Edgar Filing: BLACK HILLS CORP /SD/

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2018
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________.

	Commission File Number 001-31303



Black Hills Corporation
Incorporated in South Dakota	IRS Identification Number 46-0458824
7001 Mount Rushmore Road
Rapid City, South Dakota 57702
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.



	Yes x		No o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).



	Yes x		No o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x		Accelerated filer o

Non-accelerated filer o	(Do not check if a smaller reporting company)

		Smaller reporting company o

		Emerging growth company o

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



	Yes o		No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.



Class	Outstanding at April 30, 2018
Common stock, $1.00 par value	53,592,446	shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	5

Item 1.	Financial Statements	5

	Condensed Consolidated Statements of Income - unaudited
	Three Months Ended March 31, 2018 and 2017	5

	Condensed Consolidated Statements of Comprehensive Income - unaudited
	Three Months Ended March 31, 2018 and 2017	6

	Condensed Consolidated Balance Sheets - unaudited
	March 31, 2018, December 31, 2017 and March 31, 2017	7

	Condensed Consolidated Statements of Cash Flows - unaudited
	Three Months Ended March 31, 2018 and 2017	9

	Notes to Condensed Consolidated Financial Statements - unaudited	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	56

Item 4.	Controls and Procedures	56

PART II.	OTHER INFORMATION	57

Item 1.	Legal Proceedings	57

Item 1A.	Risk Factors	57

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57

Item 4.	Mine Safety Disclosures	57

Item 5.	Other Information	57

Item 6.	Exhibits	58

	Signatures	60

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
Arkansas Gas	Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
ASC	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
ATM	At-the-market equity offering program
Availability	The availability factor of a power plant is the percentage of the time that it is available to provide energy.
Bbl	Barrel
BHC	Black Hills Corporation; the Company
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility companies
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
CAPP	Customer Appliance Protection Plan
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
CIAC	Contribution In Aid of Construction
City of Gillette	Gillette, Wyoming
Colorado Electric	Black Hills Colorado Electric Utility Company, LP, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado IPP	Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Consolidated Indebtedness to Capitalization Ratio	Any Indebtedness outstanding at such time, divided by Capital at such time. Capital being Consolidated Net-Worth (excluding noncontrolling interest and including the aggregate outstanding amount of RSNs) plus Consolidated Indebtedness (including letters of credit, certain guarantees issued and excluding RSNs) as defined within the current Credit Agreement.
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
CP Program	Commercial Paper Program
CPUC	Colorado Public Utilities Commission
CVA	Credit Valuation Adjustment
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Equity Unit	Each Equity Unit has a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs due 2028.
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America



Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
IPP	Independent power producer
IRS	United States Internal Revenue Service
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
LIBOR	London Interbank Offered Rate
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MWh	Megawatt-hours
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Peak View Wind Project	$109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm
PPA	Power Purchase Agreement
Revolving Credit Facility	Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2021.
RMNG	Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy)
RSNs	Remarketable junior subordinated notes, issued on November 23, 2015
SEC	U. S. Securities and Exchange Commission
SourceGas	SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas Acquisition	The acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings
S&P	Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
SSIR	System Safety and Integrity Rider
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017
VIE	Variable interest entity
Winter Storm Atlas	An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by Pacificorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	Includes Cheyenne Light’s electric utility operations

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



(unaudited)	Three Months Ended March 31,
	2018			2017
	(in thousands, except per share amounts)

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

Other income (expense):
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
(Loss) from discontinued operations, net of tax	(2,343		)	(1,569		)
Net income	136,634			80,146
Net income attributable to noncontrolling interest	(3,630		)	(3,623		)
Net income available for common stock	$	133,004		$	76,523

Amounts attributable to common shareholders:
Net income from continuing operations	135,347			78,092
Net (loss) from discontinued operations	(2,343		)	(1,569		)
Net income (loss) available for common stock	$	133,004		$	76,523

Earnings per share of common stock:
Earnings (loss) per share, Basic -
Income from continuing operations, per share	$	2.54		$	1.47
(Loss) from discontinued operations, per share	(0.05		)	(0.03		)
Earnings per share, Basic	$	2.49		$	1.44

Earnings (loss) per share, Diluted -
Income from continuing operations, per share	$	2.50		$	1.42
(Loss) from discontinued operations, per share	(0.04		)	(0.03		)
Earnings per share, Diluted	$	2.46		$	1.39
Weighted average common shares outstanding:
Basic	53,319			53,152
Diluted	54,122			54,932

Dividends declared per share of common stock	$	0.475		$	0.445

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



(unaudited)	Three Months Ended March 31,
	2018			2017
	(in thousands)

Net income	$	136,634		$	80,146

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax benefit of $10 and $17 for the three months ended March 31, 2018 and 2017, respectively)	(35		)	(31		)
Reclassification adjustments of benefit plan liability - net gain (net of tax expense of $(136) and $(154) for the three months ended March 31, 2018 and 2017, respectively)	486			260
Derivative instruments designated as cash flow hedges:
Net unrealized gains (losses) on interest rate swaps (net of tax of $0 and $(32) for the three months ended March 31, 2018 and 2017, respectively)	—			58
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(152) and $(249) for the three months ended March 31, 2018 and 2017, respectively)	561			463
Net unrealized gains (losses) on commodity derivatives (net of tax of $69 and $(342) for the three months ended March 31, 2018 and 2017, respectively)	(228		)	584
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(145) and $106 for the three months ended March 31, 2018 and 2017, respectively)	476			(181		)
Other comprehensive income, 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

See Note 14 for additional disclosures.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



(unaudited)	As of
	March 31, 2018			December 31, 2017			March 31, 2017
	(in thousands)
ASSETS
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			—			—
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	—			—			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

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)



(unaudited)	As of
	March 31, 2018			December 31, 2017			March 31, 2017
	(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
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	—			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	—			—			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:
Stockholders’ 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

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



(unaudited)	Three Months Ended March 31,
	2018			2017
Operating activities:	(in thousands)
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		)	—
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

See Note 15 for supplemental disclosure of cash flow information.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2017 Annual Report on Form 10-K)

(1) 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.

(2) 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.

(3) 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.

(4) 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

(5) 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.

(6) 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

(7) 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

(8) 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	—

(9) 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.

(10) 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

(11) 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.

(12) 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.