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 June 30, 2017
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
625 Ninth Street
Rapid City, South Dakota 57701
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 July 31, 2017
Common stock, $1.00 par value	53,475,190	shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	6

Item 1.	Financial Statements	6

	Condensed Consolidated Statements of Income - unaudited
	Three and Six Months Ended June 30, 2017 and 2016	6

	Condensed Consolidated Statements of Comprehensive Income - unaudited
	Three and Six Months Ended June 30, 2017 and 2016	7

	Condensed Consolidated Balance Sheets - unaudited
	June 30, 2017, December 31, 2016 and June 30, 2016	8

	Condensed Consolidated Statements of Cash Flows - unaudited
	Six Months Ended June 30, 2017 and 2016	10

	Notes to Condensed Consolidated Financial Statements - unaudited	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	74

Item 4.	Controls and Procedures	75

PART II.	OTHER INFORMATION	76

Item 1.	Legal Proceedings	76

Item 1A.	Risk Factors	76

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	76

Item 4.	Mine Safety Disclosures	76

Item 5.	Other Information	76

Item 6.	Exhibits	77

	Signatures	79

	Index to Exhibits	80

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)
APSC	Arkansas Public Service Commission
Arkansas Gas	Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
Stockton Storage	Arkansas Gas storage facility
ARMRP	At-Risk Meter Relocation Program
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 Gas	Black Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC
Black Hills Gas Holdings	Black Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC
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 Energy Arkansas Gas	Includes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations
Black Hills Energy Colorado Electric	Includes Colorado Electric’s utility operations
Black Hills Energy Colorado Gas	Includes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado gas operations and RMNG
Black Hills Energy Iowa Gas	Includes Black Hills Energy Iowa gas utility operations
Black Hills Energy Kansas Gas	Includes Black Hills Energy Kansas gas utility operations
Black Hills Energy Nebraska Gas	Includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations
Black Hills Energy South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
Black Hills Energy Wyoming Electric	Includes Cheyenne Light’s electric utility operations
Black Hills Energy Wyoming Gas	Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Black Hills Gas Distribution	Black Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Colorado, Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC.
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
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
Btu	British thermal unit
CAPP	Customer Appliance Protection Plan



Ceiling Test	Related to our Oil and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using prices and a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.
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 Gas	Black Hills Colorado Gas 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.
Cost of Service Gas Program (COSG)	Proposed Cost of Service Gas Program designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.
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
DSM	Demand Side Management
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
ECA	Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
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
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
GSRS	Gas System Reliability Surcharge
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.
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
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)
KCC	Kansas Corporation Commission
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	Thousand cubic feet
Mcfe	Thousand cubic feet equivalent
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MRP	Meter Relocation Program
MW	Megawatts
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)
NGL	Natural Gas Liquids (1 barrel equals 6 Mcfe)
NOL	Net Operating Loss
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
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
SDPUC	South Dakota Public Utilities Commission
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
SourceGas Transaction	On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing.
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
TCA	Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
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.
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is 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
Wyoming Gas	Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands, except per share amounts)

Revenue	$	347,978		$	325,441		$	901,981		$	775,400

Operating expenses:
Fuel, purchased power and cost of natural gas sold	98,164			84,489			317,941			256,345
Operations and maintenance	117,374			112,541			239,504			219,603
Depreciation, depletion and amortization	48,663			47,305			97,310			91,712
Taxes - property, production and severance	13,743			12,760			27,712			24,877
Impairment of long-lived assets	—			25,497			—			39,993
Other operating expenses	1,168			7,551			3,137			33,982
Total operating expenses	279,112			290,143			685,604			666,512

Operating income	68,866			35,298			216,377			108,888

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(35,098		)	(34,609		)	(70,194		)	(66,683		)
Allowance for funds used during construction - borrowed	822			754			1,308			1,255
Capitalized interest	130			268			299			503
Interest income	257			946			298			1,601
Allowance for funds used during construction - equity	794			982			1,286			1,689
Other income (expense), net	(58		)	(47		)	(160		)	641
Total other income (expense), net	(33,153		)	(31,706		)	(67,163		)	(60,994		)

Income before income taxes	35,713			3,592			149,214			47,894
Income tax benefit (expense)	(10,402		)	(309		)	(43,757		)	(4,561		)
Net income	25,311			3,283			105,457			43,333
Net income attributable to noncontrolling interest	(3,116		)	(2,614		)	(6,739		)	(2,662		)
Net income available for common stock	$	22,195		$	669		$	98,718		$	40,671

Earnings per share of common stock:
Earnings per share, Basic	$	0.42		$	0.01		$	1.86		$	0.79
Earnings per share, Diluted	$	0.40		$	0.01		$	1.79		$	0.78
Weighted average common shares outstanding:
Basic	53,229			51,514			53,191			51,279
Diluted	55,384			52,986			55,179			52,454

Dividends declared per share of common stock	$	0.445		$	0.420		$	0.890		$	0.840

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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)

Net income (loss)	$	25,311		$	3,283		$	105,457		$	43,333

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $18 and $19 for the three months ended June 30, 2017 and 2016 and $35 and $38 for the six months ended June 30, 2017 and 2016, respectively)	(31		)	(36		)	(62		)	(72		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(146) and $(173) for the three months ended June 30, 2017 and 2016 and $(300) and $(346) for the six months ended June 30, 2017 and 2016, respectively)	268			321			528			643
Derivative instruments designated as cash flow hedges:
Net unrealized gains (losses) on interest rate swaps (net of tax of $0 and $4,440 for the three months ended June 30, 2017 and 2016 and $0 and $10,767 for the six months ended June 30, 2017 and 2016, respectively)	—			(8,174		)	—			(19,898		)
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(249) and $(294) for the three months ended June 30, 2017 and 2016 and $(530) and $(592) for the six months ended June 30, 2017 and 2016, respectively)	464			546			985			1,098
Net unrealized gains (losses) on commodity derivatives (net of tax of $(194) and $906 for the three months ended June 30, 2017 and 2016 and $(536) and $98 for the six months ended June 30, 2017 and 2016, respectively)	331			(1,546		)	915			(168		)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $143 and $1,176 for the three months ended June 30, 2017 and 2016 and $249 and $2,476 for the six months ended June 30, 2017 and 2016, respectively)	(243		)	(2,050		)	(424		)	(4,312		)
Other comprehensive income (loss), net of tax	789			(10,939		)	1,942			(22,709		)

Comprehensive income (loss)	26,100			(7,656		)	107,399			20,624
Less: comprehensive income attributable to noncontrolling interest	(3,116		)	(2,614		)	(6,739		)	(2,662		)
Comprehensive income (loss) available for common stock	$	22,984		$	(10,270	)	$	100,660		$	17,962

See Note 13 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
	June 30, 2017			December 31, 2016			June 30, 2016
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	11,590		$	13,580		$	61,859
Restricted cash and equivalents	2,534			2,274			1,975
Accounts receivable, net	169,957			263,289			150,227
Materials, supplies and fuel	99,126			107,210			85,189
Derivative assets, current	1,148			4,138			4,030
Regulatory assets, current	53,061			49,260			54,856
Other current assets	21,840			27,063			30,652
Total current assets	359,256			466,814			388,788

Investments	12,761			12,561			12,363

Property, plant and equipment	6,533,581			6,412,223			6,209,816
Less: accumulated depreciation and depletion	(1,981,880		)	(1,943,234		)	(1,819,886		)
Total property, plant and equipment, net	4,551,701			4,468,989			4,389,930

Other assets:
Goodwill	1,299,454			1,299,454			1,303,453
Intangible assets, net	7,972			8,392			9,164
Regulatory assets, non-current	244,099			246,882			220,556
Derivative assets, non-current	37			222			226
Other assets, non-current	13,812			12,130			15,438
Total other assets, non-current	1,565,374			1,567,080			1,548,837

TOTAL ASSETS	$	6,489,092		$	6,515,444		$	6,339,918

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
	June 30, 2017			December 31, 2016			June 30, 2016
	(in thousands, except share amounts)
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
Current liabilities:
Accounts payable	$	99,970		$	153,477		$	115,203
Accrued liabilities	201,993			244,034			218,250
Derivative liabilities, current	719			2,459			28,855
Accrued income taxes, net	5,160			12,552			10,624
Regulatory liabilities, current	17,305			13,067			34,275
Notes payable	107,975			96,600			75,000
Current maturities of long-term debt	5,743			5,743			930,743
Total current liabilities	438,865			527,932			1,412,950

Long-term debt	3,160,302			3,211,189			2,221,347

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	589,189			535,606			530,746
Derivative liabilities, non-current	88			274			231
Regulatory liabilities, non-current	199,005			193,689			195,166
Benefit plan liabilities	176,102			173,682			173,347
Other deferred credits and other liabilities	135,510			138,643			122,015
Total deferred credits and other liabilities	1,099,894			1,041,894			1,021,505

Commitments and contingencies (See Notes 8, 10, 15, 16)

Redeemable noncontrolling interest	—			4,295			4,171

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 53,513,521; 53,397,467; and 52,299,075 shares, respectively	53,514			53,397			52,299
Additional paid-in capital	1,145,493			1,138,982			1,072,927
Retained earnings	512,498			457,934			469,940
Treasury stock, at cost – 39,329; 15,258; and 18,900 shares, respectively	(2,325		)	(791		)	(975		)
Accumulated other comprehensive income (loss)	(32,941		)	(34,883		)	(31,764		)
Total stockholders’ equity	1,676,239			1,614,639			1,562,427
Noncontrolling interest	113,792			115,495			117,518
Total equity	1,790,031			1,730,134			1,679,945

TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY	$	6,489,092		$	6,515,444		$	6,339,918

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)	Six Months Ended June 30,
	2017			2016
Operating activities:	(in thousands)
Net income (loss)	$	105,457		$	40,671
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	97,310			91,712
Deferred financing cost amortization	4,138			2,857
Impairment of long-lived assets	—			39,993
Stock compensation	6,589			7,054
Deferred income taxes	51,153			32,606
Employee benefit plans	5,717			7,782
Other adjustments, net	(6,515		)	(6,332		)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	7,720			17,722
Accounts receivable, unbilled revenues and other operating assets	97,902			82,361
Accounts payable and other operating liabilities	(113,541		)	(124,695		)
Regulatory assets - current	3,086			1,862
Regulatory liabilities - current	5,908			2,994
Contributions to defined benefit pension plans	—			(10,200		)
Other operating activities, net	(2,055		)	(2,884		)
Net cash provided by (used in) operating activities	262,869			183,503

Investing activities:
Property, plant and equipment additions	(163,768		)	(199,854		)
Acquisition, net of long term debt assumed	—			(1,124,238		)
Other investing activities	(22		)	(649		)
Net cash provided by (used in) investing activities	(163,790		)	(1,324,741		)

Financing activities:
Dividends paid on common stock	(47,544		)	(43,265		)
Common stock issued	2,965			57,490
Sale of noncontrolling interest	—			216,370
Net (payments) borrowings of short-term debt	11,375			(1,800		)
Long-term debt - issuances	—			574,672
Long-term debt - repayments	(52,871		)	(41,436		)
Distributions to noncontrolling interest	(8,335		)	—
Other financing activities	(6,659		)	205
Net cash provided by (used in) financing activities	(101,069		)	762,236
Net change in cash and cash equivalents	(1,990		)	(379,002		)
Cash and cash equivalents, beginning of period	13,580			440,861
Cash and cash equivalents, end of period	$	11,590		$	61,859

See Note 14 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 2016 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 2016 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, Mining and Oil and Gas. 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.

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 June 30, 2017, December 31, 2016, and June 30, 2016 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 and six months ended June 30, 2017 and June 30, 2016, and our financial condition as of June 30, 2017, December 31, 2016, and June 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. June 30, 2017 reflects a full six months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the six months ended June 30, 2016 which reflects a partial period of approximately 4.5 months. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Revisions

Certain revisions have been made to prior years’ financial information to conform to the current year presentation.

The Company revised its presentation of cash as of December 31, 2016. The Company has banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $55 million as of June 30, 2016, and decreased net cash flows provided by operations by $39 million for the six months ended June 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the condensed consolidated balance sheet as of June 30, 2016 and to the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Condensed Consolidated Statements of Income or the Condensed Consolidated Statements of Comprehensive Income for any period reported.

Recently Issued and Adopted Accounting Standards

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

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require 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. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.

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

In August 2016, the FASB issued 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. The ASU will be effective for fiscal years beginning after December 15, 2017. We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows.

Improvements to Employee Share-Based Payment Accounting, ASU 2016-09

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment to retained earnings as of the date of adoption of $3.2 million in the Condensed Consolidated Balance Sheets, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows.

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 all leases with a term greater than 12 months, 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. 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.

We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, pole attachments and other industry-related areas. We also expect to implement changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

(2) ACQUISITION

2016 Acquisition of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas (now referred to as Black Hills Gas Holdings). We acquired SourceGas for $1.1 billion of cash plus the assumption of $760 million of long-term debt. We finalized our purchase price allocation at December 31, 2016. See Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details.

Pro Forma Results

The following unaudited pro forma financial information reflects the consolidated results of operations as if the SourceGas Acquisition had taken place on January 1, 2015. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results.

The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three and six months ended June 30, 2016 exclude approximately $4.0 million and $20 million, respectively, of after-tax transaction costs, professional fees, employee related expenses and other miscellaneous costs.



	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016
	(in thousands, except per share amounts)
Revenue	$	325,441	$	854,362
Net income (loss) available for common stock	$	4,658	$	72,978
Earnings (loss) per share, Basic	$	0.09	$	1.42
Earnings (loss) per share, Diluted	$	0.09	$	1.39

Redemption of seller’s noncontrolling interest

As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with the holder of the 0.5% retained interest. The terms of the agreement provided us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas Transaction. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million.

(3) BUSINESS SEGMENT INFORMATION

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



Three Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	165,517	$	2,936		$	18,832
Gas	166,439		8			(272		)
Power Generation ^(b)	1,470		20,325			5,332
Mining	8,403		6,543			2,681
Oil and Gas	6,149		—			(1,946		)
Corporate activities ^(c)	—		—			(2,432		)
Inter-company eliminations	—		(29,812		)	—
Total	$	347,978	$	—		$	22,195



Three Months Ended June 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric^.	$	158,560	$	2,921		$	19,229
Gas	153,767		(1,806		)	987
Power Generation ^(b)	1,546		20,168			5,683
Mining	3,922		7,125			724
Oil and Gas ^(e)	7,646		—			(19,424		)
Corporate activities ^(c)	—		—			(6,530		)
Inter-company eliminations	—		(28,408		)	—
Total	$	325,441	$	—		$	669




Six Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	337,687	$	6,790		$	41,062
Gas ^(a)	531,340		17			45,738
Power Generation ^(b)	3,572		41,790			11,862
Mining	16,758		14,734			5,571
Oil and Gas	12,624		—			(4,897		)
Corporate activities ^(c)(d)	—		—			(618		)
Inter-company eliminations	—		(63,331		)	—
Total	$	901,981	$	—		$	98,718




Six Months Ended June 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	322,091	$	6,666		$	38,444
Gas ^(a)	422,434		—			32,914
Power Generation ^(b)	3,398		41,624			14,265
Mining	11,456		15,873			3,662
Oil and Gas ^(e)	16,021		—			(26,448		)
Corporate activities ^(c)(d)	—		—			(22,166		)
Inter-company eliminations	—		(64,163		)	—
Total	$	775,400	$	—		$	40,671

___________


(a)	Gas Utility revenue increased for the six months ended June 30, 2017 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016.


(b)	Net income (loss) available for common stock for the three and six months ended June 30, 2017 was net of net income attributable to noncontrolling interests of $3.1 million and $6.6 million, respectively, and $2.6 million for both the three and six months ended June 30, 2016.

(c)

Net income (loss) available for common stock for the three and six months ended June 30, 2017 and June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.3 million and $1.2 million, and $4.1 million and $20 million respectively. The three and six months ended June 30, 2016 also included $2.0 million and $5.7 million, respectively, of after-tax internal labor costs attributable to the acquisition.

(d)

Net income (loss) available for common stock for the six months ended June 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. Net income (loss) available for common stock for the six months ended June 30, 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. See Note 18.


(e)	Net income (loss) available for common stock for the three and six months ended June 30, 2016 included non-cash after-tax impairments of oil and gas properties of $16 million and $25 million. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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:	June 30, 2017		December 31, 2016		June 30, 2016
Segment:
Electric ^(a)	$	2,901,570	$	2,859,559	$	2,755,695
Gas	3,242,461		3,307,967		3,118,626
Power Generation ^(a)	66,292		73,445		80,360
Mining	67,365		67,347		71,319
Oil and Gas ^(b)	103,044		96,435		171,239
Corporate activities	108,360		110,691		142,679
Total assets	$	6,489,092	$	6,515,444	$	6,339,918

__________


(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.


(b)	As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $107 million for the year ended December 31, 2016 and $40 million for the six months ended June 30, 2016. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(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
June 30, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	41,635	$	33,686	$	(466	)	$	74,855
Gas Utilities	62,908		26,584		(2,535		)	86,957
Power Generation	877		—		—			877
Mining	2,904		—		—			2,904
Oil and Gas	3,280		—		(83		)	3,197
Corporate	1,167		—		—			1,167
Total	$	112,771	$	60,270	$	(3,084	)	$	169,957



	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2016	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	41,730	$	36,463	$	(353	)	$	77,840
Gas Utilities	88,168		88,329		(2,026		)	174,471
Power Generation	1,420		—		—			1,420
Mining	3,352		—		—			3,352
Oil and Gas	3,991		—		(13		)	3,978
Corporate	2,228		—		—			2,228
Total	$	140,889	$	124,792	$	(2,392	)	$	263,289



	Accounts		Unbilled		Less Allowance for			Accounts
June 30, 2016	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	40,991	$	34,174	$	(716	)	$	74,449
Gas Utilities	47,600		23,124		(2,997		)	67,727
Power Generation	1,229		—		—			1,229
Mining	1,114		—		—			1,114
Oil and Gas	3,094		—		(13		)	3,081
Corporate	2,627		—		—			2,627
Total	$	96,655	$	57,298	$	(3,726	)	$	150,227

(5) REGULATORY ACCOUNTING

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



	Maximum	As of		As of		As of
	Amortization	June 30, 2017		December 31, 2016		June 30, 2016
	(in years)
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)(d)	1	$	20,761	$	17,491	$	20,603
Deferred gas cost adjustments ^(a)(d)	1	9,060		15,329		12,122
Gas price derivatives ^(a)	3.5	11,159		8,843		11,515
Deferred taxes on AFUDC^(b)	45	15,322		15,227		13,879
Employee benefit plans ^(c)	12	107,419		108,556		109,522
Environmental^(a)	subject to approval	1,070		1,108		1,144
Asset retirement obligations^(a)	44	510		505		505
Loss on reacquired debt^(a)	30	21,466		22,266		3,061
Renewable energy standard adjustment ^(b)	5	768		1,605		2,679
Deferred taxes on flow through accounting^(c)	35	40,586		37,498		31,554
Decommissioning costs ^(e)	6	14,681		16,859		18,399
Gas supply contract termination	5	22,793		26,666		28,385
Other regulatory assets^{(a) (e)}	15	31,565		24,189		22,044
		$	297,160	$	296,142	$	275,412

Regulatory liabilities
Deferred energy and gas costs^{(a) (d)}	1	$	16,767	$	10,368	$	32,868
Employee benefit plan costs and related deferred taxes^(c)	12	67,297		68,654		62,712
Cost of removal^(a)	44	125,247		118,410		126,002
Revenue subject to refund	1	1,518		2,485		1,616
Other regulatory liabilities^(c)	25	5,481		6,839		6,243
		$	216,310	$	206,756	$	229,441

__________


(a)	We are allowed 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)

Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

(e)

In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million will be amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

(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:



	June 30, 2017		December 31, 2016		June 30, 2016
Materials and supplies	$	72,397	$	68,456	$	67,440
Fuel - Electric Utilities	3,106		3,667		4,659
Natural gas in storage held for distribution	23,623		35,087		13,090
Total materials, supplies and fuel	$	99,126	$	107,210	$	85,189

(7) 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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016

Net income (loss) available for common stock	$	22,195	$	669	$	98,718	$	40,671

Weighted average shares - basic	53,229		51,514		53,191		51,279
Dilutive effect of:
Equity Units ^(a)	1,977		1,362		1,796		1,068
Equity compensation	178		110		192		107
Weighted average shares - diluted	55,384		52,986		55,179		52,454

__________


(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 June 30,		Six Months Ended June 30,
	2017	2016	2017	2016

Equity compensation	—	4	—	10
Anti-dilutive shares	—	4	—	10

(8) NOTES PAYABLE AND LONG-TERM DEBT

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



	June 30, 2017				December 31, 2016				June 30, 2016
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	24,540	$	96,600	$	36,000	$	75,000	$	24,700
CP Program	107,975		—		—		—		—		—
Total	$	107,975	$	24,540	$	96,600	$	36,000	$	75,000	$	24,700

Revolving Credit Facility and CP Program

On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one-year extension options (subject to consent from lenders). This facility is similar to the former agreement, which 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 continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our 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 June 30, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

On December 22, 2016, we implemented 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 six months ended June 30, 2017 and our notes outstanding as of June 30, 2017 were $108 million. As of June 30, 2017, the weighted average interest rate on CP Program borrowings was 1.41%.

Debt Covenants

On December 7, 2016, we amended our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated 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 our Term Loans require compliance with the following financial covenant at the end of each quarter:



	As of June 30, 2017	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	61%	Less than	65%

As of June 30, 2017, we were in compliance with this covenant.

Long-Term Debt

On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan.

(9) EQUITY

A summary of the changes in equity is as follows:



Six Months Ended June 30, 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)	98,718			6,632			105,350
Other comprehensive income (loss)	1,942			—			1,942
Dividends on common stock	(47,544		)	—			(47,544		)
Share-based compensation	4,133			—			4,133
Issuance of common stock	—			—			—
Dividend reinvestment and stock purchase plan	1,530			—			1,530
Redeemable noncontrolling interest	(886		)	—			(886		)
Cumulative effect of ASU 2016-09 implementation	3,714			—			3,714
Other stock transactions	(7		)	—			(7		)
Distribution to noncontrolling interest	—			(8,335		)	(8,335		)
Balance at June 30, 2017	$	1,676,239		$	113,792		$	1,790,031



Six Months Ended June 30, 2016	Total Stockholders’ Equity			Noncontrolling Interest		Total Equity
				(in thousands)
Balance at December 31, 2015	$	1,465,867		$	—	$	1,465,867
Net income (loss)	40,671			2,632		43,303
Other comprehensive income (loss)	(22,709		)	—		(22,709		)
Dividends on common stock	(43,270		)	—		(43,270		)
Share-based compensation	2,192			—		2,192
Issuance of common stock	55,802			—		55,802
Dividend reinvestment and stock purchase plan	1,478			—		1,478
Other stock transactions	(20		)	—		(20		)
Sale of noncontrolling interest	62,416			114,886		177,302
Balance at June 30, 2016	$	1,562,427		$	117,518	$	1,679,945

At-the-Market Equity Offering Program

On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. 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 six months ended June 30, 2017. During the three months ended June 30, 2016, we sold 809,649 common shares for $49 million, net of $0.5 million in commissions, under the ATM equity offering program. During the six months ended June 30, 2016, we sold and issued an aggregate of 930,649 shares of common stock under the ATM equity offering program for $56 million, net of $0.6 million in commissions with settlement dates through June 30, 2016. On August 4, 2017, the Company plans to file for renewal of the ATM equity offering program initiated in 2016 which resets the size of the ATM equity offering program to an aggregate sales price of up to $300 million.

Sale of Noncontrolling Interest in Subsidiary

Black Hills 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 Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. 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.

This partial sale was required to be recorded as an equity transaction with no resulting gain or loss on the sale. Further, GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.

Black Hills Colorado IPP has been determined to be a 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 Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of:



	June 30, 2017		December 31, 2016		June 30, 2016
	(in thousands)
Assets
Current assets	$	12,042	$	12,627	$	12,681
Property, plant and equipment of variable interest entities, net	$	214,239	$	218,798	$	224,128

Liabilities
Current liabilities	$	2,651	$	4,342	$	4,174

(10) 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 2016 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 natural long position in crude oil and natural gas reserves and production, our retail natural gas marketing activities, and our fuel procurement for certain of our gas-fired generation assets.

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 11.

Oil and Gas

We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.

To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on our futures and swaps. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income.

The contract or notional amounts and terms of the crude oil futures and natural gas futures and swaps held at our Oil and Gas segment are composed of short positions. We had the following short positions as of:



	June 30, 2017			December 31, 2016			June 30, 2016
	Crude Oil Futures	Crude Oil Options	Natural Gas Futures and Swaps	Crude Oil Futures	Crude Oil Options	Natural Gas Futures and Swaps	Crude Oil Futures	Natural Gas Futures and Swaps
Notional ^(a)	72,000	18,000	1,080,000	108,000	36,000	2,700,000	210,000	2,530,000
Maximum terms in months ^(b)	18	6	6	24	12	12	30	18

__________


(a)	Crude oil futures and call options in Bbls, natural gas in MMBtus.


(b)	Term reflects the maximum forward period hedged.

Based on June 30, 2017 prices, a $0.5 million gain 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.

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, fixed to float 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, or the Condensed Consolidated Statements of Comprehensive 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 July 2017 through December 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 least quarterly.

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:



	June 30, 2017		December 31, 2016		June 30, 2016
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	11,060,000	42	14,770,000	48	18,080,000	54
Natural gas options purchased, net	1,640,000	20	3,020,000	5	3,770,000	20
Natural gas basis swaps purchased	10,070,000	42	12,250,000	48	15,320,000	54
Natural gas over-the-counter swaps, net ^(b)	5,200,000	23	4,622,302	28	5,029,500	23
Natural gas physical contracts, net	8,427,119	10	21,504,378	10	1,666,800	9

__________


(a)	Term reflects the maximum forward period hedged.


(b)	2,480,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.

Based on June 30, 2017 prices, a $0.2 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

In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to reduce the interest rate risk associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten-year senior notes on August 10, 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten-year life of the $400 million unsecured senior note issued on August 19, 2016. Amortization of approximately $2.9 million, which includes the amortization of the $28 million loss currently deferred in AOCI will be recognized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. The ineffective portion of $1.0 million, related to the timing of the debt issuance, was recognized in earnings as a component of interest expense in 2016. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	June 30, 2017			December 31, 2016			June 30, 2016
	Designated Interest Rate Swaps			Designated Interest Rate Swap^(a)			Designated Interest Rate Swap ^(b)			Designated Interest Rate Swap ^(b)			Designated Interest Rate Swaps ^(a)
Notional	$	—		$	50,000		$	150,000		$	250,000		$	75,000
Weighted average fixed interest rate	—		%	4.94		%	2.09		%	2.29		%	4.97		%
Maximum terms in months	0			1			10			10			6
Derivative liabilities, current	$	—		$	90		$	8,553		$	18,500		$	1,505

__________


(a)	The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.


(b)	These swaps were settled and terminated in August 2016 in conjunction with the refinancing of acquired SourceGas debt.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and six months ended June 30, 2017 and 2016 (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 June 30, 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	$	(713	)	Interest expense	$	—
Commodity derivatives	Revenue	430			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(44		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	(327	)		$	—



Three Months Ended June 30, 2016
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	$	(840	)	Interest expense	$	—
Commodity derivatives	Revenue	3,287			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(61		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	2,386			$	—




Six Months Ended June 30, 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	$	(1,515	)	Interest expense	$	—
Commodity derivatives	Revenue	659			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	14			Fuel, purchased power and cost of natural gas sold	—
Total		$	(842	)		$	—




Six Months Ended June 30, 2016
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	$	(1,690	)	Interest expense	$	—
Commodity derivatives	Revenue	6,939			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(151		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	5,098			$	—

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 and six months ended June 30, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income as incurred.



	Three Months Ended June 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(12,614	)
Forward commodity contracts	525			(2,452		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			840
Forward commodity contracts	(386		)	(3,226		)
Total other comprehensive income (loss) from hedging	$	852		$	(17,452	)



	Six Months Ended June 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(30,665	)
Forward commodity contracts	1,451			(266		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	1,515			1,690
Forward commodity contracts	(673		)	6,788
Total other comprehensive income (loss) from hedging	$	2,293		$	(22,453	)

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three and six months ended June 30, 2017 and 2016 (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 June 30,
		2017			2016
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	Revenue	$	26		$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(691		)	2,201
		$	(665	)	$	2,201



		Six Months Ended June 30,
		2017			2016
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	Revenue	$	143		$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(1,500		)	2,835
		$	(1,357	)	$	2,835

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. The net unrealized losses included in our Regulatory assets related to the hedges in our Utilities were $11 million, $8.8 million and $12 million at June 30, 2017, December 3