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Document and Entity Information Document - shares	3 Months Ended
Document and Entity Information Document - shares	Mar. 31, 2018	Apr. 30, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	0001130464
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,592,446
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Statement [Abstract]
Revenue	$ 575,389	$ 547,528
Operating expenses:
Fuel, purchased power and cost of natural gas sold	247,639	219,777
Operations and maintenance	116,096	114,552
Depreciation, depletion and amortization	48,590	46,702
Taxes - property, production and severance	13,300	13,386
Other operating expenses	1,490	2,925
Total operating expenses	427,115	397,342
Operating income	148,274	150,186
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(35,455)	(35,058)
Allowance for funds used during construction - borrowed	133	486
Capitalized interest	17	75
Interest income	310	41
Allowance for funds used during construction - equity	68	492
Other income (expense), net	(172)	(119)
Total other income (expense), net	(35,099)	(34,083)
Income before income taxes	113,175	116,103
Income tax benefit (expense)	25,802	(34,388)
Income from continuing operations	138,977	81,715
Net (loss) from discontinued operations	(2,343)	(1,569)
Net income	136,634	80,146
Net income attributable to noncontrolling interest	(3,630)	(3,623)
Net income from continuing operations	135,347	78,092
Net income available for common stock	$ 133,004	$ 76,523
Earnings Per Share, Basic [Abstract]
Income from continuing operations, Basic (usd per share)	$ 2.54	$ 1.47
(Loss) from discontinued operations, Basic (usd per share)	(0.05)	(0.03)
Earnings (loss) per share, Basic (usd per share)	2.49	1.44
Earnings Per Share, Diluted [Abstract]
Income from continuing operations, Diluted (usd per share)	2.50	1.42
(Loss) from discontinued operations, Diluted (usd per share)	(0.04)	(0.03)
Earnings (loss) per share, Diluted (usd per share)	$ 2.46	$ 1.39
Weighted Average Number of Shares Outstanding, Basic and Diluted [Abstract]
Basic (in shares)	53,319	53,152
Diluted (in shares)	54,122	54,932
Dividends declared per share of common stock (usd per share)	$ 0.475	$ 0.445

Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net income	$ 136,634	$ 80,146
Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost	(35)	(31)
Reclassification adjustments of benefit plan liability - net gain (loss)	486	260
Other comprehensive income (loss), net of tax	1,260	1,153
Comprehensive income	137,894	81,299
Less: comprehensive income attributable to noncontrolling interest	(3,630)	(3,623)
Comprehensive income available for common stock	134,264	77,676
Interest rate swaps
Other comprehensive income (loss), net of tax:
Net unrealized gains (losses)	0	58
Reclassification of net realized (gains) losses	561	463
Commodity Contract
Other comprehensive income (loss), net of tax:
Net unrealized gains (losses)	(228)	584
Reclassification of net realized (gains) losses	$ 476	$ (181)

Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reclassification adjustment of benefit plan - prior service cost, (tax) benefit	$ 10	$ 17
Reclassification adjustment of benefit plan liabilities, (tax) benefit	(136)	(154)
Interest rate swaps
Net unrealized gains/losses, (tax) benefit	0	(32)
Reclassification of net realized gains/losses, (tax) benefit	(152)	(249)
Commodity Contract
Net unrealized gains/losses, (tax) benefit	69	(342)
Reclassification of net realized gains/losses, (tax) benefit	$ (145)	$ 106

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Current assets:
Cash and cash equivalents	$ 30,947	$ 15,420	$ 11,291
Restricted cash	2,958	2,820	2,409
Accounts receivable, net	257,772	248,330	221,775
Materials, supplies and fuel	82,045	113,283	80,863
Derivative assets, current	295	304	982
Income tax receivable, net	13,900	0	0
Regulatory assets, current	54,492	81,016	53,476
Other current assets	24,972	25,367	21,558
Current assets held for sale	24,724	84,242	9,048
Total current assets	492,105	570,782	401,402
Investments	40,927	13,090	12,712
Property, plant and equipment	5,608,539	5,567,518	5,337,031
Less: accumulated depreciation and depletion	(1,048,933)	(1,026,088)	(928,306)
Total property, plant and equipment, net	4,559,606	4,541,430	4,408,725
Other assets:
Goodwill	1,299,454	1,299,454	1,299,454
Intangible assets, net	7,357	7,559	8,182
Regulatory assets, non-current	212,740	216,438	249,113
Other assets, non-current	14,800	10,149	11,291
Noncurrent assets held for sale	0	0	108,692
Total other assets, non-current	1,534,351	1,533,600	1,676,732
TOTAL ASSETS	6,626,989	6,658,902	6,499,571
Current liabilities:
Accounts payable	106,281	160,887	104,375
Accrued liabilities	194,040	219,462	196,576
Derivative liabilities, current	891	2,081	75
Accrued income taxes, net	0	1,022	3,726
Regulatory liabilities, current	42,499	6,832	22,118
Notes payable	164,200	211,300	50,950
Current maturities of long-term debt	255,743	5,743	5,743
Current liabilities held for sale	24,910	41,774	7,979
Total current liabilities	788,564	649,101	391,542
Long-term debt	2,858,787	3,109,400	3,210,730
Deferred credits and other liabilities:
Deferred income tax liabilities, net	290,491	336,520	600,933
Regulatory liabilities, non-current	495,362	478,294	196,538
Benefit plan liabilities	160,580	159,646	174,827
Other deferred credits and other liabilities	105,221	105,735	112,828
Non-current liabilities held for sale	0	0	23,195
Total deferred credits and other liabilities	1,051,654	1,080,195	1,108,321
Commitments and contingencies (See Notes 9, 11, 16, 17)
Equity:
Common stock $1 par value; 100,000,000 shares authorized; issued 53,648,817; 53,579,986; and 53,502,252 shares, respectively	53,649	53,580	53,502
Additional paid-in capital	1,151,933	1,150,285	1,143,102
Retained earnings	656,161	548,617	513,885
Treasury stock, at cost – 53,959; 39,064; and 41,443 shares, respectively	(3,049)	(2,306)	(2,443)
Accumulated other comprehensive income (loss)	(39,924)	(41,202)	(33,730)
Total stockholders’ equity	1,818,770	1,708,974	1,674,316
Noncontrolling interest	109,214	111,232	114,662
Total equity	1,927,984	1,820,206	1,788,978
TOTAL LIABILITIES AND TOTAL EQUITY	$ 6,626,989	$ 6,658,902	$ 6,499,571

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1	$ 1
Common Stock, Shares Issued	53,648,817	53,579,986	53,502,252
Treasury Stock, Shares	53,959	39,064	41,443
Common Stock, Shares Authorized	100,000,000	100,000,000	100,000,000

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities:
Net income	$ 136,634	$ 80,146
Loss from discontinued operations, net of tax	2,343	1,569
Income (loss) from continuing operations	138,977	81,715
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	48,590	46,702
Deferred financing cost amortization	1,900	1,690
Stock compensation	2,209	3,091
Deferred income taxes	(25,430)	41,213
Employee benefit plans	3,378	3,242
Other adjustments, net	3,053	(2,303)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	31,196	22,461
Accounts receivable, unbilled revenues and other operating assets	(25,113)	38,746
Accounts payable and other operating liabilities	(71,149)	(98,559)
Regulatory assets - current	47,903	236
Regulatory liabilities - current	16,098	9,083
Other operating activities, net	(278)	(1,644)
Net cash provided by operating activities of continuing operations	171,334	145,673
Net cash provided by (used in) operating activities of discontinued operations	(1,459)	1,167
Net cash provided by (used in) operating activities	169,875	146,840
Investing activities:
Property, plant and equipment additions	(69,972)	(66,480)
Purchase of investment	(23,500)	0
Other investing activities	(261)	(50)
Net cash provided by (used in) investing activities of continuing operations	(93,733)	(66,530)
Net cash provided by (used in) investing activities of discontinued operations	20,179	(2,829)
Net cash provided by (used in) investing activities	(73,554)	(69,359)
Financing activities:
Dividends paid on common stock	(25,444)	(23,754)
Common stock issued	372	2,171
Net (payments) borrowings of short-term debt	(47,100)	(45,650)
Long-term debt - repayments	(1,436)	(1,436)
Distributions to noncontrolling interest	(5,648)	(4,349)
Other financing activities	(1,400)	(6,555)
Net cash provided by (used in) financing activities	(80,656)	(79,573)
Net change in cash, cash equivalents and restricted cash	15,665	(2,092)
Cash, cash equivalents and restricted cash at beginning of period	18,240	15,792
Cash, cash equivalents and restricted cash at end of period	$ 33,905	$ 13,700

Management's Statement:	3 Months Ended
Management's Statement:	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Management's Statement	MANAGEMENT’S STATEMENT The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2017 Annual Report on Form 10-K filed with the SEC. Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. 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. On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of May 4, 2018, we have executed agreements to sell or we have closed on sales transactions for approximately 96% of our oil and gas properties. We expect to execute agreements to sell all remaining assets by mid-year 2018. See Note 18 for more information on discontinued operations. Use of Estimates and Basis of Presentation The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2018, December 31, 2017, and March 31, 2017 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2018 and March 31, 2017, and our financial condition as of March 31, 2018, December 31, 2017, and March 31, 2017, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted. Cash and Cash Equivalents and Restricted Cash For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents. Investments We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared. Recently Issued Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. We currently expect to adopt this standard on January 1, 2019 and anticipate electing not to assess existing or expired land easements that were not previously accounted for as a lease when transitioning to the new standard. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor utility industry implementation guidance. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and initiated implementation of a new lease software solution. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, 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. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Restricted Cash, ASU 2016-18 Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.

Revenue:

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

Revenue Recognition

Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. 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, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract 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 regulator-empowered statute 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, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. 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.

•

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 coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered.

•

Other non-regulated services - Our natural gas and electric utility 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 table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments. Sales tax and other similar taxes are excluded from revenues.



Three Months Ended March 31, 2018	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	147,057	$	341,394	$	—	$	16,557	$	(7,842	)	$	497,166
Transportation	—		41,669		—		—		(409		)	41,260
Wholesale	9,050		—		13,933		—		(12,213		)	10,770
Market - off-system sales	4,144		427		—		—		(2,522		)	2,049
Transmission/Other	13,071		12,670		—		—		(3,631		)	22,110
Revenue from contracts with customers	173,322		396,160		13,933		16,557		(26,617		)	573,355
Other revenues	233		1,184		9,170		571		(9,124		)	2,034
Total revenues	$	173,555	$	397,344	$	23,103	$	17,128	$	(35,741	)	$	575,389

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	16,557	$	(7,842	)	$	8,715
Services transferred over time	173,322		396,160		13,933		—		(18,775		)	564,640
Revenue from contracts with customers	$	173,322	$	396,160	$	13,933	$	16,557	$	(26,617	)	$	573,355

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 include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues.

Significant Judgments and Estimates

TCJA Revenue Reserve

The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Many of Black Hills’ regulators have directed the utilities to calculate the impact of tax reform on existing customer rates and tariffs caused by the income tax rate reduction. Until the regulators have a chance to review and approve these calculations, the utilities continue to charge customers existing rates with the embedded 35% tax rate, resulting in a reserve to revenue until new rates reflecting the 21% federal tax rate are effective. We estimated and recorded a reserve to revenue of approximately $15 million during the three months ended March 31, 2018.

Unbilled Revenue

Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends.

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 4. We do not typically incur costs that would be capitalized to obtain or fulfill a contract.

Practical Expedients

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.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

Business Segment Information:

3 Months Ended

Mar. 31, 2018

Segment Reporting Information, Additional Information [Abstract]

Business Segment Information

BUSINESS SEGMENT INFORMATION

Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):



Three Months Ended March 31, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues			Net income (loss) from continuing operations
Three Months Ended March 31, 2018	Contract Customers		Other Revenues		Contract Customers			Other Revenues			Total Revenues			Net income (loss) from continuing operations
Segment:
Electric	$	167,178	$	233	$	6,144		$	—		$	173,555		$	19,845
Gas ^(a)	395,742		1,184		418			—			397,344			107,620
Power Generation ^(b)	1,720		371		12,213			8,799			23,103			5,856
Mining	8,715		246		7,842			325			17,128			2,984
Corporate and Other	—		—		—			—			—			(958		)
Inter-company eliminations	—		—		(26,617		)	(9,124		)	(35,741		)	—
Total	$	573,355	$	2,034	$	—		$	—		$	575,389		$	135,347

Under our modified retrospective adoption of ASU 2014-09, revenues for the three months ended March 31, 2017 are not presented by contract type.



Three Months Ended March 31, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Three Months Ended March 31, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Segment:
Electric^.	$	172,170	$	3,854		$	22,230
Gas	364,901		9			46,010
Power Generation ^(b)	2,102		21,465			6,530
Mining	8,355		8,191			2,890
Corporate and Other ^(c)	—		—			432
Inter-company eliminations	—		(33,519		)	—
Total	$	547,528	$	—		$	78,092

___________


(a)	Net income from continuing operations available for common stock for the three months ended March 31, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 of the Notes to Condensed Consolidated Financial Statements for more information.


(b)	Net income from continuing operations available for common stock for the three months ended March 31, 2018 and March 31, 2017 reflects net income attributable to noncontrolling interests of $3.6 million and $3.5 million, respectively.


(c)	Net income (loss) from continuing operations available for common stock for the three months ended March 31, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years.

Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):



Total Assets (net of inter-company eliminations) as of:	March 31, 2018		December 31, 2017		March 31, 2017
Segment:
Electric ^(a)	$	2,890,708	$	2,906,275	$	2,872,989
Gas	3,398,473		3,426,466		3,260,989
Power Generation ^(a)	53,323		60,852		69,737
Mining	65,568		65,455		64,973
Corporate activities	194,193		115,612		113,143
Discontinued operations	24,724		84,242		117,740
Total assets	$	6,626,989	$	6,658,902	$	6,499,571

__________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

Accounts Receivable:

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Accounts Receivable

ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2018	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	40,492	$	33,907	$	(624	)	$	73,775
Gas Utilities	120,910		60,142		(3,684		)	177,368
Power Generation	1,580		—		—			1,580
Mining	3,133		—		—			3,133
Corporate	1,916		—		—			1,916
Total	$	168,031	$	94,049	$	(4,308	)	$	257,772



	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,347	$	36,384	$	(586	)	$	75,145
Gas Utilities	81,256		88,967		(2,495		)	167,728
Power Generation	1,196		—		—			1,196
Mining	2,804		—		—			2,804
Corporate	1,457		—		—			1,457
Total	$	126,060	$	125,351	$	(3,081	)	$	248,330



	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,679	$	30,778	$	(639	)	$	69,818
Gas Utilities	98,027		51,926		(3,646		)	146,307
Power Generation	1,353		—		—			1,353
Mining	3,197		—		—			3,197
Corporate	1,100		—		—			1,100
Total	$	143,356	$	82,704	$	(4,285	)	$	221,775

- Definition

The entire disclosure for claims held for amounts due a entity, excluding financing receivables. Examples include, but are not limited to, trade accounts receivables, notes receivables, loans receivables. Includes disclosure for allowance for credit losses.

+ References + Details

Regulatory Accounting:

3 Months Ended

Mar. 31, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Accounting

REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands) as of:



	Maximum Amortization (in years)	March 31, 2018			December 31, 2017			March 31, 2017
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)	1	$	25,056		$	20,187		$	23,756
Deferred gas cost adjustments ^(a)	1	2,118			31,844			8,610
Gas price derivatives ^(a)	3	11,045			11,935			11,520
Deferred taxes on AFUDC^{(b) (f)}	45	7,808			7,847			14,976
Employee benefit plans ^(c)	12	109,999			109,235			109,172
Environmental^(a)	subject to approval	1,012			1,031			1,089
Asset retirement obligations^(a)	44	521			517			507
Loss on reacquired debt^(a)	28	20,267			20,667			21,866
Renewable energy standard adjustment ^(a)	subject to approval	1,600			1,088			963
Deferred taxes on flow through accounting^{(c) (f)}	54	28,014			26,978			39,152
Decommissioning costs	10	12,552			13,287			15,745
Gas supply contract termination ^(a)	4	18,590			20,001			24,178
Other regulatory assets^(a)	30	28,650			32,837			31,055
Total regulatory assets		267,232			297,454			302,589
Less current regulatory assets		(54,492		)	(81,016		)	(53,476		)
Regulatory assets, non-current		$	212,740		$	216,438		$	249,113

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	20,194		$	3,427		$	19,494
Employee benefit plan costs and related deferred taxes^{(c) (f)}	12	40,332			40,629			67,973
Cost of removal^(a)	44	139,002			130,932			122,548
Excess deferred income taxes ^{(c) (d)}	40	310,622			301,553			59
TCJA revenue reserve ^(e)	subject to approval	15,239			—			—
Other regulatory liabilities^(c)	25	12,472			8,585			8,582
Total regulatory liabilities		537,861			485,126			218,656
Less current regulatory liabilities		(42,499		)	(6,832		)	(22,118		)
Regulatory liabilities, non-current		$	495,362		$	478,294		$	196,538

__________


(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.

(d)

The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of March 31, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions of other revenue offsets in 2018.


(e)	As of March 31, 2018, the amortization periods are yet to be determined and subject to approval by our regulators.


(f)	The variance to the prior periods is primarily due to the TCJA.

Regulatory Matters

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 2017 Annual Report on Form 10-K.

TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Many of Black Hills’ regulators have issued orders directing the utilities to calculate the impacts of tax reform on existing rates/tariffs caused by the income tax rate reduction. Until each regulator has a chance to review and approve the calculations, the utilities continue to charge customers existing rates with the embedded 35% federal tax rate, resulting in a reserve to revenue until new rates reflecting the 21% federal tax rate are effective. We estimated and recorded a reserve to revenue of approximately $15 million during the three months ended March 31, 2018.

Each of our utilities is working with their respective regulators to address the impact of tax reform and the appropriate benefit to customers.

Rate Review - On April 16, 2018, RMNG received a recommended decision from a Colorado administrative law judge approving a settlement agreement with the Colorado Office of Consumer Counsel and staff on its rate review application previously filed on October 3, 2017. The settlement included $1.1 million in annual revenue increases and an extension of SSIR to recover costs from 2018 through December 31, 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are expected to be effective June 1, 2018 pending approval from the CPUC.

Materials, Supplies and Fuel:

3 Months Ended

Mar. 31, 2018

Inventory, Net [Abstract]

Materials, Supplies and Fuel

MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2018		December 31, 2017		March 31, 2017
Materials and supplies	$	72,045	$	69,732	$	68,202
Fuel - Electric Utilities	2,903		2,962		3,433
Natural gas in storage held for distribution	7,097		40,589		9,228
Total materials, supplies and fuel	$	82,045	$	113,283	$	80,863

Investments:

3 Months Ended

Mar. 31, 2018

Long-term Investments [Abstract]

Investments

INVESTMENTS

In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We will 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. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of March 31, 2018.

The following table presents the carrying value of our investments (in thousands) as of:



	March 31, 2018		December 31, 2017		March 31, 2017
Cost method investment	$	28,100	$	—	$	—
Cash surrender value	12,827		13,090		12,712
Total investments	$	40,927	$	13,090	$	12,712

Earnings Per Share:

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):



	Three Months Ended March 31,
	2018		2017

Net income available for common stock	$	133,004	$	76,523

Weighted average shares - basic	53,319		53,152
Dilutive effect of:
Equity Units ^(a)	733		1,595
Equity compensation	70		185
Weighted average shares - diluted	54,122		54,932

__________


(a)	Calculated using the treasury stock method.

The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):



	Three Months Ended March 31,
	2018	2017

Equity compensation	71	—
Anti-dilutive shares	71	—

Notes Payable and Current Maturities:

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Notes Payable and Long-term Debt

NOTES PAYABLE AND CURRENT MATURITIES

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2018				December 31, 2017				March 31, 2017
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	15,830	$	—	$	26,848	$	—	$	28,100
CP Program	164,200		—		211,300		—		50,950		—
Total	$	164,200	$	15,830	$	211,300	$	26,848	$	50,950	$	28,100

Revolving Credit Facility and CP Program

Our $750 million corporate Revolving Credit Facility extends through August 9, 2021 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 and issuing agents, to increase total commitments of the facility up to $1.0 billion. Borrowings are 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 most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at March 31, 2018. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

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 amount borrowed under the CP Program during the three months ended March 31, 2018 and our notes outstanding as of March 31, 2018 were $164 million. As of March 31, 2018, the weighted average interest rate on CP Program borrowings was 2.34%.

Debt Covenants

Our Revolving Credit Facility and term loan agreements allow for the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. 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 and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs.

Our Revolving Credit Facility and Term Loans require compliance with the following financial covenant at the end of each quarter:



	As of March 31, 2018	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	59%	Less than	65%

As of March 31, 2018, we were in compliance with this covenant.

Current Maturities

As of March 31, 2018, our $250 million Senior unsecured notes due January 11, 2019 and $5.7 million of principal due in the next twelve months on our Corporate term loan due June 7, 2021 are classified as Current maturities of long-term debt.

Equity:

3 Months Ended

Mar. 31, 2018

Statement of Stockholders' Equity [Abstract]

Equity

EQUITY

A summary of the changes in equity is as follows:



Three Months Ended March 31, 2018	Total Stockholders’ Equity			Noncontrolling Interest			Total Equity
				(in thousands)
Balance at December 31, 2017	$	1,708,974		$	111,232		$	1,820,206
Net income (loss)	133,004			3,630			136,634
Other comprehensive income (loss)	1,260			—			1,260
Dividends on common stock	(25,444		)	—			(25,444		)
Share-based compensation	755			—			755
Issuance of common stock	—			—			—
Dividend reinvestment and stock purchase plan	219			—			219
Other	2			—			2
Distribution to noncontrolling interest	—			(5,648		)	(5,648		)
Balance at March 31, 2018	$	1,818,770		$	109,214		$	1,927,984



Three Months Ended March 31, 2017	Total Stockholders’ Equity			Noncontrolling Interest			Total Equity
				(in thousands)
Balance at December 31, 2016	$	1,614,639		$	115,495		$	1,730,134
Net income (loss)	76,523			3,516			80,039
Other comprehensive income (loss)	1,153			—			1,153
Dividends on common stock	(23,754		)	—			(23,754		)
Share-based compensation	2,392			—			2,392
Dividend reinvestment and stock purchase plan	748			—			748
Redeemable noncontrolling interest	(1,096		)	—			(1,096		)
Cumulative effect of ASU 2016-09 implementation	3,714			—			3,714
Other stock transactions	(3		)	—			(3		)
Distribution to noncontrolling interest	—			(4,349		)	(4,349		)
Balance at March 31, 2017	$	1,674,316		$	114,662		$	1,788,978

At-the-Market Equity Offering Program

On August 4, 2017, we renewed our ATM equity offering program which reset the size of the program to an aggregate value of up to $300 million. The renewed 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 $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the three months ended March 31, 2018 and March 31, 2017 under the ATM equity offering program.

Noncontrolling Interest

Colorado IPP owns a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in 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 Black Hills Colorado Electric.

Colorado IPP has been determined to be a variable interest entity (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 Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Colorado IPP. Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. 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 Condensed Consolidated Balance Sheets related to the VIE described above as of:



	March 31, 2018		December 31, 2017		March 31, 2017
	(in thousands)
Assets
Current assets	$	12,567	$	14,837	$	12,167
Property, plant and equipment of variable interest entities, net	$	205,725	$	208,595	$	217,083

Liabilities
Current liabilities	$	3,404	$	4,565	$	3,464

Risk Management Activities:

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation 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 as discussed in our 2017 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to:


•	Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain gas-fired generation assets; and


•	Interest rate risk associated with our variable rate debt.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, 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, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based on 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 and any specific customer collection issue that is identified.

Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 12.

Utilities

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 volatility in natural gas prices. 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 Condensed 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 Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed 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/or sales during time frames ranging from April 2018 through May 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income. Effectiveness of our hedging position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We were in a net long position as of:



	March 31, 2018		December 31, 2017		March 31, 2017
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	6,760,000	33	8,330,000	36	12,330,000	45
Natural gas options purchased, net	170,000	11	3,540,000	14	500,000	21
Natural gas basis swaps purchased	6,770,000	33	8,060,000	36	11,230,000	45
Natural gas over-the-counter swaps, net ^(b)	2,760,000	26	3,820,000	29	3,165,952	26
Natural gas physical contracts, net ^(c)	386,250	32	12,826,605	35	3,015,234	12

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of March 31, 2018, 675,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.


(c)	Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Based on March 31, 2018 prices, a $0.4 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Financing Activities

At March 31, 2018, we had no outstanding interest rate swap agreements. Our last interest rate swap agreement with a $50 million notional value, which was designated to borrowings on our Revolving Credit Facility, expired in January 2017.

Discontinued Operations

Our Oil and Gas segment was exposed to risks associated with changes in the market prices of oil and gas. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas assets, these activities were discontinued and there were no outstanding derivative agreements as of March 31, 2018 or December 31, 2017. At March 31, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 90,000 Bbls, crude oil option contracts with notional volumes of 27,000 Bbls and natural gas futures and swap contracts with notional volumes of 1,890,000 MMBtus.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three months ended March 31, 2018 and 2017 (in thousands). Note that this presentation does not reflect 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.



Three Months Ended March 31, 2018
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	Interest expense	$	(713	)	Interest expense	$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(621		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	(1,334	)		$	—



Three Months Ended March 31, 2017
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	Interest expense	$	(712	)	Interest expense	$	—
Commodity derivatives	Net (loss) from discontinued operations	229			Net (loss) from discontinued operations	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	58			Fuel, purchased power and cost of natural gas sold	—
Total		$	(425	)		$	—

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three months ended March 31, 2018 and 2017. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred.



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	90
Forward commodity contracts	(297		)	926
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			712
Forward commodity contracts	621			(287		)
Total other comprehensive income (loss) from hedging	$	1,037		$	1,441

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three months ended March 31, 2018 and 2017 (in thousands). Note that this presentation does not reflect 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.



		Three Months Ended March 31,
		2018		2017
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income		Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives	Net (loss) from discontinued operations	$	—	$	117
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	254		(809		)
		$	254	$	(692	)

As discussed above, financial instruments used in our regulated 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 the hedges in our Utilities were $11 million, $12 million and $12 million at March 31, 2018, December 31, 2017 and March 31, 2017, respectively.

Fair Value Measurements:

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 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. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2017 Annual Report on Form 10-K filed with the SEC.

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

Discontinued Operations:


•	Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18.

Utilities Segments:

•

The commodity contracts for our Utilities Segments, are valued using the market approach and include exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for natural gas contracts. 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 component 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.

Corporate Activities:


•	As of March 31, 2018, we no longer have derivatives within our corporate activities as our last interest rate swaps matured in January 2017.

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.



	As of March 31, 2018
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	414	$	—	$	(119	)	$	295
Total	$	—	$	414	$	—	$	(119	)	$	295

Liabilities:
Commodity derivatives — Utilities	$	—	$	12,259	$	—	$	(11,175	)	$	1,084
Total	$	—	$	12,259	$	—	$	(11,175	)	$	1,084



	As of December 31, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives —Utilities	$	—	$	1,586	$	—	$	(1,282	)	$	304
Total	$	—	$	1,586	$	—	$	(1,282	)	$	304

Liabilities:
Commodity derivatives — Utilities	$	—	$	13,756	$	—	$	(11,497	)	$	2,259
Total	$	—	$	13,756	$	—	$	(11,497	)	$	2,259



	As of March 31, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	2,642	$	—	$	(1,651	)	$	991
Total	$	—	$	2,642	$	—	$	(1,651	)	$	991

Liabilities:
Commodity derivatives — Utilities	$	—	$	13,139	$	—	$	(12,933	)	$	206
Total	$	—	$	13,139	$	—	$	(12,933	)	$	206

Fair Value Measures 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 permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable 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 (in thousands):



As of March 31, 2018
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative liabilities — current	$	—	$	394
Commodity derivatives	Other deferred credits and other liabilities	—		29
Total derivatives designated as hedges		$	—	$	423

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	295	$	—
Commodity derivatives	Derivative liabilities — current	—		497
Commodity derivatives	Other deferred credits and other liabilities	—		164
Total derivatives not designated as hedges		$	295	$	661



As of December 31, 2017
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative liabilities — current	$	—	$	817
Commodity derivatives	Other deferred credits and other liabilities	—		67
Total derivatives designated as hedges		$	—	$	884

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	304	$	—
Commodity derivatives	Derivative liabilities — current	—		1,264
Commodity derivatives	Other deferred credits and other liabilities	—		111
Total derivatives not designated as hedges		$	304	$	1,375



As of March 31, 2017
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	163	$	—
Commodity derivatives	Current assets held for sale	559		—
Commodity derivatives	Derivative liabilities — current	—		12
Commodity derivatives	Other deferred credits and other liabilities	—		26
Commodity derivatives	Current liabilities held for sale	—		293
Commodity derivatives	Noncurrent liabilities held for sale	—		45
Total derivatives designated as hedges		$	722	$	376

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	819	$	—
Commodity derivatives	Other assets, non—current	9		—
Commodity derivatives	Derivative liabilities — current	—		63
Commodity derivatives	Other deferred credits and other liabilities	—		105
Commodity derivatives	Current liabilities held for sale	—		96
Total derivatives not designated as hedges		$	828	$	264

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 2017 Annual Report on Form 10-K.

Fair Value of Financial Instruments:

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 12, were as follows (in thousands) as of:



	March 31, 2018				December 31, 2017				March 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	30,947	$	30,947	$	15,420	$	15,420	$	11,291	$	11,291
Restricted cash ^(a)	$	2,958	$	2,958	$	2,820	$	2,820	$	2,409	$	2,409
Notes payable ^(b)	$	164,200	$	164,200	$	211,300	$	211,300	$	50,950	$	50,950
Long-term debt, including current maturities ^{(c) (d)}	$	3,114,530	$	3,265,965	$	3,115,143	$	3,350,544	$	3,216,473	$	3,388,809

__________


(a)	Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.


(b)	Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.


(c)	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.


(d)	Carrying amount of long-term debt is net of deferred financing costs.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Other Comprehensive Income (Loss):

3 Months Ended

Mar. 31, 2018

Statement of Comprehensive Income [Abstract]

Other Comprehensive Income (Loss)

OTHER COMPREHENSIVE INCOME (LOSS)

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 Condensed Consolidated Statements of Income for the period, net of tax (in thousands):



	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended
		March 31, 2018			March 31, 2017
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(712	)
Commodity contracts	Net (loss) from discontinued operations	—			229
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(621		)	58
		(1,334		)	(425		)
Income tax	Income tax benefit (expense)	297			143
Total reclassification adjustments related to cash flow hedges, net of tax		$	(1,037	)	$	(282	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	45		$	48

Actuarial gain (loss)	Operations and maintenance	(622		)	(414		)
		(577		)	(366		)
Income tax	Income tax benefit (expense)	126			137
Total reclassification adjustments related to defined benefit plans, net of tax		$	(451	)	$	(229	)
Total reclassifications		$	(1,488	)	$	(511	)

Balances by classification included within AOCI, net of tax on the accompanying Condensed 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, 2017	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)
Other comprehensive income (loss)
before reclassifications	—			(228		)	—			(228		)
Amounts reclassified from AOCI	561			476			451			1,488
Reclassifications of certain tax effects from AOCI	15			—			3			18
Ending Balance March 31, 2018	$	(19,005	)	$	(270	)	$	(20,649	)	$	(39,924	)


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
Balance as of December 31, 2016	$	(18,109	)	$	(233	)	$	(16,541	)	$	(34,883	)
Other comprehensive income (loss)
before reclassifications	58			584			—			642
Amounts reclassified from AOCI	463			(181		)	229			511
Ending Balance March 31, 2017	$	(17,588	)	$	170		$	(16,312	)	$	(33,730	)

Supplemental Disclosure of Cash Flow Information:

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Three Months Ended	March 31, 2018			March 31, 2017
	(in thousands)
Non-cash investing and financing activities—
Property, plant and equipment acquired with accrued liabilities	$	21,708		$	26,532

Cash (paid) refunded during the period —
Interest (net of amounts capitalized)	$	(36,928	)	$	(36,418	)
Income taxes (paid) refunded	$	(14,336	)	$	13

Employee Benefit Plans:

3 Months Ended

Mar. 31, 2018

Defined Benefit Plan [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):



	Three Months Ended March 31,
	2018			2017
Service cost	$	1,708		$	1,758
Interest cost	3,867			3,880
Expected return on plan assets	(6,185		)	(6,129		)
Prior service cost	15			14
Net loss (gain)	2,158			1,002
Net periodic benefit cost	$	1,563		$	525

Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):



	Three Months Ended March 31,
	2018			2017
Service cost	$	573		$	575
Interest cost	521			533
Expected return on plan assets	(57		)	(79		)
Prior service cost (benefit)	(99		)	(109		)
Net loss (gain)	54			125
Net periodic benefit cost	$	992		$	1,045

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):



	Three Months Ended March 31,
	2018		2017
Service cost	$	280	$	827
Interest cost	293		319
Prior service cost	—		1
Net loss (gain)	250		250
Net periodic benefit cost	$	823	$	1,397

For the three months ended March 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net, on the Condensed Consolidated Statements of Income. For the three months ended March 31, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Consolidated Statements of Income. See Note 1 for additional information.

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands):



	Contributions Made		Additional Contributions		Contributions
	Three Months Ended March 31, 2018		Anticipated for 2018		Anticipated for 2019
Defined Benefit Pension Plan	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,234	$	3,702	$	4,802
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	343	$	1,029	$	1,921

Commitments and Contingencies:	3 Months Ended
Commitments and Contingencies:	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2017 Annual Report on Form 10-K. Dividend Restrictions Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of March 31, 2018, we were in compliance with the debt covenants. 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 stockholders 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. Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of March 31, 2018, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.

Discontinued Operations:

3 Months Ended

Mar. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS

Results of operations for discontinued operations have been classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our condensed consolidated financial statements.

Oil and Gas Segment

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of May 4, 2018, we have executed agreements to sell or we have closed on sales transactions for approximately 96% of our oil and gas properties. We expect to execute agreements to sell all remaining assets, transfer associated liabilities, and settle substantially all remaining liabilities by mid-year 2018.

In the process of divesting our Oil and Gas segment, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties.

There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made and how they compared with the additional property sales occurring in the first quarter of 2018.

At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million. There were no further adjustments made to the fair value of our held for sale assets at March 31, 2018.

Total assets and liabilities of BHEP at March 31, 2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the expected final disposals occurring by mid-year 2018. Held for sale assets and liabilities at March 31, 2017 are classified as current and non-current.



	As of
(in thousands)	March 31, 2018			December 31, 2017			March 31, 2017
Other current assets	$	4,332		$	10,360		$	9,112
Derivative assets, current and noncurrent	—			—			559
Deferred income tax assets, noncurrent, net	3,739			16,966			23,722
Property, plant and equipment, net	16,653			56,916			84,347
Other current liabilities	(17,233		)	(18,966		)	(7,589		)
Derivative liabilities, current and noncurrent	—			—			(434		)
Other noncurrent liabilities	(7,677		)	(22,808		)	(23,150		)
Net assets (liabilities)	$	(186	)	$	42,468		$	86,567

At March 31, 2018, December 31, 2017 and March 31, 2017, the Oil and Gas segment’s net deferred tax assets were primarily comprised of basis differences on oil and gas properties, which are settled when their related properties are sold.

BHEP’s accrued liabilities at March 31, 2018 and December 31, 2017 consisted primarily of a liability contingent on final approval from the Bureau of Indian Affairs on the Jicarilla property sale, accrued royalties, payroll and property taxes. Current liabilities at March 31, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other liabilities at March 31, 2018, December 31, 2017 and March 31, 2017 consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas wells.

Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):



	Three Months Ended March 31,
	2018			2017
	(in thousands)
Revenue	$	3,915		$	6,475

Operations and maintenance	5,901			7,205
Depreciation, depletion and amortization	1,300			1,945
Total operating expenses	7,201			9,150

Operating (loss)	(3,286		)	(2,675		)

Other income (expense), net	29			73
Income tax benefit (expense)	914			1,033

(Loss) from discontinued operations	$	(2,343	)	$	(1,569	)

Income Taxes:

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

The effective tax rate differs from the federal statutory rate as follows:



	Three Months Ended March 31,
Tax (benefit) expense	2018		2017
Federal statutory rate	21.0	%	35.0	%
State income tax (net of federal tax effect)	2.0		1.4
Percentage depletion in excess of cost	(0.2	)	(0.4	)
Noncontrolling interest	(0.7	)	(1.1	)
IRC 172(f) carryback claim ^(a)	—		(1.7	)
Tax credits	(1.3	)	(1.2	)
Effective tax rate adjustment	(2.1	)	(2.4	)
Flow-through adjustments	(0.4	)	—
TCJA change in estimate ^(b)	2.0		—
Tax benefit related to legal restructuring ^(c)	(43.7	)	—
Other tax differences	0.6		—
	(22.8	)%	29.6	%

__________

(a)

During the first quarter of 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC 172(f). As a result of filing the amended returns, the Company’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased.


(b)	The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended March 31, 2018, certain estimated items associated with the revaluation have been updated.


(c)	Tax benefit from legal restructuring associated with amortizable goodwill as part of ongoing jurisdictional simplification.

Tax benefit related to legal restructuring

As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018. As a result of these transactions, additional deferred income tax assets of $49 million, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to income tax benefit (expense) on the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.

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%. The Company remeasured 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 rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.

Accrued Liabilities:

3 Months Ended

Mar. 31, 2018

Payables and Accruals [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2018		December 31, 2017		March 31, 2017
Accrued employee compensation, benefits and withholdings	$	46,262	$	52,467	$	46,410
Accrued property taxes	42,912		42,029		39,134
Customer deposits and prepayments	35,748		44,420		41,135
Accrued interest and contract adjustment payments	30,426		33,822		30,488
CIAC current portion	1,552		1,552		1,575
Other (none of which is individually significant)	37,140		45,172		37,834
Total accrued liabilities	$	194,040	$	219,462	$	196,576

Management's Statement (Policies)

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Segment Reporting

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. 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.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of May 4, 2018, we have executed agreements to sell or we have closed on sales transactions for approximately 96% of our oil and gas properties. We expect to execute agreements to sell all remaining assets by mid-year 2018. See Note 18 for more information on discontinued operations.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2018, December 31, 2017, and March 31, 2017 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2018 and March 31, 2017, and our financial condition as of March 31, 2018, December 31, 2017, and March 31, 2017, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Cash and Cash Equivalents and Restricted Cash

For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.

Investments

We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared.

Recently Issued and Adopted Accounting Standards

Recently Issued Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing not to assess existing or expired land easements that were not previously accounted for as a lease when transitioning to the new standard. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor utility industry implementation guidance. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and initiated implementation of a new lease software solution.

Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, 2017-12

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

Simplifying the Test for Goodwill Impairment, 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. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows.

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

Statement of Cash Flows: Restricted Cash, ASU 2016-18

Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.

Revenue Recognition

•



Three Months Ended March 31, 2018	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	147,057	$	341,394	$	—	$	16,557	$	(7,842	)	$	497,166
Transportation	—		41,669		—		—		(409		)	41,260
Wholesale	9,050		—		13,933		—		(12,213		)	10,770
Market - off-system sales	4,144		427		—		—		(2,522		)	2,049
Transmission/Other	13,071		12,670		—		—		(3,631		)	22,110
Revenue from contracts with customers	173,322		396,160		13,933		16,557		(26,617		)	573,355
Other revenues	233		1,184		9,170		571		(9,124		)	2,034
Total revenues	$	173,555	$	397,344	$	23,103	$	17,128	$	(35,741	)	$	575,389

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	16,557	$	(7,842	)	$	8,715
Services transferred over time	173,322		396,160		13,933		—		(18,775		)	564,640
Revenue from contracts with customers	$	173,322	$	396,160	$	13,933	$	16,557	$	(26,617	)	$	573,355

Revenue Not in Scope of ASC 606

Significant Judgments and Estimates

TCJA Revenue Reserve

Unbilled Revenue

Contract Balances

Practical Expedients

- Definition

Disclosure of accounting policy for investments in financial assets, including marketable securities (debt and equity securities with readily determinable fair values), investments accounted for under the equity method and cost method, securities borrowed and loaned, and repurchase and resale agreements. For marketable securities, the disclosure may include the entity's accounting treatment for transfers between investment categories and how the fair values for such securities are determined. Also, for all investments, an entity may describe its policy for assessing, recognizing and measuring impairment of the investment.

+ References + Details

Revenue (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue



Three Months Ended March 31, 2018	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	147,057	$	341,394	$	—	$	16,557	$	(7,842	)	$	497,166
Transportation	—		41,669		—		—		(409		)	41,260
Wholesale	9,050		—		13,933		—		(12,213		)	10,770
Market - off-system sales	4,144		427		—		—		(2,522		)	2,049
Transmission/Other	13,071		12,670		—		—		(3,631		)	22,110
Revenue from contracts with customers	173,322		396,160		13,933		16,557		(26,617		)	573,355
Other revenues	233		1,184		9,170		571		(9,124		)	2,034
Total revenues	$	173,555	$	397,344	$	23,103	$	17,128	$	(35,741	)	$	575,389

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	16,557	$	(7,842	)	$	8,715
Services transferred over time	173,322		396,160		13,933		—		(18,775		)	564,640
Revenue from contracts with customers	$	173,322	$	396,160	$	13,933	$	16,557	$	(26,617	)	$	573,355

Business Segment Information (Tables)

3 Months Ended

Mar. 31, 2018

Segment Reporting Information, Additional Information [Abstract]

Segment Reporting

Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):



Three Months Ended March 31, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues			Net income (loss) from continuing operations
Three Months Ended March 31, 2018	Contract Customers		Other Revenues		Contract Customers			Other Revenues			Total Revenues			Net income (loss) from continuing operations
Segment:
Electric	$	167,178	$	233	$	6,144		$	—		$	173,555		$	19,845
Gas ^(a)	395,742		1,184		418			—			397,344			107,620
Power Generation ^(b)	1,720		371		12,213			8,799			23,103			5,856
Mining	8,715		246		7,842			325			17,128			2,984
Corporate and Other	—		—		—			—			—			(958		)
Inter-company eliminations	—		—		(26,617		)	(9,124		)	(35,741		)	—
Total	$	573,355	$	2,034	$	—		$	—		$	575,389		$	135,347

Under our modified retrospective adoption of ASU 2014-09, revenues for the three months ended March 31, 2017 are not presented by contract type.



Three Months Ended March 31, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Three Months Ended March 31, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Segment:
Electric^.	$	172,170	$	3,854		$	22,230
Gas	364,901		9			46,010
Power Generation ^(b)	2,102		21,465			6,530
Mining	8,355		8,191			2,890
Corporate and Other ^(c)	—		—			432
Inter-company eliminations	—		(33,519		)	—
Total	$	547,528	$	—		$	78,092

___________


(a)	Net income from continuing operations available for common stock for the three months ended March 31, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 of the Notes to Condensed Consolidated Financial Statements for more information.


(b)	Net income from continuing operations available for common stock for the three months ended March 31, 2018 and March 31, 2017 reflects net income attributable to noncontrolling interests of $3.6 million and $3.5 million, respectively.


(c)	Net income (loss) from continuing operations available for common stock for the three months ended March 31, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years.

Reconciliation of Assets from Segment to Consolidated

Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):



Total Assets (net of inter-company eliminations) as of:	March 31, 2018		December 31, 2017		March 31, 2017
Segment:
Electric ^(a)	$	2,890,708	$	2,906,275	$	2,872,989
Gas	3,398,473		3,426,466		3,260,989
Power Generation ^(a)	53,323		60,852		69,737
Mining	65,568		65,455		64,973
Corporate activities	194,193		115,612		113,143
Discontinued operations	24,724		84,242		117,740
Total assets	$	6,626,989	$	6,658,902	$	6,499,571

__________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

Accounts Receivable (Tables)

3 Months Ended

Mar. 31, 2018

Receivables [Abstract]

Accounts Receivable and Allowance for Doubtful Accounts

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2018	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	40,492	$	33,907	$	(624	)	$	73,775
Gas Utilities	120,910		60,142		(3,684		)	177,368
Power Generation	1,580		—		—			1,580
Mining	3,133		—		—			3,133
Corporate	1,916		—		—			1,916
Total	$	168,031	$	94,049	$	(4,308	)	$	257,772



	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,347	$	36,384	$	(586	)	$	75,145
Gas Utilities	81,256		88,967		(2,495		)	167,728
Power Generation	1,196		—		—			1,196
Mining	2,804		—		—			2,804
Corporate	1,457		—		—			1,457
Total	$	126,060	$	125,351	$	(3,081	)	$	248,330



	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,679	$	30,778	$	(639	)	$	69,818
Gas Utilities	98,027		51,926		(3,646		)	146,307
Power Generation	1,353		—		—			1,353
Mining	3,197		—		—			3,197
Corporate	1,100		—		—			1,100
Total	$	143,356	$	82,704	$	(4,285	)	$	221,775

Regulatory Accounting (Tables)

3 Months Ended

Mar. 31, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities

We had the following regulatory assets and liabilities (in thousands) as of:



	Maximum Amortization (in years)	March 31, 2018			December 31, 2017			March 31, 2017
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)	1	$	25,056		$	20,187		$	23,756
Deferred gas cost adjustments ^(a)	1	2,118			31,844			8,610
Gas price derivatives ^(a)	3	11,045			11,935			11,520
Deferred taxes on AFUDC^{(b) (f)}	45	7,808			7,847			14,976
Employee benefit plans ^(c)	12	109,999			109,235			109,172
Environmental^(a)	subject to approval	1,012			1,031			1,089
Asset retirement obligations^(a)	44	521			517			507
Loss on reacquired debt^(a)	28	20,267			20,667			21,866
Renewable energy standard adjustment ^(a)	subject to approval	1,600			1,088			963
Deferred taxes on flow through accounting^{(c) (f)}	54	28,014			26,978			39,152
Decommissioning costs	10	12,552			13,287			15,745
Gas supply contract termination ^(a)	4	18,590			20,001			24,178
Other regulatory assets^(a)	30	28,650			32,837			31,055
Total regulatory assets		267,232			297,454			302,589
Less current regulatory assets		(54,492		)	(81,016		)	(53,476		)
Regulatory assets, non-current		$	212,740		$	216,438		$	249,113

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	20,194		$	3,427		$	19,494
Employee benefit plan costs and related deferred taxes^{(c) (f)}	12	40,332			40,629			67,973
Cost of removal^(a)	44	139,002			130,932			122,548
Excess deferred income taxes ^{(c) (d)}	40	310,622			301,553			59
TCJA revenue reserve ^(e)	subject to approval	15,239			—			—
Other regulatory liabilities^(c)	25	12,472			8,585			8,582
Total regulatory liabilities		537,861			485,126			218,656
Less current regulatory liabilities		(42,499		)	(6,832		)	(22,118		)
Regulatory liabilities, non-current		$	495,362		$	478,294		$	196,538

__________


(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.

(d)


(e)	As of March 31, 2018, the amortization periods are yet to be determined and subject to approval by our regulators.


(f)	The variance to the prior periods is primarily due to the TCJA.

Materials, Supplies and Fuel (Tables)

3 Months Ended

Mar. 31, 2018

Inventory, Net [Abstract]

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2018		December 31, 2017		March 31, 2017
Materials and supplies	$	72,045	$	69,732	$	68,202
Fuel - Electric Utilities	2,903		2,962		3,433
Natural gas in storage held for distribution	7,097		40,589		9,228
Total materials, supplies and fuel	$	82,045	$	113,283	$	80,863

Investments (Tables)

3 Months Ended

Mar. 31, 2018

Long-term Investments [Abstract]

Investments

The following table presents the carrying value of our investments (in thousands) as of:



	March 31, 2018		December 31, 2017		March 31, 2017
Cost method investment	$	28,100	$	—	$	—
Cash surrender value	12,827		13,090		12,712
Total investments	$	40,927	$	13,090	$	12,712

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):



	Three Months Ended March 31,
	2018		2017

Net income available for common stock	$	133,004	$	76,523

Weighted average shares - basic	53,319		53,152
Dilutive effect of:
Equity Units ^(a)	733		1,595
Equity compensation	70		185
Weighted average shares - diluted	54,122		54,932

__________


(a)	Calculated using the treasury stock method.

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):



	Three Months Ended March 31,
	2018	2017

Equity compensation	71	—
Anti-dilutive shares	71	—

Notes Payable and Current Maturities (Tables)

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Schedule of Short-term Debt

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2018				December 31, 2017				March 31, 2017
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	15,830	$	—	$	26,848	$	—	$	28,100
CP Program	164,200		—		211,300		—		50,950		—
Total	$	164,200	$	15,830	$	211,300	$	26,848	$	50,950	$	28,100

Schedule of Credit Facility Covenants

Our Revolving Credit Facility and Term Loans require compliance with the following financial covenant at the end of each quarter:



	As of March 31, 2018	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	59%	Less than	65%

Equity (Tables)

3 Months Ended

Mar. 31, 2018

Statement of Stockholders' Equity [Abstract]

Schedule of Stockholders Equity

A summary of the changes in equity is as follows:



Three Months Ended March 31, 2018	Total Stockholders’ Equity			Noncontrolling Interest			Total Equity
				(in thousands)
Balance at December 31, 2017	$	1,708,974		$	111,232		$	1,820,206
Net income (loss)	133,004			3,630			136,634
Other comprehensive income (loss)	1,260			—			1,260
Dividends on common stock	(25,444		)	—			(25,444		)
Share-based compensation	755			—			755
Issuance of common stock	—			—			—
Dividend reinvestment and stock purchase plan	219			—			219
Other	2			—			2
Distribution to noncontrolling interest	—			(5,648		)	(5,648		)
Balance at March 31, 2018	$	1,818,770		$	109,214		$	1,927,984



Three Months Ended March 31, 2017	Total Stockholders’ Equity			Noncontrolling Interest			Total Equity
				(in thousands)
Balance at December 31, 2016	$	1,614,639		$	115,495		$	1,730,134
Net income (loss)	76,523			3,516			80,039
Other comprehensive income (loss)	1,153			—			1,153
Dividends on common stock	(23,754		)	—			(23,754		)
Share-based compensation	2,392			—			2,392
Dividend reinvestment and stock purchase plan	748			—			748
Redeemable noncontrolling interest	(1,096		)	—			(1,096		)
Cumulative effect of ASU 2016-09 implementation	3,714			—			3,714
Other stock transactions	(3		)	—			(3		)
Distribution to noncontrolling interest	—			(4,349		)	(4,349		)
Balance at March 31, 2017	$	1,674,316		$	114,662		$	1,788,978

Schedule of Variable Interest Entities

We have recorded the following assets and liabilities on our Condensed Consolidated Balance Sheets related to the VIE described above as of:



	March 31, 2018		December 31, 2017		March 31, 2017
	(in thousands)
Assets
Current assets	$	12,567	$	14,837	$	12,167
Property, plant and equipment of variable interest entities, net	$	205,725	$	208,595	$	217,083

Liabilities
Current liabilities	$	3,404	$	4,565	$	3,464

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Risk Managment Activities (Tables)

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Contract or notionial amounts and terms of marketing activites and derivative commodity instruments



	March 31, 2018		December 31, 2017		March 31, 2017
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	6,760,000	33	8,330,000	36	12,330,000	45
Natural gas options purchased, net	170,000	11	3,540,000	14	500,000	21
Natural gas basis swaps purchased	6,770,000	33	8,060,000	36	11,230,000	45
Natural gas over-the-counter swaps, net ^(b)	2,760,000	26	3,820,000	29	3,165,952	26
Natural gas physical contracts, net ^(c)	386,250	32	12,826,605	35	3,015,234	12

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of March 31, 2018, 675,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.


(c)	Volumes exclude contracts that qualify for the normal purchase, normal sales exception.

Derivative Instruments, Gain (Loss)



Three Months Ended March 31, 2018
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	Interest expense	$	(713	)	Interest expense	$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(621		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	(1,334	)		$	—



Three Months Ended March 31, 2017
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	Interest expense	$	(712	)	Interest expense	$	—
Commodity derivatives	Net (loss) from discontinued operations	229			Net (loss) from discontinued operations	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	58			Fuel, purchased power and cost of natural gas sold	—
Total		$	(425	)		$	—



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	90
Forward commodity contracts	(297		)	926
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			712
Forward commodity contracts	621			(287		)
Total other comprehensive income (loss) from hedging	$	1,037		$	1,441

Derivatives Not Designated as Hedge Instruments



		Three Months Ended March 31,
		2018		2017
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income		Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives	Net (loss) from discontinued operations	$	—	$	117
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	254		(809		)
		$	254	$	(692	)

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value Hierarchy, Measured on Recurring Basis

The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.



	As of March 31, 2018
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	414	$	—	$	(119	)	$	295
Total	$	—	$	414	$	—	$	(119	)	$	295

Liabilities:
Commodity derivatives — Utilities	$	—	$	12,259	$	—	$	(11,175	)	$	1,084
Total	$	—	$	12,259	$	—	$	(11,175	)	$	1,084



	As of December 31, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives —Utilities	$	—	$	1,586	$	—	$	(1,282	)	$	304
Total	$	—	$	1,586	$	—	$	(1,282	)	$	304

Liabilities:
Commodity derivatives — Utilities	$	—	$	13,756	$	—	$	(11,497	)	$	2,259
Total	$	—	$	13,756	$	—	$	(11,497	)	$	2,259



	As of March 31, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	2,642	$	—	$	(1,651	)	$	991
Total	$	—	$	2,642	$	—	$	(1,651	)	$	991

Liabilities:
Commodity derivatives — Utilities	$	—	$	13,139	$	—	$	(12,933	)	$	206
Total	$	—	$	13,139	$	—	$	(12,933	)	$	206

Schedule of Derivative Instruments Balance Sheet Location

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):



As of March 31, 2018
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative liabilities — current	$	—	$	394
Commodity derivatives	Other deferred credits and other liabilities	—		29
Total derivatives designated as hedges		$	—	$	423

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	295	$	—
Commodity derivatives	Derivative liabilities — current	—		497
Commodity derivatives	Other deferred credits and other liabilities	—		164
Total derivatives not designated as hedges		$	295	$	661



As of December 31, 2017
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative liabilities — current	$	—	$	817
Commodity derivatives	Other deferred credits and other liabilities	—		67
Total derivatives designated as hedges		$	—	$	884

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	304	$	—
Commodity derivatives	Derivative liabilities — current	—		1,264
Commodity derivatives	Other deferred credits and other liabilities	—		111
Total derivatives not designated as hedges		$	304	$	1,375



As of March 31, 2017
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	163	$	—
Commodity derivatives	Current assets held for sale	559		—
Commodity derivatives	Derivative liabilities — current	—		12
Commodity derivatives	Other deferred credits and other liabilities	—		26
Commodity derivatives	Current liabilities held for sale	—		293
Commodity derivatives	Noncurrent liabilities held for sale	—		45
Total derivatives designated as hedges		$	722	$	376

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	819	$	—
Commodity derivatives	Other assets, non—current	9		—
Commodity derivatives	Derivative liabilities — current	—		63
Commodity derivatives	Other deferred credits and other liabilities	—		105
Commodity derivatives	Current liabilities held for sale	—		96
Total derivatives not designated as hedges		$	828	$	264

Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 12, were as follows (in thousands) as of:



	March 31, 2018				December 31, 2017				March 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	30,947	$	30,947	$	15,420	$	15,420	$	11,291	$	11,291
Restricted cash ^(a)	$	2,958	$	2,958	$	2,820	$	2,820	$	2,409	$	2,409
Notes payable ^(b)	$	164,200	$	164,200	$	211,300	$	211,300	$	50,950	$	50,950
Long-term debt, including current maturities ^{(c) (d)}	$	3,114,530	$	3,265,965	$	3,115,143	$	3,350,544	$	3,216,473	$	3,388,809

__________


(a)	Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.


(b)	Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.


(c)	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.


(d)	Carrying amount of long-term debt is net of deferred financing costs.

Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2018

Statement of Comprehensive Income [Abstract]

Reclassification Out of Accumulated Other Comprehensive Income (Loss)



	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended
		March 31, 2018			March 31, 2017
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(712	)
Commodity contracts	Net (loss) from discontinued operations	—			229
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(621		)	58
		(1,334		)	(425		)
Income tax	Income tax benefit (expense)	297			143
Total reclassification adjustments related to cash flow hedges, net of tax		$	(1,037	)	$	(282	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	45		$	48

Actuarial gain (loss)	Operations and maintenance	(622		)	(414		)
		(577		)	(366		)
Income tax	Income tax benefit (expense)	126			137
Total reclassification adjustments related to defined benefit plans, net of tax		$	(451	)	$	(229	)
Total reclassifications		$	(1,488	)	$	(511	)

Schedule of Accumulated Other Comprehensive Income (Loss)

Balances by classification included within AOCI, net of tax on the accompanying Condensed 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, 2017	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)
Other comprehensive income (loss)
before reclassifications	—			(228		)	—			(228		)
Amounts reclassified from AOCI	561			476			451			1,488
Reclassifications of certain tax effects from AOCI	15			—			3			18
Ending Balance March 31, 2018	$	(19,005	)	$	(270	)	$	(20,649	)	$	(39,924	)


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
Balance as of December 31, 2016	$	(18,109	)	$	(233	)	$	(16,541	)	$	(34,883	)
Other comprehensive income (loss)
before reclassifications	58			584			—			642
Amounts reclassified from AOCI	463			(181		)	229			511
Ending Balance March 31, 2017	$	(17,588	)	$	170		$	(16,312	)	$	(33,730	)

Supplemental Disclosure of Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information



Three Months Ended	March 31, 2018			March 31, 2017
	(in thousands)
Non-cash investing and financing activities—
Property, plant and equipment acquired with accrued liabilities	$	21,708		$	26,532

Cash (paid) refunded during the period —
Interest (net of amounts capitalized)	$	(36,928	)	$	(36,418	)
Income taxes (paid) refunded	$	(14,336	)	$	13

Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2018

Defined Benefit Plan [Abstract]

Schedule of Net Benefit Costs

The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):



	Three Months Ended March 31,
	2018			2017
Service cost	$	1,708		$	1,758
Interest cost	3,867			3,880
Expected return on plan assets	(6,185		)	(6,129		)
Prior service cost	15			14
Net loss (gain)	2,158			1,002
Net periodic benefit cost	$	1,563		$	525

Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):



	Three Months Ended March 31,
	2018			2017
Service cost	$	573		$	575
Interest cost	521			533
Expected return on plan assets	(57		)	(79		)
Prior service cost (benefit)	(99		)	(109		)
Net loss (gain)	54			125
Net periodic benefit cost	$	992		$	1,045

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):



	Three Months Ended March 31,
	2018		2017
Service cost	$	280	$	827
Interest cost	293		319
Prior service cost	—		1
Net loss (gain)	250		250
Net periodic benefit cost	$	823	$	1,397

Schedule of Defined Benefit Plans Contributions

Contributions made in 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands):



	Contributions Made		Additional Contributions		Contributions
	Three Months Ended March 31, 2018		Anticipated for 2018		Anticipated for 2019
Defined Benefit Pension Plan	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,234	$	3,702	$	4,802
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	343	$	1,029	$	1,921

Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Balance Sheet Accounts

Held for sale assets and liabilities at March 31, 2017 are classified as current and non-current.



	As of
(in thousands)	March 31, 2018			December 31, 2017			March 31, 2017
Other current assets	$	4,332		$	10,360		$	9,112
Derivative assets, current and noncurrent	—			—			559
Deferred income tax assets, noncurrent, net	3,739			16,966			23,722
Property, plant and equipment, net	16,653			56,916			84,347
Other current liabilities	(17,233		)	(18,966		)	(7,589		)
Derivative liabilities, current and noncurrent	—			—			(434		)
Other noncurrent liabilities	(7,677		)	(22,808		)	(23,150		)
Net assets (liabilities)	$	(186	)	$	42,468		$	86,567

Disposal Groups, Including Discontinued Operations, Income Statement

Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):



	Three Months Ended March 31,
	2018			2017
	(in thousands)
Revenue	$	3,915		$	6,475

Operations and maintenance	5,901			7,205
Depreciation, depletion and amortization	1,300			1,945
Total operating expenses	7,201			9,150

Operating (loss)	(3,286		)	(2,675		)

Other income (expense), net	29			73
Income tax benefit (expense)	914			1,033

(Loss) from discontinued operations	$	(2,343	)	$	(1,569	)

Income Taxes (Tables)

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

The effective tax rate differs from the federal statutory rate as follows:



	Three Months Ended March 31,
Tax (benefit) expense	2018		2017
Federal statutory rate	21.0	%	35.0	%
State income tax (net of federal tax effect)	2.0		1.4
Percentage depletion in excess of cost	(0.2	)	(0.4	)
Noncontrolling interest	(0.7	)	(1.1	)
IRC 172(f) carryback claim ^(a)	—		(1.7	)
Tax credits	(1.3	)	(1.2	)
Effective tax rate adjustment	(2.1	)	(2.4	)
Flow-through adjustments	(0.4	)	—
TCJA change in estimate ^(b)	2.0		—
Tax benefit related to legal restructuring ^(c)	(43.7	)	—
Other tax differences	0.6		—
	(22.8	)%	29.6	%

__________

(a)


(b)	The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended March 31, 2018, certain estimated items associated with the revaluation have been updated.


(c)	Tax benefit from legal restructuring associated with amortizable goodwill as part of ongoing jurisdictional simplification.

Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Payables and Accruals [Abstract]

Schedule of Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2018		December 31, 2017		March 31, 2017
Accrued employee compensation, benefits and withholdings	$	46,262	$	52,467	$	46,410
Accrued property taxes	42,912		42,029		39,134
Customer deposits and prepayments	35,748		44,420		41,135
Accrued interest and contract adjustment payments	30,426		33,822		30,488
CIAC current portion	1,552		1,552		1,575
Other (none of which is individually significant)	37,140		45,172		37,834
Total accrued liabilities	$	194,040	$	219,462	$	196,576

Management's Statement (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Cumulative adoption adjustment to the opening balance of Retained earnings	$ 656,161,000	$ 548,617,000	$ 513,885,000
Accounting Standards Update 2014-09
Disaggregation of Revenue [Line Items]
Cumulative adoption adjustment to the opening balance of Retained earnings	$ 0

Management's Statement: Segment Reporting (Details)	May 04, 2018
Subsequent Event
Subsequent Event [Line Items]
Percent of Properties Having Either Closed Transactions or Signed Contracts to Sell	96.00%

Revenue: Significant Judgements and Estimates (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Revenue from Contract with Customer [Abstract]
Estimated and recorded revenue reduction from TCJA tax benefits	$ 15

Business Segment Information: Information Relating to Segment Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information
Revenue from contracts with customers	$ 573,355
Other revenues	2,034
Total revenues	575,389	$ 547,528
Net income (loss) from continuing operations	135,347	78,092
Deferred income taxes	(25,430)	41,213
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	3,630	3,623
Net tax benefit		1,400
Other Restructuring
Segment Reporting Information
Deferred income taxes	49,000
Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	(26,617)
Other revenues	(9,124)
Total revenues	(35,741)	(33,519)
Net income (loss) from continuing operations	0	0
Corporate
Segment Reporting Information
Net income (loss) from continuing operations	(958)	432
Consolidation, Eliminations
Segment Reporting Information
Revenue from contracts with customers	0
Other revenues	0
Total revenues		0
Electric Utilities
Segment Reporting Information
Revenue from contracts with customers	173,322
Other revenues	233
Total revenues	173,555	172,170
Net income (loss) from continuing operations	19,845	22,230
Electric Utilities \| Inter-company Revenues
Segment Reporting Information
Total revenues		3,854
Gas Utilities
Segment Reporting Information
Revenue from contracts with customers	396,160
Other revenues	1,184
Total revenues	397,344	364,901
Net income (loss) from continuing operations	107,620	46,010
Gas Utilities \| Inter-company Revenues
Segment Reporting Information
Total revenues		9
Power Generation
Segment Reporting Information
Revenue from contracts with customers	13,933
Other revenues	9,170
Total revenues	23,103	2,102
Net income (loss) from continuing operations	5,856	6,530
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	3,600	3,500
Power Generation \| Inter-company Revenues
Segment Reporting Information
Total revenues		21,465
Mining
Segment Reporting Information
Revenue from contracts with customers	16,557
Other revenues	571
Total revenues	17,128	8,355
Net income (loss) from continuing operations	2,984	2,890
Mining \| Inter-company Revenues
Segment Reporting Information
Total revenues		$ 8,191
External Operating Revenue
Segment Reporting Information
Revenue from contracts with customers	0
Other revenues	0
External Operating Revenue \| Electric Utilities
Segment Reporting Information
Revenue from contracts with customers	167,178
Other revenues	233
External Operating Revenue \| Gas Utilities
Segment Reporting Information
Revenue from contracts with customers	395,742
Other revenues	1,184
External Operating Revenue \| Power Generation
Segment Reporting Information
Revenue from contracts with customers	1,720
Other revenues	371
External Operating Revenue \| Mining
Segment Reporting Information
Revenue from contracts with customers	8,715
Other revenues	246
Inter-company Operating Revenue \| Electric Utilities \| Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	6,144
Other revenues	0
Inter-company Operating Revenue \| Gas Utilities \| Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	418
Other revenues	0
Inter-company Operating Revenue \| Power Generation \| Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	12,213
Other revenues	8,799
Inter-company Operating Revenue \| Mining \| Inter-company Revenues
Segment Reporting Information
Revenue from contracts with customers	7,842
Other revenues	$ 325

Business Segment Information: Segment and Corporate Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 6,626,989	$ 6,658,902	$ 6,499,571
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	194,193	115,612	113,143
Electric Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	2,890,708	2,906,275	2,872,989
Gas Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	3,398,473	3,426,466	3,260,989
Power Generation
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	53,323	60,852	69,737
Mining
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	65,568	65,455	64,973
Discontinued Operations, Held-for-sale
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 24,724	$ 84,242	$ 117,740

Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 168,031	$ 126,060	$ 143,356
Unbilled Receivables, Current	94,049	125,351	82,704
Allowance for Doubtful Accounts	(4,308)	(3,081)	(4,285)
Accounts receivable, net	257,772	248,330	221,775
Corporate
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,916	1,457	1,100
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	1,916	1,457	1,100
Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	40,492	39,347	39,679
Unbilled Receivables, Current	33,907	36,384	30,778
Allowance for Doubtful Accounts	(624)	(586)	(639)
Accounts receivable, net	73,775	75,145	69,818
Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	120,910	81,256	98,027
Unbilled Receivables, Current	60,142	88,967	51,926
Allowance for Doubtful Accounts	(3,684)	(2,495)	(3,646)
Accounts receivable, net	177,368	167,728	146,307
Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,580	1,196	1,353
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	1,580	1,196	1,353
Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,133	2,804	3,197
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	$ 3,133	$ 2,804	$ 3,197

Regulatory Accounting (Details) - USD ($) $ in Thousands	3 Months Ended
Regulatory Accounting (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Regulatory assets
Regulatory assets	$ 267,232	$ 297,454	$ 302,589
Less current regulatory assets	(54,492)	(81,016)	(53,476)
Regulatory assets, non-current	212,740	216,438	249,113
Regulatory liabilities
Regulatory liabilities	537,861	485,126	218,656
Less current regulatory liabilities	(42,499)	(6,832)	(22,118)
Regulatory liabilities, non-current	$ 495,362	478,294	196,538
Deferred energy and gas costs
Regulatory liabilities
Maximum Amortization (in years)	1 year
Regulatory liabilities	$ 20,194	3,427	19,494
Employee benefit plans
Regulatory liabilities
Maximum Amortization (in years)	12 years
Regulatory liabilities	$ 40,332	40,629	67,973
Cost of removal
Regulatory liabilities
Maximum Amortization (in years)	44 years
Regulatory liabilities	$ 139,002	130,932	122,548
Excess deferred income taxes
Regulatory liabilities
Maximum Amortization (in years)	40 years
Regulatory liabilities	$ 310,622	301,553	59
TCJA revenue reduction
Regulatory liabilities
Regulatory liabilities	$ 15,239	0	0
Other regulatory liabilities
Regulatory liabilities
Maximum Amortization (in years)	25 years
Regulatory liabilities	$ 12,472	8,585	8,582
Deferred energy and gas costs
Regulatory assets
Maximum Amortization (in years)	1 year
Regulatory assets	$ 25,056	20,187	23,756
Deferred gas cost adjustments
Regulatory assets
Maximum Amortization (in years)	1 year
Regulatory assets	$ 2,118	31,844	8,610
Gas price derivatives
Regulatory assets
Maximum Amortization (in years)	3 years
Regulatory assets	$ 11,045	11,935	11,520
Deferred taxes on AFUDC
Regulatory assets
Maximum Amortization (in years)	45 years
Regulatory assets	$ 7,808	7,847	14,976
Employee benefit plans
Regulatory assets
Maximum Amortization (in years)	12 years
Regulatory assets	$ 109,999	109,235	109,172
Environmental
Regulatory assets
Regulatory assets	$ 1,012	1,031	1,089
Asset retirement obligations
Regulatory assets
Maximum Amortization (in years)	44 years
Regulatory assets	$ 521	517	507
Loss on reacquired debt
Regulatory assets
Maximum Amortization (in years)	28 years
Regulatory assets	$ 20,267	20,667	21,866
Renewable energy standard adjustment
Regulatory assets
Regulatory assets	$ 1,600	1,088	963
Deferred taxes on flow through accounting
Regulatory assets
Maximum Amortization (in years)	54 years
Regulatory assets	$ 28,014	26,978	39,152
Decommissioning costs
Regulatory assets
Maximum Amortization (in years)	10 years
Regulatory assets	$ 12,552	13,287	15,745
Gas supply contract termination
Regulatory assets
Maximum Amortization (in years)	4 years
Regulatory assets	$ 18,590	20,001	24,178
Other regulatory assets
Regulatory assets
Maximum Amortization (in years)	30 years
Regulatory assets	$ 28,650	$ 32,837	$ 31,055

Regulatory Accounting: TCJA Revenue Reduction (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Regulatory Assets and Liabilities Disclosure [Abstract]
Estimated and recorded revenue reduction from TCJA tax benefits	$ 15

Regulatory Accounting: Rate Review (Details) - Colorado Public Utilities Commission (CPUC) - Black Hills Energy, Rocky Mountain Natural Gas $ in Millions	Mar. 02, 2018 USD ($)
Public Utilities, General Disclosures [Line Items]
Annual revenue increases and an extension of SSIR	$ 1.1
Return on equity	9.90%
Capital structure, equity	46.63%
Capital structure, debt	53.37%

Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Inventory, Net [Abstract]
Materials and supplies	$ 72,045	$ 69,732	$ 68,202
Fuel - Electric Utilities	2,903	2,962	3,433
Natural gas in storage held for distribution	7,097	40,589	9,228
Total materials, supplies and fuel	$ 82,045	$ 113,283	$ 80,863

Investments (Details) - USD ($) $ in Thousands	Feb. 28, 2018	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Investment [Line Items]
Total investments		$ 40,927	$ 13,090	$ 12,712
Cost method investment
Investment [Line Items]
Assets held for sale contributed in exchange for equity securities in a privately held company	$ 28,000
Total investments		28,100	0	0
Cash surrender value
Investment [Line Items]
Total investments		$ 12,827	$ 13,090	$ 12,712

Earnings Per Share Reconciliation (Details) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Net income available for common stock	$ 133,004	$ 76,523
Weighted average shares - basic (in shares)	53,319	53,152
Dilutive effect of:
Equity Units (in shares)	733	1,595
Equity compensation (in shares)	70	185
Weighted average shares - diluted (in shares)	54,122	54,932

Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	71	0
Equity compensation
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	71	0

Notes Payable and Current Maturities: Schedule of Short-term Debt and Narrative (Details)	3 Months Ended
	Mar. 31, 2018 USD ($) credit_extension	Dec. 31, 2017 USD ($)	Mar. 31, 2017 USD ($)
Short-term Debt [Line Items]
Notes payable	$ 164,200,000	$ 211,300,000	$ 50,950,000
Letters of Credit	15,830,000	26,848,000	28,100,000
Commercial paper, maximum borrowing capacity	750,000,000
Commercial Paper
Short-term Debt [Line Items]
Notes payable	$ 164,200,000	211,300,000	50,950,000
Debt term	397 days
Short-term interest rate	2.34%
Revolving Credit Facility
Short-term Debt [Line Items]
Notes payable	$ 0	0	0
Letters of Credit	15,830,000	$ 26,848,000	$ 28,100,000
Current borrowing capacity	$ 750,000,000
Number of extension options \| credit_extension	2
Debt term	1 year
Maximum borrowing capacity	$ 1,000,000,000
Commitment fee	0.20%
Revolving Credit Facility \| Base Rate
Short-term Debt [Line Items]
Interest rate	0.25%
Revolving Credit Facility \| Eurodollar
Short-term Debt [Line Items]
Interest rate	1.25%
Revolving Credit Facility \| Letter of Credit
Short-term Debt [Line Items]
Interest rate	1.25%

Notes Payable and Current Maturities: Debt Covenants (Details)	Mar. 31, 2018
Revolving Credit Facility
Line of Credit Facility [Line Items]
Recourse Leverage Ratio	59.00%
Debt instrument, covenant, Leverage Recourse Ratio	0.65
Maximum
Line of Credit Facility [Line Items]
Consolidated Indebtedness to Capitalization Ratio	0.65

Notes Payable and Current Maturities: Current Maturities (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Debt Instrument [Line Items]
Current maturities of long-term debt	$ 255,743	$ 5,743	$ 5,743
Corporate \| Black Hills Corporation \| Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Current maturities of long-term debt	250,000
Corporate \| Black Hills Corporation \| Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Current maturities of long-term debt	$ 5,700

Equity: Stockholders Equity Recap (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Equity, beginning balance	$ 1,820,206	$ 1,730,134
Net income (loss)	136,634	80,039
Other comprehensive income (loss)	1,260	1,153
Dividends on common stock	(25,444)	(23,754)
Share-based compensation	755	2,392
Issuance of common stock	0
Dividend reinvestment and stock purchase plan	219	748
Redeemable noncontrolling interest		(1,096)
Cumulative effect of ASU 2016-09 implementation		3,714
Other	2	(3)
Distribution to noncontrolling interest	(5,648)	(4,349)
Total Equity, ending balance	1,927,984	1,788,978
Total Stockholders’ Equity
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Equity, beginning balance	1,708,974	1,614,639
Net income (loss)	133,004	76,523
Other comprehensive income (loss)	1,260	1,153
Dividends on common stock	(25,444)	(23,754)
Share-based compensation	755	2,392
Issuance of common stock	0
Dividend reinvestment and stock purchase plan	219	748
Redeemable noncontrolling interest		(1,096)
Cumulative effect of ASU 2016-09 implementation		3,714
Other	2	(3)
Distribution to noncontrolling interest	0	0
Total Equity, ending balance	1,818,770	1,674,316
Noncontrolling Interest
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Equity, beginning balance	111,232	115,495
Net income (loss)	3,630	3,516
Other comprehensive income (loss)	0	0
Dividends on common stock	0	0
Share-based compensation	0	0
Issuance of common stock	0
Dividend reinvestment and stock purchase plan	0	0
Redeemable noncontrolling interest		0
Cumulative effect of ASU 2016-09 implementation		0
Other	0	0
Distribution to noncontrolling interest	(5,648)	(4,349)
Total Equity, ending balance	$ 109,214	$ 114,662

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions	Aug. 04, 2017	Jun. 30, 2017
Statement of Stockholders' Equity [Abstract]
At The Market Equity Offering Program Authorized Aggregate Value	$ 300	$ 200

Equity: Variable Interest Entities (Details) $ in Thousands		3 Months Ended
Equity: Variable Interest Entities (Details) $ in Thousands	Apr. 14, 2016	Mar. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)	Mar. 31, 2017 USD ($)
Current assets		$ 492,105	$ 570,782	$ 401,402
Property, plant and equipment of variable interest entities, net		5,608,539	5,567,518	5,337,031
Current liabilities		$ 788,564	649,101	391,542
Variable Interest Entity, Primary Beneficiary
Electric Generation Capacity, Megawatts \| MW		200
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Current assets		$ 12,567	14,837	12,167
Property, plant and equipment of variable interest entities, net		205,725	208,595	217,083
Current liabilities		$ 3,404	$ 4,565	$ 3,464

Risk Management Activities: Utilities (Details) - Natural Gas, Distribution $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018 USD ($) MMBTU	Mar. 31, 2017 MMBTU	Dec. 31, 2017 MMBTU
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months \| $	$ 0.4
Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,760,000	12,330,000	8,330,000
Derivative, Remaining Maturity	33 months	45 months	36 months
Commodity Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	170,000	500,000	3,540,000
Derivative, Remaining Maturity	11 months	21 months	14 months
Basis Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	6,770,000	11,230,000	8,060,000
Derivative, Remaining Maturity	33 months	45 months	36 months
Fixed for Float Swaps Purchased
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2,760,000	3,165,952	3,820,000
Derivative, Remaining Maturity	26 months	26 months	29 months
Natural Gas Physical Purchases
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	386,250	3,015,234	12,826,605
Derivative, Remaining Maturity	32 months	12 months	35 months
Cash Flow Hedging
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	675,000

Risk Management Activities: Financing Activities (Details) $ in Millions	1 Months Ended
	Jan. 31, 2017 USD ($)
Interest rate swaps
Derivative [Line Items]
Derivative Expired During the Period	$ 50

Risk Management Activities: Discontinued Operations (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale	Mar. 31, 2017 bbl MMBTU
Crude Oil \| Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	90,000
Crude Oil \| Options Held
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	27,000
Natural Gas \| Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount \| MMBTU	1,890,000

Risk Management Activities: Cash Flow Hedges (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0	$ 0
Cash Flow Hedging
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(1,334)	(425)
Cash Flow Hedging \| Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1,037	1,441
Cash Flow Hedging \| Interest rate swaps \| Designated as Hedging Instrument
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	713	712
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	0	90
Cash Flow Hedging \| Commodity Contract \| Designated as Hedging Instrument
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	621	(287)
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(297)	926
Interest Expense \| Interest rate swaps
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0
Interest Expense \| Cash Flow Hedging \| Interest rate swaps
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(713)	(712)
Sales Revenue, Net \| Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net		0
Sales Revenue, Net \| Cash Flow Hedging \| Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		229
Cost of Sales \| Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0
Cost of Sales \| Cash Flow Hedging \| Commodity Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (621)	$ 58

Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Derivative [Line Items]
Regulatory assets	$ 267,232	$ 302,589	$ 297,454
Price Risk Derivative
Derivative [Line Items]
Regulatory assets	11,045	11,520	$ 11,935
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	254	(692)
Not Designated as Hedging Instrument \| Sales Revenue, Net
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	117
Not Designated as Hedging Instrument \| Cost of Sales
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 254	$ (809)

Fair Value Measurements: Schedule of Fair Values (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
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	$ (119)	$ (1,282)	$ (1,651)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,175)	(11,497)	(12,933)
Utilities Group
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	(119)	(1,282)	(1,651)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,175)	(11,497)	(12,933)
Estimate of Fair Value Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	295	304	991
Derivative Liabilities, Total	1,084	2,259	206
Estimate of Fair Value Measurement \| Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	295	304	991
Derivative Liabilities, Fair Value Disclosure	1,084	2,259	206
Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Fair Value, Inputs, Level 1 \| Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	414	1,586	2,642
Derivative Liabilities, Total	12,259	13,756	13,139
Fair Value, Inputs, Level 2 \| Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	414	1,586	2,642
Derivative Liabilities, Fair Value Disclosure	12,259	13,756	13,139
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Fair Value, Inputs, Level 3 \| Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	$ 0	$ 0	$ 0

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 0	$ 0	$ 722
Derivative Liability, Fair Value, Net	423	884	376
Not Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	295	304	828
Derivative Liability, Fair Value, Net	661	1,375	264
Commodity Contract \| Designated as Hedging Instrument \| Derivative assets — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			163
Derivative Asset, Fair Value, Gross Liability			0
Commodity Contract \| Designated as Hedging Instrument \| Current assets held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			559
Derivative Asset, Fair Value, Gross Liability			0
Commodity Contract \| Designated as Hedging Instrument \| Derivative liabilities — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	394	817	12
Commodity Contract \| Designated as Hedging Instrument \| Other deferred credits and other liabilities
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	29	67	26
Commodity Contract \| Designated as Hedging Instrument \| Current liabilities held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset			0
Derivative Liability, Fair Value, Gross Liability			293
Commodity Contract \| Designated as Hedging Instrument \| Noncurrent liabilities held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset			0
Derivative Liability, Fair Value, Gross Liability			45
Commodity Contract \| Not Designated as Hedging Instrument \| Derivative assets — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	295	304	819
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract \| Not Designated as Hedging Instrument \| Other assets, non—current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			9
Derivative Asset, Fair Value, Gross Liability			0
Commodity Contract \| Not Designated as Hedging Instrument \| Derivative liabilities — current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	497	1,264	63
Commodity Contract \| Not Designated as Hedging Instrument \| Other deferred credits and other liabilities
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	$ 164	$ 111	105
Commodity Contract \| Not Designated as Hedging Instrument \| Current liabilities held for sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset			0
Derivative Liability, Fair Value, Gross Liability			$ 96

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 30,947	$ 15,420	$ 11,291
Restricted cash	2,958	2,820	2,409
Notes payable	164,200	211,300	50,950
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	30,947	15,420	11,291
Restricted cash	2,958	2,820	2,409
Notes payable	164,200	211,300	50,950
Long-term debt, including current maturities	3,114,530	3,115,143	3,216,473
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, Fair Value	30,947	15,420	11,291
Restricted Cash Fair Value Disclosure	2,958	2,820	2,409
Notes payable, Fair Value	164,200	211,300	50,950
Long-term debt, including current maturities, Fair Value	$ 3,265,965	$ 3,350,544	$ 3,388,809

Other Comprehensive Income (Loss): Reclassification Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$ 35,455	$ 35,058
Revenue	575,389	547,528
Fuel, purchased power and cost of natural gas sold	247,639	219,777
Operations and maintenance	116,096	114,552
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	113,175	116,103
Income tax benefit (expense)	25,802	(34,388)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	136,634	80,146
Reclassification Out Of Accumulated Other Comprehensive Income
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(1,488)	(511)
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(1,334)	(425)
Income tax benefit (expense)	297	143
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(1,037)	(282)
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges \| Interest Rate Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(713)	(712)
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges \| Commodity Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Revenue	0	229
Fuel, purchased power and cost of natural gas sold	(621)	58
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	45	48
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	(622)	(414)
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Defined Benefit Plans Adjustment
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(577)	(366)
Income tax benefit (expense)	126	137
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (451)	$ (229)

Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (41,202)	$ (34,883)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(39,924)	(33,730)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Interest Rate Swaps
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(19,581)	(18,109)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	58
Reclassification from AOCI, Current Period, Tax	15
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(19,005)	(17,588)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Interest Rate Swaps \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	561	463
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Commodity Contract
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(518)	(233)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(228)	584
Reclassification from AOCI, Current Period, Tax	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(270)	170
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Commodity Contract \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	476	(181)
Accumulated Defined Benefit Plans Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(21,103)	(16,541)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Reclassification from AOCI, Current Period, Tax	3
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(20,649)	(16,312)
Accumulated Defined Benefit Plans Adjustment \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	451	229
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(228)	642
Reclassification from AOCI, Current Period, Tax	18
AOCI Attributable to Parent \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 1,488	$ 511

Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 21,708	$ 26,532
Supplemental Cash Flow Elements [Abstract]
Interest (net of amounts capitalized)	(36,928)	(36,418)
Income taxes (paid) refunded	$ (14,336)	$ 13

Employee Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended
Employee Benefit Plans (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Pension Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 1,708	$ 1,758
Interest cost	3,867	3,880
Expected return on plan assets	(6,185)	(6,129)
Prior service cost (benefit)	15	14
Net loss (gain)	2,158	1,002
Net periodic benefit cost	1,563	525
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions by Employer	0
Estimated Future Employer Contributions in Current Fiscal Year	12,700
Estimated Future Employer Contributions in Next Fiscal Year	12,700
Defined Benefit Postretirement Healthcare Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	573	575
Interest cost	521	533
Expected return on plan assets	(57)	(79)
Prior service cost (benefit)	(99)	(109)
Net loss (gain)	54	125
Net periodic benefit cost	992	1,045
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions by Employer	1,234
Estimated Future Employer Contributions in Current Fiscal Year	3,702
Estimated Future Employer Contributions in Next Fiscal Year	4,802
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	280	827
Interest cost	293	319
Prior service cost (benefit)	0	1
Net loss (gain)	250	250
Net periodic benefit cost	823	$ 1,397
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions by Employer	343
Estimated Future Employer Contributions in Current Fiscal Year	1,029
Estimated Future Employer Contributions in Next Fiscal Year	$ 1,921

Commitments and Contingencies: Dividend Restrictions (Details) $ in Millions	Mar. 31, 2018 USD ($)
Utilities Group
Related Party Transaction [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Discontinued Operations: Oil and Gas Segment (Details)	May 04, 2018
Subsequent Event
Subsequent Event [Line Items]
Percent of Properties Having Either Closed Transactions or Signed Contracts to Sell	96.00%

Discontinued Operations: Impairment of Long-Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Discontinued Operations, Held-for-sale or Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Impairment Of Long-lived Assets (Net of Tax)	$ 0	$ 13

Discontinued Operations (Details) - USD ($) $ in Thousands	3 Months Ended
Discontinued Operations (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Other current assets	$ 4,332	$ 9,112	$ 10,360
Derivative assets, current and noncurrent	0	559	0
Deferred income tax assets, noncurrent, net	3,739	23,722	16,966
Property, plant and equipment, net	16,653	84,347	56,916
Other current liabilities	(17,233)	(7,589)	(18,966)
Derivative liabilities, current and noncurrent	0	(434)	0
Other noncurrent liabilities	(7,677)	(23,150)	(22,808)
Net liabilities	(186)
Net assets		86,567	$ 42,468
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue	3,915	6,475
Operations and maintenance	5,901	7,205
Depreciation, depletion and amortization	1,300	1,945
Total operating expenses	7,201	9,150
Operating (loss)	(3,286)	(2,675)
Other income (expense), net	29	73
Income tax benefit (expense)	914	1,033
(Loss) from discontinued operations	$ (2,343)	$ (1,569)

Income Taxes (Details)	3 Months Ended
Income Taxes (Details)	Mar. 31, 2018	Mar. 31, 2017
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate	21.00%	35.00%
State income tax (net of federal tax effect)	2.00%	1.40%
Percentage depletion in excess of cost	(0.20%)	(0.40%)
Noncontrolling interest	(0.70%)	(1.10%)
IRC 172(f) carryback claim	0.00%	(1.70%)
Tax credits	(1.30%)	(1.20%)
Effective tax rate adjustment	(2.10%)	(2.40%)
Flow-through adjustments	(0.40%)	0.00%
TCJA change in estimate	2.00%	0.00%
Tax benefit related to legal restructuring	(43.70%)	0.00%
Other tax differences	0.60%	0.00%
Effective Tax Rate	(22.80%)	29.60%

Income Taxes: Tax Benefit Related to Legal Restructuing (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Deferred Tax Assets, Goodwill and Intangible Assets	$ 49,000
Deferred income taxes	(25,430)	$ 41,213
Other Restructuring
Deferred income taxes	$ 49,000

Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Payables and Accruals [Abstract]
Accrued employee compensation, benefits and withholdings	$ 46,262	$ 52,467	$ 46,410
Accrued property taxes	42,912	42,029	39,134
Customer deposits and prepayments	35,748	44,420	41,135
Accrued interest and contract adjustment payments	30,426	33,822	30,488
CIAC current portion	1,552	1,552	1,575
Other (none of which is individually significant)	37,140	45,172	37,834
Total accrued liabilities	$ 194,040	$ 219,462	$ 196,576

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
Revenue (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 573,355
Other revenues	2,034
Total revenues	575,389	$ 547,528
Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	497,166
Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	41,260
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	10,770
Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,049
Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	22,110
Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	8,715
Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	564,640
Inter-company Revenues
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(26,617)
Other revenues	(9,124)
Total revenues	(35,741)	(33,519)
Inter-company Revenues \| Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(7,842)
Inter-company Revenues \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(409)
Inter-company Revenues \| Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(12,213)
Inter-company Revenues \| Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(2,522)
Inter-company Revenues \| Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(3,631)
Inter-company Revenues \| Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(7,842)
Inter-company Revenues \| Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(18,775)
Electric Utilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	173,322
Other revenues	233
Total revenues	173,555	172,170
Electric Utilities \| Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	147,057
Electric Utilities \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Electric Utilities \| Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	9,050
Electric Utilities \| Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4,144
Electric Utilities \| Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	13,071
Electric Utilities \| Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Electric Utilities \| Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	173,322
Electric Utilities \| Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		3,854
Gas Utilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	396,160
Other revenues	1,184
Total revenues	397,344	364,901
Gas Utilities \| Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	341,394
Gas Utilities \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	41,669
Gas Utilities \| Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Gas Utilities \| Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	427
Gas Utilities \| Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	12,670
Gas Utilities \| Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Gas Utilities \| Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	396,160
Gas Utilities \| Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		9
Power Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	13,933
Other revenues	9,170
Total revenues	23,103	2,102
Power Generation \| Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Power Generation \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Power Generation \| Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	13,933
Power Generation \| Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Power Generation \| Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Power Generation \| Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Power Generation \| Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	13,933
Power Generation \| Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		21,465
Mining
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	16,557
Other revenues	571
Total revenues	17,128	8,355
Mining \| Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	16,557
Mining \| Transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Mining \| Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Mining \| Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Mining \| Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Mining \| Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	16,557
Mining \| Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 0
Mining \| Inter-company Revenues
Disaggregation of Revenue [Line Items]
Total revenues		$ 8,191