal primarily to affiliates or regional utilities. We maintain an allowance for credit losses which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for credit losses to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. |
Materials, Supplies and Fuel | Materials, Supplies and Fuel The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2020 2019 Materials and supplies $ 85,250 $ 82,809 Fuel 1,531 2,425 Natural gas in storage 30,619 31,938 Total materials, supplies and fuel $ 117,400 $ 117,172 Materials and supplies represent parts and supplies for all of our business segments. Fuel represents diesel oil and gas used by our Electric Utilities to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. |
Investments | Investments In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment at that time. During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time. |
Property, Plant and Equipment | Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our stored natural gas base or Cushion Gas as property, plant and equipment. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs related to our regulated properties that do not have legal retirement obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. The composite depreciation method is applied to regulated utility property. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. See Note 5 for additional information. |
Asset Retirement Obligations | Asset Retirement Obligations Accounting standards for AROs associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. Additional information is included in Note 7 . |
Goodwill and Intangible Assets | Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life are amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, which are also its reportable segments. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies. |
Fair Value Measurements | Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives The wholesale electric energy and natural gas commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2). For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Additional information on fair value measurements is included in Notes 12 and 15 . |
Derivatives and Hedging Activities | Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. In addition, certain derivative contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980, Regulated Operations . We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on these designated derivatives is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivative contracts are recognized in earnings. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures. See additional information in Notes 11 , 12 and 13 . |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities. See additional information in Note 9 . |
Regulatory Accounting | Regulatory Accounting Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates. • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings. If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows. As of December 31, 2020 and 2019, we had total regulatory assets of $278 million and $271 million respectively, and total regulatory liabilities of $533 million and $537 million respectively. See Note 2 for further information. |
Income Taxes | Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax benefit (expense) on the Consolidated Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 17 for additional information. |
Earnings per Share of Common Stock | Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans. |
Noncontrolling Interest | Noncontrolling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidation. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 14 for additional detail on noncontrolling interests. |
Share-Based Compensation | Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation , by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. See additional information in Note 16 . Change in Accounting Principle - Pension Accounting Asset Method Effective January 1, 2020, we changed our method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will continue to use a calculated value for the return-seeking assets (equities) in the portfolio but was changed to fair value for the liability-hedging assets (fixed income). See Note 15 for additional information. |
Recently Issued and Adopted Accounting Standards | Recently Issued Accounting Standards Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting , which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2022. We are currently evaluating if we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements and the potential impact on our financial position, results of operations and cash flows. Simplifying the Accounting for Income Taxes, ASU 2019-12 In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740 , Income Taxes , and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. Adoption of this standard is not anticipated to have a material impact on our financial position, results of operations and cash flows. Recently Adopted Accounting Standards Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-13 In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for credit losses, primarily associated with the inclusion of expected losses on unbilled revenue. The cumulative effect of the adoption, net of tax impact, was $0.2 million, which was recorded as an adjustment to retained earnings. Simplifying the Test for Goodwill Impairment, ASU 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have any impact on our financial position, results of operations or cash flows. Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15 In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract , which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows. |
Revenue from Contract with Customer | REVENUE Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, Regulated Operations, that provide services to regulated customers under tariff rates, charges, terms and conditions of service and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our Utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. Certain energy sale and purchase transactions with the same counterparty and at the same delivery point are netted to reflect the economic substance of the arrangement. • Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate Electric Utilities, and an affiliate non-regulated Power Generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered. • Other non-regulated services - Our Electric and Gas Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The majority of our revenue contracts are based on variable quantities delivered. Any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative revenue programs revenue under ASC 980, Regulated Operations . Significant Judgments and Estimates Unbilled Revenue To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month, the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 1 . |
Business Description And Sign_3
Business Description And Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Accounts Receivable and Allowance for Doubtful Accounts | Following is a summary of accounts receivable as of December 31 (in thousands): 2020 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net Electric Utilities $ 45,841 $ 32,915 $ (1,269) $ 77,487 Gas Utilities 95,592 93,150 (5,734) 183,008 Power Generation 1,837 — — 1,837 Mining 2,511 — — 2,511 Corporate 1,118 — — 1,118 Total $ 146,899 $ 126,065 $ (7,003) $ 265,961 2019 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net Electric Utilities $ 41,428 $ 33,886 $ (592) $ 74,722 Gas Utilities 97,607 79,616 (1,683) 175,540 Power Generation 2,164 — — 2,164 Mining 2,277 — — 2,277 Corporate 1,271 — (169) 1,102 Total $ 144,747 $ 113,502 $ (2,444) $ 255,805 |
Financing Receivable, Current, Allowance for Credit Loss | Changes to allowance for credit losses for the years ended December 31, were as follows (in thousands): Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year 2020 $ 2,444 $ 8,927 (a) $ 4,728 $ (9,096) $ 7,003 2019 $ 3,209 $ 5,795 $ 3,942 $ (10,502) $ 2,444 2018 $ 3,081 $ 6,859 $ 4,092 $ (10,823) $ 3,209 _________________ (a) Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections due to non-payment for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the year ended December 31, 2020 by an incremental $3.3 million. The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 11 . |
Materials, Supplies and Fuel | The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2020 2019 Materials and supplies $ 85,250 $ 82,809 Fuel 1,531 2,425 Natural gas in storage 30,619 31,938 Total materials, supplies and fuel $ 117,400 $ 117,172 |
Investments | The following table presents the carrying value of our investments (in thousands), which are included in Other assets, non-current on the Consolidated Balance Sheets, as of December 31: 2020 2019 Investment in privately held oil and gas company $ 1,500 $ 8,359 Cash surrender value of life insurance contracts 13,628 13,056 Other investments 682 514 Total investments $ 15,810 $ 21,929 |
Goodwill | As of December 31, 2020 and 2019, Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Goodwill $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 |
Intangible Assets | Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2020 2019 2018 Intangible assets, net, beginning balance $ 13,266 $ 14,337 $ 7,559 Additions — — 7,602 Amortization expense (a) (1,322) (1,071) (824) Intangible assets, net, ending balance $ 11,944 $ 13,266 $ 14,337 _________________ (a) Amortization expense for existing intangible assets is expected to be $1.3 million for each year of the next five years. |
Schedule of Accrued Liabilities | The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2020 2019 Accrued employee compensation, benefits and withholdings $ 77,806 $ 62,837 Accrued property taxes 47,105 44,547 Customer deposits and prepayments 52,185 54,728 Accrued interest 31,520 31,868 Other (none of which is individually significant) 34,996 32,787 Total accrued liabilities $ 243,612 $ 226,767 |
Earnings Per Share of Common Stock | A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands): 2020 2019 2018 Net income available for common stock $ 227,608 $ 199,310 $ 258,442 Weighted average shares - basic 62,378 60,662 54,420 Dilutive effect of: Equity Units — — 898 Equity compensation 61 136 168 Weighted average shares - diluted 62,439 60,798 55,486 Net income available for common stock, per share - Diluted $ 3.65 $ 3.28 $ 4.66 |
Antidilutive Securities | The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands): 2020 2019 2018 Equity compensation 60 1 16 Anti-dilutive shares excluded from computation of earnings per share 60 1 16 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets and Liabilities | We had the following regulatory assets and liabilities as of December 31 (in thousands): 2020 2019 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 39,035 $ 34,088 Deferred gas cost adjustments (a) 3,200 1,540 Gas price derivatives (a) 2,226 3,328 Deferred taxes on AFUDC (b) 7,491 7,790 Employee benefit plans and related deferred taxes (c) 116,598 115,900 Environmental (a) 1,413 1,454 Loss on reacquired debt (a) 22,864 24,777 Renewable energy standard adjustment (a) — 1,622 Deferred taxes on flow-through accounting (c) 47,515 41,220 Decommissioning costs (a) 8,988 10,670 Gas supply contract termination (a) 2,524 8,485 Other regulatory assets (a) 26,404 20,470 Total regulatory assets 278,258 271,344 Less current regulatory assets (51,676) (43,282) Regulatory assets, non-current $ 226,582 $ 228,062 Regulatory liabilities Deferred energy and gas costs (a) $ 13,253 $ 17,278 Employee benefit plan costs and related deferred taxes (c) 40,256 43,349 Cost of removal (a) 172,902 166,727 Excess deferred income taxes (c) 285,259 285,438 Other regulatory liabilities (c) 21,050 23,860 Total regulatory liabilities 532,720 536,652 Less current regulatory liabilities (25,061) (33,507) Regulatory liabilities, non-current $ 507,659 $ 503,145 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. |
Commitment, Contingencies And_2
Commitment, Contingencies And Guarentees (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Long-term Purchase Commitment [Line Items] | |
Unrecorded Unconditional Purchase Obligations Disclosure | The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and natural gas transportation and storage agreements (in thousands): Power purchase and transmission services agreements (a) Natural gas transportation and storage agreements 2021 $ 24,452 $ 116,563 2022 $ 11,678 $ 121,819 2023 $ 11,678 $ 100,282 2024 $ 2,738 $ 67,089 2025 $ — $ 50,709 Thereafter $ — $ 167,100 _____________ (a) This schedule does not reflect renewable energy PPA obligations since these agreements vary based on weather conditions. |
Schedule of Unit Contingent Capacity | The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: Contract Years Total Contract Capacity Contingent Capacity Amounts on Wygen III Contingent Capacity Amounts on Neil Simpson II 2020-2022 15 MW 7 MW 8 MW 2022-2023 15 MW 8 MW 7 MW 2023-2028 10 MW 5 MW 5 MW |
Schedule of Guarantor Obligations | To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets. We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2020 Expiration Indemnification for subsidiary reclamation/surety bonds $ 53,769 Ongoing |
Transmission Service Agreement | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment | Through our subsidiaries, we have the following significant long-term power purchase contracts and transmission services agreement (TSA) with non-affiliated third-parties: Subsidiary Contract Type Counterparty Fuel Type Quantity (MW) Expiration Date Colorado Electric (a) PPA PRPA Wind 60 May 31, 2030 Colorado Electric PPA PRPA Coal 25 June 30, 2024 South Dakota Electric PPA PacifiCorp Coal 50 December 31, 2023 South Dakota Electric (b) TSA PacifiCorp N/A 50 December 31, 2023 South Dakota Electric PPA PRPA Wind 12 September 30, 2029 South Dakota Electric PPA Fall River Solar, LLC Solar 80 Pending Completion (c) Wyoming Electric (d) PPA Happy Jack Wind 30 September 3, 2028 Wyoming Electric (e) PPA Silver Sage Wind 30 September 30, 2029 _____________ (a) Colorado Electric sells the wind energy purchased under this PPA to City of Colorado Springs as discussed below. (b) This is a firm point-to-point transmission service agreement that provides 50 MW of capacity and energy to be transmitted annually. (c) This agreement relates to a new solar facility currently being constructed and will expire 20 years after construction completion, which is expected by the end of 2022. (d) Under a separate intercompany PSA, Wyoming Electric sells 50% of the facility output to South Dakota Electric. (e) Under a separate intercompany PSA, Wyoming Electric sells 67% of the facility output to South Dakota Electric. |
Power purchased | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment | Costs under these agreements for the years ended December 31 were as follows (in thousands): Subsidiary Contract Type Counterparty Fuel Type 2020 2019 2018 Colorado Electric PPA PRPA Wind $ 2,791 $ — $ — Colorado Electric PPA PRPA Coal $ 4,524 $ 1,802 $ — South Dakota Electric PPA PacifiCorp Coal $ 5,897 $ 7,477 $ 13,681 South Dakota Electric TSA PacifiCorp N/A $ 1,776 $ 1,741 $ 1,742 South Dakota Electric PPA PRPA Wind $ 715 $ 688 $ 223 Wyoming Electric PPA Happy Jack Wind $ 4,531 $ 3,936 $ 3,884 Wyoming Electric PPA Silver Sage Wind $ 6,203 $ 5,366 $ 5,376 |
Purchased Gas Cost Obligation | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment | At December 31, 2020, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): Northern Natural Gas - Ventura Northwest Pipeline - Wyoming ONEOK - Oklahoma Southern Star Central Gas Pipeline Panhandle Eastern Pipe Line 2021 3,650,000 1,510,000 5,475,000 113,130 4,680 2022 1,810,000 1,510,000 5,475,000 — — 2023 1,840,000 1,510,000 5,475,000 — — 2024 1,820,000 910,000 5,490,000 — — 2025 — — 4,560,000 — — Thereafter — — — — — |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments, for the years ended December 31, 2020, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 610,721 $ 765,922 $ — $ 58,567 $ (31,478) $ 1,403,732 Transportation — 154,581 — — (526) 154,055 Wholesale 17,848 — 103,258 — (97,169) 23,937 Market - off-system sales 24,309 260 — — (8,797) 15,772 Transmission/Other 58,965 43,658 — — (19,315) 83,308 Revenue from contracts with customers 711,843 964,421 103,258 58,567 (157,285) 1,680,804 Other revenues 2,201 10,249 1,789 2,508 (610) 16,137 Total revenues $ 714,044 $ 974,670 $ 105,047 $ 61,075 $ (157,895) $ 1,696,941 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 58,567 $ (31,478) $ 27,089 Services transferred over time 711,843 964,421 103,258 — (125,807) 1,653,715 Revenue from contracts with customers $ 711,843 $ 964,421 $ 103,258 $ 58,567 $ (157,285) $ 1,680,804 Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 605,756 $ 817,840 $ — $ 59,233 $ (32,053) $ 1,450,776 Transportation — 143,390 — — (1,042) 142,348 Wholesale 20,884 — 99,157 — (91,577) 28,464 Market - off-system sales 23,817 691 — — (7,736) 16,772 Transmission/Other 57,104 47,725 — — (16,797) 88,032 Revenue from contracts with customers 707,561 1,009,646 99,157 59,233 (149,205) 1,726,392 Other revenues 5,191 384 2,101 2,396 (1,564) 8,508 Total revenues $ 712,752 $ 1,010,030 $ 101,258 $ 61,629 $ (150,769) $ 1,734,900 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 59,233 $ (32,053) $ 27,180 Services transferred over time 707,561 1,009,646 99,157 — (117,152) 1,699,212 Revenue from contracts with customers $ 707,561 $ 1,009,646 $ 99,157 $ 59,233 $ (149,205) $ 1,726,392 Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 594,329 $ 833,379 $ — $ 65,803 $ (32,194) $ 1,461,317 Transportation — 140,705 — — (1,348) 139,357 Wholesale 33,687 — 90,791 — (84,957) 39,521 Market - off-system sales 24,799 866 — — (8,102) 17,563 Transmission/Other 56,209 49,402 — — (14,827) 90,784 Revenue from contracts with customers 709,024 1,024,352 90,791 65,803 (141,428) 1,748,542 Other revenues 2,427 955 1,660 2,230 (1,546) 5,726 Total revenues $ 711,451 $ 1,025,307 $ 92,451 $ 68,033 $ (142,974) $ 1,754,268 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 65,803 $ (32,194) $ 33,609 Services transferred over time 709,024 1,024,352 90,791 — (109,234) 1,714,933 Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 90,791 $ 65,803 $ (141,428) $ 1,748,542 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2020 2019 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,417,951 40 $ 1,348,049 41 32 46 Electric transmission 517,794 49 483,640 51 44 51 Electric distribution 959,453 46 861,042 47 46 48 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 259,010 28 259,266 28 26 29 Total electric plant in service 3,159,078 2,956,867 Construction work in progress 89,402 102,268 Total electric plant 3,248,480 3,059,135 Less accumulated depreciation (666,669) (670,861) Electric plant net of accumulated depreciation $ 2,581,811 $ 2,388,274 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 10 years remaining. 2020 2019 Lives (in years) Gas Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Gas plant: Production $ 15,603 40 $ 13,000 35 24 46 Gas transmission 578,278 54 516,172 50 22 71 Gas distribution 2,115,082 53 1,857,233 43 45 59 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciable (a) 39,184 N/A 44,443 N/A N/A N/A Storage 55,481 38 46,977 31 24 52 General 438,217 19 437,054 20 12 23 Total gas plant in service 3,245,384 2,918,418 Construction work in progress 67,229 63,080 Total gas plant 3,312,613 2,981,498 Less accumulated depreciation (323,679) (336,721) Gas plant net of accumulated depreciation $ 2,988,934 $ 2,644,777 _____________ (a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 529,927 $ 4,876 $ 534,803 $ (167,787) $ 367,016 31 2 40 Mining $ 186,552 $ 988 $ 187,540 $ (126,537) $ 61,003 14 2 59 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 532,397 $ 2,121 $ 534,518 $ (154,362) $ 380,156 31 2 40 Mining $ 179,198 $ 1,275 $ 180,473 $ (118,585) $ 61,888 13 2 59 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,692 $ 16,402 $ 22,094 $ (1,144) $ 20,950 10 10 22 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,721 $ 23,334 $ 29,055 $ (964) $ 28,091 10 3 30 |
Jointly Owned Facilities (Table
Jointly Owned Facilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Jointly Owned Utility Plants | At December 31, 2020, our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation Wyodak Plant $ 116,074 $ 2,249 $ (67,762) $ 50,561 Transmission Tie $ 26,176 $ 509 $ (7,103) $ 19,582 Wygen III $ 142,739 $ 582 $ (24,783) $ 118,538 Wygen I $ 114,975 $ 318 $ (49,459) $ 65,834 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2019 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2020 Electric Utilities (a) $ 9,329 $ 1,217 $ — $ 407 $ — $ 10,953 Gas Utilities (b) 36,085 4,782 (132) 1,539 — 42,274 Power Generation 4,739 — — 206 — 4,945 Mining (c) 14,052 — (185) 617 (1,225) 13,259 Total 64,205 $ 5,999 $ (317) $ 2,769 $ (1,225) $ 71,431 December 31, 2018 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2019 Electric Utilities (d) $ 6,258 $ — $ — $ 385 $ 2,686 $ 9,329 Gas Utilities 34,627 — — 1,458 — 36,085 Power Generation (a) 300 3,445 — 158 836 4,739 Mining (c) 15,615 — (380) 740 (1,923) 14,052 Total $ 56,800 $ 3,445 $ (380) $ 2,741 $ 1,599 $ 64,205 _____________________ (a) Liabilities incurred were related to new wind assets. (b) Liabilities incurred were driven by an increase in gas pipeline miles; which increases our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The Mining Revisions to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process. (d) The Electric Utilities Revisions to Prior Estimates was primarily driven by an increase in the estimated cost to decommission certain regulated wind farm assets. |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Lessee Disclosure [Abstract] | |
Lease, Cost | Lease expense for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease cost Operations and maintenance $ 978 $ 1,456 |
Lessee Supplemental Balance Sheet Information | Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2020 2019 Assets: Operating lease assets Other assets, non-current $ 4,188 $ 4,629 Total lease assets $ 4,188 $ 4,629 Liabilities: Current: Operating leases Accrued liabilities $ 736 $ 1,179 Noncurrent: Operating leases Other deferred credits and other liabilities 3,807 3,821 Total lease liabilities $ 4,543 $ 5,000 |
Lessee Supplemental Cash Flow Information | Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2020 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,023 $ 1,263 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 161 $ 2,801 |
Lessee Supplemental Weighted Average Schedule | Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2020 2019 Weighted average remaining lease term: Operating leases 8 years 8 years Weighted average discount rate: Operating leases 4.24 % 4.27 % |
Finance Lease, Liability, Maturity | As of December 31, 2020, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases 2021 $ 907 2022 804 2023 779 2024 776 2025 529 Thereafter 1,643 Total lease payments $ 5,438 Less imputed interest 895 Present value of lease liabilities $ 4,543 |
Lessor Disclosure [Abstract] | |
Operating Lease, Lease Income | Lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease income Revenue $ 2,534 $ 2,306 |
Lessor - Operating And Finance Lease, Liability, Maturity | As of December 31, 2020, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2021 $ 2,383 2022 2,122 2023 2,130 2024 2,074 2025 2,090 Thereafter 58,829 Total lease receivables $ 69,628 |
Debt and Credit Facilities (Tab
Debt and Credit Facilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |
Schedule of Short-term Debt | We had the following Notes payable outstanding at the Consolidated Balance Sheets date (in thousands): December 31, 2020 December 31, 2019 Balance Outstanding Letters of Credit (a) Balance Outstanding Letters of Credit (a) Revolving Credit Facility $ — $ 24,730 $ — $ 30,274 CP Program 234,040 — 349,500 — Total $ 234,040 $ 24,730 $ 349,500 $ 30,274 _______________ (a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility. |
Schedule of Long-term Debt Instruments | Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2020 December 31, 2020 December 31, 2019 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 300,000 Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 400,000 Senior unsecured notes, due 2029 October 15, 2029 3.05% 400,000 400,000 Senior unsecured notes, due 2030 June 15, 2030 2.50% 400,000 — Senior unsecured notes due 2033 May 1, 2033 4.35% 400,000 400,000 Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Senior unsecured notes, due 2049 October 15, 2049 3.88% 300,000 300,000 Corporate term loan due 2021 June 7, 2021 2.32% 1,436 7,178 Total Corporate debt 3,026,436 2,632,178 Less unamortized debt discount (7,013) (6,462) Total Corporate debt, net 3,019,423 2,625,716 South Dakota Electric Series 94A Debt, variable rate (a) June 1, 2024 N/A — 2,855 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 Total South Dakota Electric debt 340,000 342,855 Less unamortized debt discount (78) (82) Total South Dakota Electric debt, net 339,922 342,773 Wyoming Electric Industrial development revenue bonds due 2021 (a) (b) September 1, 2021 0.12% 7,000 7,000 Industrial development revenue bonds due 2027 (a) (b) March 1, 2027 0.12% 10,000 10,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 Total Wyoming Electric debt 202,000 202,000 Less unamortized debt discount — — Total Wyoming Electric debt, net 202,000 202,000 Total long-term debt 3,561,345 3,170,489 Less current maturities 8,436 5,743 Less unamortized deferred financing costs (c) 24,809 24,650 Long-term debt, net of current maturities and deferred financing costs $ 3,528,100 $ 3,140,096 _______________ (a) Variable interest rate. (b) A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due March 1, 2027 and the 2009B bonds of $7.0 million due September 1, 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. (c) Includes deferred financing costs associated with our Revolving Credit Facility of $1.0 million and $1.7 million as of December 31, 2020 and December 31, 2019, respectively. |
Schedule of Maturities of Long-term Debt | Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2021 $ 8,436 2022 $ — 2023 $ 525,000 2024 $ — 2025 $ — Thereafter $ 3,035,000 |
Deferred Financing Costs | Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2020 2020 2019 2018 $ 24,809 $ 3,272 $ 3,242 $ 2,829 |
Credit Facility and Short Term Debt Covenants | We were in compliance with our covenants at December 31, 2020 as shown below: As of December 31, 2020 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 59.9% Less than 65% |
Risk Management And Derivativ_2
Risk Management And Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Contract or notional amounts and terms of marketing activities and derivative commodity instruments | The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our utilities are comprised of both short and long positions. We had the following net long positions as of: December 31, 2020 December 31, 2019 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 620,000 3 1,450,000 12 Natural gas options purchased, net 3,160,000 3 3,240,000 3 Natural gas basis swaps purchased 900,000 3 1,290,000 12 Natural gas over-the-counter swaps, net (b) 3,850,000 17 4,600,000 24 Natural gas physical commitments, net (c) 17,513,061 22 13,548,235 12 Electric wholesale contracts (c) 219,000 12 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2020, 914,600 of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP. |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands): Balance Sheet Location 2020 2019 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 181 $ 1 Noncurrent commodity derivatives Other assets, non-current 43 3 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (108) (490) Noncurrent commodity derivatives Other deferred credits and other liabilities — (29) Total derivatives designated as hedges $ 116 $ (515) Derivatives not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1,667 $ 341 Noncurrent commodity derivatives Other assets, non-current 151 2 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (1,936) (1,764) Noncurrent commodity derivatives Other deferred credits and other liabilities — (63) Total derivatives not designated as hedges $ (118) $ (1,484) |
Derivative Instruments, Gain (Loss) | The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2020, 2019 and 2018. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. 2020 2019 2018 2020 2019 2018 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in OCI Income Statement Location Amount of Gain/(Loss) Reclassified from AOCI into Income (in thousands) (in thousands) Interest rate swaps $ 2,851 $ 2,851 $ 2,851 Interest expense $ (2,851) $ (2,851) $ (2,851) Commodity derivatives 540 (965) 1,113 Fuel, purchased power and cost of natural gas sold (601) 417 (130) Total $ 3,391 $ 1,886 $ 3,964 $ (3,452) $ (2,434) $ (2,981) As of December 31, 2020, $2.8 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. 2020 2019 2018 Derivatives Not Designated as Hedging Instruments Income Statement Location Amount of Gain/(Loss) on Derivatives Recognized in Income (in thousands) Commodity derivatives - Electric Fuel, purchased power and cost of natural gas sold $ 144 $ — $ — Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 1,640 (1,100) 1,101 $ 1,784 $ (1,100) $ 1,101 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of December 31, 2020 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in thousands) Assets: Commodity derivatives - Gas Utilities $ — $ 2,504 $ — $ (1,527) $ 977 Commodity derivatives - Electric Utilities — 1,065 — — 1,065 Total $ — $ 3,569 $ — $ (1,527) $ 2,042 Liabilities: Commodity derivatives - Gas Utilities $ — $ 2,675 $ — $ (1,552) $ 1,123 Commodity derivatives - Electric Utilities $ 921 $ — $ 921 Total $ — $ 3,596 $ — $ (1,552) $ 2,044 _______________ (a) As of December 31, 2020, $1.5 million of our commodity derivative gross assets and $1.6 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements. As of December 31, 2019 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total Assets: Commodity derivatives - Gas Utilities $ — 1,433 $ — $ (1,085) $ 348 Total $ — $ 1,433 $ — $ (1,085) $ 348 Liabilities: Commodity derivatives - Gas Utilities $ — $ 5,254 $ — $ (2,909) $ 2,345 Total $ — $ 5,254 $ — $ (2,909) $ 2,345 _______________ (a) As of December 31, 2019, $1.1 million of our commodity derivative assets and $2.9 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements. |
Fair Value, by Balance Sheet Grouping | The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets at December 31 (in thousands): 2020 2019 Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current maturities (a) $ 3,536,536 $ 4,208,167 $ 3,145,839 $ 3,479,367 _______________ (a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs. |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Statement of Comprehensive Income [Abstract] | |
Reclassification out of Accumulated Other Comprehensive Income | The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Consolidated Statements of Income Amount Reclassified from AOCI December 31, 2020 December 31, 2019 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,851) $ (2,851) Commodity contracts Fuel, purchased power and cost of natural gas sold (601) 417 (3,452) (2,434) Income tax Income tax benefit (expense) 383 611 Total reclassification adjustments related to cash flow hedges, net of tax $ (3,069) $ (1,823) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 103 $ 77 Actuarial gain (loss) Operations and maintenance (2,387) (745) (2,284) (668) Income tax Income tax benefit (expense) 935 (453) Total reclassification adjustments related to defined benefit plans, net of tax $ (1,349) $ (1,121) Total reclassifications $ (4,418) $ (2,944) |
Schedule of Accumulated Other Comprehensive Income (Loss) | Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655) Other comprehensive income (loss) before reclassifications — (47) (1,062) (1,109) Amounts reclassified from AOCI 2,564 505 1,349 4,418 As of December 31, 2020 $ (12,558) $ 2 $ (14,790) $ (27,346) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2018 $ (17,307) $ 328 $ (9,937) $ (26,916) Other comprehensive income (loss) before reclassifications — (422) (6,261) (6,683) Amounts reclassified from AOCI 2,185 (362) 1,121 2,944 As of December 31, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655) |
Variable Interest Entity (Table
Variable Interest Entity (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Variable Interest Entities | We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31 (in thousands): 2020 2019 Assets: Current assets $ 13,604 $ 13,350 Property, plant and equipment of variable interest entities, net $ 190,637 $ 193,046 Liabilities: Current liabilities $ 5,318 $ 6,013 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows: 2020 2019 Equity 21% 20% Real estate 3 3 Fixed income 69 71 Cash 3 1 Hedge funds 4 5 Total 100% 100% |
Schedule of Employer Contribution to Employee Benefit Plans | Contributions for the years ended December 31 were as follows (in thousands): 2020 2019 Defined Contribution Plan Company retirement contributions $ 10,455 $ 9,714 Company matching contributions $ 15,240 $ 14,558 2020 2019 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 12,700 Non-Pension Defined Benefit Postretirement Healthcare Plan $ 6,058 $ 7,033 Supplemental Non-Qualified Defined Benefit Plans $ 2,674 $ 2,344 |
Schedule of Changes in Projected Benefit Obligations | The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, amounts recognized in the Consolidated Balance Sheets, accumulated benefit obligation, and reconciliation of components of the net periodic expense and elements of AOCI (in thousands): Employee Benefit Plan Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Change in benefit obligation: Projected benefit obligation at beginning of year $ 485,376 $ 445,381 $ 54,088 $ 43,010 $ 65,277 $ 60,817 Service cost (a) 5,411 5,383 1,579 4,995 2,056 1,815 Interest cost 13,426 17,374 1,099 1,295 1,649 2,247 Actuarial (gain) loss 47,064 56,384 962 7,132 5,804 5,976 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Plan participants’ contributions — — — — 1,510 1,455 Projected benefit obligation at end of year $ 514,008 $ 485,376 $ 55,054 $ 54,088 $ 70,238 $ 65,277 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised. |
Schedule of Changes in Fair Value of Plan Assets | Defined Benefit Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan (a) As of December 31, 2020 2019 2020 2019 2020 2019 Change in fair value of plan assets: Beginning fair value of plan assets $ 434,284 $ 390,796 $ — $ — $ 8,305 $ 8,162 Investment income (loss) 64,006 69,934 — — 33 260 Employer contributions 12,700 12,700 2,674 2,344 4,374 5,461 Retiree contributions — — — — 1,511 1,455 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Ending fair value of plan assets $ 473,721 $ 434,284 $ — $ — $ 8,165 $ 8,305 ____________________ (a) Assets of VEBA trusts. |
Schedule of Amounts Recognized in Balance Sheet | Amounts Recognized in the Consolidated Balance Sheets Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Regulatory assets $ 86,677 $ 88,471 $ — $ — $ 16,102 $ 11,670 Current liabilities $ — $ — $ 1,927 $ 1,420 $ 4,931 $ 4,802 Non-current liabilities $ 40,287 $ 51,093 $ 53,127 $ 51,243 $ 57,142 $ 52,136 Regulatory liabilities $ 3,607 $ 3,524 $ — $ — $ 2,140 $ 4,088 |
Schedule of Accumulated and Projected Benefit Obligations | Accumulated Benefit Obligation Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Accumulated Benefit Obligation $ 498,815 $ 470,615 $ 54,779 $ 49,241 $ 70,238 $ 65,277 |
Components of net periodic benefit cost | Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan For the years ended December 31, 2020 2019 2018 2020 2019 2018 2020 2019 2018 Service cost (a) $ 5,411 $ 5,383 $ 6,834 $ 1,579 $ 4,995 $ 1,764 $ 2,056 $ 1,815 $ 2,291 Interest cost 13,426 17,374 15,470 1,099 1,295 1,170 1,649 2,247 2,085 Expected return on assets (22,591) (24,401) (24,741) — — — (182) (230) (315) Net amortization of prior service cost — 26 58 2 2 2 (546) (398) (398) Recognized net actuarial loss (gain) 8,372 3,763 8,632 1,702 535 1,000 20 — 216 Net periodic expense $ 4,618 $ 2,145 $ 6,253 $ 4,382 $ 6,827 $ 3,936 $ 2,997 $ 3,434 $ 3,879 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised. |
Schedule of Net Periodic Benefit Cost Not yet Recognized | Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Net (gain) loss $ 5,511 $ 5,322 $ 9,323 $ 9,893 $ 100 $ 90 Prior service cost (gain) — — — 2 (144) (230) Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense $ 5,511 $ 5,322 $ 9,323 $ 9,895 $ (44) $ (140) |
Schedule of Assumptions Used | Assumptions Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine benefit obligations: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate 2.56 % 3.27 % 4.40 % 2.41 % 3.14 % 4.34 % 2.41 % 3.15 % 4.28 % Rate of increase in compensation levels 3.34 % 3.49 % 3.52 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate (a) 3.27 % 4.40 % 3.71 % 3.14 % 4.34 % 3.67 % 3.15 % 4.28 % 3.60 % Expected long-term rate of return on assets (b) 5.25 % 6.00 % 6.25 % N/A N/A N/A 2.35 % 3.00 % 3.93 % Rate of increase in compensation levels 3.49 % 3.52 % 3.43 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 2.56% for the calculation of the 2021 net periodic pension costs. (b) The expected rate of return on plan assets is 4.50% for the calculation of the 2021 net periodic pension cost. |
Schedule of Health Care Cost Trend Rates | The healthcare benefit obligation at December 31 was determined as follows: 2020 2019 Trend Rate - Medical Pre-65 for next year - All Plans 6.10% 6.40% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2027 Post-65 for next year - All Plans 4.92% 4.92% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2029 2028 |
Schedule of Expected Benefit Payments | The following benefit payments to employees, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2021 $ 25,842 $ 1,927 $ 6,108 2022 $ 26,658 $ 1,968 $ 5,965 2023 $ 27,581 $ 2,033 $ 5,725 2024 $ 28,284 $ 2,231 $ 5,532 2025 $ 29,062 $ 2,690 $ 5,244 2026-2030 $ 144,273 $ 13,117 $ 22,872 |
Pension Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Common Collective Trust - Cash and Cash Equivalents $ — $ 16,810 $ — $ 16,810 $ — $ 16,810 Common Collective Trust - Equity — 100,311 — 100,311 — 100,311 Common Collective Trust - Fixed Income — 324,845 — 324,845 — 324,845 Common Collective Trust - Real Estate — — — — 14,301 14,301 Hedge Funds — — — — 17,454 17,454 Total investments measured at fair value $ — $ 441,966 $ — $ 441,966 $ 31,755 $ 473,721 Pension Plan December 31, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 60 $ — $ 60 $ — $ 60 Common Collective Trust - Cash and Cash Equivalents — 7,054 — 7,054 — 7,054 Common Collective Trust - Equity — 87,106 — 87,106 — 87,106 Common Collective Trust - Fixed Income — 306,275 — 306,275 — 306,275 Common Collective Trust - Real Estate — — — — 14,239 14,239 Hedge Funds — — — — 19,550 19,550 Total investments measured at fair value $ — $ 400,495 $ — $ 400,495 $ 33,789 $ 434,284 _____________ (a) Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. |
Postretirement Health Coverage | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,165 $ — $ — $ 8,165 $ 8,165 Total investments measured at fair value $ 8,165 $ — $ — $ 8,165 $ 8,165 Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,305 $ — $ — $ 8,305 $ 8,305 Total investments measured at fair value $ 8,305 $ — $ — $ 8,305 $ 8,305 |
Share-based Compensation Plans
Share-based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement [Abstract] | |
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs | Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31 (in thousands): 2020 2019 2018 Stock-based compensation expense $ 5,373 $ 12,095 $ 12,390 |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | A summary of the status of the restricted stock and restricted stock units at December 31, 2020, was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at January 1, 2020 192 $ 65.66 Granted 116 69.49 Vested (90) 63.30 Forfeited (22) 65.30 Balance at December 31, 2020 196 $ 69.05 The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, were as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2020 $ 69.49 $ 6,722 2019 $ 73.66 $ 8,438 2018 $ 57.31 $ 6,776 |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | Outstanding performance periods at December 31, 2020 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2020 January 1, 2020 - December 31, 2022 36 0% 200% January 1, 2019 January 1, 2019 - December 31, 2021 36 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 49 0% 200% A summary of the status of the Performance Share Plan at December 31, 2020 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2020 (in thousands) (in thousands) Performance Shares balance at beginning of period 67 $ 64.32 67 Granted 19 81.42 19 Forfeited (2) 73.89 (2) Vested (23) 63.52 (23) Performance Shares balance at end of period 61 $ 69.71 61 $ 52.42 _____________________ (a) The grant date fair values for the performance shares granted in 2020, 2019 and 2018 were determined by Monte Carlo simulation using a blended volatility of 18%, 21% and 21%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2020 $ 81.42 December 31, 2019 $ 68.72 December 31, 2018 $ 61.82 |
Performance Plan Payouts | Performance plan payouts have been as follows (in thousands): Performance Period Year Paid Stock Issued Cash Paid Total Intrinsic Value January 1, 2017 to December 31, 2019 2020 14 $ 1,100 $ 2,199 January 1, 2016 to December 31, 2018 2019 44 $ 2,860 $ 5,720 January 1, 2015 to December 31, 2017 2018 — — — |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2020 2019 2018 Current: Federal $ (6,020) $ (8,578) $ 325 State 847 138 247 Current income tax expense (benefit) (5,173) (8,440) 572 Deferred: Federal 35,672 34,551 (25,022) State 2,419 3,469 783 Deferred income tax expense (benefit) 38,091 38,020 (24,239) Income tax expense (benefit) $ 32,918 $ 29,580 $ (23,667) |
Schedule of Effective Income Tax Rate Reconciliation | Effective Tax Rates The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2020 2019 2018 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax (net of federal tax effect) 2.4 1.5 2.3 Non-controlling interest (a) (1.2) (1.2) (1.3) Tax credits (b) (c) (9.2) (3.9) (2.0) Flow-through adjustments (d) (1.6) (2.4) (1.6) Jurisdictional consolidation project (e) — — (28.5) Uncertain Tax Benefits 1.5 — — Valuation Allowance 0.7 — — Other tax differences 0.6 (1.6) (0.1) TCJA corporate rate reduction (f) — — 1.6 Amortization of excess deferred income tax expense (g) (2.3) (1.2) (0.7) Effective Tax Rate 11.9 % 12.2 % (9.3) % _________________________ (a) The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (b) The current year increase of PTCs reflect full year production of two wind facilities that were acquired/ placed into service during 2019; Top of Iowa purchased February 2019 and Busch Ranch II with an in-service date of November 2019. Additionally, in November 2020, the Corriedale qualifying wind facility was placed in service. (c) In 2020, the Company completed a research and development study which encompassed tax years from 2013 to 2019. (d) Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. (e) In 2018, the Company restructured certain legal entities from earlier acquisitions, which resulted in additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, and deferred tax benefits of $73 million. (f) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. During the year ended December 31, 2018, we recorded $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. (g) Primarily TCJA - see above. |
Schedule of Deferred Tax Assets and Liabilities | The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2020 2019 Deferred tax assets: Regulatory liabilities $ 90,535 $ 89,754 State tax credits 23,339 23,261 Federal NOL 96,155 120,624 State NOL 9,914 13,537 Partnership 15,601 14,030 Credit Carryovers 51,445 27,139 Other deferred tax assets 40,143 33,395 Less: Valuation allowance (13,943) (12,063) Total deferred tax assets 313,189 309,677 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (551,137) (533,292) Regulatory assets (28,007) (23,586) Goodwill (30,590) (15,875) State deferred tax liability (73,910) (72,911) Other deferred tax liabilities (38,169) (24,732) Total deferred tax liabilities (721,813) (670,396) Net deferred tax liability $ (408,624) $ (360,719) |
Summary of Operating Loss Carryforwards | At December 31, 2020, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal NOL Carryforward $ 378,236 2022 to 2037 Federal NOL Carryforward $ 79,644 No expiration State NOL Carryforward (a) $ 173,867 2021 to 2040 _________________________ (a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes. |
Summary of Income Tax Contingencies | The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands): Changes in Uncertain Tax Positions Beginning balance at January 1, 2018 $ 3,263 Additions for prior year tax positions 251 Reductions for prior year tax positions (417) Additions for current year tax positions 486 Settlements — Ending balance at December 31, 2018 3,583 Additions for prior year tax positions 446 Reductions for prior year tax positions (862) Additions for current year tax positions 998 Settlements — Ending balance at December 31, 2019 4,165 Additions for prior year tax positions 3,788 Reductions for prior year tax positions (1,313) Additions for current year tax positions 1,743 Settlements — Ending balance at December 31, 2020 $ 8,383 |
Summary of State Tax Carryforwards | State tax credits have been generated and are available to offset future state income taxes. At December 31, 2020, we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year ITC $ 23,060 2023 to 2041 Research and development $ 278 No expiration |
Business Segment Information (T
Business Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting Information, Additional Information [Abstract] | |
Segment information included in Consolidated Balance Sheets | Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2020 2019 Electric Utilities $ 3,120,928 $ 2,900,983 Gas Utilities 4,376,204 4,032,339 Power Generation 404,220 417,715 Mining 77,085 77,175 Corporate and Other 110,349 130,245 Total assets $ 8,088,786 $ 7,558,457 Capital Expenditures (a) for the years ended December 31, 2020 2019 Electric Utilities $ 271,104 $ 222,911 Gas Utilities 449,209 512,366 Power Generation 9,329 85,346 Mining 8,250 8,430 Corporate and Other 17,500 20,702 Total capital expenditures $ 755,392 $ 849,755 _________________ (a) Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows . Property, Plant and Equipment as of December 31, 2020 2019 Electric Utilities $ 3,248,480 $ 3,059,135 Gas Utilities 3,312,613 2,981,498 Power Generation 534,803 534,518 Mining 187,540 180,473 Corporate and Other 22,094 29,055 Total property, plant and equipment $ 7,305,530 $ 6,784,679 |
Segment information included in Consolidated Statements of Income | Consolidating Income Statement Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 687,929 $ 959,696 $ 6,090 $ 27,089 $ — $ — $ 1,680,804 Other revenues 2,201 9,962 1,566 2,408 — — 16,137 690,130 969,658 7,656 29,497 — — 1,696,941 Inter-company operating revenue - Contracts with customers 23,914 4,724 97,169 31,478 167 (157,452) — Other revenues — 288 222 100 352,976 (353,586) — 23,914 5,012 97,391 31,578 353,143 (511,038) — Total revenue 714,044 974,670 105,047 61,075 353,143 (511,038) 1,696,941 Fuel, purchased power and cost of natural gas sold 267,045 354,645 8,993 — 83 (138,362) 492,404 Operations and maintenance, including taxes 196,794 303,577 33,695 39,033 284,501 (305,823) 551,777 Depreciation, depletion and amortization 94,150 100,559 20,247 9,235 25,150 (24,884) 224,457 Adjusted operating income (loss) $ 156,055 $ 215,889 $ 42,112 $ 12,807 $ 43,409 $ (41,969) $ 428,303 Interest expense, net (143,470) Impairment of investment (6,859) Other income (expense), net (2,293) Income tax benefit (expense) (32,918) Income from continuing operations 242,763 (Loss) from discontinued operations, net of tax — Net income 242,763 Net income attributable to noncontrolling interest (15,155) Net income available for common stock $ 227,608 Consolidating Income Statement Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 684,445 $ 1,007,187 $ 7,580 $ 27,180 $ — $ — $ 1,726,392 Other revenues 5,191 384 1,859 1,074 — $ — 8,508 689,636 1,007,571 9,439 28,254 — — 1,734,900 Inter-company operating revenue - Contracts with customers 23,116 2,459 91,577 32,053 230 (149,435) — Other revenues — — 242 1,322 343,975 (345,539) — 23,116 2,459 91,819 33,375 344,205 (494,974) — Total revenue 712,752 1,010,030 101,258 61,629 344,205 (494,974) 1,734,900 Fuel, purchased power and cost of natural gas sold 268,297 425,898 9,059 — 268 (132,693) 570,829 Operations and maintenance, including taxes 195,581 301,844 28,429 40,032 286,799 (303,776) 548,909 Depreciation, depletion and amortization 88,577 92,317 18,991 8,970 22,065 (21,800) 209,120 Adjusted operating income (loss) 160,297 189,971 44,779 12,627 35,073 (36,705) 406,042 Interest expense, net (137,659) Impairment of investment (19,741) Other income (expense), net (5,740) Income tax benefit (expense) (29,580) Income from continuing operations 213,322 (Loss) from discontinued operations, net of tax — Net income 213,322 Net income attributable to noncontrolling interest (14,012) Net income available for common stock $ 199,310 Consolidating Income Statement Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 686,272 $ 1,022,828 $ 5,833 $ 33,609 $ — $ — $ 1,748,542 Other revenues 2,427 955 1,413 931 — — 5,726 688,699 1,023,783 7,246 34,540 — — 1,754,268 Inter-company operating revenue - Contracts with customers 22,752 1,524 84,959 32,194 148 (141,577) — Other revenues — — 246 1,299 379,775 (381,320) — 22,752 1,524 85,205 33,493 379,923 (522,897) — Total revenue 711,451 1,025,307 92,451 68,033 379,923 (522,897) 1,754,268 Fuel, purchased power and cost of natural gas sold 283,840 462,153 8,592 — 44 (129,019) 625,610 Operations and maintenance, including taxes 186,175 291,481 25,135 43,728 324,916 (336,142) 535,293 Depreciation, depletion and amortization 85,567 86,434 16,110 7,965 21,161 (20,909) 196,328 Adjusted operating income (loss) 155,869 185,239 42,614 16,340 33,802 (36,827) 397,037 Interest expense, net (139,975) Other income (expense), net (1,180) Income tax benefit (expense) 23,667 Income from continuing operations 279,549 (Loss) from discontinued operations, net of tax (6,887) Net income 272,662 Net income attributable to noncontrolling interest (14,220) Net income available for common stock $ 258,442 |
Business Description And Sign_4
Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts Receivable [Line Items] | ||||
Allowance for credit losses | $ (7,003) | $ (2,444) | $ (3,209) | $ (3,081) |
Accounts receivable, net | 265,961 | 255,805 | ||
Corporate, Non-Segment | ||||
Accounts Receivable [Line Items] | ||||
Allowance for credit losses | 0 | (169) | ||
Accounts receivable, net | 1,118 | 1,102 | ||
Electric Utilities | ||||
Accounts Receivable [Line Items] | ||||
Allowance for credit losses | (1,269) | (592) | ||
Accounts receivable, net | 77,487 | 74,722 | ||
Gas Utilities | ||||
Accounts Receivable [Line Items] | ||||
Allowance for credit losses | (5,734) | (1,683) | ||
Accounts receivable, net | 183,008 | 175,540 | ||
Power Generation | ||||
Accounts Receivable [Line Items] | ||||
Allowance for credit losses | 0 | 0 | ||
Accounts receivable, net | 1,837 | 2,164 | ||
Mining | ||||
Accounts Receivable [Line Items] | ||||
Allowance for credit losses | 0 | 0 | ||
Accounts receivable, net | 2,511 | 2,277 | ||
Billed Revenues | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 146,899 | 144,747 | ||
Billed Revenues | Corporate, Non-Segment | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 1,118 | 1,271 | ||
Billed Revenues | Electric Utilities | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 45,841 | 41,428 | ||
Billed Revenues | Gas Utilities | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 95,592 | 97,607 | ||
Billed Revenues | Power Generation | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 1,837 | 2,164 | ||
Billed Revenues | Mining | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 2,511 | 2,277 | ||
Unbilled Revenues | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 126,065 | 113,502 | ||
Unbilled Revenues | Corporate, Non-Segment | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 0 | 0 | ||
Unbilled Revenues | Electric Utilities | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 32,915 | 33,886 | ||
Unbilled Revenues | Gas Utilities | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 93,150 | 79,616 | ||
Unbilled Revenues | Power Generation | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | 0 | 0 | ||
Unbilled Revenues | Mining | ||||
Accounts Receivable [Line Items] | ||||
Accounts Receivable, Trade | $ 0 | $ 0 |
Business Description And Sign_5
Business Description And Significant Accounting Policies: Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Accounts Receivable, Allowance for Credit Loss, Current | $ 2,444 | $ 3,209 | $ 3,081 |
Additions Charged to Costs and Expenses | 8,927 | 5,795 | 6,859 |
Recoveries and Other Additions | 4,728 | 3,942 | 4,092 |
Write-offs and Other Deductions | (9,096) | (10,502) | (10,823) |
Accounts Receivable, Allowance for Credit Loss, Current | 7,003 | $ 2,444 | $ 3,209 |
Potential economic impact of the COVID-19 pandemic | |||
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Additions Charged to Costs and Expenses | 3,300 | ||
Accounts Receivable, Allowance for Credit Loss, Current | $ 3,300 |
Business Description And Sign_6
Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Inventory, Net [Abstract] | ||
Materials and supplies | $ 85,250 | $ 82,809 |
Fuel | 1,531 | 2,425 |
Natural gas in storage | 30,619 | 31,938 |
Total materials, supplies and fuel | $ 117,400 | $ 117,172 |
Business Description And Sign_7
Business Description And Significant Accounting Policies: Investments (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Sep. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Feb. 28, 2019 | |
Investment [Line Items] | ||||||
Assets Held For Sale Used to Acquire Other Investments | $ 28,000 | |||||
Discount Rate Used in Valuation of Fair Value of Oil and Gas Reserve Quantities | 10.00% | |||||
Impairment of investment | $ 20,000 | $ 6,900 | $ 6,859 | $ 19,741 | $ 0 | |
Investments | 15,810 | 21,929 | ||||
Balance Sheet Reclassification from Investments to Other Assets, Non-current | 22,000 | |||||
Investment in privately held oil and gas company | ||||||
Investment [Line Items] | ||||||
Investments | 1,500 | 8,359 | ||||
Cash surrender value of life insurance contracts | ||||||
Investment [Line Items] | ||||||
Investments | 13,628 | 13,056 | ||||
Other investments | ||||||
Investment [Line Items] | ||||||
Investments | $ 682 | $ 514 |
Business Description And Sign_8
Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Goodwill [Line Items] | ||
Goodwill | $ 1,299,454 | $ 1,299,454 |
Electric Utilities | ||
Goodwill [Line Items] | ||
Goodwill | 248,479 | |
Gas Utilities | ||
Goodwill [Line Items] | ||
Goodwill | 1,042,210 | |
Power Generation | ||
Goodwill [Line Items] | ||
Goodwill | $ 8,765 |
Business Description And Sign_9
Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Finite-Lived Intangible Assets [Roll Forward] | |||
Intangible assets, net, beginning balance | $ 13,266 | $ 14,337 | $ 7,559 |
Intangible assets, additions | 0 | 0 | 7,602 |
Intangible assets, amortization expense | (1,322) | (1,071) | (824) |
Intangible assets, net, ending balance | 11,944 | $ 13,266 | $ 14,337 |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |||
Future Amortization Expense, Year One | 1,300 | ||
Future Amortization Expense, Year Two | 1,300 | ||
Future Amortization Expense, Year Three | 1,300 | ||
Future Amortization Expense, Year Four | 1,300 | ||
Future Amortization Expense, Year Five | $ 1,300 | ||
Minimum | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Useful Life | 2 years | ||
Maximum | |||
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Useful Life | 40 years |
Business Description And Sig_10
Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Accrued employee compensation, benefits and withholdings | $ 77,806 | $ 62,837 |
Accrued property taxes | 47,105 | 44,547 |
Customer deposits and prepayments | 52,185 | 54,728 |
Accrued interest | 31,520 | 31,868 |
Other (none of which is individually significant) | 34,996 | 32,787 |
Total accrued liabilities | $ 243,612 | $ 226,767 |
Business Description And Sig_11
Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Regulatory assets | $ 278,258 | $ 271,344 |
Regulatory liabilities | $ 532,720 | $ 536,652 |
Business Description And Sig_12
Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Net income available for common stock | $ 227,608 | $ 199,310 | $ 258,442 |
Weighted average shares - Basic (in shares) | 62,378 | 60,662 | 54,420 |
Dilutive effect of: | |||
Equity Units (in shares) | 0 | 0 | 898 |
Equity compensation (in shares) | 61 | 136 | 168 |
Weighted average shares - diluted (in shares) | 62,439 | 60,798 | 55,486 |
Total earnings (loss) per share of common stock, Diluted (usd per share) | $ 3.65 | $ 3.28 | $ 4.66 |
Business Description And Sig_13
Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 60 | 1 | 16 |
Equity Compensation | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 60 | 1 | 16 |
Business Description And Sig_14
Business Description And Significant Accounting Policies: Recently Adopted Accounting Standards (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Jan. 01, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | $ 2,662,647 | $ 2,464,069 | $ 2,287,423 | $ 1,820,206 | |
Cumulative Effect, Period of Adoption, Adjustment | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | $ (207) | $ 200 | $ 3,390 |
Regulatory Matters_ Regulatory
Regulatory Matters: Regulatory Matters (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Regulatory assets | $ 278,258 | $ 271,344 |
Regulatory assets, current | (51,676) | (43,282) |
Regulatory assets, non-current | 226,582 | 228,062 |
Regulatory liabilities | 532,720 | 536,652 |
Regulatory liabilities, current | (25,061) | (33,507) |
Regulatory liabilities, non-current | 507,659 | 503,145 |
Deferred energy and gas costs | ||
Regulatory liabilities | 13,253 | 17,278 |
Employee benefit plan costs and related deferred taxes | ||
Regulatory liabilities | 40,256 | 43,349 |
Cost of removal | ||
Regulatory liabilities | 172,902 | 166,727 |
Excess deferred income taxes | ||
Regulatory liabilities | 285,259 | 285,438 |
Other regulatory liabilities | ||
Regulatory liabilities | 21,050 | 23,860 |
Deferred energy and gas costs | ||
Regulatory assets | 39,035 | 34,088 |
Deferred gas cost adjustments | ||
Regulatory assets | 3,200 | 1,540 |
Gas price derivatives | ||
Regulatory assets | 2,226 | 3,328 |
Deferred taxes on AFUDC | ||
Regulatory assets | 7,491 | 7,790 |
Employee benefit plan costs and related deferred taxes | ||
Regulatory assets | 116,598 | 115,900 |
Environmental | ||
Regulatory assets | 1,413 | 1,454 |
Loss on reacquired debt | ||
Regulatory assets | 22,864 | 24,777 |
Renewable energy standard adjustment | ||
Regulatory assets | 0 | 1,622 |
Deferred taxes on flow through accounting | ||
Regulatory assets | 47,515 | 41,220 |
Decommissioning costs | ||
Regulatory assets | 8,988 | 10,670 |
Gas supply contract termination | ||
Regulatory assets | 2,524 | 8,485 |
Other regulatory assets | ||
Regulatory assets | $ 26,404 | $ 20,470 |
Regulatory Matters_ Gas Price D
Regulatory Matters: Gas Price Derivatives (Details) | 12 Months Ended |
Dec. 31, 2020 | |
Maximum | |
Derivative, Term of Contract | 2 years |
Regulatory Matters_ Decommissio
Regulatory Matters: Decommissioning Costs (Details) | 12 Months Ended |
Dec. 31, 2020 | |
Decommissioning costs | |
Public Utilities, General Disclosures [Line Items] | |
Regulatory Asset, Amortization Period | 3 years |
Regulatory Matters_ Gas Supply
Regulatory Matters: Gas Supply Contract Termination (Details) | 12 Months Ended |
Dec. 31, 2020$ / Btu | |
Gas supply contract termination | |
Regulatory Asset, Amortization Period | 5 years |
Minimum | |
Oil and Gas Delivery Commitments and Contracts, Fixed Price | 6 |
Maximum | |
Oil and Gas Delivery Commitments and Contracts, Fixed Price | 8 |
Regulatory Matters_ Regulator_2
Regulatory Matters: Regulatory Activity (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Jan. 26, 2021 | Dec. 30, 2020 | |
Benefit from Relieved TCJA Related Liabilities | $ 4,000 | ||
Colorado Public Utilities Commission (CPUC) | Black Hills Energy - Colorado Electric | |||
Settlement of plan to provide TCJA-related customer billing credits to its customers | $ 9,300 | ||
Nebraska Public Service Commission (NPSC) | Black Hills Energy - Nebraska Gas | Subsequent Event | |||
Settlement of plan to provide TCJA-related customer billing credits to its customers | $ 2,900 |
Regulatory Matters_ Electric Ut
Regulatory Matters: Electric Utilities Regulatory Activity (Details) $ in Thousands | Jan. 01, 2022 | Jan. 01, 2020USD ($) | Dec. 31, 2020USD ($) | Oct. 15, 2020MW |
Black Hills Energy, South Dakota Electric | Federal Energy Regulatory Commission (FERC) Common Use System (CUS) | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Annual Revenue Requirement, as Required by the FERC Joint-Access Transmission Tariff | $ 27,000 | |||
Capital Addition Requirements by the FERC Joint-Access Transmission Tariff | $ 33,000 | |||
Black Hills Energy, South Dakota Electric | South Dakota Public Utilities Commission (SDPUC) | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Moratorium Period | 6 years | |||
Public Utilities, Increase in Moratorium Period | 3 years | |||
Public Utilities, Previous Approved Moratorium Period | 6 years | |||
Black Hills Energy, South Dakota Electric | South Dakota Public Utilities Commission (SDPUC) | Application for Deferred Accounting Treatment Withdrawn | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Development Costs Expensed | $ 5,400 | |||
Black Hills Wyoming and Wyoming Electric | Federal Energy Regulatory Commission (FERC) | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Number of Megawatts Capacity Purchased | MW | 60 | |||
Black Hills Wyoming and Wyoming Electric | Federal Energy Regulatory Commission (FERC) | Subsequent Event | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities Term of Power Purchase Agreement | 11 years |
Regulatory Matters_ Gas Utiliti
Regulatory Matters: Gas Utilities Regulatory Activity (Details) $ in Thousands | Mar. 01, 2021 | Jan. 26, 2021USD ($)mi | Sep. 11, 2020USD ($)mi | May 19, 2020USD ($) | Dec. 11, 2019USD ($)utility | Feb. 01, 2019USD ($)gas_distribution_territory |
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Number of Gas Distribution Territories Consolidating | gas_distribution_territory | 2 | |||||
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Colorado Gas | Rate Review Filed with the Regulatory Agency | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities - Length of Natural Gas Pipeline to Receive Infrastructure Investments | mi | 7,000 | |||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 13,500 | $ 2,500 | ||||
Public Utilities, Requested Equity Capital Structure, Percentage | 50.00% | |||||
Public Utilities, Requested Debt Capital Structure, Percentage | 50.00% | |||||
Public Utilities, Requested Return on Equity, Percentage | 9.95% | |||||
Public Utilities, Term Extension of System Saftey and Integrity Rider | 5 years | |||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ (600) | |||||
Public Utilities, Approved Return on Equity, Percentage | 9.20% | |||||
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Rocky Mountain Natural Gas | Rate Review Filed with the Regulatory Agency | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 33,000 | |||||
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Gas | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Number of Gas Distribution Territories Consolidating | utility | 4 | |||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 13,000 | |||||
Public Utilities, Approved Return on Equity, Percentage | 9.40% | |||||
Public Utilities, Approved Equity Capital Structure, Percentage | 50.23% | |||||
Public Utilities, Approved Debt Capital Structure, Percentage | 49.77% | |||||
Nebraska Publc Service Commission (NPSC) | Black Hills Energy - Nebraska Gas | Subsequent Event | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Term Extension of System Saftey and Integrity Rider | 5 years | |||||
Public Utilities, Approved Return on Equity, Percentage | 950.00% | |||||
Public Utilities, Approved Equity Capital Structure, Percentage | 50.00% | |||||
Nebraska Publc Service Commission (NPSC) | Black Hills Energy - Nebraska Gas | Rate Review Filed with the Regulatory Agency | Subsequent Event | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities - Length of Natural Gas Pipeline to Receive Infrastructure Investments | mi | 13,000 | |||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 6,500 | |||||
Public Utilities Amount of System Safety and Integrety Rider Moved to Base Rates | $ 4,600 |
Commitment, Contingencies And_3
Commitment, Contingencies And Guarentees: Power Purchase and Transmission Services Agreements (Details) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2020USD ($)MW | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Jun. 26, 2019MW |
PacifiCorp Transmission | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | $ 1,776 | ||||
Colorado Electric | Wind | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 60 | ||||
Colorado Electric | Coal | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 25 | ||||
Black Hills Energy, South Dakota Electric | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 50 | ||||
Black Hills Energy, South Dakota Electric | Wind | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 12 | ||||
Black Hills Energy, South Dakota Electric | Coal | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 50 | ||||
Black Hills Energy, South Dakota Electric | Solar | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 80 | ||||
Wyoming Electric | Wind | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 30 | ||||
Fall River Solar | Black Hills Energy, South Dakota Electric | Subsequent Event | |||||
Long-term Purchase Commitment [Line Items] | |||||
Purchase Power Agreement Set to Expire after a Certain Number of Years Following Completion of the Facility | 20 years | ||||
Platte River Power Authority - Unit Contingent Energy | Wind | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | $ 2,791 | $ 0 | $ 0 | ||
Platte River Power Authority - Unit Contingent Energy | Coal | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | 4,524 | 1,802 | 0 | ||
PacifiCorp Purchase Power Agreement | Coal | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | 5,897 | 7,477 | 13,681 | ||
PacifiCorp Transmission | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | 1,741 | 1,742 | |||
Platte River Power Authority Wind Power Agreement | |||||
Long-term Purchase Commitment [Line Items] | |||||
Number of Megawatts Capacity Purchased | MW | 60 | ||||
Platte River Power Authority Wind Power Agreement | Wind | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | 715 | 688 | 223 | ||
Happy Jack Wind Purchase Power Agreement | Wind | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | $ 4,531 | 3,936 | 3,884 | ||
Happy Jack Wind Purchase Power Agreement | Wyoming Electric | Subsidiary of Common Parent | |||||
Long-term Purchase Commitment [Line Items] | |||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 50.00% | ||||
Silver Sage Wind Power Purchase Agreement | Wind | |||||
Long-term Purchase Commitment [Line Items] | |||||
Cost of Purchased Power | $ | $ 6,203 | $ 5,366 | $ 5,376 | ||
Silver Sage Wind Power Purchase Agreement | Wyoming Electric | Subsidiary of Common Parent | |||||
Long-term Purchase Commitment [Line Items] | |||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 67.00% |
Commitment, Contingencies And_4
Commitment, Contingencies And Guarentees: Power Purchase Agreement - Related Party (Details) - MW | Jan. 01, 2022 | Dec. 31, 2020 | Oct. 15, 2020 |
Federal Energy Regulatory Commission (FERC) | Black Hills Wyoming and Wyoming Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Megawatts Sold Under Long-Term Contract | 60 | ||
Number of Megawatts Capacity Purchased | 60 | ||
Federal Energy Regulatory Commission (FERC) | Black Hills Wyoming and Wyoming Electric | Subsequent Event | |||
Long-term Purchase Commitment [Line Items] | |||
Public Utilities Term of Power Purchase Agreement | 11 years | ||
Black Hills Wyoming and Wyoming Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Megawatts Sold Under Long-Term Contract | 60 | ||
Black Hills Electric Generation and Colorado Electric | Busch Ranch I Wind Farm | |||
Long-term Purchase Commitment [Line Items] | |||
Number of Megawatts Capacity Purchased | 14.5 | ||
Colorado Electric and Black Hills Colorado IPP | |||
Long-term Purchase Commitment [Line Items] | |||
Number of Megawatts Capacity Purchased | 200 |
Commitment, Contingencies And_5
Commitment, Contingencies And Guarentees: Purchase Commitment (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020USD ($)MMBTU | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Maximum | |||
Long-term Purchase Commitment [Line Items] | |||
We maintain natural gas supply contracts with several vendors that generally cover a period up to: | 1 year | ||
Natural Gas, Distribution | |||
Long-term Purchase Commitment [Line Items] | |||
Natural Gas Purchases | $ | $ 25 | $ 6.7 | $ 27 |
Northern Natural Gas - Ventura | |||
Long-term Purchase Commitment [Line Items] | |||
2021 | 3,650,000 | ||
2022 | 1,810,000 | ||
2023 | 1,840,000 | ||
2024 | 1,820,000 | ||
2025 | 0 | ||
Thereafter | 0 | ||
Northwest Pipeline - Wyoming | |||
Long-term Purchase Commitment [Line Items] | |||
2021 | 1,510,000 | ||
2022 | 1,510,000 | ||
2023 | 1,510,000 | ||
2024 | 910,000 | ||
2025 | 0 | ||
Thereafter | 0 | ||
ONEOK - Oklahoma | |||
Long-term Purchase Commitment [Line Items] | |||
2021 | 5,475,000 | ||
2022 | 5,475,000 | ||
2023 | 5,475,000 | ||
2024 | 5,490,000 | ||
2025 | 4,560,000 | ||
Thereafter | 0 | ||
Southern Star Central Gas Pipeline | |||
Long-term Purchase Commitment [Line Items] | |||
2021 | 113,130 | ||
2022 | 0 | ||
2023 | 0 | ||
2024 | 0 | ||
2025 | 0 | ||
Thereafter | 0 | ||
Panhandle Eastern Pipe Line | |||
Long-term Purchase Commitment [Line Items] | |||
2021 | 4,680 | ||
2022 | 0 | ||
2023 | 0 | ||
2024 | 0 | ||
2025 | 0 | ||
Thereafter | 0 | ||
Gas Utilities | |||
Long-term Purchase Commitment [Line Items] | |||
Term of Evergreen Contracts | 60 days |
Commitment, Contingencies And_6
Commitment, Contingencies And Guarentees: Unconditional Purchase Obligations (Details) $ in Thousands | Dec. 31, 2020USD ($) |
Power purchase and transmission services agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2021 | $ 24,452 |
2022 | 11,678 |
2023 | 11,678 |
2024 | 2,738 |
2025 | 0 |
Thereafter | 0 |
Natural gas transportation and storage agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2021 | 116,563 |
2022 | 121,819 |
2023 | 100,282 |
2024 | 67,089 |
2025 | 50,709 |
Thereafter | $ 167,100 |
Commitment, Contingencies And_7
Commitment, Contingencies And Guarentees: Power Sales Agreements (Details) - MW | 12 Months Ended | |||
Dec. 31, 2020 | Jul. 01, 2020 | Jun. 26, 2019 | Sep. 03, 2014 | |
M D U, Montana Dakota Utilities | Contingent Capacity Amounts on Wygen III | ||||
Long-term Purchase Commitment [Line Items] | ||||
Megawatts Sold Under Long-Term Contract | 25 | |||
M D U, Montana Dakota Utilities | Maximum | ||||
Long-term Purchase Commitment [Line Items] | ||||
Megawatts Sold Under Long-Term Contract | 50 | |||
City Of Gillette | ||||
Long-term Purchase Commitment [Line Items] | ||||
Megawatts Sold Under Long-Term Contract | 23 | |||
Purchase Power Contract, MEAN, for up to 20 Megawatts | ||||
Long-term Purchase Commitment [Line Items] | ||||
Megawatts Sold Under Long-Term Contract | 20 | |||
2020-2022 | 15 | |||
2022-2023 | 15 | |||
2023-2028 | 10 | |||
Purchase Power Contract, MEAN, for up to 20 Megawatts | Contingent Capacity Amounts on Wygen III | ||||
Long-term Purchase Commitment [Line Items] | ||||
2020-2022 | 7 | |||
2022-2023 | 8 | |||
2023-2028 | 5 | |||
Purchase Power Contract, MEAN, for up to 20 Megawatts | Contingent Capacity Amounts on Neil Simpson II | ||||
Long-term Purchase Commitment [Line Items] | ||||
2020-2022 | 8 | |||
2022-2023 | 7 | |||
2023-2028 | 5 | |||
Macquarie Energy, LLC Supply Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Megawatts Sold Under Long-Term Contract | 50 | |||
City of Colorado Springs | Colorado Electric | ||||
Long-term Purchase Commitment [Line Items] | ||||
Number of Megawatts Capacity Purchased | 60 | |||
Platte River Power Authority Wind Power Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Number of Megawatts Capacity Purchased | 60 | |||
Sharing Arrangement with the City of Gillette, Wyoming | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Purchase Commitment, Period | 20 years | |||
Sharing Arrangement with the City of Gillette, Wyoming | Black Hills Wyoming | ||||
Long-term Purchase Commitment [Line Items] | ||||
Number of Megawatts Capacity Sold | 40 |
Commitment, Contingencies And_8
Commitment, Contingencies And Guarentees: Reclamation Liability (Details) $ in Millions | Dec. 31, 2020USD ($) |
Electric Utilities | |
Loss Contingencies [Line Items] | |
Accrual for Environmental Loss Contingencies - Pueblo Airport Generation Site | $ 4.1 |
Commitment, Contingencies And_9
Commitment, Contingencies And Guarentees: Manufactured Gas Processing (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Loss Contingencies [Line Items] | ||
Regulatory assets | $ 278,258 | $ 271,344 |
Environmental | ||
Loss Contingencies [Line Items] | ||
Regulatory assets | 1,413 | $ 1,454 |
Manufactured Gas Plant | Gas Utilities | ||
Loss Contingencies [Line Items] | ||
Insurance Settlements Receivable, Noncurrent | 1,200 | |
Manufactured Gas Plant | Gas Utilities | Black Hills Energy - Iowa Gas | ||
Loss Contingencies [Line Items] | ||
Accrual for Environmental Loss Contingencies, Gross | 2,600 | |
Manufactured Gas Plant | Gas Utilities | Black Hills Energy - Nebraska Gas | ||
Loss Contingencies [Line Items] | ||
Accrual for Environmental Loss Contingencies, Gross | 600 | |
Manufactured Gas Plant | Gas Utilities | Environmental | ||
Loss Contingencies [Line Items] | ||
Regulatory assets | $ 1,400 |
Commitment, Contingencies An_10
Commitment, Contingencies And Guarentees: Guarantees (Details) $ in Thousands | Dec. 31, 2020USD ($) |
Surety Bond | |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | $ 53,769 |
Revenue_ Disaggregation of Reve
Revenue: Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Revenue from contracts with customers | $ 1,680,804 | $ 1,726,392 | $ 1,748,542 |
Revenue | 1,696,941 | 1,734,900 | 1,754,268 |
Services transferred at a point in time | |||
Revenue from contracts with customers | 27,089 | 27,180 | 33,609 |
Services transferred over time | |||
Revenue from contracts with customers | 1,653,715 | 1,699,212 | 1,714,933 |
Other revenues | |||
Revenue | 16,137 | 8,508 | 5,726 |
Intercompany Eliminations | |||
Revenue from contracts with customers | (157,285) | (149,205) | (141,428) |
Revenue | (157,895) | (150,769) | (142,974) |
Intercompany Eliminations | Services transferred at a point in time | |||
Revenue from contracts with customers | (31,478) | (32,053) | (32,194) |
Intercompany Eliminations | Services transferred over time | |||
Revenue from contracts with customers | (125,807) | (117,152) | (109,234) |
Intercompany Eliminations | Other revenues | |||
Revenue | (610) | (1,564) | (1,546) |
Electric Utilities | |||
Revenue from contracts with customers | 711,843 | 707,561 | 709,024 |
Revenue | 714,044 | 712,752 | 711,451 |
Electric Utilities | Services transferred at a point in time | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Electric Utilities | Services transferred over time | |||
Revenue from contracts with customers | 711,843 | 707,561 | 709,024 |
Electric Utilities | Other revenues | |||
Revenue | 2,201 | 5,191 | 2,427 |
Gas Utilities | |||
Revenue from contracts with customers | 964,421 | 1,009,646 | 1,024,352 |
Revenue | 974,670 | 1,010,030 | 1,025,307 |
Gas Utilities | Services transferred at a point in time | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Gas Utilities | Services transferred over time | |||
Revenue from contracts with customers | 964,421 | 1,009,646 | 1,024,352 |
Gas Utilities | Other revenues | |||
Revenue | 10,249 | 384 | 955 |
Power Generation | |||
Revenue from contracts with customers | 103,258 | 99,157 | 90,791 |
Revenue | 105,047 | 101,258 | 92,451 |
Power Generation | Services transferred at a point in time | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Power Generation | Services transferred over time | |||
Revenue from contracts with customers | 103,258 | 99,157 | 90,791 |
Power Generation | Other revenues | |||
Revenue | 1,789 | 2,101 | 1,660 |
Mining | |||
Revenue from contracts with customers | 58,567 | 59,233 | 65,803 |
Revenue | 61,075 | 61,629 | 68,033 |
Mining | Services transferred at a point in time | |||
Revenue from contracts with customers | 58,567 | 59,233 | 65,803 |
Mining | Services transferred over time | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Mining | Other revenues | |||
Revenue | 2,508 | 2,396 | 2,230 |
Retail | |||
Revenue from contracts with customers | 1,403,732 | 1,450,776 | 1,461,317 |
Retail | Intercompany Eliminations | |||
Revenue from contracts with customers | (31,478) | (32,053) | (32,194) |
Retail | Electric Utilities | |||
Revenue from contracts with customers | 610,721 | 605,756 | 594,329 |
Retail | Gas Utilities | |||
Revenue from contracts with customers | 765,922 | 817,840 | 833,379 |
Retail | Power Generation | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Retail | Mining | |||
Revenue from contracts with customers | 58,567 | 59,233 | 65,803 |
Transportation | |||
Revenue from contracts with customers | 154,055 | 142,348 | 139,357 |
Transportation | Intercompany Eliminations | |||
Revenue from contracts with customers | (526) | (1,042) | (1,348) |
Transportation | Electric Utilities | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Transportation | Gas Utilities | |||
Revenue from contracts with customers | 154,581 | 143,390 | 140,705 |
Transportation | Power Generation | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Transportation | Mining | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Wholesale | |||
Revenue from contracts with customers | 23,937 | 28,464 | 39,521 |
Wholesale | Intercompany Eliminations | |||
Revenue from contracts with customers | (97,169) | (91,577) | (84,957) |
Wholesale | Electric Utilities | |||
Revenue from contracts with customers | 17,848 | 20,884 | 33,687 |
Wholesale | Gas Utilities | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Wholesale | Power Generation | |||
Revenue from contracts with customers | 103,258 | 99,157 | 90,791 |
Wholesale | Mining | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Market - off-system sales | |||
Revenue from contracts with customers | 15,772 | 16,772 | 17,563 |
Market - off-system sales | Intercompany Eliminations | |||
Revenue from contracts with customers | (8,797) | (7,736) | (8,102) |
Market - off-system sales | Electric Utilities | |||
Revenue from contracts with customers | 24,309 | 23,817 | 24,799 |
Market - off-system sales | Gas Utilities | |||
Revenue from contracts with customers | 260 | 691 | 866 |
Market - off-system sales | Power Generation | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Market - off-system sales | Mining | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Transmission/Other | |||
Revenue from contracts with customers | 83,308 | 88,032 | 90,784 |
Transmission/Other | Intercompany Eliminations | |||
Revenue from contracts with customers | (19,315) | (16,797) | (14,827) |
Transmission/Other | Electric Utilities | |||
Revenue from contracts with customers | 58,965 | 57,104 | 56,209 |
Transmission/Other | Gas Utilities | |||
Revenue from contracts with customers | 43,658 | 47,725 | 49,402 |
Transmission/Other | Power Generation | |||
Revenue from contracts with customers | 0 | 0 | 0 |
Transmission/Other | Mining | |||
Revenue from contracts with customers | $ 0 | $ 0 | $ 0 |
Property, Plant and Equipment_2
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 7,305,530 | $ 6,784,679 |
Less accumulated depreciation and depletion | (1,285,816) | (1,281,493) |
Property, plant and equipment of variable interest entities, net | 6,019,714 | 5,503,186 |
Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | 22,094 | 29,055 |
Less accumulated depreciation and depletion | (1,144) | (964) |
Property, plant and equipment of variable interest entities, net | 20,950 | 28,091 |
Property, Plant and Equipment | 5,692 | 5,721 |
Construction in progress, gross | $ 16,402 | $ 23,334 |
Weighted Average | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 10 years | 10 years |
Minimum | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 10 years | 3 years |
Maximum | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 22 years | 30 years |
Electric Utilities | ||
Property, Plant and Equipment [Line Items] | ||
Total plant in service before construction work in progress | $ 3,159,078 | $ 2,956,867 |
Construction work in progress | 89,402 | 102,268 |
Property, plant and equipment | 3,248,480 | 3,059,135 |
Less accumulated depreciation and depletion | (666,669) | (670,861) |
Property, plant and equipment of variable interest entities, net | $ 2,581,811 | 2,388,274 |
Depreciation, depletion and amortization, remaining amortization period | 10 years | |
Electric Utilities | Production, Electric | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 1,417,951 | $ 1,348,049 |
Electric Utilities | Production, Electric | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 40 years | 41 years |
Electric Utilities | Production, Electric | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | |
Electric Utilities | Production, Electric | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 46 years | |
Electric Utilities | Electric transmission | ||
Property, Plant and Equipment [Line Items] | ||
Transmission | $ 517,794 | $ 483,640 |
Electric Utilities | Electric transmission | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 49 years | 51 years |
Electric Utilities | Electric transmission | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 44 years | |
Electric Utilities | Electric transmission | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 51 years | |
Electric Utilities | Electric distribution | ||
Property, Plant and Equipment [Line Items] | ||
Distribution | $ 959,453 | $ 861,042 |
Electric Utilities | Electric distribution | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 46 years | 47 years |
Electric Utilities | Electric distribution | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 46 years | |
Electric Utilities | Electric distribution | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 48 years | |
Electric Utilities | Plant acquisition adjustment | ||
Property, Plant and Equipment [Line Items] | ||
Plant acquisition adjustment | $ 4,870 | $ 4,870 |
Electric Utilities | Plant acquisition adjustment | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | 32 years |
Electric Utilities | Plant acquisition adjustment | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | |
Electric Utilities | Plant acquisition adjustment | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | |
Electric Utilities | General | ||
Property, Plant and Equipment [Line Items] | ||
General | $ 259,010 | $ 259,266 |
Electric Utilities | General | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | 28 years |
Electric Utilities | General | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 26 years | |
Electric Utilities | General | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 29 years | |
Gas Utilities | ||
Property, Plant and Equipment [Line Items] | ||
Total plant in service before construction work in progress | $ 3,245,384 | $ 2,918,418 |
Construction work in progress | 67,229 | 63,080 |
Property, plant and equipment | 3,312,613 | 2,981,498 |
Less accumulated depreciation and depletion | (323,679) | (336,721) |
Property, plant and equipment of variable interest entities, net | 2,988,934 | 2,644,777 |
Gas Utilities | Production, Gas | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 15,603 | $ 13,000 |
Gas Utilities | Production, Gas | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 40 years | 35 years |
Gas Utilities | Production, Gas | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 24 years | |
Gas Utilities | Production, Gas | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 46 years | |
Gas Utilities | Gas transmission | ||
Property, Plant and Equipment [Line Items] | ||
Transmission | $ 578,278 | $ 516,172 |
Gas Utilities | Gas transmission | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 54 years | 50 years |
Gas Utilities | Gas transmission | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 22 years | |
Gas Utilities | Gas transmission | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 71 years | |
Gas Utilities | Gas distribution | ||
Property, Plant and Equipment [Line Items] | ||
Distribution | $ 2,115,082 | $ 1,857,233 |
Gas Utilities | Gas distribution | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 53 years | 43 years |
Gas Utilities | Gas distribution | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 45 years | |
Gas Utilities | Gas distribution | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 59 years | |
Gas Utilities | Cushion Gas - Depreciable | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 3,539 | $ 3,539 |
Gas Utilities | Cushion Gas - Depreciable | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | 28 years |
Gas Utilities | Cushion Gas - Depreciable | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | |
Gas Utilities | Cushion Gas - Depreciable | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | |
Gas Utilities | Cushion Gas - Not Depreciated | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 39,184 | $ 44,443 |
Gas Utilities | Gas, Storage | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 55,481 | $ 46,977 |
Gas Utilities | Gas, Storage | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 38 years | 31 years |
Gas Utilities | Gas, Storage | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 24 years | |
Gas Utilities | Gas, Storage | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 52 years | |
Gas Utilities | General | ||
Property, Plant and Equipment [Line Items] | ||
General | $ 438,217 | $ 437,054 |
Gas Utilities | General | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 19 years | 20 years |
Gas Utilities | General | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 12 years | |
Gas Utilities | General | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 23 years | |
Power Generation | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 534,803 | $ 534,518 |
Less accumulated depreciation and depletion | (167,787) | (154,362) |
Property, plant and equipment of variable interest entities, net | 367,016 | 380,156 |
Property, Plant and Equipment | 529,927 | 532,397 |
Construction in progress, gross | $ 4,876 | $ 2,121 |
Power Generation | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 31 years | 31 years |
Power Generation | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 2 years | 2 years |
Power Generation | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 40 years | 40 years |
Mining | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 187,540 | $ 180,473 |
Less accumulated depreciation and depletion | (126,537) | (118,585) |
Property, plant and equipment of variable interest entities, net | 61,003 | 61,888 |
Property, Plant and Equipment | 186,552 | 179,198 |
Construction in progress, gross | $ 988 | $ 1,275 |
Mining | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 14 years | 13 years |
Mining | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 2 years | 2 years |
Mining | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 59 years | 59 years |
Jointly Owned Facilities (Detai
Jointly Owned Facilities (Details) $ in Thousands | Dec. 31, 2020USD ($) |
Wyodak Plant | Electric Utilities | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 20.00% |
Plant in Service | $ 116,074 |
Construction Work in Progress | 2,249 |
Less Accumulated Depreciation | (67,762) |
Plant Net of Accumulated Depreciation | $ 50,561 |
Transmission Tie | Electric Utilities | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 35.00% |
Plant in Service | $ 26,176 |
Construction Work in Progress | 509 |
Less Accumulated Depreciation | (7,103) |
Plant Net of Accumulated Depreciation | $ 19,582 |
Wygen III Generating Facility | Electric Utilities | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 52.00% |
Plant in Service | $ 142,739 |
Construction Work in Progress | 582 |
Less Accumulated Depreciation | (24,783) |
Plant Net of Accumulated Depreciation | $ 118,538 |
Wygen I Generating Facility | Power Generation | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 76.50% |
Plant in Service | $ 114,975 |
Construction Work in Progress | 318 |
Less Accumulated Depreciation | (49,459) |
Plant Net of Accumulated Depreciation | $ 65,834 |
Jointly Owned Facilities - Rela
Jointly Owned Facilities - Related Party (Details) | Dec. 31, 2020MW |
Black Hills Energy, Wyoming Electric | Cheyenne Prairie, Simple-Cycle Combustion Turbine | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | 37 |
Cheyenne Prairie | Black Hills Energy, Wyoming Electric | Cheyenne Prairie, Combined Cycle | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | 42.4 |
Cheyenne Prairie | Black Hills Energy, South Dakota Electric | Cheyenne Prairie, Combined Cycle | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | 58 |
Cheyenne Prairie | South Dakota Electric and Wyoming Electric | Cheyenne Prairie, Combined Cycle | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | 100.4 |
Corriedale Wind Project | Black Hills Energy, Wyoming Electric | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | 20 |
Corriedale Wind Project | Black Hills Energy, South Dakota Electric | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | 32.5 |
Corriedale Wind Project | South Dakota Electric and Wyoming Electric | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | 52.5 |
Electric Utilities | Busch Ranch I Wind Farm | |
Jointly Owned Utility Plant Interests [Line Items] | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% |
Power Generation | Busch Ranch I Wind Farm | |
Jointly Owned Utility Plant Interests [Line Items] | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | $ 64,205 | $ 56,800 |
Liabilities Incurred | 5,999 | 3,445 |
Liabilities Settled | (317) | (380) |
Accretion | 2,769 | 2,741 |
Revisions to Prior Estimates | (1,225) | 1,599 |
Ending Balance | 71,431 | 64,205 |
Electric Utilities | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 9,329 | 6,258 |
Liabilities Incurred | 1,217 | 0 |
Liabilities Settled | 0 | 0 |
Accretion | 407 | 385 |
Revisions to Prior Estimates | 0 | 2,686 |
Ending Balance | 10,953 | 9,329 |
Gas Utilities | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 36,085 | 34,627 |
Liabilities Incurred | 4,782 | 0 |
Liabilities Settled | (132) | 0 |
Accretion | 1,539 | 1,458 |
Revisions to Prior Estimates | 0 | 0 |
Ending Balance | 42,274 | 36,085 |
Power Generation | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 4,739 | 300 |
Liabilities Incurred | 0 | 3,445 |
Liabilities Settled | 0 | 0 |
Accretion | 206 | 158 |
Revisions to Prior Estimates | 0 | 836 |
Ending Balance | 4,945 | 4,739 |
Mining | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 14,052 | 15,615 |
Liabilities Incurred | 0 | 0 |
Liabilities Settled | (185) | (380) |
Accretion | 617 | 740 |
Revisions to Prior Estimates | (1,225) | (1,923) |
Ending Balance | $ 13,259 | $ 14,052 |
Operating Leases (Details)
Operating Leases (Details) - lease | Dec. 31, 2020 | Dec. 31, 2019 |
Lessee, Lease, Description [Line Items] | ||
Number of Finance Leases | 1 | |
Discount Rate - Operating leases | 4.24% | 4.27% |
Minimum | ||
Lessee, Lease, Description [Line Items] | ||
Lessee, Operating Lease, Term of Contract | 1 year | |
Maximum | ||
Lessee, Lease, Description [Line Items] | ||
Lessee, Operating Lease, Term of Contract | 35 years |
Lessee - Lease Costs (Details)
Lessee - Lease Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Operations and maintenance | ||
Operating lease cost | $ 978 | $ 1,456 |
Lessee - Supplemental Balance S
Lessee - Supplemental Balance Sheet Information (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Lessee, Lease, Description [Line Items] | ||
Operating lease assets | $ 4,188 | $ 4,629 |
Total lease liabilities | 4,543 | 5,000 |
Other assets, non-current | ||
Lessee, Lease, Description [Line Items] | ||
Operating lease assets | 4,188 | 4,629 |
Accrued liabilities | ||
Lessee, Lease, Description [Line Items] | ||
Operating lease liability, current | 736 | 1,179 |
Other deferred credits and other liabilities | ||
Lessee, Lease, Description [Line Items] | ||
Operating lease, liability, noncurrent | $ 3,807 | $ 3,821 |
Lessee - Supplemental Cash Flow
Lessee - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Leases [Abstract] | ||
Operating cash flows from operating leases | $ 1,023 | $ 1,263 |
Operating leases | $ 161 | $ 2,801 |
Lessee - Weighted Average Infor
Lessee - Weighted Average Information (Details) | Dec. 31, 2020 | Dec. 31, 2019 |
Leases [Abstract] | ||
Lease Term - Operating leases | 8 years | 8 years |
Discount Rate - Operating leases | 4.24% | 4.27% |
Lessee - Future Minimum Payment
Lessee - Future Minimum Payments (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Leases [Abstract] | ||
2021 | $ 907 | |
2022 | 804 | |
2023 | 779 | |
2024 | 776 | |
2025 | 529 | |
Thereafter | 1,643 | |
Total lease payments | 5,438 | |
Less imputed interest | 895 | |
Total lease liabilities | $ 4,543 | $ 5,000 |
Lessor (Details)
Lessor (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Lessor, Lease, Description [Line Items] | ||
Operating lease income | $ 2,534 | $ 2,306 |
Minimum | ||
Lessor, Lease, Description [Line Items] | ||
Lessor - lease term | 1 year | |
Maximum | ||
Lessor, Lease, Description [Line Items] | ||
Lessor - lease term | 34 years |
Lessor - Future Minimum Payment
Lessor - Future Minimum Payments (Details) $ in Thousands | Dec. 31, 2020USD ($) |
Leases [Abstract] | |
2021 | $ 2,383 |
2022 | 2,122 |
2023 | 2,130 |
2024 | 2,074 |
2025 | 2,090 |
Thereafter | 58,829 |
Total lease receivables | $ 69,628 |
Short-Term Debt_ (Details)
Short-Term Debt: (Details) | 12 Months Ended | |||
Dec. 31, 2020USD ($)credit_extension | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Jul. 30, 2018USD ($) | |
Short-term Debt [Line Items] | ||||
Notes payable | $ 234,040,000 | $ 349,500,000 | ||
Letters of Credit Outstanding, Amount | 24,730,000 | 30,274,000 | ||
Commercial Paper, Maximum Borrowing Capacity | 750,000,000 | |||
Net (payments) borrowings of short-term debt | (115,460,000) | 163,880,000 | $ (25,680,000) | |
Commercial Paper | ||||
Short-term Debt [Line Items] | ||||
Notes payable | 234,040,000 | 349,500,000 | ||
Letters of Credit Outstanding, Amount | $ 0 | 0 | ||
Debt Instrument, Term | 397 days | |||
Debt, Weighted Average Interest Rate | 0.27% | |||
Revolving Credit Facility | ||||
Short-term Debt [Line Items] | ||||
Notes payable | $ 0 | 0 | ||
Letters of Credit Outstanding, Amount | $ 24,730,000 | $ 30,274,000 | ||
Line of Credit Facility, Current Borrowing Capacity | $ 750,000,000 | |||
Number Of One-Year Extension Options | credit_extension | 2 | |||
Debt Instrument, Term | 1 year | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,000,000,000 | |||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.175% | |||
Debt Issuance Cost, Gross, Noncurrent | $ 6,700,000 | |||
Revolving Credit Facility | Base Rate | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Interest Rate at Period End | 0.125% | |||
Revolving Credit Facility | Eurodollar | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Interest Rate at Period End | 1.125% | |||
Revolving Credit Facility | Letter of Credit | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Interest Rate at Period End | 1.125% |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Jun. 17, 2020 | Dec. 31, 2019 | Oct. 03, 2019 |
Debt Instrument [Line Items] | ||||
Total long-term debt | $ 3,561,345 | $ 3,170,489 | ||
Less current maturities | 8,436 | 5,743 | ||
Less unamortized deferred financing costs | 24,809 | 24,650 | ||
Long-term debt, net of current maturities | 3,528,100 | 3,140,096 | ||
Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Less unamortized deferred financing costs | 1,000 | 1,700 | ||
Corporate, Non-Segment | Senior Unsecured Notes Due 2029 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 3.05% | |||
Corporate, Non-Segment | Senior Unsecured Notes Due 2030 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 2.50% | |||
Corporate, Non-Segment | Senior Unsecured Notes Due 2049 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 3.875% | |||
Black Hills Corporation | Corporate, Non-Segment | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | 3,026,436 | 2,632,178 | ||
Less unamortized debt discount | (7,013) | (6,462) | ||
Total long-term debt | $ 3,019,423 | 2,625,716 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2023 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 4.25% | |||
Long-term debt | $ 525,000 | 525,000 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 3.95% | |||
Long-term debt | $ 300,000 | 300,000 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 3.15% | |||
Long-term debt | $ 400,000 | 400,000 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2029 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 3.05% | |||
Long-term debt | $ 400,000 | 400,000 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2030 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 2.50% | |||
Long-term debt | $ 400,000 | 0 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2033 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 4.35% | |||
Long-term debt | $ 400,000 | 400,000 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 4.20% | |||
Long-term debt | $ 300,000 | 300,000 | ||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2049 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 3.88% | |||
Long-term debt | $ 300,000 | 300,000 | ||
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 2.32% | |||
Long-term debt | $ 1,436 | 7,178 | ||
Black Hills Energy, South Dakota Electric | Electric Utilities | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | 340,000 | 342,855 | ||
Less unamortized debt discount | (78) | (82) | ||
Total long-term debt | 339,922 | 342,773 | ||
Black Hills Energy, South Dakota Electric | Electric Utilities | Series 94 A Debt, Due 2024 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ 0 | 2,855 | ||
Black Hills Energy, South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2032 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 7.23% | |||
Long-term debt | $ 75,000 | 75,000 | ||
Black Hills Energy, South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2039 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 6.13% | |||
Long-term debt | $ 180,000 | 180,000 | ||
Black Hills Energy, South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2044 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 4.43% | |||
Long-term debt | $ 85,000 | 85,000 | ||
Wyoming Electric | Electric Utilities | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | 202,000 | 202,000 | ||
Less unamortized debt discount | 0 | 0 | ||
Total long-term debt | $ 202,000 | 202,000 | ||
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2044 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 4.53% | |||
Long-term debt | $ 75,000 | 75,000 | ||
Wyoming Electric | Electric Utilities | Industrial Development Revenue Bonds Due 2021 | ||||
Debt Instrument [Line Items] | ||||
Variable interest rate (percent) | 0.12% | |||
Long-term debt | $ 7,000 | 7,000 | ||
Wyoming Electric | Electric Utilities | Industrial Development Revenue Bonds Due 2027 | ||||
Debt Instrument [Line Items] | ||||
Variable interest rate (percent) | 0.12% | |||
Long-term debt | $ 10,000 | 10,000 | ||
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2037 | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate (percent) | 6.67% | |||
Long-term debt | $ 110,000 | $ 110,000 |
Long-Term Debt_ Aggregate Matur
Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Debt Disclosure [Abstract] | ||
Less current maturities | $ 8,436 | $ 5,743 |
2022 | 0 | |
2023 | 525,000 | |
2024 | 0 | |
2025 | 0 | |
Thereafter | $ 3,035,000 |
Long-Term Debt_ Amortization Ex
Long-Term Debt: Amortization Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |||
Deferred Finance Costs Remaining, Noncurrent | $ 24,809 | ||
Amortization expense for deferred financing costs | $ 3,272 | $ 3,242 | $ 2,829 |
Long-Term Debt_ Debt Transactio
Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands | Jun. 17, 2020 | Mar. 24, 2020 | Oct. 03, 2019 | Jun. 17, 2019 | Dec. 31, 2020 |
Corporate Term Loan Due June 2021 | |||||
Debt Instrument [Line Items] | |||||
Extinguishment of Debt, Amount | $ 400,000 | ||||
Senior Unsecured Notes Due 2020 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate (percent) | 5.875% | ||||
Extinguishment of Debt, Amount | $ 200,000 | ||||
Black Hills Energy, South Dakota Electric | Series 94 A Debt, Due 2024 | |||||
Debt Instrument [Line Items] | |||||
Extinguishment of Debt, Amount | $ 2,900 | ||||
Corporate, Non-Segment | |||||
Debt Instrument [Line Items] | |||||
Proceeds from Issuance of Debt | 700,000 | ||||
Corporate, Non-Segment | Senior Unsecured Notes Due 2030 | |||||
Debt Instrument [Line Items] | |||||
Proceeds from Issuance of Debt | $ 400,000 | ||||
Stated interest rate (percent) | 2.50% | ||||
Long-term Debt, Term | 10 years | ||||
Corporate, Non-Segment | Senior Unsecured Notes Due 2029 | |||||
Debt Instrument [Line Items] | |||||
Proceeds from Issuance of Debt | $ 400,000 | ||||
Stated interest rate (percent) | 3.05% | ||||
Long-term Debt, Term | 10 years | ||||
Corporate, Non-Segment | Senior Unsecured Notes Due 2049 | |||||
Debt Instrument [Line Items] | |||||
Proceeds from Issuance of Debt | $ 300,000 | ||||
Stated interest rate (percent) | 3.875% | ||||
Long-term Debt, Term | 30 years | ||||
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2030 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate (percent) | 2.50% | ||||
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2029 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate (percent) | 3.05% | ||||
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2049 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate (percent) | 3.88% | ||||
Corporate, Non-Segment | Black Hills Corporation | Corporate Term Loan Due June 2021 | |||||
Debt Instrument [Line Items] | |||||
Proceeds from Issuance of Debt | $ 400,000 | ||||
Stated interest rate (percent) | 2.32% | ||||
Corporate, Non-Segment | Black Hills Corporation | Corporate Term Loan Due July 2020 | |||||
Debt Instrument [Line Items] | |||||
Extinguishment of Debt, Amount | $ 300,000 |
Debt Covenants (Details)
Debt Covenants (Details) | Dec. 31, 2020 |
Debt Instrument [Line Items] | |
Ratio of Indebtedness to Net Capital | 0.599 |
Maximum | |
Debt Instrument [Line Items] | |
Debt Instrument, Debt to Capitalization Ratio Requirement | 0.65 |
Maximum | Wyoming Electric | |
Debt Instrument [Line Items] | |
Debt Instrument, Debt to Capitalization Ratio Requirement | 0.60 |
Long-Term Debt_ Dividend Restri
Long-Term Debt: Dividend Restrictions (Details) $ in Millions | Dec. 31, 2020USD ($) |
Utilities Group | |
Debt Instrument [Line Items] | |
Restricted Net Assets for Subsidiaries | $ 155 |
Stockholders' Equity_ Equity Is
Stockholders' Equity: Equity Issuance (Details) - Private Placement $ / shares in Units, shares in Thousands, $ in Thousands | Feb. 27, 2020USD ($)$ / sharesshares |
Sale of Stock, Number of Shares Issued in Transaction | shares | 1,200 |
Sale of Stock, Price Per Share | $ / shares | $ 81.77 |
Sale of Stock, Consideration Received on Transaction | $ 99,000 |
Payments of Stock Issuance Costs | $ 1,000 |
Equity_ At-the-Market Equity Of
Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Aug. 03, 2020 | Jun. 30, 2020 | |
At The Market Equity Offering Program Authorized Aggregate Value | $ 400,000 | $ 300,000 | |
Common Stock | |||
At The Market Equity Offering Program Shares Issued | 1,328,332 | ||
At The Market Equity Program Proceeds from Sale of Stock | $ 99,000 | ||
Payments of Stock Issuance Costs | $ 1,200 |
Equity_ Shareholder Dividend Re
Equity: Shareholder Dividend Reinvestment and Stock Purchase Plan (Details) | Dec. 31, 2020shares |
Class of Stock [Line Items] | |
Unissued Shares Available | 163,962 |
Dividend Reinvestment Plan | |
Class of Stock [Line Items] | |
Percent of recent average market price | 100.00% |
Equity_ Preferred Stock (Detail
Equity: Preferred Stock (Details) | Dec. 31, 2020shares |
Stockholders' Equity Note [Abstract] | |
Preferred Stock, Shares Authorized | 25,000,000 |
Preferred Stock, Shares Outstanding | 0 |
Risk Management And Derivativ_3
Risk Management And Derivatives: Market and Credit Risk Disclosures (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Bad Debt Expense | $ 8,927 | $ 5,795 | $ 6,859 | |
Allowance for credit losses | 7,003 | $ 2,444 | $ 3,209 | $ 3,081 |
Potential economic impact of the COVID-19 pandemic | ||||
Bad Debt Expense | 3,300 | |||
Allowance for credit losses | $ 3,300 |
Risk Management Activities_ Uti
Risk Management Activities: Utilities (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020USD ($)MMBTUmW | Dec. 31, 2019MMBTUmW | |
Derivative [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | $ | $ 1,500 | |
Natural Gas, Distribution | Future | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 620,000 | 1,450,000 |
Derivative, Remaining Maturity | 3 months | 12 months |
Natural Gas, Distribution | Commodity Option | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 3,160,000 | 3,240,000 |
Derivative, Remaining Maturity | 3 months | 3 months |
Natural Gas, Distribution | Basis Swap | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 900,000 | 1,290,000 |
Derivative, Remaining Maturity | 3 months | 12 months |
Natural Gas, Distribution | Fixed for Float Swaps Purchased | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 3,850,000 | 4,600,000 |
Derivative, Remaining Maturity | 17 months | 24 months |
Natural Gas, Distribution | Fixed for Float Swaps Purchased | Cash Flow Hedging | Over the Counter | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 914,600 | |
Natural Gas, Distribution | Natural Gas Physical Purchases | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 17,513,061 | 13,548,235 |
Derivative, Remaining Maturity | 22 months | 12 months |
Electricity | Energy Related Derivative | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | mW | 219,000 | 0 |
Derivative, Remaining Maturity | 12 months | 0 months |
Risk Management And Derivativ_4
Risk Management And Derivatives: Derivatives by Balance Sheet Classification (Details) - Commodity Contract - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Designated as Hedging Instrument | ||
Fair Value Hedges, Net | $ 116 | $ (515) |
Not Designated as Hedging Instrument | ||
Fair Value Hedges, Net | (118) | (1,484) |
Derivative Assets, Current | Designated as Hedging Instrument | ||
Fair Value Hedge Assets | 181 | 1 |
Derivative Assets, Current | Not Designated as Hedging Instrument | ||
Fair Value Hedge Assets | 1,667 | 341 |
Derivative Assets, Noncurrent | Designated as Hedging Instrument | ||
Fair Value Hedge Assets | 43 | 3 |
Derivative Assets, Noncurrent | Not Designated as Hedging Instrument | ||
Fair Value Hedge Assets | 151 | 2 |
Derivative Liabilities, Current | Designated as Hedging Instrument | ||
Derivative Liability, Current | (108) | (490) |
Derivative Liabilities, Current | Not Designated as Hedging Instrument | ||
Derivative Liability, Current | (1,936) | (1,764) |
Derivative Liabilities, Noncurrent | Designated as Hedging Instrument | ||
Derivative Liability, Current | 0 | (29) |
Derivative Liabilities, Noncurrent | Not Designated as Hedging Instrument | ||
Derivative Liability, Current | $ 0 | $ (63) |
Risk Management Activities_ Cas
Risk Management Activities: Cash Flow Hedges (Details) - Cash Flow Hedging - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Interest Rate Swap and Commodity Derivative | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $ 2,800 | ||
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (3,452) | $ (2,434) | $ (2,981) |
Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Swap | Cash Flow Hedging | Interest Expense | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2,851) | (2,851) | (2,851) |
Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract | Cash Flow Hedging | Fuel, purchased power and cost of natural gas sold | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (601) | 417 | (130) |
Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 3,391 | 1,886 | 3,964 |
Designated as Hedging Instrument | Interest Rate Swap | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2,851 | 2,851 | 2,851 |
Designated as Hedging Instrument | Commodity Contract | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 540 | $ (965) | $ 1,113 |
Risk Management Activities_ Der
Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory assets | $ 278,258 | $ 271,344 | |
Gas price derivatives | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory assets | 2,226 | 3,328 | |
Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 1,784 | (1,100) | $ 1,101 |
Not Designated as Hedging Instrument | Fuel, purchased power and cost of natural gas sold | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 1,640 | (1,100) | 1,101 |
Not Designated as Hedging Instrument | Fuel, purchased power and cost of natural gas sold | Electricity | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 144 | $ 0 | $ 0 |
Fair Value Measurements_ Recurr
Fair Value Measurements: Recurring Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Contract Subject to Master Netting Arrangement | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 1,500 | $ 1,100 |
Derivative Liability, Fair Value, Gross Liability | 1,600 | 2,900 |
Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (1,527) | (1,085) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (1,552) | (2,909) |
Fair Value, Measurements, Recurring | Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 2,042 | 348 |
Derivative Liabilities, Total | 2,044 | 2,345 |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 0 | 0 |
Derivative Liabilities, Total | 0 | 0 |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 3,569 | 1,433 |
Derivative Liabilities, Total | 3,596 | 5,254 |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 0 | 0 |
Derivative Liabilities, Total | 0 | 0 |
Fair Value, Measurements, Recurring | Gas Utilities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (1,527) | (1,085) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (1,552) | (2,909) |
Fair Value, Measurements, Recurring | Gas Utilities | Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 977 | 348 |
Derivative, Liabilities, Fair Value Disclosure | 1,123 | 2,345 |
Fair Value, Measurements, Recurring | Gas Utilities | Fair Value, Inputs, Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Fair Value, Measurements, Recurring | Gas Utilities | Fair Value, Inputs, Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 2,504 | 1,433 |
Derivative, Liabilities, Fair Value Disclosure | 2,675 | 5,254 |
Fair Value, Measurements, Recurring | Gas Utilities | Fair Value, Inputs, Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | $ 0 |
Fair Value, Measurements, Recurring | Electric Utilities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | 0 | |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | 0 | |
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 1,065 | |
Derivative, Liabilities, Fair Value Disclosure | 921 | |
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value, Inputs, Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | |
Derivative, Liabilities, Fair Value Disclosure | ||
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value, Inputs, Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 1,065 | |
Derivative, Liabilities, Fair Value Disclosure | 921 | |
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value, Inputs, Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | |
Derivative, Liabilities, Fair Value Disclosure |
Fair Value Measurements_ Other
Fair Value Measurements: Other Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt | $ 3,536,536 | $ 3,145,839 |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt, including current maturities - fair value | $ 4,208,167 | $ 3,479,367 |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Interest expense | $ 144,931 | $ 139,291 | $ 141,616 |
Fuel, purchased power and cost of natural gas sold | 492,404 | 570,829 | 625,610 |
Operations and maintenance | 495,404 | 495,994 | 481,706 |
Income before income taxes | 275,681 | 242,902 | 255,882 |
Income Tax Expense (Benefit) | (32,918) | (29,580) | 23,667 |
Net income | 242,763 | 213,322 | $ 272,662 |
Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net income | (4,418) | (2,944) | |
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Income before income taxes | (3,452) | (2,434) | |
Income Tax Expense (Benefit) | 383 | 611 | |
Net income | (3,069) | (1,823) | |
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Swap | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Interest expense | (2,851) | (2,851) | |
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Fuel, purchased power and cost of natural gas sold | (601) | 417 | |
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Operations and maintenance | 103 | 77 | |
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Operations and maintenance | (2,387) | (745) | |
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Income before income taxes | (2,284) | (668) | |
Income Tax Expense (Benefit) | 935 | (453) | |
Net income | $ (1,349) | $ (1,121) |
Other Comprehensive Income_ Acc
Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | $ (30,655) | $ (26,916) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (27,346) | (30,655) |
Accumulated Defined Benefit Plans Adjustment | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (15,077) | (9,937) |
Other comprehensive income (loss), before reclassifications | (1,062) | (6,261) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (14,790) | (15,077) |
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | 1,349 | 1,121 |
Accumulated Other Comprehensive Income (Loss) | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Other comprehensive income (loss), before reclassifications | (1,109) | (6,683) |
Accumulated Other Comprehensive Income (Loss) | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | 4,418 | 2,944 |
Interest Rate Swap | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (15,122) | (17,307) |
Other comprehensive income (loss), before reclassifications | 0 | 0 |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (12,558) | (15,122) |
Interest Rate Swap | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | 2,564 | 2,185 |
Commodity Contract | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (456) | 328 |
Other comprehensive income (loss), before reclassifications | (47) | (422) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | 2 | (456) |
Commodity Contract | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | $ 505 | $ (362) |
Variable Interest Entity_ (Deta
Variable Interest Entity: (Details) $ in Thousands | Apr. 14, 2016 | Dec. 31, 2020USD ($)MW | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) |
Variable Interest Entity [Line Items] | ||||
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | |||
Net income attributable to noncontrolling interest | $ (15,155) | $ (14,012) | $ (14,220) | |
Current assets | 493,291 | 473,184 | ||
Property, plant and equipment of variable interest entities, net | 6,019,714 | 5,503,186 | ||
Current liabilities | 696,533 | 811,294 | ||
Variable Interest Entity, Primary Beneficiary | ||||
Variable Interest Entity [Line Items] | ||||
Current assets | 13,604 | 13,350 | ||
Property, plant and equipment of variable interest entities, net | 190,637 | 193,046 | ||
Current liabilities | 5,318 | 6,013 | ||
Power Generation | ||||
Variable Interest Entity [Line Items] | ||||
Net income attributable to noncontrolling interest | (15,000) | (14,000) | $ (14,000) | |
Property, plant and equipment of variable interest entities, net | $ 367,016 | $ 380,156 | ||
Pueblo Airport Generation | Subsidiary of Common Parent | ||||
Variable Interest Entity [Line Items] | ||||
Electric Generation Capacity, Megawatts | MW | 200 |
Defined Contribution Plans (Det
Defined Contribution Plans (Details) | 12 Months Ended |
Dec. 31, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 50.00% |
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage | 20.00% |
Defined Contribution Plan, Employee Vesting Period | 5 years |
Maximum | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage | 100.00% |
Defined Benefit Pension Plan (D
Defined Benefit Pension Plan (Details) - gas_distribution_territory | Dec. 31, 2020 | Dec. 31, 2019 |
Number of Defined Pension Plans | 1 | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 100.00% | 100.00% |
Investment in privately held oil and gas company | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 21.00% | 20.00% |
Real Estate | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 3.00% | 3.00% |
Fixed Income | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 69.00% | 71.00% |
Cash | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 3.00% | 1.00% |
Hedge Funds | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 4.00% | 5.00% |
Minimum | Return Seeking Assets | Pension Plan | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 28.00% | |
Minimum | Hedge Funds | Pension Plan | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 64.00% | |
Maximum | Pension Plan | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 72.00% | |
Maximum | Return Seeking Assets | Pension Plan | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 36.00% |
Plan Contributions (Details)
Plan Contributions (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Payment for Pension and Other Postretirement Benefits | $ 12,700 | $ 12,700 |
Other Postretirement Benefits Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Payment for Pension and Other Postretirement Benefits | 6,058 | 7,033 |
Supplemental Employee Retirement Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Payment for Pension and Other Postretirement Benefits | 2,674 | 2,344 |
Defined Contribution Plan, Company Retirement | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Contribution Plan, Employer Discretionary Contribution Amount | 10,455 | 9,714 |
Defined Contribution Plan, 401K | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Contribution Plan, Employer Discretionary Contribution Amount | $ 15,240 | $ 14,558 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Hedge Funds | Minimum | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period | 15 days | ||
Hedge Funds | Maximum | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period | 60 days | ||
Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | $ 473,721 | $ 434,284 | $ 390,796 |
Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 473,721 | 434,284 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 441,966 | 400,495 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 31,755 | 33,789 | |
Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | 8,165 | 8,305 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 8,165 | 8,305 | |
Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | 8,165 | 8,305 | |
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 441,966 | 400,495 | |
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fixed Income | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 60 | ||
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 60 | ||
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | ||
Fixed Income | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | ||
Fixed Income | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 60 | ||
Fixed Income | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | ||
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 16,810 | 7,054 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 16,810 | 7,054 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | 0 | |
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 16,810 | 7,054 | |
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Common Collective Trust, Equity Fund | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 100,311 | 87,106 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 100,311 | 87,106 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | 0 | |
Common Collective Trust, Equity Fund | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Common Collective Trust, Equity Fund | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 100,311 | 87,106 | |
Common Collective Trust, Equity Fund | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Common Collective Trust, Fixed Income Fund | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 324,845 | 306,275 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 324,845 | 306,275 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | 0 | |
Common Collective Trust, Fixed Income Fund | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Common Collective Trust, Fixed Income Fund | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 324,845 | 306,275 | |
Common Collective Trust, Fixed Income Fund | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Real Estate Funds | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 14,301 | 14,239 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 0 | 0 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 14,301 | 14,239 | |
Real Estate Funds | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Real Estate Funds | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Real Estate Funds | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | 0 | |
Hedge Funds | Minimum | |||
Percentage Of Monthly Redemption | 1000.00% | ||
Hedge Funds | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | $ 17,454 | 19,550 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 0 | 0 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 17,454 | 19,550 | |
Hedge Funds | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Hedge Funds | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Hedge Funds | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Cash | Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | 8,165 | 8,305 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 8,165 | 8,305 | |
Cash | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | 8,165 | 8,305 | |
Cash | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Cash | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Postretirement Health Coverage | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 |
Employee Benefit Plans_ Employe
Employee Benefit Plans: Employee Benefit Plan Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Pension Plan | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | $ 485,376 | $ 445,381 | |
Service Cost | 5,411 | 5,383 | $ 6,834 |
Interest cost | 13,426 | 17,374 | 15,470 |
Actuarial (gain) loss | 47,064 | 56,384 | |
Benefits paid | (37,269) | (39,146) | |
Plan participants’ contributions | 0 | 0 | |
Projected benefit obligation at end of year | 514,008 | 485,376 | 445,381 |
Supplemental Employee Retirement Plan | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | 54,088 | 43,010 | |
Service Cost | 1,579 | 4,995 | |
Interest cost | 1,099 | 1,295 | |
Actuarial (gain) loss | 962 | 7,132 | |
Benefits paid | (2,674) | (2,344) | |
Plan participants’ contributions | 0 | 0 | |
Projected benefit obligation at end of year | 55,054 | 54,088 | 43,010 |
Supplemental Employee Retirement Plan | Error Correction, Other | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Service Cost | 1,400 | ||
Other Postretirement Benefits Plan | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | 65,277 | 60,817 | |
Service Cost | 2,056 | 1,815 | 2,291 |
Interest cost | 1,649 | 2,247 | 2,085 |
Actuarial (gain) loss | 5,804 | 5,976 | |
Benefits paid | (6,058) | (7,033) | |
Plan participants’ contributions | 1,510 | 1,455 | |
Projected benefit obligation at end of year | $ 70,238 | $ 65,277 | $ 60,817 |
Employee Benefit Plans_ Fair Va
Employee Benefit Plans: Fair Value Employee Benefit Plan Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Beginning fair value of plan assets | $ 434,284 | $ 390,796 |
Investment income (loss) | 64,006 | 69,934 |
Employer contributions | 12,700 | 12,700 |
Retiree contributions | 0 | 0 |
Defined Benefit Plan, Plan Assets, Benefits Paid | (37,269) | (39,146) |
Ending fair value of plan assets | 473,721 | 434,284 |
Supplemental Employee Retirement Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Beginning fair value of plan assets | 0 | 0 |
Investment income (loss) | 0 | 0 |
Employer contributions | 2,674 | 2,344 |
Retiree contributions | 0 | 0 |
Defined Benefit Plan, Plan Assets, Benefits Paid | (2,674) | (2,344) |
Ending fair value of plan assets | 0 | 0 |
Other Postretirement Benefits Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Beginning fair value of plan assets | 8,305 | 8,162 |
Investment income (loss) | 33 | 260 |
Employer contributions | 4,374 | 5,461 |
Retiree contributions | 1,511 | 1,455 |
Defined Benefit Plan, Plan Assets, Benefits Paid | (6,058) | (7,033) |
Ending fair value of plan assets | $ 8,165 | $ 8,305 |
Employee Benefit Plans_ Amounts
Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Defined Benefit Plan Disclosure [Line Items] | ||
Regulatory assets | $ 278,258 | $ 271,344 |
Benefit plan liabilities | 150,556 | 154,472 |
Regulatory liabilities | 532,720 | 536,652 |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Regulatory assets | 86,677 | 88,471 |
Current liabilities | 0 | 0 |
Benefit plan liabilities | 40,287 | 51,093 |
Regulatory liabilities | 3,607 | 3,524 |
Supplemental Employee Retirement Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Regulatory assets | 0 | 0 |
Current liabilities | 1,927 | 1,420 |
Benefit plan liabilities | 53,127 | 51,243 |
Regulatory liabilities | 0 | 0 |
Other Postretirement Benefits Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Regulatory assets | 16,102 | 11,670 |
Current liabilities | 4,931 | 4,802 |
Benefit plan liabilities | 57,142 | 52,136 |
Regulatory liabilities | $ 2,140 | $ 4,088 |
Employee Benefit Plans_ Accumul
Employee Benefit Plans: Accumulated Benefit Obligations (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Accumulated Benefit Obligation | $ 498,815 | $ 470,615 |
Supplemental Employee Retirement Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Accumulated Benefit Obligation | 54,779 | 49,241 |
Other Postretirement Benefits Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Accumulated Benefit Obligation | $ 70,238 | $ 65,277 |
Employee Benefit Plans_ Compone
Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | $ 5,411 | $ 5,383 | $ 6,834 |
Interest cost | 13,426 | 17,374 | 15,470 |
Expected return on assets | (22,591) | (24,401) | (24,741) |
Net amortization of prior service cost | 0 | 26 | 58 |
Recognized net actuarial loss (gain) | 8,372 | 3,763 | 8,632 |
Net periodic benefit expense | 4,618 | 2,145 | 6,253 |
Other Pension, Postretirement and Supplemental Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 1,579 | 4,995 | 1,764 |
Interest cost | 1,099 | 1,295 | 1,170 |
Expected return on assets | 0 | 0 | 0 |
Net amortization of prior service cost | 2 | 2 | 2 |
Recognized net actuarial loss (gain) | 1,702 | 535 | 1,000 |
Net periodic benefit expense | 4,382 | 6,827 | 3,936 |
Other Pension, Postretirement and Supplemental Plans | Error Correction, Other | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 1,400 | ||
Other Postretirement Benefits Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 2,056 | 1,815 | 2,291 |
Interest cost | 1,649 | 2,247 | 2,085 |
Expected return on assets | (182) | (230) | (315) |
Net amortization of prior service cost | (546) | (398) | (398) |
Recognized net actuarial loss (gain) | 20 | 0 | 216 |
Net periodic benefit expense | $ 2,997 | $ 3,434 | $ 3,879 |
Employee Benefit Plans_ Change
Employee Benefit Plans: Change in Accounting Principal (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Other income (expense), net | $ (2,293) | $ (5,740) | $ (1,180) |
Income tax benefit (expense) | (32,918) | (29,580) | 23,667 |
Net income available for common stock | 227,608 | $ 199,310 | $ 258,442 |
Cumulative Effect, Period of Adoption, Adjustment | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Other income (expense), net | 600 | ||
Income tax benefit (expense) | 200 | ||
Net income available for common stock | $ 400 |
Employee Benefit Plans_ AOCI Am
Employee Benefit Plans: AOCI Amounts (After-Tax) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net (gain) loss | $ 5,511 | $ 5,322 |
Prior service cost (gain) | 0 | 0 |
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense | 5,511 | 5,322 |
Supplemental Employee Retirement Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net (gain) loss | 9,323 | 9,893 |
Prior service cost (gain) | 0 | 2 |
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense | 9,323 | 9,895 |
Other Postretirement Benefits Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net (gain) loss | 100 | 90 |
Prior service cost (gain) | (144) | (230) |
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense | $ (44) | $ (140) |
Assumptions (Details)
Assumptions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Trend Year | 2027 | 2027 | |
Maximum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Trend Year | 2029 | 2028 | |
Black Hills Corporation | Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Post-65 for next year - All Plans | 6.10% | 6.40% | |
Black Hills Corporation | Maximum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Post-65 for next year - All Plans | 4.92% | 4.92% | |
Black Hills Service Company | Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Post-65 Ultimate trend rate - Black Hills Corp | 4.50% | 4.50% | |
Black Hills Service Company | Maximum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Post-65 Ultimate trend rate - Black Hills Corp | 4.50% | 4.50% | |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 2.56% | 3.27% | 4.40% |
Rate of increase in compensation levels | 3.34% | 3.49% | 3.52% |
Expected long-term rate of return on assets | 5.25% | 6.00% | 6.25% |
Rate of increase in compensation levels | 3.49% | 3.52% | 3.43% |
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year | 4.50% | ||
2021 | $ 25,842 | ||
2022 | 26,658 | ||
2023 | 27,581 | ||
2024 | 28,284 | ||
2025 | 29,062 | ||
2026-2030 | $ 144,273 | ||
Pension Plan | Black Hills Corporation | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 3.27% | 4.40% | 3.71% |
Pension Plan | Black Hills Corporation Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Post-65 for next year - All Plans | 2.56% | ||
Supplemental Employee Retirement Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 2.41% | 3.14% | 4.34% |
Rate of increase in compensation levels | 5.00% | 5.00% | 5.00% |
Rate of increase in compensation levels | 5.00% | 5.00% | 5.00% |
2021 | $ 1,927 | ||
2022 | 1,968 | ||
2023 | 2,033 | ||
2024 | 2,231 | ||
2025 | 2,690 | ||
2026-2030 | $ 13,117 | ||
Supplemental Employee Retirement Plan | Black Hills Corporation | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 3.14% | 4.34% | 3.67% |
Other Postretirement Benefits Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 2.41% | 3.15% | 4.28% |
Expected long-term rate of return on assets | 2.35% | 3.00% | 3.93% |
2021 | $ 6,108 | ||
2022 | 5,965 | ||
2023 | 5,725 | ||
2024 | 5,532 | ||
2025 | 5,244 | ||
2026-2030 | $ 22,872 | ||
Other Postretirement Benefits Plan | Black Hills Corporation | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 3.15% | 4.28% | 3.60% |
Compensation Related Costs, Sha
Compensation Related Costs, Share Based Payments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Payment Arrangement [Abstract] | |||
Shares available for grant | 561,073 | ||
Unrecognized compensation expense | $ 12,000 | ||
Weighted-average recognition period | 2 years | ||
Stock compensation | $ 5,373 | $ 12,095 | $ 12,390 |
Stock Options (Details)
Stock Options (Details) - Employee Stock Option | Dec. 31, 2020shares |
Share-based Payment Arrangement [Abstract] | |
Shares exercisable at end of period | 5,000 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares exercisable at end of period | 5,000 |
Restricted Stock (Details)
Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Restricted Stock and RSUs, total fair value of shares vested | $ 2,199 | $ 5,720 | $ 0 |
Unrecognized compensation expense | $ 12,000 | ||
Weighted-average recognition period | 2 years | ||
Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Award vesting period | 3 years | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | 196 | 192 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 69.05 | $ 65.66 | |
Performance Shares, Granted in Period | 116 | ||
Granted (usd per share) | $ 69.49 | $ 73.66 | $ 57.31 |
Shares Vested | (90) | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 63.30 | ||
Shares Forfeited | (22) | ||
Forfeited (usd per share) | $ 65.30 | ||
Restricted Stock and RSUs, total fair value of shares vested | $ 6,722 | $ 8,438 | $ 6,776 |
Unrecognized compensation expense | $ 10,300 | ||
Weighted-average recognition period | 2 years 2 months 12 days |
Performance Share Plan (Details
Performance Share Plan (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation expense | $ 12,000 | ||
Stock Issued During Period, Shares, Treasury Stock Reissued | 14 | 44 | 0 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid | $ 1,100 | $ 2,860 | $ 0 |
Restricted Stock and RSUs, total fair value of shares vested | $ 2,199 | $ 5,720 | $ 0 |
Performance Goal - Percentile of Peer Group Performance | 5500.00% | ||
Weighted-average recognition period | 2 years | ||
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Share Award Payout, Cash Percentage | 50.00% | ||
Performance Share Award Payout, Shares of Common Stock Percentage | 50.00% | ||
The percentage paid in cash for the accrued equity portion of the performance share plan upon change in control | 100.00% | ||
Unrecognized compensation expense | $ 2,700 | ||
Performance Shares, Number of Shares Authorized | 36 | 36 | 49 |
Performance Share Award, Percentage of Target | 112.35% | ||
Weighted Average Grant Date Fair Value (usd per share) | $ 81.42 | $ 68.72 | $ 61.82 |
Blended volatility | 18.00% | 21.00% | 21.00% |
Historical volatility | 50.00% | ||
Target shares, value | $ 3,300 | ||
Weighted-average recognition period | 1 year 8 months 12 days | ||
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount | $ 2,000 | ||
Performance Shares | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Share Award, Percentage of Target | 0.00% | 0.00% | 0.00% |
Performance Shares | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Share Award, Percentage of Target | 200.00% | 200.00% | 200.00% |
Performance Shares, Equity Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Shares, Number of Shares Authorized | 61 | 67 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 69.71 | $ 64.32 | |
Performance Shares, Granted in Period | 19 | ||
Shares Forfeited | (2) | ||
Forfeited (usd per share) | $ 73.89 | ||
Shares Vested | (23) | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 63.52 | ||
Performance Shares, Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Shares, Number of Shares Authorized | 61 | 67 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 52.42 | ||
Performance Shares, Granted in Period | 19 | ||
Shares Forfeited | (2) | ||
Shares Vested | (23) |
Income Taxes_ CARES Act (Detail
Income Taxes: CARES Act (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2020USD ($) | |
Income Tax Disclosure [Abstract] | |
Proceeds from Income Tax Refunds | $ 2,400 |
Amount of Payroll Tax (Social Security Employment Tax) Deferral Allowed Under the CARES Act | $ 10,000 |
Income Taxes_ Tax Cut and Jobs
Income Taxes: Tax Cut and Jobs Act (Details) - USD ($) $ in Thousands | 12 Months Ended | 36 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2020 | |
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Regulatory Liability | $ 309,000 | |||
Increase (Decrease) in Regulatory Liabilities | $ (10,706) | $ (15,158) | 18,533 | |
Deferred Income Tax Charge | ||||
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Regulatory Liability | 301,000 | |||
Increase (Decrease) in Regulatory Liabilities | $ 11,000 | |||
Revenue Subject to Refund | ||||
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 13,300 |
Income Taxes_ Current and Defer
Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Current: | |||
Federal | $ (6,020) | $ (8,578) | $ 325 |
State | 847 | 138 | 247 |
Total Current | (5,173) | (8,440) | 572 |
Deferred: | |||
Federal | 35,672 | 34,551 | (25,022) |
State | 2,419 | 3,469 | 783 |
Total Deferred | 38,091 | 38,020 | (24,239) |
Total Current and Deferred | $ 32,918 | $ 29,580 | $ (23,667) |
Income Taxes_ Effective Tax Rat
Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Federal Statutory Rate | 21.00% | 21.00% | 21.00% |
State income tax (net of federal tax effect) | 2.40% | 1.50% | 2.30% |
Non-controlling interest | (1.20%) | (1.20%) | (1.30%) |
Tax Credits | (9.20%) | (3.90%) | (2.00%) |
Flow-through adjustments | (1.60%) | (2.40%) | (1.60%) |
Jurisdictional simplification project | 0.00% | 0.00% | (28.50%) |
Uncertain Tax Benefits | 1.50% | 0.00% | 0.00% |
Valuation Allowance | 0.70% | 0.00% | 0.00% |
Other tax differences | 0.60% | (1.60%) | (0.10%) |
TCJA corporate rate reduction | 0 | 0 | 0.016 |
Effective Income Tax Reconciliation, Amortization Of Excess Deferred Income Tax Expense | (2.30%) | (1.20%) | (0.70%) |
Effective Income Tax Rate, Continuing Operations | 11.90% | 12.20% | (9.30%) |
Deferred Income Tax Expense (Benefit) | $ (38,091) | $ (38,020) | $ 24,239 |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | 4,000 | ||
Other Restructuring | |||
Deferred Tax Assets, Goodwill and Intangible Assets | 73,000 | ||
Deferred Income Tax Expense (Benefit) | $ 73,000 |
Income Taxes_ Deferred Income T
Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Deferred Tax Assets, Net [Abstract] | ||
Regulatory liabilities | $ 90,535 | $ 89,754 |
State tax credits | 23,339 | 23,261 |
Federal NOL | 96,155 | 120,624 |
State NOL | 9,914 | 13,537 |
Partnership | 15,601 | 14,030 |
Credit Carryovers | 51,445 | 27,139 |
Other deferred tax assets | 40,143 | 33,395 |
Less: Valuation allowance | (13,943) | (12,063) |
Total deferred tax assets | 313,189 | 309,677 |
Deferred tax liabilities: | ||
Accelerated depreciation, amortization and other plant-related differences | (551,137) | (533,292) |
Regulatory assets | (28,007) | (23,586) |
Goodwill | (30,590) | (15,875) |
State deferred tax liability | (73,910) | (72,911) |
Other deferred tax liabilities | (38,169) | (24,732) |
Total deferred tax liabilities | (721,813) | (670,396) |
Net deferred tax liability | $ (408,624) | $ (360,719) |
Income Taxes_ Net Operating Los
Income Taxes: Net Operating Loss Carryforwards (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Operating Loss Carryforwards [Line Items] | |||
Deferred Income Tax Expense (Benefit) | $ 38,091 | $ 38,020 | $ (24,239) |
Deferred Tax Assets, Operating Loss Carryforwards, State and Local | 9,914 | $ 13,537 | |
Internal Revenue Service (IRS) | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 378,236 | ||
Operating Loss Carryforwards, With no Expiration Date | 79,644 | ||
State and Local Jurisdiction | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 173,867 | ||
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | 1,300 | ||
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards Valuation Allowance | 1,100 | ||
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | 800 | ||
Valuation Allowance Reduction due to Expired NOL | 200 | ||
Deferred Income Tax Expense (Benefit) | 800 | ||
Deferred Tax Assets, Operating Loss Carryforwards, State and Local | $ 200 |
Income Taxes_ Reconciliation of
Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Liability for Uncertain Tax Positions, Noncurrent, Period Start | $ 4,165 | $ 3,583 | $ 3,263 |
Additions for prior year tax positions | 3,788 | 446 | 251 |
Reductions for prior year tax positions | (1,313) | (862) | (417) |
Additions for current year tax positions | 1,743 | 998 | 486 |
Settlements | 0 | 0 | 0 |
Liability for Uncertain Tax Positions, Noncurrent, Period End | 8,383 | $ 4,165 | $ 3,583 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | $ 4,300 |
Income Taxes_ Interest, Penalti
Income Taxes: Interest, Penalties and Audits (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |||
Unrecognized Tax Benefits, Interest Expense | $ 0 | $ 0 | $ 0 |
Unrecognized Tax Benefits, Interest Accrued | $ 0 | $ 0 | $ 0 |
Income Taxes_ Carryforwards, St
Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Tax Credit Carryforward [Line Items] | |||
Income Tax Expense (Benefit) | $ 32,918 | $ 29,580 | $ (23,667) |
State and Local Jurisdiction | |||
Tax Credit Carryforward [Line Items] | |||
Tax Credit Carryforward, Valuation Allowance | 12,800 | ||
Income Tax Expense (Benefit) | 1,300 | ||
State and Local Jurisdiction | Investment Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Deferred Tax Assets, State Tax Credits | 23,060 | ||
State and Local Jurisdiction | Research Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Deferred Tax Assets, State Tax Credits | $ 278 |
Business Segment Information_ S
Business Segment Information: Segment Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 8,088,786 | $ 7,558,457 |
Corporate, Non-Segment | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 110,349 | 130,245 |
Electric Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 3,120,928 | 2,900,983 |
Gas Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 4,376,204 | 4,032,339 |
Power Generation | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 404,220 | 417,715 |
Mining | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 77,085 | $ 77,175 |
Business Segment Information_ C
Business Segment Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Segment Reporting Information [Line Items] | ||
Capital Expenditures | $ 755,392 | $ 849,755 |
Corporate, Non-Segment | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures | 17,500 | 20,702 |
Electric Utilities | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures | 271,104 | 222,911 |
Gas Utilities | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures | 449,209 | 512,366 |
Power Generation | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures | 9,329 | 85,346 |
Mining | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures | $ 8,250 | $ 8,430 |
Business Segment Information_ P
Business Segment Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Segment Reporting Information [Line Items] | ||
Property, Plant and Equipment, Gross | $ 7,305,530 | $ 6,784,679 |
Corporate, Non-Segment | ||
Segment Reporting Information [Line Items] | ||
Property, Plant and Equipment, Gross | 22,094 | 29,055 |
Electric Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, Plant and Equipment, Gross | 3,248,480 | 3,059,135 |
Gas Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, Plant and Equipment, Gross | 3,312,613 | 2,981,498 |
Power Generation | ||
Segment Reporting Information [Line Items] | ||
Property, Plant and Equipment, Gross | 534,803 | 534,518 |
Mining | ||
Segment Reporting Information [Line Items] | ||
Property, Plant and Equipment, Gross | $ 187,540 | $ 180,473 |
Business Segment Information_ I
Business Segment Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Sep. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Segment Reporting Information | |||||
Revenue from contracts with customers | $ 1,680,804 | $ 1,726,392 | $ 1,748,542 | ||
Revenue | 1,696,941 | 1,734,900 | 1,754,268 | ||
Fuel, purchased power and cost of natural gas sold | 492,404 | 570,829 | 625,610 | ||
Operations and maintenance, including taxes | 551,777 | 548,909 | 535,293 | ||
Depreciation, depletion and amortization | 224,457 | 209,120 | 196,328 | ||
Operating income | 428,303 | 406,042 | 397,037 | ||
Interest expense | (143,470) | (137,659) | (139,975) | ||
Impairment of investment | $ (20,000) | $ (6,900) | (6,859) | (19,741) | 0 |
Other income (expense), net | (2,293) | (5,740) | (1,180) | ||
Income tax benefit (expense) | (32,918) | (29,580) | 23,667 | ||
Income from continuing operations | 242,763 | 213,322 | 279,549 | ||
(Loss) from discontinued operations, net of tax | 0 | 0 | (6,887) | ||
Net income | 242,763 | 213,322 | 272,662 | ||
Net income attributable to noncontrolling interest | (15,155) | (14,012) | (14,220) | ||
Net income available for common stock | 227,608 | 199,310 | 258,442 | ||
Electric Utilities | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 711,843 | 707,561 | 709,024 | ||
Revenue | 714,044 | 712,752 | 711,451 | ||
Fuel, purchased power and cost of natural gas sold | 267,045 | 268,297 | 283,840 | ||
Operations and maintenance, including taxes | 196,794 | 195,581 | 186,175 | ||
Depreciation, depletion and amortization | 94,150 | 88,577 | 85,567 | ||
Adjusted operating income (loss) | 156,055 | 160,297 | 155,869 | ||
Gas Utilities | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 964,421 | 1,009,646 | 1,024,352 | ||
Revenue | 974,670 | 1,010,030 | 1,025,307 | ||
Fuel, purchased power and cost of natural gas sold | 354,645 | 425,898 | 462,153 | ||
Operations and maintenance, including taxes | 303,577 | 301,844 | 291,481 | ||
Depreciation, depletion and amortization | 100,559 | 92,317 | 86,434 | ||
Adjusted operating income (loss) | 215,889 | 189,971 | 185,239 | ||
Power Generation | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 103,258 | 99,157 | 90,791 | ||
Revenue | 105,047 | 101,258 | 92,451 | ||
Fuel, purchased power and cost of natural gas sold | 8,993 | 9,059 | 8,592 | ||
Operations and maintenance, including taxes | 33,695 | 28,429 | 25,135 | ||
Depreciation, depletion and amortization | 20,247 | 18,991 | 16,110 | ||
Adjusted operating income (loss) | 42,112 | 44,779 | 42,614 | ||
Net income attributable to noncontrolling interest | (15,000) | (14,000) | (14,000) | ||
Mining | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 58,567 | 59,233 | 65,803 | ||
Revenue | 61,075 | 61,629 | 68,033 | ||
Fuel, purchased power and cost of natural gas sold | 0 | 0 | 0 | ||
Operations and maintenance, including taxes | 39,033 | 40,032 | 43,728 | ||
Depreciation, depletion and amortization | 9,235 | 8,970 | 7,965 | ||
Adjusted operating income (loss) | 12,807 | 12,627 | 16,340 | ||
Intercompany Eliminations | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | (157,285) | (149,205) | (141,428) | ||
Revenue | (157,895) | (150,769) | (142,974) | ||
Fuel, purchased power and cost of natural gas sold | (138,362) | (132,693) | (129,019) | ||
Operations and maintenance, including taxes | (305,823) | (303,776) | (336,142) | ||
Depreciation, depletion and amortization | (24,884) | (21,800) | (20,909) | ||
Adjusted operating income (loss) | (41,969) | (36,705) | (36,827) | ||
Corporate, Non-Segment | |||||
Segment Reporting Information | |||||
Revenue | 353,143 | 344,205 | 379,923 | ||
Fuel, purchased power and cost of natural gas sold | 83 | 268 | 44 | ||
Operations and maintenance, including taxes | 284,501 | 286,799 | 324,916 | ||
Depreciation, depletion and amortization | 25,150 | 22,065 | 21,161 | ||
Adjusted operating income (loss) | 43,409 | 35,073 | 33,802 | ||
Other revenues | |||||
Segment Reporting Information | |||||
Revenue | 16,137 | 8,508 | 5,726 | ||
Other revenues | Electric Utilities | |||||
Segment Reporting Information | |||||
Revenue | 2,201 | 5,191 | 2,427 | ||
Other revenues | Gas Utilities | |||||
Segment Reporting Information | |||||
Revenue | 10,249 | 384 | 955 | ||
Other revenues | Power Generation | |||||
Segment Reporting Information | |||||
Revenue | 1,789 | 2,101 | 1,660 | ||
Other revenues | Mining | |||||
Segment Reporting Information | |||||
Revenue | 2,508 | 2,396 | 2,230 | ||
Other revenues | Intercompany Eliminations | |||||
Segment Reporting Information | |||||
Revenue | (610) | (1,564) | (1,546) | ||
External Customers | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 1,680,804 | 1,726,392 | 1,748,542 | ||
Revenue | 1,696,941 | 1,734,900 | 1,754,268 | ||
External Customers | Electric Utilities | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 687,929 | 684,445 | 686,272 | ||
Revenue | 690,130 | 689,636 | 688,699 | ||
External Customers | Gas Utilities | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 959,696 | 1,007,187 | 1,022,828 | ||
Revenue | 969,658 | 1,007,571 | 1,023,783 | ||
External Customers | Power Generation | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 6,090 | 7,580 | 5,833 | ||
Revenue | 7,656 | 9,439 | 7,246 | ||
External Customers | Mining | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 27,089 | 27,180 | 33,609 | ||
Revenue | 29,497 | 28,254 | 34,540 | ||
External Customers | Other revenues | |||||
Segment Reporting Information | |||||
Revenue | 16,137 | 8,508 | 5,726 | ||
External Customers | Other revenues | Electric Utilities | |||||
Segment Reporting Information | |||||
Revenue | 2,201 | 5,191 | 2,427 | ||
External Customers | Other revenues | Gas Utilities | |||||
Segment Reporting Information | |||||
Revenue | 9,962 | 384 | 955 | ||
External Customers | Other revenues | Power Generation | |||||
Segment Reporting Information | |||||
Revenue | 1,566 | 1,859 | 1,413 | ||
External Customers | Other revenues | Mining | |||||
Segment Reporting Information | |||||
Revenue | 2,408 | 1,074 | 931 | ||
Intercompany Customers | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 0 | 0 | 0 | ||
Revenue | 0 | 0 | 0 | ||
Intercompany Customers | Electric Utilities | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 23,914 | 23,116 | 22,752 | ||
Revenue | 23,914 | 23,116 | 22,752 | ||
Intercompany Customers | Gas Utilities | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 4,724 | 2,459 | 1,524 | ||
Revenue | 5,012 | 2,459 | 1,524 | ||
Intercompany Customers | Power Generation | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 97,169 | 91,577 | 84,959 | ||
Revenue | 97,391 | 91,819 | 85,205 | ||
Intercompany Customers | Mining | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 31,478 | 32,053 | 32,194 | ||
Revenue | 31,578 | 33,375 | 33,493 | ||
Intercompany Customers | Intercompany Eliminations | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | (157,452) | (149,435) | (141,577) | ||
Revenue | (511,038) | (494,974) | (522,897) | ||
Intercompany Customers | Corporate, Non-Segment | |||||
Segment Reporting Information | |||||
Revenue from contracts with customers | 167 | 230 | 148 | ||
Revenue | 353,143 | 344,205 | 379,923 | ||
Intercompany Customers | Other revenues | |||||
Segment Reporting Information | |||||
Revenue | 0 | 0 | 0 | ||
Intercompany Customers | Other revenues | Electric Utilities | |||||
Segment Reporting Information | |||||
Revenue | 0 | 0 | 0 | ||
Intercompany Customers | Other revenues | Gas Utilities | |||||
Segment Reporting Information | |||||
Revenue | 288 | 0 | 0 | ||
Intercompany Customers | Other revenues | Power Generation | |||||
Segment Reporting Information | |||||
Revenue | 222 | 242 | 246 | ||
Intercompany Customers | Other revenues | Mining | |||||
Segment Reporting Information | |||||
Revenue | 100 | 1,322 | 1,299 | ||
Intercompany Customers | Other revenues | Intercompany Eliminations | |||||
Segment Reporting Information | |||||
Revenue | (353,586) | (345,539) | (381,320) | ||
Intercompany Customers | Other revenues | Corporate, Non-Segment | |||||
Segment Reporting Information | |||||
Revenue | $ 352,976 | $ 343,975 | $ 379,775 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) | Feb. 24, 2021 | Oct. 03, 2019 | Dec. 31, 2020 | Dec. 31, 2019 |
Subsequent Event [Line Items] | ||||
Notes payable | $ 234,040,000 | $ 349,500,000 | ||
Corporate, Non-Segment | ||||
Subsequent Event [Line Items] | ||||
Proceeds from Issuance of Debt | $ 700,000,000 | |||
Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Subsequent Event, Estimated Cost of Incremental Gas Purchases, Due to Historic Cold Weather Event | $ 600,000,000 | |||
Subsequent Event | Corporate, Non-Segment | Corporate Term Loan Due November 2021 | Black Hills Corporation | ||||
Subsequent Event [Line Items] | ||||
Proceeds from Issuance of Debt | $ 800,000,000 | |||
Interest rate based on LIBOR plus basis points | 75.00% | |||
Prepayment penalty | $ 0 | |||
Notes payable | $ 800,000,000 |