Black Hills - 10-Q quarterly report FY2019 Q2

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended	June 30, 2019
OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________.

	Commission File Number	001-31303



Black Hills Corporation
Incorporated in	South Dakota	IRS Identification Number		46-0458824

7001 Mount Rushmore Road	Rapid City		South Dakota	57702

Registrant’s telephone number		(605)	721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

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



Yes	x	No o

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted 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 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	☐

Non-accelerated Filer	☐	Smaller Reporting Company	☐

		Emerging Growth Company	☐

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	☐	No x



Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock of $1.00 par value	BKH	New York Stock Exchange

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, 2019
Common stock, $1.00 par value	61,063,230	shares

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TABLE OF CONTENTS
		Page
Glossary of Terms and Abbreviations		3

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements - unaudited	5
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Statements of Comprehensive Income	6
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Cash Flows	9
	Condensed Consolidated Statements of Equity	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1. Management’s Statement	11
	Note 2. Revenue	13
	Note 3. Business Segment Information	15
	Note 4. Accounts Receivable	18
	Note 5. Regulatory Accounting	19
	Note 6. Materials, Supplies and Fuel	20
	Note 7. Earnings Per Share	20
	Note 8. Notes Payable, Current Maturities and Debt	22
	Note 9. Equity	23
	Note 10. Risk Management Activities	23
	Note 11. Fair Value Measurements	26
	Note 12. Fair Value of Financial Instruments	29
	Note 13. Other Comprehensive Income (Loss)	29
	Note 14. Supplemental Disclosure of Cash Flow Information	30
	Note 15. Employee Benefit Plans	31
	Note 16. Commitments and Contingencies	32
	Note 17. Discontinued Operations	32
	Note 18. Income Taxes	33
	Note 19. Accrued Liabilities	33
	Note 20. Leases	34
	Note 21. Subsequent Event	36
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	57
Item 4.	Controls and Procedures	58

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	58
Item 4.	Mine Safety Disclosures	58
Item 6.	Exhibits	58

Signatures		60

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
Arkansas Gas	Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
ASC	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
ATM	At-the-market equity offering program
Availability	The availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHC	Black Hills Corporation; the Company
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility companies
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Busch Ranch I	Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm.
Busch Ranch II	Busch Ranch II wind project will be a 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement.
CAPP	Customer Appliance Protection Plan
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy and providing electric service)
Choice Gas Program	The unbundling of the natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution and Wyoming Gas distribute the gas and Black Hills Energy Services, Wyoming Gas and Black Hills Gas Distribution are Choice Gas suppliers.
CIAC	Contribution In Aid of Construction
City of Gillette	Gillette, Wyoming
Chief operating decision maker (CODM)	Chief Executive Officer
Colorado Electric	Black Hills Colorado Electric, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Gas	Black Hills Colorado Gas, Inc., 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) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)	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.
CPCN	Certificate of Public Convenience and Necessity
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

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Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Equity Unit	Each Equity Unit had 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 that were formerly due 2028. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Heating Degree Day (HDD)	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.
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)
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
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)
NPSC	Nebraska Public Service Commission
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 was amended and restated on July 30, 2018 and now terminates on July 30, 2023.
RSNs	Remarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.
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
S&P	Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric	Black Hills Power, which includes operations in South Dakota, Wyoming and Montana
SSIR	System Safety and Integrity Rider
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017
Tech Services	Non-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts.
WPSC	Wyoming Public Service Commission
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, 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	Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands, except per share amounts)

Revenue	$	333,888		$	355,704		$	931,698		$	931,093

Operating expenses:
Fuel, purchased power and cost of natural gas sold	89,826			104,661			338,605			352,300
Operations and maintenance	124,931			118,282			248,844			234,378
Depreciation, depletion and amortization	51,595			48,709			102,623			97,299
Taxes - property and production	13,142			13,976			26,661			27,276
Other operating expenses	393			525			833			2,015
Total operating expenses	279,887			286,153			717,566			713,268

Operating income	54,001			69,551			214,132			217,825

Other income (expense):
Interest charges -
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(36,058		)	(35,365		)	(72,032		)	(70,803		)
Allowance for funds used during construction - borrowed	1,397			511			2,355			644
Interest income	396			320			695			630
Allowance for funds used during construction - equity	127			242			175			310
Other income (expense), net	137			(1,551		)	(700		)	(1,723		)
Total other income (expense)	(34,001		)	(35,843		)	(69,507		)	(70,942		)

Income before income taxes	20,000			33,708			144,625			146,883
Income tax benefit (expense)	(2,307		)	(6,541		)	(19,570		)	19,261
Income from continuing operations	17,693			27,167			125,055			166,144
Net (loss) from discontinued operations	—			(2,427		)	—			(4,770		)
Net income	17,693			24,740			125,055			161,374
Net income attributable to noncontrolling interest	(3,110		)	(2,823		)	(6,664		)	(6,453		)
Net income available for common stock	$	14,583		$	21,917		$	118,391		$	154,921

Amounts attributable to common shareholders:
Net income from continuing operations	$	14,583		$	24,344		$	118,391		$	159,691
Net (loss) from discontinued operations	—			(2,427		)	—			(4,770		)
Net income available for common stock	$	14,583		$	21,917		$	118,391		$	154,921

Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations	$	0.24		$	0.46		$	1.97		$	2.99
(Loss) from discontinued operations	—			(0.05		)	—			(0.09		)
Total earnings per share of common stock, Basic	$	0.24		$	0.41		$	1.97		$	2.90

Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations	$	0.24		$	0.45		$	1.96		$	2.94
(Loss) from discontinued operations	—			(0.05		)	—			(0.09		)
Total earnings per share of common stock, Diluted	$	0.24		$	0.40		$	1.96		$	2.85

Weighted average common shares outstanding:
Basic	60,467			53,355			60,195			53,337
Diluted	60,606			54,520			60,333			54,361

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)

Net income	$	17,693		$	24,740		$	125,055		$	161,374

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $5, $9, $10 and $19, respectively)	(15		)	(35		)	(29		)	(70		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(52), $(135), $(105), and $(271), respectively)	169			487			336			973
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(172), $(152), $(335), and $(304), respectively)	541			561			1,091			1,122
Net unrealized gains (losses) on commodity derivatives (net of tax of $119, $(18), $65 and $51, respectively)	(399		)	30			(219		)	(198		)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $19, $(45), $147 and $(190), respectively)	(64		)	118			(490		)	594
Other comprehensive income, net of tax	232			1,161			689			2,421

Comprehensive income	17,925			25,901			125,744			163,795
Less: comprehensive income attributable to noncontrolling interest	(3,110		)	(2,823		)	(6,664		)	(6,453		)
Comprehensive income available for common stock	$	14,815		$	23,078		$	119,080		$	157,342

See Note 13 for additional disclosures.

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



(unaudited)	As of
	June 30, 2019			December 31, 2018
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	6,642		$	20,776
Restricted cash	3,602			3,369
Accounts receivable, net	166,513			269,153
Materials, supplies and fuel	102,830			117,299
Derivative assets, current	405			1,500
Income tax receivable, net	13,547			12,978
Regulatory assets, current	48,925			48,776
Other current assets	27,209			29,982
Total current assets	369,673			503,833

Investments	41,271			41,013

Property, plant and equipment	6,317,112			6,000,015
Less: accumulated depreciation and depletion	(1,224,600		)	(1,145,136		)
Total property, plant and equipment, net	5,092,512			4,854,879

Other assets:
Goodwill	1,299,454			1,299,454
Intangible assets, net	13,867			14,337
Regulatory assets, non-current	234,124			235,459
Other assets, non-current	30,552			14,352
Total other assets, non-current	1,577,997			1,563,602

TOTAL ASSETS	$	7,081,453		$	6,963,327

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)



(unaudited)	As of
	June 30, 2019			December 31, 2018
	(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
Current liabilities:
Accounts payable	$	150,508		$	210,609
Accrued liabilities	188,517			215,501
Derivative liabilities, current	1,491			947
Regulatory liabilities, current	39,642			29,810
Notes payable	102,500			185,620
Current maturities of long-term debt	5,743			5,743
Total current liabilities	488,401			648,230

Long-term debt	3,049,672			2,950,835

Deferred credits and other liabilities:
Deferred income tax liabilities, net	343,207			311,331
Regulatory liabilities, non-current	514,914			510,984
Benefit plan liabilities	146,648			145,147
Other deferred credits and other liabilities	118,613			109,377
Total deferred credits and other liabilities	1,123,382			1,076,839

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

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 61,091,385 and 60,048,567 shares, respectively	61,091			60,049
Additional paid-in capital	1,522,208			1,450,569
Retained earnings	761,222			700,396
Treasury stock, at cost – 25,359 and 44,253 shares, respectively	(1,544		)	(2,510		)
Accumulated other comprehensive income (loss)	(26,227		)	(26,916		)
Total stockholders’ equity	2,316,750			2,181,588
Noncontrolling interest	103,248			105,835
Total equity	2,419,998			2,287,423

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,081,453		$	6,963,327

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



(unaudited)	Six Months Ended June 30,
	2019			2018
Operating activities:	(in thousands)
Net income	$	125,055		$	161,374
Loss from discontinued operations, net of tax	—			4,770
Income from continuing operations	125,055			166,144
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	102,623			97,299
Deferred financing cost amortization	4,219			3,694
Stock compensation	7,093			5,221
Deferred income taxes	21,935			(21,419		)
Employee benefit plans	5,683			6,911
Other adjustments, net	8,991			4,884
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	14,911			18,492
Accounts receivable, unbilled revenues and other operating assets	99,925			50,711
Accounts payable and other operating liabilities	(107,563		)	(96,394		)
Regulatory assets - current	16,116			55,637
Regulatory liabilities - current	(6,348		)	19,990
Other operating activities, net	(2,861		)	(1,372		)
Net cash provided by operating activities of continuing operations	289,779			309,798
Net cash provided by operating activities of discontinued operations	—			903
Net cash provided by operating activities	289,779			310,701

Investing activities:
Property, plant and equipment additions	(317,686		)	(156,748		)
Purchase of investment	—			(24,429		)
Other investing activities	389			(373		)
Net cash provided by (used in) investing activities of continuing operations	(317,297		)	(181,550		)
Net cash provided by investing activities of discontinued operations	—			18,024
Net cash provided by (used in) investing activities	(317,297		)	(163,526		)

Financing activities:
Dividends paid on common stock	(60,952		)	(50,879		)
Common stock issued	71,759			1,074
Net (payments) borrowings of short-term debt	(83,120		)	(89,500		)
Long-term debt - issuances	400,000			—
Long-term debt - repayments	(302,871		)	(2,871		)
Distributions to noncontrolling interest	(9,251		)	(9,998		)
Other financing activities	(1,948		)	(1,527		)
Net cash provided by (used in) financing activities	13,617			(153,701		)
Net change in cash, cash equivalents and restricted cash	(13,901		)	(6,526		)
Cash, cash equivalents and restricted cash at beginning of period	24,145			18,240
Cash, cash equivalents and restricted cash at end of period	$	10,244		$	11,714

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.

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY



(unaudited)	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares		Value			Additional Paid in Capital			Retained Earnings			AOCI			Non controlling Interest			Total
December 31, 2018	60,048,567	$	60,049	44,253		$	(2,510	)	$	1,450,569		$	700,396		$	(26,916	)	$	105,835		$	2,287,423
Net income available for common stock	—	—		—		—			—			103,808			—			3,554			107,362
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			457			—			457
Dividends on common stock ($0.505 per share)	—	—		—		—			—			(30,332		)	—			—			(30,332		)
Share-based compensation	48,956	49		(20,497	)	1,078			(589		)	—			—			—			538
Issuance of common stock	280,497	280		—		—			19,719			—			—			—			19,999
Issuance costs	—	—		—		—			(289		)	—			—			—			(289		)
Implementation of ASU 2016-02 Leases	—	—		—		—			—			3,390			—			—			3,390
Distributions to noncontrolling interest	—	—		—		—			—			—			—			(4,846		)	(4,846		)
March 31, 2019	60,378,020	$	60,378	23,756		$	(1,432	)	$	1,469,410		$	777,262		$	(26,459	)	$	104,543		$	2,383,702
Net income available for common stock	—	—		—		—			—			14,583			—			3,110			17,693
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			232			—			232
Dividends on common stock ($0.505 per share)	—	—		—		—			—			(30,620		)	—			—			(30,620		)
Share-based compensation	54,767	54		1,603		(112		)	3,948			—			—			—			3,890
Issuance of common stock	658,598	659		—		—			49,342			—			—			—			50,001
Issuance costs	—	—		—		—			(492		)	—			—			—			(492		)
Implementation of ASU 2016-02 Leases	—	—		—		—			—			(3		)	—			—			(3		)
Distributions to noncontrolling interest	—	—		—		—			—			—			—			(4,405		)	(4,405		)
June 30, 2019	61,091,385	$	61,091	25,359		$	(1,544	)	$	1,522,208		$	761,222		$	(26,227	)	$	103,248		$	2,419,998



	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares	Value			Additional Paid in Capital			Retained Earnings			AOCI			Non controlling Interest			Total
December 31, 2017	53,579,986	$	53,580	39,064	$	(2,306	)	$	1,150,285		$	548,617		$	(41,202	)	$	111,232		$	1,820,206
Net income available for common stock	—	—		—	—			—			133,004			—			3,630			136,634
Other comprehensive income (loss), net of tax	—	—		—	—			—			—			1,260			—			1,260
Dividends on common stock ($0.475 per share)	—	—		—	—			—			(25,444		)	—			—			(25,444		)
Share-based compensation	64,770	65		14,895	(743		)	1,433			—			—			—			755
Dividend reinvestment and stock purchase plan	4,061	4		—	—			215			—			—			—			219
Other stock transactions	—	—		—	—			—			(16		)	18			—			2
Distributions to noncontrolling interest	—	—		—	—			—			—			—			(5,648		)	(5,648		)
March 31, 2018	53,648,817	$	53,649	53,959	$	(3,049	)	$	1,151,933		$	656,161		$	(39,924	)	$	109,214		$	1,927,984
Net income available for common stock	—	—		—	—			—			21,917			—			2,823			24,740
Other comprehensive income (loss), net of tax	—	—		—	—			—			—			1,161			—			1,161
Dividends on common stock ($0.475 per share)	—	—		—	—			—			(25,435		)	—			—			(25,435		)
Share-based compensation	13,033	13		11,022	(593		)	3,019			—			—			—			2,439
Other stock transactions	—	—		—	—			(5		)	(1		)	—			—			(6		)
Distributions to noncontrolling interest	—	—		—	—			—			—			—			(4,350		)	(4,350		)
June 30, 2018	53,661,850	$	53,662	64,981	$	(3,642	)	$	1,154,947		$	652,642		$	(38,763	)	$	107,687		$	1,926,533

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2018 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 2018 Annual Report on Form 10-K filed with the SEC.

Segment Reporting

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.

Effective January 1, 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 for more information.

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, except for certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 17 for more information on discontinued operations.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2019 and December 31, 2018 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. 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, 2019 and June 30, 2018, and our financial condition as of June 30, 2019 and December 31, 2018 are not necessarily indicative of the results of operations and financial condition to be expected for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Recently Issued Accounting Standards

Simplifying the Test for Goodwill Impairment, 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 1, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows.

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Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19

In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19 in November 2018. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We are currently assessing the impacts of adopting this standard.

Recently Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.

Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued rent receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings.

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

Effective January 1, 2019, we adopted ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

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(2) REVENUE

Revenue Recognition

As of January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and six months ended June 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.



Three Months Ended June 30, 2019	Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	139,732	$	123,630	$	—	$	12,428	$	(7,041	)	$	268,749
Transportation	—		28,623		—		—		(276		)	28,347
Wholesale	6,781		—		15,062		—		(13,296		)	8,547
Market - off-system sales	3,448		161		—		—		(1,335		)	2,274
Transmission/Other	14,416		11,612		—		—		(4,199		)	21,829
Revenue from contracts with customers	$	164,377	$	164,026	$	15,062	$	12,428	$	(26,147	)	$	329,746
Other revenues	1,977		1,443		9,646		617		(9,541		)	4,142
Total revenues	$	166,354	$	165,469	$	24,708	$	13,045	$	(35,688	)	$	333,888

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	12,428	$	(7,041	)	$	5,387
Services transferred over time	164,377		164,026		15,062		—		(19,106		)	324,359
Revenue from contracts with customers	$	164,377	$	164,026	$	15,062	$	12,428	$	(26,147	)	$	329,746



Three Months Ended June 30, 2018	Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues			Total
Customer Types:
Retail	$	145,377	$	135,863	$	—	$	16,345	$	(7,979	)	$	289,606
Transportation	—		29,011		—		—		(301		)	28,710
Wholesale	8,191		—		13,603		—		(12,473		)	9,321
Market - Off-System Sales	4,938		162		—		—		(1,660		)	3,440
Transmission/Other	13,356		11,672		—		—		(3,644		)	21,384
Revenue from contracts with customers	$	171,862	$	176,708	$	13,603	$	16,345	$	(26,057	)	$	352,461
Other Revenues	1,754		912		9,141		554		(9,118		)	3,243
Total Revenues	$	173,616	$	177,620	$	22,744	$	16,899	$	(35,175	)	$	355,704

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	16,345	$	(7,978	)	$	8,367
Services transferred over time	171,862		176,708		13,603		—		(18,079		)	344,094
Revenue from Contracts with Customers	$	171,862	$	176,708	$	13,603	$	16,345	$	(26,057	)	$	352,461

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Six Months Ended June 30, 2019	Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Customer types:	(in thousands)
Retail	$	293,195	$	477,905	$	—	$	28,257	$	(15,169	)	$	784,188
Transportation	—		73,140		—		—		(708		)	72,432
Wholesale	15,124		—		30,531		—		(26,509		)	19,146
Market - off-system sales	10,140		378		—		—		(3,559		)	6,959
Transmission/Other	28,591		24,802		—		—		(8,402		)	44,991
Revenue from contracts with customers	$	347,050	$	576,225	$	30,531	$	28,257	$	(54,347	)	$	927,716
Other revenues	2,231		324		19,422		1,217		(19,212		)	3,982
Total revenues	$	349,281	$	576,549	$	49,953	$	29,474	$	(73,559	)	$	931,698

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	28,257	$	(15,169	)	$	13,088
Services transferred over time	347,050		576,225		30,531		—		(39,178		)	914,628
Revenue from contracts with customers	$	347,050	$	576,225	$	30,531	$	28,257	$	(54,347	)	$	927,716



Six Months Ended June 30, 2018	Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Customer Types:
Retail	$	292,434	$	477,257	$	—	$	32,902	$	(15,821	)	$	786,772
Transportation	—		70,681		—		—		(710		)	69,971
Wholesale	17,241		—		28,371		—		(25,521		)	20,091
Market - Off-System Sales	9,082		589		—		—		(4,182		)	5,489
Transmission/Other	26,427		24,341		—		—		(7,275		)	43,493
Revenue from contracts with customers	$	345,184	$	572,868	$	28,371	$	32,902	$	(53,509	)	$	925,816
Other Revenues	1,987		2,096		18,311		1,125		(18,242		)	5,277
Total Revenues	$	347,171	$	574,964	$	46,682	$	34,027	$	(71,751	)	$	931,093

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	32,902	$	(15,820	)	$	17,082
Services transferred over time	345,184		572,868		28,371		—		(37,689		)	908,734
Revenue from contracts with customers	$	345,184	$	572,868	$	28,371	$	32,902	$	(53,509	)	$	925,816

(a)

Due to the changes in our segment disclosures discussed in Note 3, Power Generation Wholesale revenue was revised for the three and six months ended June 30, 2018, which resulted in an increase of $0.9 million and $1.7 million, respectively. The changes to Power Generation Wholesale revenue were offset by changes to eliminations in Inter-company Revenues within Corporate and Other and there was no impact to our consolidated Total Revenues.

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Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4. We do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.

(3) BUSINESS SEGMENT INFORMATION

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation.

Accounting standards for presentation of segments requires an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance. Effective January 1, 2019, we concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance. The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment performance.

Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments and Corporate and Other included the impacts of finance lease accounting relating to Colorado Electric’s PPA with Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment).

The CODM assesses the performance of our segments by using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Colorado IPP on an accrual basis rather than as a finance lease. Effective January 1, 2019, we changed how we account for this PPA at the segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no adjustments to Gas Utilities and Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets.

Segment information and Corporate and Other is as follows (in thousands):




Three Months Ended June 30, 2019	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Segment:
Electric Utilities	$	159,140	$	1,977	$	5,237		$	—		$	166,354
Gas Utilities	163,303		1,443		723			—			165,469
Power Generation ^(a)	1,765		434		13,297			9,212			24,708
Mining	5,538		288		6,890			329			13,045
Inter-company eliminations ^(a)	—		—		(26,147		)	(9,541		)	(35,688		)
Total	$	329,746	$	4,142	$	—		$	—		$	333,888




Three Months Ended June 30, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Segment:
Electric Utilities	$	166,565	$	1,754	$	5,297		$	—		$	173,616
Gas Utilities	176,399		912		309			—			177,620
Power Generation ^(a)	1,130		348		12,473			8,793			22,744
Mining	8,367		229		7,978			325			16,899
Inter-company eliminations ^(a)	—		—		(26,057		)	(9,118		)	(35,175		)
Total	$	352,461	$	3,243	$	—		$	—		$	355,704

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Six Months Ended June 30, 2019	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
Six Months Ended June 30, 2019	Contract Customers		Other Revenues		Contract Customers			Other Revenues			Total Revenues
Segment:
Electric Utilities	$	335,803	$	2,231	$	11,247		$	—		$	349,281
Gas Utilities	574,803		324		1,422			—			576,549
Power Generation ^(a)	4,022		870		26,509			18,552			49,953
Mining	13,088		557		15,169			660			29,474
Inter-company eliminations ^(a)	—		—		(54,347		)	(19,212		)	(73,559		)
Total	$	927,716	$	3,982	$	—		$	—		$	931,698




Six Months Ended June 30, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Segment:
Electric Utilities	$	333,743	$	1,987	$	11,441		$	—		$	347,171
Gas Utilities	572,141		2,096		727			—			574,964
Power Generation ^(a)	2,850		718		25,521			17,593			46,682
Mining	17,082		476		15,820			649			34,027
Inter-company eliminations ^(a)	—		—		(53,509		)	(18,242		)	(71,751		)
Total	$	925,816	$	5,277	$	—		$	—		$	931,093

(a)

Due to the changes in our segment disclosures, Power Generation Inter-company Operating Revenue for Contract Customers was revised for the three and six months ended June 30, 2018 which resulted in an increase of $0.9 million and $1.7 million, respectively. The changes to Power Generation were offset by changes to Inter-company eliminations within Corporate and Other and there was no impact on our consolidated Total revenues.

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	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Adjusted operating income:
Electric Utilities ^(a)	$	33,546		$	41,200		$	74,566		$	79,680
Gas Utilities	8,557			16,485			111,871			111,928
Power Generation ^(a)	10,156			8,877			22,123			20,652
Mining	1,640			3,825			5,977			8,096
Corporate and Other ^(a)	102			(836		)	(405		)	(2,531		)
Operating income	54,001			69,551			214,132			217,825

Interest expense, net	(34,265		)	(34,534		)	(68,982		)	(69,529		)
Other income (expense), net	264			(1,309		)	(525		)	(1,413		)
Income tax benefit (expense) ^(b)	(2,307		)	(6,541		)	(19,570		)	19,261
Income from continuing operations	17,693			27,167			125,055			166,144
Net (loss) from discontinued operations	—			(2,427		)	—			(4,770		)
Net income	17,693			24,740			125,055			161,374
Net income attributable to noncontrolling interest	(3,110		)	(2,823		)	(6,664		)	(6,453		)
Net income available for common stock	$	14,583		$	21,917		$	118,391		$	154,921

___________


(a)	Due to the changes in our segment disclosures, Adjusted operating income was revised for the three and six months ended June 30, 2018, which resulted in an increase (decrease) as follows (in millions):



Segment	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
Electric Utilities	$	1.6		$	3.3
Power Generation	(1.4		)	(3.0		)
Corporate and Other	(0.2		)	(0.3		)
	$	—		$	—


(b)	Income tax benefit (expense) for the six months ended June 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 18 for more information.

Segment information and Corporate and Other 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, 2019		December 31, 2018
Segment:
Electric Utilities ^(a)	$	2,777,803	$	2,707,695
Gas Utilities	3,645,840		3,623,475
Power Generation ^(a)	379,140		342,085
Mining	62,491		80,594
Corporate and Other	216,179		209,478
Total assets	$	7,081,453	$	6,963,327

___________


(a)	Due to the changes in our segment disclosures, Electric Utilities and Power Generation Total assets were revised as of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on our consolidated Total assets.

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(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, 2019	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,982	$	31,573	$	(526	)	$	71,029
Gas Utilities	67,686		23,753		(4,391		)	87,048
Power Generation	2,867		—		—			2,867
Mining	2,505		—		—			2,505
Corporate	3,233		—		(169		)	3,064
Total	$	116,273	$	55,326	$	(5,086	)	$	166,513



	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2018	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,721	$	35,125	$	(448	)	$	74,398
Gas Utilities	96,123		90,521		(2,592		)	184,052
Power Generation	1,876		—		—			1,876
Mining	3,988		—		—			3,988
Corporate	5,008		—		(169		)	4,839
Total	$	146,716	$	125,646	$	(3,209	)	$	269,153

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(5) REGULATORY ACCOUNTING

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



	June 30, 2019			December 31, 2018
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	34,257		$	29,661
Deferred gas cost adjustments ^(a)	2,342			3,362
Gas price derivatives ^(a)	3,945			6,201
Deferred taxes on AFUDC^(b)	7,716			7,841
Employee benefit plans ^(c)	109,899			110,524
Environmental^(a)	931			959
Loss on reacquired debt^(a)	20,140			21,001
Renewable energy standard adjustment ^(a)	1,994			1,722
Deferred taxes on flow through accounting^(c)	36,552			31,044
Decommissioning costs ^(b)	11,518			11,700
Gas supply contract termination ^(a)	11,413			14,310
Other regulatory assets^(a)	42,342			45,910
Total regulatory assets	283,049			284,235
Less current regulatory assets	(48,925		)	(48,776		)
Regulatory assets, non-current	$	234,124		$	235,459

Regulatory liabilities
Deferred energy and gas costs^(a)	$	16,808		$	6,991
Employee benefit plan costs and related deferred taxes^(c)	41,814			42,533
Cost of removal^(a)	158,477			150,123
Excess deferred income taxes ^(c)	307,871			310,562
TCJA revenue reserve	11,436			18,032
Other regulatory liabilities^(c)	18,150			12,553
Total regulatory liabilities	554,556			540,794
Less current regulatory liabilities	(39,642		)	(29,810		)
Regulatory liabilities, non-current	$	514,914		$	510,984

__________


(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.

Regulatory Matters

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K.

Regulatory Activity

Renewable Ready Service Tariffs and Corriedale Wind Energy Project

South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40 MW Corriedale Wind Energy Project. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial and industrial customers and governmental agencies. The project is expected to be in service in 2020.

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Kansas

On June 25, 2019, Kansas Gas received approval from the Kansas Corporation Commission for an annual increase in revenue of $1.4 million, effective July 1, 2019, based on updates to the Gas System Reliability Surcharge Rider.

Wyoming Gas

On June 13, 2019, we received approval from the WPSC for a request to consolidate our Wyoming gas utility operations into a new utility entity. The Wyoming portion of Black Hills Gas Distribution, LLC, Cheyenne Light’s natural gas utility operations, and Wyoming Gas (Northwest Wyoming) will be combined into a new company called Black Hills Wyoming Gas, LLC. On June 3, 2019, Wyoming Gas filed a rate review application with the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories in Wyoming. The rate review requests $16 million in new revenue to recover investments in safety, reliability and system integrity. Wyoming Gas is also requesting a new rider mechanism to recover safety and integrity investments in its system.

Blockchain Interruptible Service Tariff

On April 30, the WPSC approved Wyoming Electric’s application for a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne and Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state.

Nebraska

On March 29, 2019, Nebraska Gas filed an application with the NPSC requesting approval to merge its two gas distribution companies in Nebraska. A rate review is expected to be filed in 2020 to consolidate the rates, tariffs and services of its two existing natural gas distribution companies.

Colorado

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its two existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover safety and integrity investments in its system.

(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, 2019		December 31, 2018
Materials and supplies	$	80,639	$	75,081
Fuel - Electric Utilities	2,350		2,850
Natural gas in storage held for distribution	19,841		39,368
Total materials, supplies and fuel	$	102,830	$	117,299

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(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,
	2019		2018		2019		2018

Net income available for common stock	$	14,583	$	21,917	$	118,391	$	154,921

Weighted average shares - basic	60,467		53,355		60,195		53,337
Dilutive effect of:
Equity Units ^(a)	—		1,057		—		904
Equity compensation	139		108		138		120
Weighted average shares - diluted	60,606		54,520		60,333		54,361

__________


(a)	Calculated using the treasury stock method. On November 1, 2018, we completed settlement of the stock purchase contracts that were components of the Equity Units issued in November 2015.

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,
	2019	2018	2019	2018

Equity compensation	—	15	—	17
Anti-dilutive shares	—	15	—	17

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(8) NOTES PAYABLE, CURRENT MATURITIES AND DEBT

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



	June 30, 2019				December 31, 2018
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	10,429	$	—	$	22,311
CP Program	102,500		—		185,620		—
Total	$	102,500	$	10,429	$	185,620	$	22,311

Our $750 million corporate Revolving Credit Facility extends through July 30, 2023 with two, one year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at June 30, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at June 30, 2019.

We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net payments under the CP Program during the six months ended June 30, 2019 were $83 million. At June 30, 2019, the weighted average interest rate on CP Program borrowings was 2.60%.

Debt Covenants

Under our Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued, by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. As of June 30, 2019, we were in compliance with these covenants.

Long-Term Debt

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. The interest cost associated with this term loan is determined based upon our corporate credit rating from S&P, Fitch, and Moody’s for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings and Eurodollar borrowings were 0.000% and 0.700%, respectively, at June 30, 2019.

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(9) EQUITY

At-the-Market Equity Offering Program

Our ATM equity offering program allows us to sell shares of our common stock with an aggregate value of up 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. During the three months ended June 30, 2019, we issued a total of 658,598 shares of common stock under the ATM equity offering program for proceeds of $49 million, net of $0.5 million in commissions. During the six months ended June 30, 2019, we issued a total of 939,095 shares of common stock under the ATM equity offering program for proceeds of $69 million, net of $0.7 million in commissions. As of June 30, 2019, there were no shares that were sold, but not settled.

(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 and Credit Policies and Procedures as discussed in our 2018 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, but not limited to, commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain gas-fired generation assets.

Credit Risk

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

For other than retail utility 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.

Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income.

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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 2019 through May 2021; a portion of these 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 gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets. Effectiveness of our hedged 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:



	June 30, 2019		December 31, 2018
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	2,480,000	18	4,000,000	24
Natural gas options purchased, net	2,160,000	9	4,320,000	13
Natural gas basis swaps purchased	2,360,000	18	3,960,000	24
Natural gas over-the-counter swaps, net ^(b)	6,020,000	23	3,660,000	24
Natural gas physical contracts, net ^(c)	1,717,075	9	18,325,852	30

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of June 30, 2019, 2,130,000 MMBtus were designated as cash flow hedges.


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

Based on June 30, 2019 prices, a $0.4 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.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At June 30, 2019, the Company posted $0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

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, 2019 and 2018. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.



Three Months Ended June 30, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income
Interest rate swaps	Interest expense	$	(713	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	83
Total		$	(630	)

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Three Months Ended June 30, 2018
(in thousands)
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income
Interest rate swaps	Interest expense	$	(713	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(163		)
Total		$	(876	)



Six Months Ended June 30, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income
Interest rate swaps	Interest expense	$	(1,426	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	637
Total		$	(789	)



Six Months Ended June 30, 2018
(in thousands)
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income
Interest rate swaps	Interest expense	$	(1,426	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(784		)
Total		$	(2,210	)

The following tables summarize 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, 2019 and 2018.




	Three Months Ended June 30,
	2019			2018
	(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts	$	(518	)	$	48
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			713
Forward commodity contracts	(83		)	163
Total other comprehensive income (loss) from hedging	$	112		$	924

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	Six Months Ended June 30,
	2019			2018
	(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts	$	(284	)	$	(249	)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	1,426			1,426
Forward commodity contracts	(637		)	784
Total other comprehensive income (loss) from hedging	$	505		$	1,961

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018 (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 profit or loss we realized when the underlying physical and financial transactions were settled.




		Three Months Ended June 30,
		2019			2018
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	Fuel, purchased power and cost of natural gas sold	$	(1,185	)	$	771
		$	(1,185	)	$	771



		Six Months Ended June 30,
		2019			2018
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	Fuel, purchased power and cost of natural gas sold	$	(1,160	)	$	1,025
		$	(1,160	)	$	1,025

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability accounts related to the hedges in our utilities were $3.9 million and $6.2 million for June 30, 2019 and December 31, 2018, respectively.

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(11) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2018 Annual Report on Form 10-K filed with the SEC.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

The commodity contracts for our Utilities Segments, are valued using the market approach and include exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

Recurring Fair Value Measurements



	As of June 30, 2019
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	986	$	—	$	(575	)	$	411
Total	$	—	$	986	$	—	$	(575	)	$	411

Liabilities:
Commodity derivatives — Utilities	$	—	$	5,567	$	—	$	(3,945	)	$	1,622
Total	$	—	$	5,567	$	—	$	(3,945	)	$	1,622

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	As of December 31, 2018
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	2,927	$	—	$	(1,408	)	$	1,519
Total	$	—	$	2,927	$	—	$	(1,408	)	$	1,519

Liabilities:
Commodity derivatives — Utilities	$	—	$	6,801	$	—	$	(5,794	)	$	1,007
Total	$	—	$	6,801	$	—	$	(5,794	)	$	1,007

Fair Value Measures by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.

The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:



	Balance Sheet Location	June 30, 2019			December 31, 2018
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets — current	$	—		$	415
Noncurrent commodity derivatives	Other assets, non-current	4			18
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities — current	(449		)	(114		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(58		)	(4		)
Total derivatives designated as hedges		$	(503	)	$	315

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets — current	$	405		$	1,085
Noncurrent commodity derivatives	Other assets, non-current	2			1
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities — current	(1,042		)	(833		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(73		)	(56		)
Total derivatives not designated as hedges		$	(708	)	$	197

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 2018 Annual Report on Form 10-K.

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(12) FAIR VALUE OF FINANCIAL INSTRUMENTS

Other financial instruments for which the carrying value did not equal fair value were as follows (in thousands) as of:



	June 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^{(a) (b)}	$	3,055,415	$	3,337,314	$	2,956,578	$	3,039,108

__________


(a)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.


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


(13)	OTHER COMPREHENSIVE INCOME (LOSS)

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Condensed Consolidated Statements of Income for the period, net of tax (in thousands):



	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended						Six Months Ended
		June 30, 2019			June 30, 2018			June 30, 2019			June 30, 2018
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(713	)	$	(1,426	)	$	(1,426	)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	83			(163		)	637			(784		)
		(630		)	(876		)	(789		)	(2,210		)
Income tax	Income tax benefit (expense)	153			197			188			494
Total reclassification adjustments related to cash flow hedges, net of tax		$	(477	)	$	(679	)	$	(601	)	$	(1,716	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	20		$	44		$	39		$	89

Actuarial gain (loss)	Operations and maintenance	(221		)	(622		)	(441		)	(1,244		)
		(201		)	(578		)	(402		)	(1,155		)
Income tax	Income tax benefit (expense)	47			126			95			252
Total reclassification adjustments related to defined benefit plans, net of tax		$	(154	)	$	(452	)	$	(307	)	$	(903	)
Total reclassifications		$	(631	)	$	(1,131	)	$	(908	)	$	(2,619	)

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Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):



	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2018	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)
Other comprehensive income (loss)
before reclassifications	—			(219		)	—			(219		)
Amounts reclassified from AOCI	1,091			(490		)	307			908
As of June 30, 2019	$	(16,216	)	$	(381	)	$	(9,630	)	$	(26,227	)


	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
Balance as of December 31, 2017	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)
Other comprehensive income (loss)
before reclassifications	—			(198		)	—			(198		)
Amounts reclassified from AOCI	1,122			594			903			2,619
Reclassifications of certain tax effects from AOCI	15			—			3			18
As of June 30, 2018	$	(18,444	)	$	(122	)	$	(20,197	)	$	(38,763	)

(14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Six Months Ended	June 30, 2019			June 30, 2018
	(in thousands)
Non-cash investing and financing activities —
Property, plant and equipment acquired with accrued liabilities	$	83,486		$	37,168

Cash (paid) refunded during the period —
Interest (net of amounts capitalized)	$	(67,624	)	$	(67,119	)
Income taxes	$	1,790		$	(14,837	)

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(15) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Service cost	$	1,345		$	1,709		$	2,691		$	3,417
Interest cost	4,344			3,868			8,687			7,735
Expected return on plan assets	(6,100		)	(6,185		)	(12,200		)	(12,370		)
Prior service cost	7			14			13			29
Net loss (gain)	940			2,157			1,881			4,315
Net periodic benefit cost	$	536		$	1,563		$	1,072		$	3,126

Defined Benefit Postretirement Healthcare Plans

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Service cost	$	454		$	572		$	908		$	1,145
Interest cost	563			521			1,123			1,042
Expected return on plan assets	(58		)	(56		)	(115		)	(113		)
Prior service cost (benefit)	(100		)	(99		)	(199		)	(198		)
Net loss (gain)	—			54			—			108
Net periodic benefit cost	$	859		$	992		$	1,717		$	1,984

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Service cost	$	692	$	435	$	1,977	$	715
Interest cost	324		292		648		585
Prior service cost	1		1		1		1
Net loss (gain)	134		250		268		500
Net periodic benefit cost	$	1,151	$	978	$	2,894	$	1,801

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Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2019 and anticipated contributions for 2019 and 2020 are as follows (in thousands):



	Contributions Made		Contributions Made		Additional Contributions		Contributions
	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019		Anticipated for 2019		Anticipated for 2020
Defined Benefit Pension Plan	$	—	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,108	$	2,217	$	2,217	$	4,271
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	366	$	732	$	732	$	1,562

(16) COMMITMENTS AND CONTINGENCIES

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K except for those described below.

Platte River Power Authority PPAs


•	On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase up to 60 MW of wind energy upon construction completion of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030.


•	On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase 25 MW of unit contingent energy. This agreement is effective September 1, 2019 and will expire June 30, 2024.

The following is a schedule of unconditional purchase obligations required under the 25 MW Platte River Power Authority PPA (in thousands):



2019	$	1,831
2020	$	5,490
2021	$	5,475
2022	$	5,475
2023	$	5,475
Thereafter	$	2,729

(17) DISCONTINUED OPERATIONS

Results of operations for discontinued operations were classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Prior periods relating to our discontinued operations were also reclassified to reflect consistency within our condensed consolidated financial statements.

Oil and Gas Segment

On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018.

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(18) INCOME TAXES

Income tax benefit (expense) for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018

Income tax benefit (expense) for the three months ended June 30, 2019 was $(2.3) million compared to $(6.5) million reported for the same period in 2018. The decrease is driven by a lower 2019 forecasted annual effective tax rate primarily due to an increase of federal production tax credits and related state investment credits associated with new wind assets; and a current year $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

Income tax benefit (expense) for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018.

Income tax benefit (expense) for the six months ended June 30, 2019 was $(20) million compared to $19 million reported for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(2.3) million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

For the six months ended June 30, 2019 the effective tax rate was 13.5% compared to 19.0% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $3.5 million of federal production tax credits and related state investment credits associated with new wind assets, a $1.7 million tax benefit for deferred tax amortization related to tax reform and a $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

(19) ACCRUED LIABILITIES

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



	June 30, 2019		December 31, 2018
Accrued employee compensation, benefits and withholdings	$	50,996	$	63,742
Accrued property taxes	34,966		42,510
Customer deposits and prepayments	40,716		43,574
Accrued interest and contract adjustment payments	32,213		31,759
CIAC current portion	1,485		1,485
Other (none of which is individually significant)	28,141		32,431
Total accrued liabilities	$	188,517	$	215,501

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(20) LEASES

Lessee

We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than one year to 37 years, including options to extend that are reasonably certain to be exercised.

The components of lease expense were as follows (in thousands):



	Income Statement Location	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	Operations and maintenance	$	385	$	696
Finance lease cost:
Amortization of right-of-use asset	Depreciation, depletion and amortization	27		44
Interest on lease liabilities	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	6		9
Total lease cost		$	418	$	749

Supplemental balance sheet information related to leases was as follows (in thousands):



	Balance Sheet Location	As of June 30, 2019
Assets:
Operating lease assets	Other assets, non-current	$	5,161
Finance lease assets	Other assets, non-current	521
Total lease assets		$	5,682

Liabilities:
Current:
Operating leases	Accrued liabilities	$	1,003
Finance lease	Accrued liabilities	106

Noncurrent:
Operating leases	Other deferred credits and other liabilities	4,470
Finance lease	Other deferred credits and other liabilities	419
Total lease liabilities		$	5,998

Supplemental cash flow information related to leases was as follows (in thousands):



	Six Months Ended June 30, 2019
Cash paid included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	528
Operating cash flows from finance lease	$	9
Financing cash flows from finance lease	$	40
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	2,738
Finance lease	$	67

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	As of June 30, 2019
Weighted average remaining lease term (years):
Operating leases	8 years
Finance lease	5 years

Weighted average discount rate:
Operating leases	4.25	%
Finance lease	4.20	%

As of June 30, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):



	Operating Leases		Finance Lease		Total
2019 ^(a)	$	705	$	63	$	768
2020	976		126		1,102
2021	858		126		984
2022	736		126		862
2023	708		126		834
Thereafter	2,654		10		2,664
Total lease payments^(b)	$	6,637	$	577	$	7,214
Less imputed interest	1,164		52		1,216
Present value of lease liabilities	$	5,473	$	525	$	5,998


(a)	Includes lease liabilities for the remaining six months of 2019.


(b)	Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance.

As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands):



	Operating Leases
2019	$	1,052
2020	464
2021	344
2022	224
2023	216
Thereafter	1,776
Total lease payments	$	4,076

Lessor

We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years.

The components of lease revenue were as follows (in thousands):



	Income Statement Location	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease income	Revenue	$	567	$	1,205

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As of June 30, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):



	Operating Leases
2019 ^(a)	$	1,085
2020	2,010
2021	1,843
2022	1,793
2023	1,799
Thereafter	55,481
Total lease receivables	$	64,011


(a)	Includes lease receivables for the remaining six months of 2019.

(21) SUBSEQUENT EVENTS

On August 2, 2019, Black Hills Wyoming and Wyoming Electric filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 years. A decision from FERC is expected by the end of 2019.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

We are a customer-focused, growth-oriented utility company operating in the United States. We report our operations and results in the following financial segments:

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 212,000 customers in Colorado, Montana, South Dakota and Wyoming. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

Gas Utilities: Our Gas Utilities conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities distribute and transport natural gas through our pipeline network to approximately 1,054,000 natural gas customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-available basis.

Our Gas Utilities also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 47,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, install and service air conditioning, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP provide appliance repair services to approximately 62,000 and 28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

Power Generation: Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts.

Mining: Our Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.

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. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

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. In particular, the normal peak usage season for our electric utilities is June through August while the normal peak usage season for our 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 six months ended June 30, 2019 and 2018, and our financial condition as of June 30, 2019 and December 31, 2018, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 57.

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The segment information does not include inter-company eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.

Results of Operations

Executive Summary, Significant Events and Overview



	Three Months Ended June 30,										Six Months Ended June 30,
	2019				2018						2019				2018
(in millions, except per share amounts)	Income		EPS		Income			EPS			Income		EPS		Income			EPS

Net income from continuing operations available for common stock	$	14.6	$	0.24	$	24.3		$	0.45		$	118.4	$	1.96	$	159.7		$	2.94
Net (loss) from discontinued operations	—		—		(2.4		)	(0.05		)	—		—		(4.8		)	(0.09		)
Net income available for common stock	$	14.6	$	0.24	$	21.9		$	0.40		$	118.4	$	1.96	$	154.9		$	2.85

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018.

The variance to the prior year included the following:


•	Electric Utilities’ adjusted operating income decreased $7.7 million primarily due to cooler spring weather compared to prior year and higher operating expenses driven by outside services and employee costs;


•	Gas Utilities’ adjusted operating income decreased $7.9 million primarily due to direct and indirect impacts from significant rainfall and flooding in our service territories and higher operating expenses driven by outside services and employee costs;


•	Power Generation’s adjusted operating income increased $1.3 million primarily due to higher revenue from increased wind MWh sold and higher power purchase agreement prices partially offset by higher depreciation from new wind assets;


•	Mining’s adjusted operating income decreased $2.2 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;


•	Corporate and Other expenses decreased $0.9 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations; and


•	A current year $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018.

The variance to the prior year included the following:


•	Electric Utilities’ adjusted operating income decreased $5.1 million primarily due to cooler spring weather compared to prior year and higher operating expenses driven by outside services and employee costs;


•	Gas Utilities’ adjusted operating income decreased $0.1 million primarily due to higher operating expenses driven by outside services and employee costs offset by new rates and favorable winter weather compared to prior year;


•	Power Generation’s adjusted operating income increased $1.5 million primarily due to higher revenue from increased wind MWh sold partially offset by higher depreciation from new wind assets;


•	Mining’s adjusted operating income decreased $2.1 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;


•	Corporate and Other expenses decreased $2.1 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;


•	A prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and


•	A lower current year effective tax rate primarily due to $3.5 million of federal production tax credits and related state investment credits associated with new wind assets, a $1.7 million tax benefit for deferred tax amortization related to tax reform and a $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

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The following table summarizes select financial results by operating segment and details significant items (in thousands):



	Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Variance			2019			2018			Variance
Revenue
Revenue	$	369,576		$	390,879		$	(21,303	)	$	1,005,257		$	1,002,844		$	2,413
Inter-company eliminations	(35,688		)	(35,175		)	(513		)	(73,559		)	(71,751		)	(1,808		)
	$	333,888		$	355,704		$	(21,816	)	$	931,698		$	931,093		$	605
Adjusted operating income ^(a)
Electric Utilities	$	33,546		$	41,200		$	(7,654	)	$	74,566		$	79,680		$	(5,114	)
Gas Utilities	8,557			16,485			(7,928		)	111,871			111,928			(57		)
Power Generation	10,156			8,877			1,279			22,123			20,652			1,471
Mining	1,640			3,825			(2,185		)	5,977			8,096			(2,119		)
Corporate and Other	102			(836		)	938			(405		)	(2,531		)	2,126
Operating income	54,001			69,551			(15,550		)	214,132			217,825			(3,693		)

Interest expense, net	(34,265		)	(34,534		)	269			(68,982		)	(69,529		)	547
Other income (expense), net	264			(1,309		)	1,573			(525		)	(1,413		)	888
Income tax benefit (expense)	(2,307		)	(6,541		)	4,234			(19,570		)	19,261			(38,831		)
Income from continuing operations	17,693			27,167			(9,474		)	125,055			166,144			(41,089		)
Net (loss) from discontinued operations	—			(2,427		)	2,427			—			(4,770		)	4,770
Net income	17,693			24,740			(7,047		)	125,055			161,374			(36,319		)
Net income attributable to noncontrolling interest	(3,110		)	(2,823		)	(287		)	(6,664		)	(6,453		)	(211		)
Net income available for common stock	$	14,583		$	21,917		$	(7,334	)	$	118,391		$	154,921		$	(36,530	)

__________


(a)	In 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 of the Notes to Condensed Consolidated Financial Statements for additional information.

Overview of Business Segments and Corporate Activity

Electric Utilities Segment


•	Colorado Electric and Wyoming Electric set new all-time and summer peak loads:


•	On July 19, 2019, Colorado Electric set a new peak load of 422 MW, exceeding the previous peak of 413 MW set in June 2018.


•	On July 19, 2019, Wyoming Electric set a new peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.

•

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•	Electric Utilities experienced cooler spring weather during the three and six months ended June 30, 2019 compared to the same periods in 2018. Cooling degree days for the three and six months ended June 30, 2019 were 38% lower than normal compared to 109% higher than normal for the same periods in 2018.

Heating degree days for the three and six months ended June 30, 2019 were 12% and 8% higher than normal, compared to 12% lower and 7% higher than normal for the same periods in 2018.


•	South Dakota Electric continued construction on a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The 94-mile final segment of the transmission line is expected to be in service in the fall of 2019.

Gas Utilities Segment


•	Gas Utilities experienced colder winter and spring weather during the three and six months ended June 30, 2019 compared to the same periods in 2018. Heating degree days for the three and six months ended June 30, 2019 were 5% and 10% higher than normal, compared to 1% lower and 1% higher than normal for the same periods in 2018.


•	Regulatory activity:

◦

On June 3, 2019, Wyoming Gas filed a rate review application with the WSPC to consolidate the rates, tariffs and services of its four existing gas distribution territories in Wyoming. The rate review also requests $16 million in new revenue to recover investments in safety, reliability and system integrity. Wyoming Gas is also requesting a new rider mechanism to recover safety and integrity investments in its system. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional details.


◦	On March 29, 2019, Nebraska Gas filed an application with the NPSC requesting approval to merge its two natural gas distribution companies in Nebraska. A rate review is expected to be filed in 2020 to consolidate the rates, tariffs and services of its two existing natural gas distribution companies.

◦

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs and services of its two existing gas distribution territories in Colorado. The rate review also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover safety and integrity investments in its system.


•	On May 10, 2019, Wyoming Gas commenced construction on the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline will interconnect from a supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. The pipeline is expected to be in service in late 2019.

Power Generation Segment


•	On August 2, 2019 Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 years. A decision from FERC is expected later this year.


•	On March 11, 2019, Black Hills Electric Generation commenced construction on the $71 million, 60 MW Busch Ranch II Wind Farm. The wind generation project remains on schedule to be in service in the fall of 2019.

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Corporate and Other


•	On July 23, 2019, Fitch affirmed South Dakota Electric’s credit rating at A.


•	During the six months ended June 30, 2019, we issued a total of 939,095 shares of common stock under the ATM equity offering program for net proceeds of $69 million.


•	On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt.


•	On April 30, 2019, S&P affirmed South Dakota Electric’s credit rating at A.


•	On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.

Operating Results

A discussion of operating results from our segments and Corporate activities follows in the sections below. Revenues for operating segments in the following sections are presented in total and by retail class. For disaggregation of revenue by contract type and operating segment, see Note 2 of the Notes to Condensed Consolidated Financial Statements for more information.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenue less cost of natural gas sold. Our gross margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income, as determined in accordance with GAAP, as an indicator of operating performance.

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Electric Utilities



	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue	$	166,354	$	173,616	$	(7,262	)	$	349,281	$	347,171	$	2,110

Total fuel and purchased power	62,128		65,942		(3,814		)	135,411		134,680		731

Gross margin (non-GAAP)	104,226		107,674		(3,448		)	213,870		212,491		1,379

Operations and maintenance	48,734		45,101		3,633			95,878		90,194		5,684
Depreciation and amortization	21,947		21,373		574			43,427		42,617		810
Total operating expenses	70,681		66,474		4,207			139,305		132,811		6,494

Adjusted operating income ^(a)	$	33,545	$	41,200	$	(7,655	)	$	74,565	$	79,680	$	(5,115	)

________________


(a)	Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Electric Utilities Adjusted operating income was revised for the three and six months ended June 30, 2018, which resulted in an increase of $1.6 million and $3.3 million, respectively.

Results of Operations for the Electric Utilities for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018:

Gross margin for the three months ended June 30, 2019 decreased as a result of the following:



	(in millions)
Weather	$	(2.5	)
Lower commercial demand	(1.8		)
Lower residential customer usage	(1.5		)
Reduction in purchased power capacity charges	1.6
Rider recovery	0.2
Other	0.6
Total decrease in Gross margin (non-GAAP)	$	(3.4	)

Operations and maintenance increased primarily due to $1.5 million of higher employee costs driven by additional headcount and $1.2 million of higher outside services expenses. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

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Results of Operations for the Electric Utilities for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018:

Gross margin for the six months ended June 30, 2019 increased as a result of the following:



	(in millions)
Reduction in purchased power capacity charges	$	3.2
Higher off-system power marketing and ancillary wheeling	0.7
Rider recovery	0.7
Weather	(1.9		)
Lower commercial demand	(1.9		)
Lower residential customer usage	(1.4		)
Other	2.0
Total increase in Gross margin (non-GAAP)	$	1.4

Operations and maintenance increased primarily due to $2.8 million of higher outside services expenses and $2.6 million of higher employee costs driven by additional headcount.

Operating Statistics



	Electric Revenue (in thousands)								Quantities sold (MWh)
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,
	2019		2018		2019		2018		2019	2018	2019	2018
Residential	$	45,700	$	50,116	$	103,338	$	105,857	301,481	328,638	690,659	711,908
Commercial	59,739		64,902		120,702		126,886		490,329	509,984	995,902	1,010,120
Industrial	31,697		31,220		64,137		62,020		445,837	418,596	872,451	819,305
Municipal	4,253		4,666		8,392		8,807		38,283	42,657	74,919	78,981
Subtotal Retail Revenue - Electric	141,389		150,904		296,569		303,570		1,275,930	1,299,875	2,633,931	2,620,314
Contract Wholesale	6,781		8,191		15,124		17,241		194,222	218,132	417,242	455,836
Off-system/Power Marketing Wholesale	3,448		4,939		10,140		9,083		135,091	178,854	275,941	307,895
Other	14,736		9,582		27,448		17,277		—	—	—	—
Total Revenue and Energy Sold	166,354		173,616		349,281		347,171		1,605,243	1,696,861	3,327,114	3,384,045
Other Uses, Losses or Generation, net	—		—		—		—		89,866	125,606	186,866	216,461
Total Revenue and Energy	166,354		173,616		349,281		347,171		1,695,109	1,822,467	3,513,980	3,600,506
Less cost of fuel and purchased power ^(a)	62,128		65,942		135,411		134,680
Gross Margin (non-GAAP) ^(a)	$	104,226	$	107,674	$	213,870	$	212,491

________________


(a)	Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, cost of fuel and purchased power was revised for the three and six months ended June 30, 2018, which resulted in an increase of $1.7 million and $3.3 million, respectively. There were corresponding decreases to Gross margin for each period.

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Three Months Ended June 30,	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(a)
	2019		2018		2019		2018		2019	2018
Colorado Electric ^(b)	$	55,412	$	62,532	$	31,051	$	35,801	485,346	542,528
South Dakota Electric	69,246		70,676		50,865		49,922		757,640	837,943
Wyoming Electric	41,696		40,408		22,310		21,951		452,123	441,996
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	166,354	$	173,616	$	104,226	$	107,674	1,695,109	1,822,467




	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(a)
Six Months Ended June 30,	2019		2018		2019		2018		2019	2018
Colorado Electric ^(b)	$	115,259	$	120,885	$	62,495	$	67,547	977,028	1,029,528
South Dakota Electric	148,287		144,491		107,173		101,298		1,602,641	1,666,120
Wyoming Electric	85,735		81,795		44,202		43,646		934,311	904,858
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	349,281	$	347,171	$	213,870	$	212,491	3,513,980	3,600,506

________________


(a)	Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 5%, 5%, and 6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, respectively.


(b)	Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Gross margin was revised for the three and six months ended June 30, 2018, which resulted in a decrease of $(1.7) million and $(3.3) million, respectively.



	Three Months Ended June 30,		Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2019	2018	2019	2018

Coal-fired	471,840	568,733	1,057,135	1,164,333
Natural Gas and Oil	86,475	105,304	211,132	146,627
Wind	56,505	68,501	111,924	142,482
Total Generated	614,820	742,538	1,380,191	1,453,442
Purchased	1,080,289	1,079,929	2,133,789	2,147,064
Total Generated and Purchased	1,695,109	1,822,467	3,513,980	3,600,506



	Three Months Ended June 30,		Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2019	2018	2019	2018
Generated:
Colorado Electric	91,886	132,927	192,416	224,975
South Dakota Electric	315,925	411,839	773,294	824,033
Wyoming Electric	207,009	197,772	414,481	404,434
Total Generated	614,820	742,538	1,380,191	1,453,442
Purchased:
Colorado Electric	393,460	409,601	784,612	804,553
South Dakota Electric	441,715	426,104	829,347	842,087
Wyoming Electric	245,114	244,224	519,830	500,424
Total Purchased	1,080,289	1,079,929	2,133,789	2,147,064

Total Generated and Purchased	1,695,109	1,822,467	3,513,980	3,600,506

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	Three Months Ended June 30,
Degree Days		2019			2018
	Actual	Variance from Normal		Actual Variance to Prior Year	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	603	(5	)%	31%	460	(27	)%
South Dakota Electric	1,279	25	%	23%	1,037	1	%
Wyoming Electric	1,359	12	%	29%	1,053	(14	)%
Combined^(a)	986	12	%	27%	777	(12	)%

Cooling Degree Days:
Colorado Electric	147	(30	)%	(70)%	494	136	%
South Dakota Electric	38	(62	)%	(71)%	132	33	%
Wyoming Electric	29	(42	)%	(72)%	102	104	%
Combined^(a)	86	(38	)%	(71)%	292	109	%



	Six Months Ended June 30,
	2019				2018
Heating Degree Days	Actual	Variance from Normal		Actual Variance to Prior Year	Actual	Variance from Normal

Colorado Electric	3,152	(4	)%	10%	2,866	12	%
South Dakota Electric	5,195	23	%	10%	4,736	12	%
Wyoming Electric	4,557	3	%	13%	4,037	(9	)%
Combined^(a)	4,132	8	%	10%	3,741	7	%

Cooling Degree Days:
Colorado Electric	147	(30	)%	(70)%	494	136	%
South Dakota Electric	38	(62	)%	(71)%	132	33	%
Wyoming Electric	29	(42	)%	(72)%	102	104	%
Combined^(a)	86	(38	)%	(71)%	292	109	%

__________


(a)	Combined actuals are calculated based on the weighted average number of total customers by state.



Electric Utilities Power Plant Availability	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Coal-fired plants ^(a)	79.2	%	91.2	%	87.7	%	93.1	%
Natural gas-fired plants and Other plants ^(b)	89.3	%	98.1	%	90.0	%	97.2	%
Wind	94.5	%	96.7	%	95.6	%	96.9	%
Total availability	86.4	%	95.8	%	89.7	%	95.9	%

Wind capacity factor	34.8	%	41.7	%	38.7	%	46.1	%

__________


(a)	2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant.


(b)	2019 included planned outages at Neil Simpson CT and Lange CT.

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Gas Utilities



	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue:
Natural gas - regulated	$	149,942	$	161,212	$	(11,270	)	$	533,817	$	531,480	$	2,337
Other - non-regulated services	15,527		16,408		(881		)	42,732		43,484		(752		)
Total revenue	165,469		177,620		(12,151		)	576,549		574,964		1,585

Cost of sales:
Natural gas - regulated	51,108		62,453		(11,345		)	252,158		267,537		(15,379		)
Other - non-regulated services	5,876		5,601		275			12,105		10,202		1,903
Total cost of sales	56,984		68,054		(11,070		)	264,263		277,739		(13,476		)

Gross margin (non-GAAP)	108,485		109,566		(1,081		)	312,286		297,225		15,061

Operations and maintenance	77,130		71,667		5,463			155,068		142,573		12,495
Depreciation and amortization	22,797		21,414		1,383			45,346		42,724		2,622
Total operating expenses	99,927		93,081		6,846			200,414		185,297		15,117

Adjusted operating income	$	8,558	$	16,485	$	(7,927	)	$	111,872	$	111,928	$	(56	)

Results of Operations for the Gas Utilities for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018:

Gross margin for the three months ended June 30, 2019 decreased as a result of:



	(in millions)
Weather ^(a)	$	(2.4	)
Lower mark-to-market on non-utility natural gas commodity contracts	(2.1		)
Lower transport and transmission	(0.6		)
New rates	3.6
Higher customer growth - distribution	1.0
Other	(0.6		)
Total decrease in Gross margin (non-GAAP)	$	(1.1	)

(a) Weather impacts for the three months ended June 30, 2019 compared to the same period in the prior year were primarily driven by direct and indirect impacts from significant rainfall and flooding within the Gas Utilities' service territories.

Operations and maintenance increased primarily due to $2.8 million of higher outside services expenses and $1.6 million of higher employee costs driven by additional headcount. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.

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Results of Operations for the Gas Utilities for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018:

Gross margin for the six months ended June 30, 2019 increase as a result of:



	(in millions)
New rates	$	12.4
Weather	2.8
Higher customer growth - distribution	2.8
Higher transport and transmission	1.1
Excess deferred taxes returned to customers	(2.7		)
Lower mark-to-market on non-utility natural gas commodity contracts	(2.5		)
Other	1.2
Total increase in Gross margin (non-GAAP)	$	15.1

Operations and maintenance increased primarily due to $6.5 million of higher outside services expenses and $3.8 million of higher employee costs driven by additional headcount. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

Depreciation and amortization increased primarily due to a higher asset base driven by previous year capital expenditures.

Operating Statistics



	Gas Revenue (in thousands)				Gross Margin(non-GAAP)(in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2019		2018		2019		2018		2019	2018

Residential	$	85,093	$	91,000	$	52,670	$	52,697	7,919,158	8,837,588
Commercial	30,984		34,031		14,926		14,807		4,194,879	4,615,571
Industrial	3,980		6,565		1,320		1,639		997,942	1,747,702
Other ^(a)	887		255		887		255		—	—
Total Distribution	120,944		131,851		69,803		69,398		13,111,979	15,200,861

Transportation and Transmission	28,998		29,361		29,031		29,361		32,767,310	32,846,279

Total Regulated	149,942		161,212		98,834		98,759		45,879,289	48,047,140

Non-regulated Services	15,527		16,408		9,651		10,807

Total Gas Revenue & Gross Margin (non-GAAP)	$	165,469	$	177,620	$	108,485	$	109,566

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	Gas Revenue (in thousands)						Gross Margin (non-GAAP)(in thousands)						Gas Utilities Quantities Sold & Transported (Dth)
	Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019	2018

Residential	$	326,222		$	325,751		$	157,727		$	149,474		40,757,176	38,933,825
Commercial	127,123			129,036			50,084			47,010			19,185,727	18,564,692
Industrial	9,994			12,547			3,337			3,313			2,180,469	2,931,319
Other ^(a)	(3,467		)	(7,276		)	(3,467		)	(7,276		)	—	—
Total Distribution	459,872			460,058			207,681			192,521			62,123,372	60,429,836

Transportation and Transmission	73,945			71,422			73,978			71,422			79,083,470	77,579,754

Total Regulated	533,817			531,480			281,659			263,943			141,206,842	138,009,590

Non-regulated Services	42,732			43,484			30,627			33,282

Total Gas Revenue & Gross Margin	$	576,549		$	574,964		$	312,286		$	297,225


(a)	Other revenue reflects the impact of revenue reserved in accordance with the TCJA.



	Revenue (in thousands)				Gross Margin (non-GAAP)(in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2019		2018		2019		2018		2019	2018

Arkansas	$	26,236	$	27,095	$	18,617	$	16,471	4,542,917	5,282,607
Colorado	36,713		32,138		19,755		18,562		6,067,353	4,705,454
Iowa	23,714		27,102		14,588		14,648		7,484,272	7,429,328
Kansas	17,379		21,002		11,957		11,870		6,290,716	6,929,756
Nebraska	39,315		48,993		27,709		32,801		14,816,996	16,405,326
Wyoming	22,112		21,290		15,859		15,214		6,677,035	7,294,669
Total Gas Revenue & Gross Margin (non-GAAP)	$	165,469	$	177,620	$	108,485	$	109,566	45,879,289	48,047,140




	Revenue (in thousands)				Gross Margin (non-GAAP)(in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Six Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019	2018

Arkansas	$	105,627	$	97,483	$	62,899	$	52,388	16,967,113	17,161,233
Colorado	113,184		103,536		57,355		51,707		19,244,278	16,408,805
Iowa	89,355		94,986		37,638		37,074		23,147,959	22,932,317
Kansas	58,596		63,383		30,076		29,767		16,733,986	17,227,084
Nebraska	148,112		155,754		83,782		86,661		43,816,014	44,392,550
Wyoming	61,675		59,822		40,536		39,628		21,297,492	19,887,601
Total Gas Revenue & Gross Margin (non-GAAP)	$	576,549	$	574,964	$	312,286	$	297,225	141,206,842	138,009,590

Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Approximately 70% of our Gas Utilities’ revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for, and certain expenses of, these operations fluctuate significantly among quarters. Depending upon the geographic location in which our Gas Utilities operate, the winter heating season begins around November 1 and ends around March 31.

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	Three Months Ended June 30,
	2019			2018
Heating Degree Days	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal
Arkansas ^(a)	246	(25)%	(39)%	400	21%
Colorado	1,017	6%	38%	735	(23)%
Iowa	738	8%	(8)%	801	17%
Kansas ^(a)	425	(5)%	(16)%	508	14%
Nebraska	664	5%	(6)%	708	12%
Wyoming	1,397	15%	30%	1,072	(12)%
Combined ^(b)	795	5%	7%	740	(1)%




	Six Months Ended June 30,
Degree Days	2019			2018
Heating Degree Days:	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal
Arkansas ^(a)	2,347	(4)%	(4)%	2,448	1%
Colorado	4,047	4%	18%	3,439	(12)%
Iowa	4,568	13%	5%	4,332	7%
Kansas ^(a)	3,204	10%	8%	2,978	2%
Nebraska	4,147	13%	6%	3,915	7%
Wyoming	4,910	11%	14%	4,316	(2)%
Combined ^(b)	4,244	10%	9%	3,899	1%

__________


(a)	Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on gross margins.


(b)	The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas is excluded based on the weather normalization mechanism in effect from November through April.

Regulatory Matters

For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 5 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 2018 Annual Report on Form 10-K filed with the SEC.

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Power Generation



	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue	$	24,708	$	22,744	$	1,964		$	49,953	$	46,682	$	3,271

Operations and maintenance	9,833		9,959		(126		)	18,521		18,086		435
Depreciation and amortization	4,719		3,908		811			9,309		7,944		1,365
Total operating expense	14,552		13,867		685			27,830		26,030		1,800

Adjusted operating income ^(a)	$	10,156	$	8,877	$	1,279		$	22,123	$	20,652	$	1,471

________________


(a)	Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Power Generation Adjusted operating income was revised for the three and six months ended June 30, 2018, which resulted in a decrease of $(1.4) million and $(3.0) million, respectively.

Results of Operations for Power Generation for the Three and Six Months Ended June 30, 2019 Compared to the Three and Six Months Ended June 30, 2018: Revenue increased in the current year due to increased wind MWh sold and higher PPA prices. Operating expenses increased in the current year due to higher depreciation and property taxes from new wind assets.

The following table summarizes MWh for our Power Generation segment:



	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Quantities Sold, Generated and Purchased (MWh) ^(a)
Sold
Black Hills Colorado IPP ^(b)	210,316	208,888	416,289	441,263
Black Hills Wyoming ^(c)	149,713	144,460	313,762	310,061
Black Hills Electric Generation ^(d)	47,796	—	81,549	—
Total Sold	407,825	353,348	811,600	751,324

Generated
Black Hills Colorado IPP ^(b)	210,316	208,888	416,289	441,263
Black Hills Wyoming ^(c)	132,189	128,819	264,782	262,848
Black Hills Electric Generation ^(d)	47,796	—	81,549	—
Total Generated	390,301	337,707	762,620	704,111

Purchased
Black Hills Wyoming ^(c)	13,761	17,122	39,340	49,039
Total Purchased	13,761	17,122	39,340	49,039

____________


(a)	Company uses and losses are not included in the quantities sold, generated, and purchased.


(b)	Decrease from the prior year is a result of the impact of Colorado Electric’s wind generation replacing natural-gas generation.


(c)	Under the 20-year economy energy PPA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.


(d)	Increase from prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets.

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The following table provides certain operating statistics for our plants within the Power Generation segment:



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Contracted power plant fleet availability:
Coal-fired plant	95.8	%	89.1	%	95.3	%	91.9	%
Natural gas-fired plants ^(a)	88.7	%	99.5	%	92.1	%	99.5	%
Wind ^(b)	94.1	%	N/A		92.3	%	N/A
Total availability	91.5	%	96.8	%	92.8	%	97.5	%

Wind capacity factor ^(b)	23.1	%	N/A		25.7	%	N/A

____________


(a)	2019 included a planned outage at Pueblo Airport Generation.


(b)	Change from the prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets.

Mining



	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue	$	13,045	$	16,899	$	(3,854	)	$	29,474	$	34,027	$	(4,553	)

Operations and maintenance	9,175		11,124		(1,949		)	19,088		22,046		(2,958		)
Depreciation, depletion and amortization	2,230		1,950		280			4,409		3,885		524
Total operating expenses	11,405		13,074		(1,669		)	23,497		25,931		(2,434		)

Adjusted operating income	$	1,640	$	3,825	$	(2,185	)	$	5,977	$	8,096	$	(2,119	)

The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Tons of coal sold	754		963		1,751		2,041
Cubic yards of overburden moved	2,045		2,380		4,039		4,402

Revenue per ton	$	16.48	$	16.97	$	16.14	$	16.12

Results of Operations for Mining for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018:

Current year revenue decreased due to 22% fewer tons sold driven primarily by planned and unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues, and lower major maintenance expenses.

Results of Operations for Mining for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018:

Current year revenue decreased due to 14% fewer tons sold driven primarily by planned and unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues, and lower major maintenance expenses.

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Corporate and Other



	Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018			Variance		2019			2018			Variance
	(in thousands)
Adjusted operating income (loss) ^(a)	$	102	$	(836	)	$	938	$	(405	)	$	(2,531	)	$	2,126

________________


(a)	Due to the changes in our segment disclosures as discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Corporate and Other Adjusted operating income (loss) was revised for the three and six months ended June 30, 2018, which resulted in a decrease of $(0.2) million and $(0.3) million, respectively.

Results of Operations for Corporate and Other for the Three and Six Months Ended June 30, 2019 Compared to the Three and Six Months Ended June 30, 2018:

The variance in Adjusted operating income (loss) was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.

Consolidated interest expense, Other income (expense) and Income tax benefit (expense) for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018.

Income Tax Benefit (Expense)

Income tax benefit (expense) for the three months ended June 30, 2019 was $(2.3) million compared to $(6.5) million for the same period in 2018. The decrease is driven by a lower 2019 forecasted annual effective tax rate primarily due to an increase of federal production tax credits and state investment credits associated with new wind assets; and a current year $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

Consolidated interest expense, Other income (expense) and Income tax benefit (expense) for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018.

Income Tax Benefit (Expense)

Income tax benefit (expense) for the six months ended June 30, 2019 was $(20) million compared to $19 million for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring and partially offset by a prior year $(2.3) million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

Critical Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our 2018 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting estimates, see Part II, Item 7 of our 2018 Annual Report on Form 10-K.

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Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC except as described below.

Collateral Requirements

Our utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At June 30, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Income Tax

The TCJA required revaluation of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. We have reached agreements with regulators in six states and are working with regulators in our seventh state, as well as FERC regarding returning benefits to customers. Our working capital requirements increased as a result of complying with the TCJA and providing the benefits of the TCJA to customers. These agreements will negatively impact our cash flows by approximately $40 million to $45 million per year for each of the next several years.

Cash Flow Activities

The following table summarizes our cash flows for the six months ended June 30, 2019 (in thousands):



Cash provided by (used in):	2019			2018			Variance
Operating activities	$	289,779		$	310,701		$	(20,922	)
Investing activities	$	(317,297	)	$	(163,526	)	$	(153,771	)
Financing activities	$	13,617		$	(153,701	)	$	167,318

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Year-to-Date 2019 Compared to Year-to-Date 2018

Operating Activities

Net cash provided by operating activities was $290 million for the six months ended June 30, 2019, compared to net cash provided by operating activities of $311 million for the same period in 2018 for a decrease of $21 million. The variance was primarily attributable to:


•	Cash earnings (income from continuing operations plus non-cash adjustments) were $13 million higher for the six months ended June 30, 2019 compared to the same period in the prior year;


•	Net cash inflows from changes in operating assets and liabilities were $14 million for the six months ended June 30, 2019, compared to net cash inflows of $47 million in the same period in the prior year. This $33 million decrease was primarily due to:


◦	Cash inflows increased by approximately $46 million primarily as a result of higher collections of accounts receivable, partially offset by higher materials inventory to support capital projects for the six months ended June 30, 2019 compared to the same period in the prior year;


◦	Cash outflows increased by approximately $11 million as a result of decreases in accounts payable and accrued liabilities driven by higher employee costs, higher gas purchases and other working capital requirements; and


◦	Cash inflows decreased by approximately $66 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments as well as revenue reserved in the prior year due to the TCJA tax rate change that has subsequently been returned to customers.

Investing Activities

Net cash used in investing activities was $317 million for the six months ended June 30, 2019, compared to net cash used in investing activities of $164 million for the same period in 2018 for a variance of $154 million. The variance was primarily attributable to:

•

Capital expenditures of approximately $318 million for the six months ended June 30, 2019 compared to $157 million for the same period in the prior year. Higher current year expenditures are primarily driven by the Busch Ranch II wind project at our Power Generation segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska at our Electric Utilities segment and the 35-mile Natural Bridge pipeline project at our Gas Utilities segment; and


•	A $24 million investment made in the prior year partially offset by an $18 million change in net cash provided by investing activities from discontinued operations primarily due to the prior year sale of assets held for sale.

Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2019 was $14 million, compared to $154 million of net cash used in financing activities for the same period in 2018 for a variance of $167 million. This variance is primarily due to:


•	We amended our Corporate term loan due July 30, 2020, which increased total commitments to $400 million from $300 million;


•	Current year issuance of common stock for net proceeds of approximately $69 million through our ATM equity offering program;


•	$10 million of higher current year dividend payments; and


•	Lower current year net repayments of short-term borrowings of $6 million. Repayments of short-term borrowings, driven by proceeds received from the amendment to the Corporate term loan and the ATM equity offering program, were mostly offset by higher borrowings driven by increased capital expenditures.

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Dividends

Dividends paid on our common stock totaled $61 million for the six months ended June 30, 2019, or $0.505 per share per quarter. On July 31, 2019, our board of directors declared a quarterly dividend of $0.505 per share payable September 1, 2019, equivalent to an annual dividend of $2.02 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

Financing Transactions and Short-Term Liquidity

Revolving Credit Facility and CP Program

Our Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):



		Current		Revolver Borrowings at		CP Program Borrowings at		Letters of Credit at		Available Capacity at
Credit Facility	Expiration	Capacity		June 30, 2019		June 30, 2019		June 30, 2019		June 30, 2019
Revolving Credit Facility	July 30, 2023	$	750	$	—	$	103	$	10	$	637

The weighted average interest rate on CP Program borrowings at June 30, 2019 was 2.60%. Revolving Credit Facility and CP Program financing activity for the six months ended June 30, 2019 was (dollars in millions):



	For the Six Months Ended June 30, 2019
Maximum amount outstanding - commercial paper (based on daily outstanding balances)	$	237
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances)	$	—
Average amount outstanding - commercial paper (based on daily outstanding balances)	$	160
Average amount outstanding - revolving credit facility (based on daily outstanding balances)	$	—
Weighted average interest rates - commercial paper	2.68		%
Weighted average interest rates - revolving credit facility	—		%

Covenant Requirements

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of June 30, 2019. See Note 8 of the Notes to Condensed Consolidated Financial Statements for more information.

Covenants within Wyoming Electric’s financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of June 30, 2019, we were in compliance with these covenants.

Financing Activities

Financing activities for the six months ended June 30, 2019 consisted of the following:

•


•	We issued a total of 939,095 shares of common stock under the ATM equity offering program for proceeds of $69 million, net of $0.7 million in commissions. As of June 30, 2019, there were no shares that were sold, but not settled.


•	Short-term borrowings from our CP Program.

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Future Financing Plans


•	Evaluate refinancing options for our $200 million senior notes due July 15, 2020.


•	Continue to assess equity needs to support our capital expenditure plan.

Credit Ratings

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

The following table represents the credit ratings and outlook and risk profile of BHC at June 30, 2019:



Rating Agency	Senior Unsecured Rating	Outlook
S&P ^(a)	BBB+	Stable
Moody’s ^(b)	Baa2	Stable
Fitch ^(c)	BBB+	Stable

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(a)	On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.


(b)	On December 12, 2018, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.


(c)	On October 11, 2018, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at June 30, 2019:



Rating Agency	Senior Secured Rating
S&P ^(a)	A
Moody’s ^(b)	A1
Fitch ^(c)	A

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(a)	On April 30, 2019, S&P affirmed A rating.


(b)	On December 12, 2018, Moody’s affirmed A1 rating.


(c)	On July 23, 2019, Fitch affirmed A rating.

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Capital Requirements

Capital Expenditures



	Actual		Planned		Planned		Planned		Planned		Planned
Capital Expenditures by Segment	Six Months Ended June 30, 2019 ^(a)		2019^(b)		2020		2021		2022		2023
(in millions)
Electric Utilities ^(c)	$	87	$	205	$	221	$	203	$	170	$	137
Gas Utilities ^(c)	185		464		323		289		277		274
Power Generation	41		84		9		8		10		4
Mining	5		8		7		11		10		7
Corporate and Other	14		16		22		8		5		7
	$	332	$	777	$	582	$	519	$	472	$	429

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(a) Expenditures for the six months ended June 30, 2019 include the impact of accruals for property, plant and equipment.

(b) Includes actual capital expenditures for the six months ended June 30, 2019.

(c) Planned capital expenditures increased for 2019 through 2023 primarily due to increased programmatic integrity spending.

We continue to evaluate potential future acquisitions and other growth opportunities when they arise. As a result, capital expenditures may vary significantly from the estimates identified above.

Contractual Obligations

There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K except for the items described in Notes 8, 16, and 20 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Off-Balance Sheet Commitments

There have been no significant changes to off-balance sheet commitments from those previously disclosed in Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC except for the items described in Note 8 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

New Accounting Pronouncements

Other than the pronouncements reported in our 2018 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.

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FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date the statement was made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2018 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2018 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information regarding our quantitative and qualitative disclosures about market risk is disclosed in Item 7A of our Annual Report on Form 10-K. During the six months ended June 30, 2019, there were no material changes to our quantitative and qualitative disclosures about market risk.

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of June 30, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, 2019.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2019, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.	Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2018 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.


ITEM 4.	Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Quarterly Report on Form 10-Q.


ITEM 6.	Exhibits



Exhibit Number	Description

Exhibit 3.1*	Restated Articles of Incorporation of the Registrant dated January 30, 2018 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 5, 2018).

Exhibit 3.2*	Amended and Restated Bylaws of the Registrant dated April 24, 2017 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on April 28, 2017).

Exhibit 4.1*	Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
	First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
	Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009).
	Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).
	Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on November 18, 2013).
	Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016).
	Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016).
	Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on August 17, 2018).

Exhibit 4.2*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
	First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)).
	Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
	Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

Exhibit 4.3*	Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014).



	First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014).
	Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).

Exhibit 4.4*	Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).

Exhibit 10.1	First Amendment dated as of June 17, 2019 to Amended and Restated Credit Agreement dated as of July 30, 2018, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8–K filed on June 17, 2019).

Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.

Exhibit 95	Mine Safety and Health Administration Safety Data.

101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

__________


*	Previously filed as part of the filing indicated and incorporated by reference herein.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS CORPORATION



		/s/ Linden R. Evans
		Linden R. Evans, President and
		Chief Executive Officer

		/s/ Richard W. Kinzley
		Richard W. Kinzley, Senior Vice President and
		Chief Financial Officer

Dated:	August 6, 2019

Black Hills - 10-Q quarterly report FY2019 Q2

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