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 September 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 October 31, 2017
Common stock, $1.00 par value	53,484,560	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 Nine Months Ended September 30, 2017 and 2016	6

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

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

	Condensed Consolidated Statements of Cash Flows - unaudited
	Nine Months Ended September 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

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands, except per share amounts)

Revenue	$	342,138		$	333,786		$	1,244,119		$	1,109,186

Operating expenses:
Fuel, purchased power and cost of natural gas sold	86,281			80,194			404,222			336,539
Operations and maintenance	114,648			115,103			354,152			334,706
Depreciation, depletion and amortization	49,434			48,925			146,744			140,637
Taxes - property, production and severance	13,092			12,114			40,804			36,991
Impairment of long-lived assets	—			12,293			—			52,286
Other operating expenses	164			6,748			3,301			40,730
Total operating expenses	263,619			275,377			949,223			941,889

Operating income	78,519			58,409			294,896			167,297

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(35,305		)	(37,306		)	(105,499		)	(103,989		)
Allowance for funds used during construction - borrowed	753			860			2,061			2,115
Capitalized interest	149			282			448			785
Interest income	402			912			700			2,513
Allowance for funds used during construction - equity	696			1,211			1,982			2,900
Other income (expense), net	189			160			29			801
Total other income (expense), net	(33,116		)	(33,881		)	(100,279		)	(94,875		)

Income before income taxes	45,403			24,528			194,617			72,422
Income tax benefit (expense)	(13,805		)	(6,644		)	(57,562		)	(11,205		)
Net income	31,598			17,884			137,055			61,217
Net income attributable to noncontrolling interest	(3,935		)	(3,753		)	(10,674		)	(6,415		)
Net income available for common stock	$	27,663		$	14,131		$	126,381		$	54,802

Earnings per share of common stock:
Earnings per share, Basic	$	0.52		$	0.27		$	2.38		$	1.06
Earnings per share, Diluted	$	0.50		$	0.26		$	2.29		$	1.04
Weighted average common shares outstanding:
Basic	53,243			52,184			53,208			51,583
Diluted	55,432			53,733			55,254			52,893

Dividends declared per share of common stock	$	0.445		$	0.420		$	1.335		$	1.260

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)

Net income	$	31,598		$	17,884		$	137,055		$	61,217

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $17 and $19 for the three months ended September 30, 2017 and 2016 and $52 and $57 for the nine months ended September 30, 2017 and 2016, respectively)	(32		)	(36		)	(94		)	(108		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(145) and $(171) for the three months ended September 30, 2017 and 2016 and $(445) and $(517) for the nine months ended September 30, 2017 and 2016, respectively)	269			323			797			966
Derivative instruments designated as cash flow hedges:
Net unrealized gains (losses) on interest rate swaps (net of tax of $0 and $163 for the three months ended September 30, 2017 and 2016 and $0 and $10,930 for the nine months ended September 30, 2017 and 2016, respectively)	—			(302		)	—			(20,200		)
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(249) and $(294) for the three months ended September 30, 2017 and 2016 and $(779) and $(886) for the nine months ended September 30, 2017 and 2016, respectively)	464			546			1,449			1,644
Net unrealized gains (losses) on commodity derivatives (net of tax of $94 and $(423) for the three months ended September 30, 2017 and 2016 and $(442) and $(324) for the nine months ended September 30, 2017 and 2016, respectively)	(160		)	(249		)	755			(417		)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $95 and $860 for the three months ended September 30, 2017 and 2016 and $344 and $3,337 for the nine months ended September 30, 2017 and 2016, respectively)	(166		)	(1,469		)	(590		)	(5,781		)
Other comprehensive income (loss), net of tax	375			(1,187		)	2,317			(23,896		)

Comprehensive income	31,973			16,697			139,372			37,321
Less: comprehensive income attributable to noncontrolling interest	(3,935		)	(3,753		)	(10,674		)	(6,415		)
Comprehensive income available for common stock	$	28,038		$	12,944		$	128,698		$	30,906

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
	September 30, 2017			December 31, 2016			September 30, 2016
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13,510		$	13,580		$	31,814
Restricted cash and equivalents	2,683			2,274			2,140
Accounts receivable, net	153,832			263,289			154,617
Materials, supplies and fuel	126,520			107,210			113,475
Derivative assets, current	657			4,138			4,382
Regulatory assets, current	61,023			49,260			50,561
Other current assets	26,793			27,063			30,032
Total current assets	385,018			466,814			387,021

Investments	12,947			12,561			12,416

Property, plant and equipment	6,615,098			6,412,223			6,306,119
Less: accumulated depreciation and depletion	(2,020,331		)	(1,943,234		)	(1,841,116		)
Total property, plant and equipment, net	4,594,767			4,468,989			4,465,003

Other assets:
Goodwill	1,299,454			1,299,454			1,300,379
Intangible assets, net	7,765			8,392			8,944
Regulatory assets, non-current	239,571			246,882			234,240
Derivative assets, non-current	—			222			183
Other assets, non-current	11,655			12,130			12,800
Total other assets, non-current	1,558,445			1,567,080			1,556,546

TOTAL ASSETS	$	6,551,177		$	6,515,444		$	6,420,986

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
	September 30, 2017			December 31, 2016			September 30, 2016
	(in thousands, except share amounts)
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY
Current liabilities:
Accounts payable	$	95,595		$	153,477		$	110,630
Accrued liabilities	213,571			244,034			228,522
Derivative liabilities, current	1,562			2,459			1,941
Accrued income taxes, net	5,587			12,552			10,909
Regulatory liabilities, current	7,042			13,067			16,925
Notes payable	225,170			96,600			75,000
Current maturities of long-term debt	5,743			5,743			5,743
Total current liabilities	554,270			527,932			449,670

Long-term debt	3,109,864			3,211,189			3,211,768

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	605,744			535,606			533,865
Derivative liabilities, non-current	74			274			317
Regulatory liabilities, non-current	198,189			193,689			186,496
Benefit plan liabilities	149,803			173,682			171,633
Other deferred credits and other liabilities	137,251			138,643			141,007
Total deferred credits and other liabilities	1,091,061			1,041,894			1,033,318

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

Redeemable noncontrolling interest	—			4,295			4,206

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 53,524,529; 53,397,467; and 53,131,469 shares, respectively	53,525			53,397			53,131
Additional paid-in capital	1,147,922			1,138,982			1,123,527
Retained earnings	516,371			457,934			462,090
Treasury stock, at cost – 41,457; 15,258; and 22,368 shares, respectively	(2,448		)	(791		)	(1,155		)
Accumulated other comprehensive income (loss)	(32,566		)	(34,883		)	(32,951		)
Total stockholders’ equity	1,682,804			1,614,639			1,604,642
Noncontrolling interest	113,178			115,495			117,382
Total equity	1,795,982			1,730,134			1,722,024

TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY	$	6,551,177		$	6,515,444		$	6,420,986

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)	Nine Months Ended September 30,
	2017			2016
Operating activities:	(in thousands)
Net income	$	137,055		$	54,802
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	146,744			140,637
Deferred financing cost amortization	6,212			4,002
Impairment of long-lived assets	—			52,286
Derivative fair value adjustments	1,931			(7,308		)
Stock compensation	7,594			9,124
Deferred income taxes	64,672			38,578
Employee benefit plans	8,470			11,830
Other adjustments, net	(5,550		)	(2,076		)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	(19,560		)	(5,166		)
Accounts receivable, unbilled revenues and other operating assets	107,026			78,869
Accounts payable and other operating liabilities	(101,471		)	(117,631		)
Regulatory assets - current	1,287			8,453
Regulatory liabilities - current	(4,328		)	(8,181		)
Contributions to defined benefit pension plans	(27,700		)	(14,200		)
Interest rate swap settlement	—			(28,820		)
Other operating activities, net	(2,952		)	(5,998		)
Net cash provided by (used in) operating activities	319,430			209,201

Investing activities:
Property, plant and equipment additions	(256,138		)	(334,098		)
Acquisition, net of long term debt assumed	—			(1,124,238		)
Other investing activities	(250		)	(860		)
Net cash provided by (used in) investing activities	(256,388		)	(1,459,196		)

Financing activities:
Dividends paid on common stock	(71,334		)	(65,247		)
Common stock issued	3,562			107,690
Sale of noncontrolling interest	—			216,370
Net (payments) borrowings of short-term debt	128,570			(1,800		)
Long-term debt - issuances	—			1,767,608
Long-term debt - repayments	(104,307		)	(1,162,872		)
Distributions to noncontrolling interest	(12,884		)	(4,516		)
Other financing activities	(6,719		)	(16,285		)
Net cash provided by (used in) financing activities	(63,112		)	840,948
Net change in cash and cash equivalents	(70		)	(409,047		)
Cash and cash equivalents, beginning of period	13,580			440,861
Cash and cash equivalents, end of period	$	13,510		$	31,814

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.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We have initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate selling or otherwise disposing of all remaining oil and gas properties and assets by year-end 2018 and have retained advisors to accelerate the marketing and sales process. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, as we did not meet the criteria for classifying assets as held for sale and presenting the segment’s activities as discontinued operations during the quarter. See Note 20.

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 September 30, 2017, December 31, 2016, and September 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 nine months ended September 30, 2017 and September 30, 2016, and our financial condition as of September 30, 2017, December 31, 2016, and September 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. September 30, 2017 reflects a full nine months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the nine months ended September 30, 2016 which reflects a partial period of approximately 7.5 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 $31 million as of September 30, 2016, and decreased net cash flows provided by operations by $15 million for the nine months ended September 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 September

30, 2016 and to the Condensed Consolidated Statements of Cash Flows for the nine months ended September 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 Accounting Standards

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 have substantially completed our assessment of all sources of revenue and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. 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 during that period. Therefore, we do not expect to have a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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 periodic 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. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income which 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 implement this standard effective January 1, 2018. This standard will not have a material impact on our 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 rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.

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

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement 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 are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.

Recently Adopted Accounting Standards

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.

(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 nine months ended September 30, 2016 exclude approximately $3.8 million and $23 million, respectively, of after-tax transaction costs, including professional fees, employee related expenses and other miscellaneous costs.



	Three Months Ended September 30, 2016		Nine Months Ended September 30, 2016
	(in thousands, except per share amounts)
Revenue	$	333,786	$	1,188,148
Net income available for common stock	$	17,376	$	89,973
Earnings per share, Basic	$	0.33	$	1.74
Earnings per share, Diluted	$	0.32	$	1.70

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 for 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 September 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	181,238	$	2,333		$	27,324
Gas	142,821		73			(4,329		)
Power Generation ^(b)	1,810		21,117			6,155
Mining	9,742		7,751			3,477
Oil and Gas	6,527		—			(2,712		)
Corporate activities ^(c)	—		—			(2,252		)
Inter-company eliminations	—		(31,274		)	—
Total	$	342,138	$	—		$	27,663



Three Months Ended September 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric^.	$	171,754	$	2,747		$	24,181
Gas	141,445		—			(2,939		)
Power Generation ^(b)	1,906		21,431			5,642
Mining	9,042		7,778			3,307
Oil and Gas ^(e)	9,639		—			(8,828		)
Corporate activities ^(c)	—		—			(7,232		)
Inter-company eliminations	—		(31,956		)	—
Total	$	333,786	$	—		$	14,131




Nine Months Ended September 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	518,925	$	9,123		$	68,386
Gas ^(a)	674,161		90			41,409
Power Generation ^(b)	5,382		62,907			18,017
Mining	26,500		22,485			9,048
Oil and Gas	19,151		—			(7,609		)
Corporate activities ^(c)(d)	—		—			(2,870		)
Inter-company eliminations	—		(94,605		)	—
Total	$	1,244,119	$	—		$	126,381




Nine Months Ended September 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	493,845	$	9,413		$	62,625
Gas ^(a)	563,879		—			29,975
Power Generation ^(b)	5,304		63,055			19,907
Mining	20,498		23,651			6,969
Oil and Gas ^(e)	25,660		—			(35,277		)
Corporate activities ^(c)(d)	—		—			(29,397		)
Inter-company eliminations	—		(96,119		)	—
Total	$	1,109,186	$	—		$	54,802

___________


(a)	Gas Utility revenue increased for the nine months ended September 30, 2017 compared to the same period 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 nine months ended September 30, 2017 and September 30, 2016 was net of net income attributable to noncontrolling interests of $3.9 million and $11 million, and $3.8 million and $6.4 million, respectively.

(c)

Net income (loss) available for common stock for the three and nine months ended September 30, 2017 and September 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.2 million and $1.5 million, and $4.0 million and $24 million respectively. The nine months ended September 30, 2017 and the three and nine months ended September 30, 2016 included $0.4 million, $1.7 million and $7.4 million, respectively, of after-tax internal labor costs attributable to the acquisition.

(d)

Net income (loss) available for common stock for the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2016 included non-cash after-tax impairments of oil and gas properties of $7.9 million and $33 million, respectively. 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:	September 30, 2017		December 31, 2016		September 30, 2016
Segment:
Electric ^(a)	$	2,911,919	$	2,859,559	$	2,814,408
Gas	3,288,104		3,307,967		3,170,571
Power Generation ^(a)	64,357		73,445		77,570
Mining	66,700		67,347		66,804
Oil and Gas ^(b)	105,963		96,435		158,981
Corporate activities	114,134		110,691		132,652
Total assets	$	6,551,177	$	6,515,444	$	6,420,986

__________


(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 $52 million for the nine months ended September 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
September 30, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	42,716	$	29,762	$	(494	)	$	71,984
Gas Utilities	49,842		24,516		(1,190		)	73,168
Power Generation	1,010		—		—			1,010
Mining	3,534		—		—			3,534
Oil and Gas	3,590		—		(83		)	3,507
Corporate	629		—		—			629
Total	$	101,321	$	54,278	$	(1,767	)	$	153,832



	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
September 30, 2016	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	44,747	$	30,970	$	(580	)	$	75,137
Gas Utilities	48,057		23,582		(1,923		)	69,716
Power Generation	1,165		—		—			1,165
Mining	3,612		—		—			3,612
Oil and Gas	3,341		—		(13		)	3,328
Corporate	1,659		—		—			1,659
Total	$	102,581	$	54,552	$	(2,516	)	$	154,617

(5) REGULATORY ACCOUNTING

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



	Maximum Amortization (in years)	September 30, 2017		December 31, 2016		September 30, 2016
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)(d)	1	$	20,559	$	17,491	$	16,525
Deferred gas cost adjustments ^{(a) (d)}	1	12,833		15,329		12,172
Gas price derivatives ^(a)	3	11,297		8,843		14,405
Deferred taxes on AFUDC^(b)	45	15,645		15,227		14,093
Employee benefit plans ^(c)	12	105,671		108,556		107,578
Environmental^(a)	subject to approval	1,051		1,108		1,126
Asset retirement obligations^(a)	44	514		505		507
Loss on reacquired debt^(a)	30	21,067		22,266		18,077
Renewable energy standard adjustment ^(b)	5	1,956		1,605		1,694
Deferred taxes on flow through accounting^(c)	35	41,900		37,498		33,136
Decommissioning costs ^(e)	6	13,989		16,859		17,271
Gas supply contract termination	5	21,402		26,666		28,164
Other regulatory assets^{(a) (e)}	30	32,710		24,189		20,053
		$	300,594	$	296,142	$	284,801

Regulatory liabilities
Deferred energy and gas costs^{(a) (d)}	1	$	3,780	$	10,368	$	15,033
Employee benefit plan costs and related deferred taxes^(c)	12	66,620		68,654		65,575
Cost of removal^(a)	44	125,360		118,410		114,616
Revenue subject to refund	1	1,386		2,485		1,892
Other regulatory liabilities^(c)	25	8,085		6,839		6,305
		$	205,231	$	206,756	$	203,421

__________


(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, 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 are being 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:



	September 30, 2017		December 31, 2016		September 30, 2016
Materials and supplies	$	73,938	$	68,456	$	67,257
Fuel - Electric Utilities	2,993		3,667		4,282
Natural gas in storage held for distribution	49,589		35,087		41,936
Total materials, supplies and fuel	$	126,520	$	107,210	$	113,475

(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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016

Net income available for common stock	$	27,663	$	14,131	$	126,381	$	54,802

Weighted average shares - basic	53,243		52,184		53,208		51,583
Dilutive effect of:
Equity Units ^(a)	2,015		1,414		1,872		1,191
Equity compensation	174		135		174		119
Weighted average shares - diluted	55,432		53,733		55,254		52,893

__________


(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 September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016

Equity compensation	—	2	—	4
Anti-dilutive shares	—	2	—	4

(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:



	September 30, 2017				December 31, 2016				September 30, 2016
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	25,391	$	96,600	$	36,000	$	75,000	$	30,500
CP Program	225,170		—		—		—		—		—
Total	$	225,170	$	25,391	$	96,600	$	36,000	$	75,000	$	30,500

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 September 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 nine months ended September 30, 2017 and our notes outstanding as of September 30, 2017 were $225 million. As of September 30, 2017, the weighted average interest rate on CP Program borrowings was 1.46%.

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 September 30, 2017	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	61%	Less than	65%

As of September 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:



Nine Months Ended September 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)	126,381			10,567			136,948
Other comprehensive income (loss)	2,317			—			2,317
Dividends on common stock	(71,334		)	—			(71,334		)
Share-based compensation	5,853			—			5,853
Issuance of common stock	—			—			—
Dividend reinvestment and stock purchase plan	2,300			—			2,300
Redeemable noncontrolling interest	(886		)	—			(886		)
Cumulative effect of ASU 2016-09 implementation	3,714			—			3,714
Other stock transactions	(180		)	—			(180		)
Distribution to noncontrolling interest	—			(12,884		)	(12,884		)
Balance at September 30, 2017	$	1,682,804		$	113,178		$	1,795,982



Nine Months Ended September 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)	54,802			6,402			61,204
Other comprehensive income (loss)	(23,896		)	—			(23,896		)
Dividends on common stock	(65,247		)	—			(65,247		)
Share-based compensation	3,822			—			3,822
Issuance of common stock	105,238			—			105,238
Dividend reinvestment and stock purchase plan	2,242			—			2,242
Other stock transactions	(24		)	—			(24		)
Sale of noncontrolling interest	61,838			115,496			177,334
Distribution to noncontrolling interest	—			(4,516		)	(4,516		)
Balance at September 30, 2016	$	1,604,642		$	117,382		$	1,722,024

At-the-Market Equity Offering Program

On August 4, 2017, we renewed the ATM equity offering program initiated in March 2016 which reset the size of the ATM equity offering 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 year 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 nine months ended September 30, 2017 under the ATM equity offering program. During the three months ended September 30, 2016, we sold 819,442 shares of common stock for $49 million, net of $0.5 million in commissions, under the ATM equity offering program. During the nine months ended September 30, 2016, we sold and issued under the ATM equity offering program an aggregate of 1,750,091 shares of common stock, with settlement dates through September 30, 2016, for $106 million, net of $1.1 million in commissions.

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 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 the noncontrolling interest are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.

Black Hills Colorado IPP has been determined to be a 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:



	September 30, 2017		December 31, 2016		September 30, 2016
	(in thousands)
Assets
Current assets	$	14,732	$	12,627	$	14,191
Property, plant and equipment of variable interest entities, net	$	211,380	$	218,798	$	220,818

Liabilities
Current liabilities	$	3,275	$	4,342	$	3,353

(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:



	September 30, 2017			December 31, 2016			September 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	Crude Oil Options	Natural Gas Futures and Swaps
Notional ^(a)	54,000	9,000	540,000	108,000	36,000	2,700,000	159,000	36,000	1,625,000
Maximum terms in months ^(b)	15	3	3	24	12	12	27	15	15

__________


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


(b)	Term reflects the maximum forward period hedged.

Based on September 30, 2017 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Concurrent with the divestiture of our Oil and Gas Business, our existing oil and gas derivative contracts are expected to be unwound within the next six months. Accordingly, we have de-designated our hedge positions in our Oil and Gas Business effective November 1, 2017. See Note 20.

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, and 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 October 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 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:



	September 30, 2017		December 31, 2016		September 30, 2016
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	10,250,000	39	14,770,000	48	17,740,000	51
Natural gas options purchased, net	7,360,000	17	3,020,000	5	6,540,000	17
Natural gas basis swaps purchased	9,170,000	39	12,250,000	48	13,650,000	51
Natural gas over-the-counter swaps, net ^(b)	4,600,000	20	4,622,302	28	4,749,000	20
Natural gas physical contracts, net	21,071,714	38	21,504,378	10	15,666,202	13

__________


(a)	Term reflects the maximum forward period hedged.


(b)	2,260,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.

Based on September 30, 2017 prices, a $0.3 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:



	September 30, 2017			December 31, 2016			September 30, 2016
	Designated Interest Rate Swaps			Designated Interest Rate Swap^(a)			Designated Interest Rate Swaps ^(a)
Notional	$	—		$	50,000		$	75,000
Weighted average fixed interest rate	—		%	4.94		%	4.97		%
Maximum terms in months	0			1			4
Derivative liabilities, current	$	—		$	90		$	654

__________


(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.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 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 September 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	295			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(34		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	(452	)		$	—



Three Months Ended September 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	2,201			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	128			Fuel, purchased power and cost of natural gas sold	—
Total		$	1,489			$	—




Nine Months Ended September 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	$	(2,228	)	Interest expense	$	—
Commodity derivatives	Revenue	954			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(20		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	(1,294	)		$	—




Nine Months Ended September 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	$	(2,530	)	Interest expense	$	—
Commodity derivatives	Revenue	9,140			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(23		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	6,587			$	—

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



	Three Months Ended September 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(787	)
Forward commodity contracts	(254		)	174
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			1,162
Forward commodity contracts	(261		)	(2,329		)
Total other comprehensive income (loss) from hedging	$	198		$	(1,780	)



	Nine Months Ended September 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(31,452	)
Forward commodity contracts	1,197			(92		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	2,228			2,852
Forward commodity contracts	(934		)	4,459
Total other comprehensive income (loss) from hedging	$	2,491		$	(24,233	)

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 nine months ended September 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 September 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	$	(53	)	$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(322		)	(342		)
		$	(375	)	$	(342	)



		Nine Months Ended September 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	$	90		$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(1,822		)	2,492
		$	(1,732	)	$	2,492

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