UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended ~~March 31,~~	June 30, 2019
OR
o☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________.

	Commission File Number	001-31303



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

7001 Mount Rushmore Road
	Rapid City		South Dakota		57702

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

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



Yes	x	No o

Indicate by check mark whether the Registrant has submitted electronically 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~~ Accelerated Filer	x	Accelerated ~~filer~~ o Filer	☐

Non-accelerated ~~filer~~ o Filer	☐	Smaller ~~reporting company~~ o Reporting Company	☐

		Emerging ~~growth company~~ oGrowth 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).



Yeso	☐	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 ~~April 30,~~July 31, 2019
Common stock, $1.00 par value	~~60,367,972~~61,063,230	shares

Table of Contents



TABLE OF CONTENTS
			Page
		Glossary of Terms and Abbreviations		3

PART I.				FINANCIAL INFORMATION	5

Item 1.	Financial Statements - unaudited		5

	Condensed Consolidated Statements of Income ~~- unaudited~~
	~~Three Months Ended March 31, 2019 and 2018~~		5

	Condensed Consolidated Statements of Comprehensive Income ~~- unaudited~~
	~~Three Months Ended March 31, 2019 and 2018~~		6

	Condensed Consolidated Balance Sheets ~~- unaudited~~
	~~March 31, 2019, December 31, 2018 and March 31, 2018~~		7

	Condensed Consolidated Statements of Cash Flows ~~- unaudited~~
	~~Three Months Ended March 31, 2019 and 2018~~		9

	~~Notes to~~ Condensed Consolidated ~~Financial~~ Statements ~~- unaudited~~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		3536
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		57
Item 4.	Controls and Procedures		58

~~Item 3.~~				~~Quantitative and Qualitative Disclosures about Market Risk~~	53

~~Item 4.~~	~~Controls and Procedures~~		54

PART II.	OTHER INFORMATION		54

Item 1.	Legal Proceedings		5458
Item 4.	Mine Safety Disclosures		58
Item 6.	Exhibits		58

~~Item 1A.~~	~~Risk Factors~~		54Signatures

~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~		54

~~Item 4.~~	~~Mine Safety Disclosures~~		54

~~Item 5.~~	~~Other Information~~		54

~~Item 6.~~	~~Exhibits~~		55

	~~Signatures~~		5760

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)~~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 ~~distributes~~and Wyoming Gas distribute the gas and Black Hills Energy Services, ~~is one of the~~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~~indebtedness outstanding at such time, divided by ~~Capital~~capital at such time. Capital being ~~Consolidated Net-Worth~~consolidated net-worth (excluding noncontrolling interest) plus ~~Consolidated Indebtedness~~consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit ~~Agreement.~~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

Table of Contents



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	~~Includes~~ 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 March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018
	(in thousands, except per share amounts)						(in thousands, except per share amounts)

Revenue	$	597,810		$	575,389		$	333,888		$	355,704		$	931,698		$	931,093

Operating expenses:
Fuel, purchased power and cost of natural gas sold	248,779			247,639			89,826			104,661			338,605			352,300
Operations and maintenance	123,913			116,096			124,931			118,282			248,844			234,378
Depreciation, depletion and amortization	51,028			48,590			51,595			48,709			102,623			97,299
Taxes - property and production	13,519			13,300			13,142			13,976			26,661			27,276
Other operating expenses	440			1,490			393			525			833			2,015
Total operating expenses	437,679			427,115			279,887			286,153			717,566			713,268

Operating income	160,131			148,274			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)	(35,974		)	(35,438		)	(36,058		)	(35,365		)	(72,032		)	(70,803		)
Allowance for funds used during construction - borrowed	958			133			1,397			511			2,355			644
Interest income	299			310			396			320			695			630
Allowance for funds used during construction - equity	48			68			127			242			175			310
Other income (expense), net	(837		)	(172		)	137			(1,551		)	(700		)	(1,723		)
Total other income (expense)	(35,506		)	(35,099		)	(34,001		)	(35,843		)	(69,507		)	(70,942		)

Income before income taxes	124,625			113,175			20,000			33,708			144,625			146,883
Income tax benefit (expense)	(17,263		)	25,802			(2,307		)	(6,541		)	(19,570		)	19,261
Income from continuing operations	107,362			138,977			17,693			27,167			125,055			166,144
Net (loss) from discontinued operations	—			(2,343		)	—			(2,427		)	—			(4,770		)
Net income	107,362			136,634			17,693			24,740			125,055			161,374
Net income attributable to noncontrolling interest	(3,554		)	(3,630		)	(3,110		)	(2,823		)	(6,664		)	(6,453		)
Net income available for common stock	$	103,808		$	133,004		$	14,583		$	21,917		$	118,391		$	154,921

Amounts attributable to common shareholders:
Net income from continuing operations	$	103,808		$	135,347		$	14,583		$	24,344		$	118,391		$	159,691
Net (loss) from discontinued operations	—			(2,343		)	—			(2,427		)	—			(4,770		)
Net income available for common stock	$	103,808		$	133,004		$	14,583		$	21,917		$	118,391		$	154,921

Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations	$	1.73		$	2.54		$	0.24		$	0.46		$	1.97		$	2.99
(Loss) from discontinued operations	—			(0.05		)	—			(0.05		)	—			(0.09		)
Total earnings per share of common stock, Basic	$	1.73		$	2.49		$	0.24		$	0.41		$	1.97		$	2.90

Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations	$	1.73		$	2.50		$	0.24		$	0.45		$	1.96		$	2.94
(Loss) from discontinued operations	—			(0.04		)	—			(0.05		)	—			(0.09		)
Total earnings per share of common stock, Diluted	$	1.73		$	2.46		$	0.24		$	0.40		$	1.96		$	2.85

Weighted average common shares outstanding:
Basic	59,920			53,319			60,467			53,355			60,195			53,337
Diluted	60,060			54,122			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 March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018
	(in thousands)						(in thousands)

Net income	$	107,362		$	136,634		$	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 and $10, respectively)	(14		)	(35		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(53) and $(136), respectively)	167			486
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 $(163) and $(152), respectively)	550			561
Net unrealized gains (losses) on commodity derivatives (net of tax of $(54) and $69, respectively)	180			(228		)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $128 and $(145), respectively)	(426		)	476
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	457			1,260			232			1,161			689			2,421

Comprehensive income	107,819			137,894			17,925			25,901			125,744			163,795
Less: comprehensive income attributable to noncontrolling interest	(3,554		)	(3,630		)	(3,110		)	(2,823		)	(6,664		)	(6,453		)
Comprehensive income available for common stock	$	104,265		$	134,264		$	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									As of
	March 31, 2019			December 31, 2018			March 31, 2018			June 30, 2019			December 31, 2018
	(in thousands)									(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	12,225		$	20,776		$	30,947		$	6,642		$	20,776
Restricted cash	3,494			3,369			2,958			3,602			3,369
Accounts receivable, net	282,602			269,153			257,772			166,513			269,153
Materials, supplies and fuel	87,676			117,299			82,045			102,830			117,299
Derivative assets, current	932			1,500			295			405			1,500
Income tax receivable, net	15,309			12,978			13,900			13,547			12,978
Regulatory assets, current	54,303			48,776			54,492			48,925			48,776
Other current assets	28,029			29,982			24,972			27,209			29,982
Current assets held for sale	—			—			24,724
Total current assets	484,570			503,833			492,105			369,673			503,833

Investments	41,247			41,013			40,927			41,271			41,013

Property, plant and equipment	6,127,050			6,000,015			5,608,539			6,317,112			6,000,015
Less: accumulated depreciation and depletion	(1,187,112		)	(1,145,136		)	(1,048,933		)	(1,224,600		)	(1,145,136		)
Total property, plant and equipment, net	4,939,938			4,854,879			4,559,606			5,092,512			4,854,879

Other assets:
Goodwill	1,299,454			1,299,454			1,299,454			1,299,454			1,299,454
Intangible assets, net	14,136			14,337			7,357			13,867			14,337
Regulatory assets, non-current	232,404			235,459			212,740			234,124			235,459
Other assets, non-current	25,823			14,352			14,800			30,552			14,352
Total other assets, non-current	1,571,817			1,563,602			1,534,351			1,577,997			1,563,602

TOTAL ASSETS	$	7,037,572		$	6,963,327		$	6,626,989		$	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									As of
	March 31, 2019			December 31, 2018			March 31, 2018			June 30, 2019			December 31, 2018
	(in thousands, except share amounts)									(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
Current liabilities:
Accounts payable	$	178,678		$	210,609		$	106,281		$	150,508		$	210,609
Accrued liabilities	196,072			215,501			194,040			188,517			215,501
Derivative liabilities, current	95			947			891			1,491			947
Regulatory liabilities, current	45,777			29,810			42,499			39,642			29,810
Notes payable	164,650			185,620			164,200			102,500			185,620
Current maturities of long-term debt	5,743			5,743			255,743			5,743			5,743
Current liabilities held for sale	—			—			24,910
Total current liabilities	591,015			648,230			788,564			488,401			648,230

Long-term debt	2,950,299			2,950,835			2,858,787			3,049,672			2,950,835

Deferred credits and other liabilities:
Deferred income tax liabilities, net	337,184			311,331			290,491			343,207			311,331
Regulatory liabilities, non-current	511,482			510,984			495,362			514,914			510,984
Benefit plan liabilities	145,883			145,147			160,580			146,648			145,147
Other deferred credits and other liabilities	118,007			109,377			105,221			118,613			109,377
Total deferred credits and other liabilities	1,112,556			1,076,839			1,051,654			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 60,378,020; 60,048,567; and 53,648,817 shares, respectively	60,378			60,049			53,649
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	1,469,410			1,450,569			1,151,933			1,522,208			1,450,569
Retained earnings	777,262			700,396			656,161			761,222			700,396
Treasury stock, at cost – 23,756; 44,253; and 53,959 shares, respectively	(1,432		)	(2,510		)	(3,049		)
Treasury stock, at cost – 25,359 and 44,253 shares, respectively										(1,544		)	(2,510		)
Accumulated other comprehensive income (loss)	(26,459		)	(26,916		)	(39,924		)	(26,227		)	(26,916		)
Total stockholders’ equity	2,279,159			2,181,588			1,818,770			2,316,750			2,181,588
Noncontrolling interest	104,543			105,835			109,214			103,248			105,835
Total equity	2,383,702			2,287,423			1,927,984			2,419,998			2,287,423

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,037,572		$	6,963,327		$	6,626,989		$	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)	Three Months Ended March 31,						Six Months Ended June 30,
	2019			2018			2019			2018
Operating activities:	(in thousands)						(in thousands)
Net income	$	107,362		$	136,634		$	125,055		$	161,374
Loss from discontinued operations, net of tax	—			2,343			—			4,770
Income from continuing operations	107,362			138,977			125,055			166,144
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	51,028			48,590			102,623			97,299
Deferred financing cost amortization	2,007			1,900			4,219			3,694
Stock compensation	3,296			2,209			7,093			5,221
Deferred income taxes	19,602			(25,430		)	21,935			(21,419		)
Employee benefit plans	3,137			3,378			5,683			6,911
Other adjustments, net	4,428			3,053			8,991			4,884
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	29,387			31,196			14,911			18,492
Accounts receivable, unbilled revenues and other operating assets	(15,857		)	(25,113		)	99,925			50,711
Accounts payable and other operating liabilities	(41,689		)	(71,149		)	(107,563		)	(96,394		)
Regulatory assets - current	13,031			47,903			16,116			55,637
Regulatory liabilities - current	(1,635		)	16,098			(6,348		)	19,990
Other operating activities, net	1,796			(278		)	(2,861		)	(1,372		)
Net cash provided by operating activities of continuing operations	175,893			171,334			289,779			309,798
Net cash provided by (used in) operating activities of discontinued operations	—			(1,459		)
Net cash provided by operating activities of discontinued operations							—			903
Net cash provided by operating activities	175,893			169,875			289,779			310,701

Investing activities:
Property, plant and equipment additions	(144,126		)	(69,972		)	(317,686		)	(156,748		)
Purchase of investment	—			(23,500		)	—			(24,429		)
Other investing activities	(901		)	(261		)	389			(373		)
Net cash provided by (used in) investing activities of continuing operations	(145,027		)	(93,733		)	(317,297		)	(181,550		)
Net cash provided by (used in) investing activities of discontinued operations	—			20,179
Net cash provided by investing activities of discontinued operations							—			18,024
Net cash provided by (used in) investing activities	(145,027		)	(73,554		)	(317,297		)	(163,526		)

Financing activities:
Dividends paid on common stock	(30,332		)	(25,444		)	(60,952		)	(50,879		)
Common stock issued	19,949			372			71,759			1,074
Net (payments) borrowings of short-term debt	(20,970		)	(47,100		)	(83,120		)	(89,500		)
Long-term debt - issuances							400,000			—
Long-term debt - repayments	(1,436		)	(1,436		)	(302,871		)	(2,871		)
Distributions to noncontrolling interest	(4,846		)	(5,648		)	(9,251		)	(9,998		)
Other financing activities	(1,657		)	(1,400		)	(1,948		)	(1,527		)
Net cash provided by (used in) financing activities	(39,292		)	(80,656		)	13,617			(153,701		)
Net change in cash, cash equivalents and restricted cash	(8,426		)	15,665			(13,901		)	(6,526		)
Cash, cash equivalents and restricted cash at beginning of period	24,145			18,240			24,145			18,240
Cash, cash equivalents and restricted cash at end of period	$	15,719		$	33,905		$	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.

~~Accounting standards for presentation of segments requires an approach based on the way~~Effective January 1, 2019, we ~~organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance. We have~~ changed our measure of segment performance ~~metrics and 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 CODM assesses the performance of our segments by using~~to adjusted operating income, which considers the power sales arrangement between Colorado IPP and Colorado Electric be treated as an executory contract. Adjusted operating income adjusts this power sales arrangement from being accounted for as a capital lease to being accounted for as an executory contract on an accrual basis. This adjustment impacts Electric Utilities and Power Generation segments and Corporate and Other. There were no adjustments to Gas Utilities and Mining segments and this adjustment had no effect onimpacted our ~~consolidated operating income.~~

~~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 profit and adjust revenues, operating income, and total assets for the power sales agreement to an executory contract and not a capital lease.presented. See ~~Notes 2 and~~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 ~~of our Oil and Gas segment~~ in 2018. The Oil and Gas segment assets and liabilities ~~have been~~were classified as held for sale and the results of operations ~~are~~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 ~~March 31,~~June 30, 2019, and December 31, 2018 ~~and~~ ~~March 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 ~~March 31,~~June 30, 2019 and ~~March 31,~~June 30, 2018, and our financial condition as of ~~March 31,~~June 30, 2019, and December 31, 2018 ~~and~~ ~~March 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 ~~March 31,~~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

Three Months Ended March 31, 2019 Electric Utilities Gas Utilities
Power Generation ^(a)
Mining
Inter-company Revenues ^(a)
Total
Customer types: (in thousands)
Retail $ 153,463
$ 354,275
$ —
$ 15,829
$ (8,128 ) $ 515,439
Transportation —
44,517
—
—
(432 ) 44,085
Wholesale 8,343
—
15,469
—
(13,213 ) 10,599
Market - off-system sales 6,692
217
—
—
(2,224 ) 4,685
Transmission/Other 14,175
13,190
—
—
(4,203 ) 23,162
Revenue from contracts with customers 182,673
412,199
15,469
15,829
(28,200 ) 597,970
Other revenues 254
(1,119 )
^(b)
9,776
600
(9,671 ) (160 )
Total revenues $ 182,927
$ 411,080
$ 25,245
$ 16,429
$ (37,871 ) $ 597,810

Timing of revenue recognition:
Services transferred at a point in time $ —
$ —
$ —
$ 15,829
$ (8,128 ) $ 7,701
Services transferred over time 182,673
412,199
15,469
—
(20,072 ) 590,269
Revenue from contracts with customers $ 182,673
$ 412,199
$ 15,469
$ 15,829
$ (28,200 ) $ 597,970

13

Table of Contents



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

Three Months Ended March 31, 2018 Electric Utilities Gas Utilities
Power Generation ^(a)
Mining
Inter-company Revenues ^(a)
Total
Customer Types:
Retail $ 147,057
$ 341,394
$ —
$ 16,557
$ (7,842 ) $ 497,166
Transportation —
41,669
—
—
(409 ) 41,260
Wholesale 9,050
—
14,769
—
(13,049 ) 10,770
Market - Off-System Sales 4,144
427
—
—
(2,522 ) 2,049
Transmission/Other 13,071
12,670
—
—
(3,631 ) 22,110
Revenue from contracts with customers $ 173,322
$ 396,160
$ 14,769
$ 16,557
$ (27,453 ) $ 573,355
Other Revenues 233
1,184
^(b)
9,170
571
(9,124 ) 2,034
Total Revenues $ 173,555
$ 397,344
$ 23,939
$ 17,128
$ (36,577 ) $ 575,389

Timing of Revenue Recognition:
Services transferred at a point in time $ —
$ —
$ —
$ 16,557
$ (7,842 ) $ 8,715
Services transferred over time 173,322
396,160
14,769
—
(19,611 ) 564,640
Revenue from contracts with customers $ 173,322
$ 396,160
$ 14,769
$ 16,557
$ (27,453 ) $ 573,355



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 toin our segment ~~performance measure as disclosed~~disclosures discussed in Note 1,3, Power Generation Wholesale revenue was ~~recast~~revised for the three and six months ended ~~March 31,~~June 30, 2018, which resulted in ~~a change~~an increase of ~~$0.8 million. For the three months ended March 31, 2019, the impact~~$0.9 million and $1.7 million, respectively. The changes to Power Generation Wholesale revenue ~~was $3.4 million. The changes to Power Generation~~ were offset by changes to eliminations in Inter-company Revenues within Corporate and Other and there was no impact to our consolidated Total Revenues.


~~(b)~~	Other revenues in the Gas Utilities segment include alternative revenue programs related to weather normalization mechanisms for Arkansas Gas and Kansas Gas that are considered out of scope for ASC 606.

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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 ~~exists.~~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.

~~As disclosed in Note~~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, ~~changes~~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 ~~adjust~~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 ~~related~~for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no adjustments to ~~the power sales arrangement between Colorado IPP~~Gas Utilities and ~~Colorado Electric from being accounted for as a capital lease to being accounted for as an executory contract on an accrual basis. This~~Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets. ~~See below for more information.~~

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

Three Months Ended March 31, 2019
External Operating
Revenue
Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 176,663
$ 254
$ 6,010
$ —
$ 182,927
Gas Utilities ^(a)
411,500
(1,119 ) 699
—
411,080
Power Generation ^(b)
2,257
436
13,212
9,340
25,245
Mining 7,550
269
8,279
331
16,429
Corporate and Other —
—
—
—
—
Inter-company eliminations ^(b)
—
—
(28,200 ) (9,671 ) (37,871 )
Total $ 597,970
$ (160 ) $ —
$ —
$ 597,810



Three Months Ended March 31, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
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	$	167,178	$	233	$	6,144		$	—		$	173,555		$	333,743	$	1,987	$	11,441		$	—		$	347,171
Gas Utilities^(a)	395,742		1,184		418			—			397,344			572,141		2,096		727			—			574,964
Power Generation ^(b)(a)	1,720		371		13,049			8,799			23,939			2,850		718		25,521			17,593			46,682
Mining	8,715		246		7,842			325			17,128			17,082		476		15,820			649			34,027
Corporate and Other	—		—		—			—			—
Inter-company eliminations ^(b)	—		—		(27,453		)	(9,124		)	(36,577		)
Inter-company eliminations ^(a)														—		—		(53,509		)	(18,242		)	(71,751		)
Total	$	573,355	$	2,034	$	—		$	—		$	575,389		$	925,816	$	5,277	$	—		$	—		$	931,093


(a)	Other revenues in the Gas Utilities segment include alternative revenue programs related to weather normalization mechanisms for Arkansas Gas and Kansas Gas that are considered out of scope for ASC 606.

~~(b)~~

Due to the changes toin our segment ~~performance measure,~~disclosures, Power Generation Inter-company Operating Revenue for Contract Customers was ~~recast~~revised for the three and six months ended ~~March 31,~~June 30, 2018 which resulted in ~~a change~~an increase of ~~$0.8 million. For the three months ended March 31, 2019, the impact to Power Generation Inter-company Operating Revenue for Contract Customers was $3.4 million.~~$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 March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018
Adjusted operating income:
Electric Utilities ^(a)	$	41,020		$	38,480		$	33,546		$	41,200		$	74,566		$	79,680
Gas Utilities	103,314			95,443			8,557			16,485			111,871			111,928
Power Generation ^(a)	11,967			11,776			10,156			8,877			22,123			20,652
Mining	4,337			4,271			1,640			3,825			5,977			8,096
Corporate and Other ^(a)	(507		)	(1,696		)	102			(836		)	(405		)	(2,531		)
Operating income	160,131			148,274			54,001			69,551			214,132			217,825

Interest expense, net	(34,717		)	(34,995		)	(34,265		)	(34,534		)	(68,982		)	(69,529		)
Other income (expense), net	(789		)	(104		)	264			(1,309		)	(525		)	(1,413		)
Income tax benefit (expense) ^(b)	(17,263		)	25,802			(2,307		)	(6,541		)	(19,570		)	19,261
Income from continuing operations	107,362			138,977			17,693			27,167			125,055			166,144
Net (loss) from discontinued operations	—			(2,343		)	—			(2,427		)	—			(4,770		)
Net income	107,362			136,634			17,693			24,740			125,055			161,374
Net income attributable to noncontrolling interest	(3,554		)	(3,630		)	(3,110		)	(2,823		)	(6,664		)	(6,453		)
Net income available for common stock	$	103,808		$	133,004		$	14,583		$	21,917		$	118,391		$	154,921

___________

(a)

Due to the changes toin our segment ~~performance measure,~~disclosures, Adjusted operating income was ~~recast~~revised for the three and six months ended ~~March 31,~~June 30, 2018, ~~for Electric Utilities, Power Generation, and Corporate and Other~~ which resulted in changes of $1.7 million, ($1.6) million, and ($0.1) million, respectively. The impact to Adjusted operating income for the three months ended March 31, 2019, for Electric Utilities, Power Generation, and Corporate and Other was ($5.4) million, $0.7 million, and $4.7 million, respectively. There was no impact on our consolidated Operating income.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 ~~three~~six months ended ~~March 31,~~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:	March 31, 2019		December 31, 2018		March 31, 2018
Total assets (net of inter-company eliminations) as of:							June 30, 2019		December 31, 2018
Segment:
Electric Utilities ^(a)	$	2,755,056	$	2,707,695	$	2,629,267	$	2,777,803	$	2,707,695
Gas Utilities	3,639,430		3,623,475		3,398,473		3,645,840		3,623,475
Power Generation ^(a)	372,503		342,085		314,764		379,140		342,085
Mining	63,088		80,594		65,568		62,491		80,594
Corporate and Other	207,495		209,478		194,193		216,179		209,478
Discontinued operations	—		—		24,724
Total assets	$	7,037,572	$	6,963,327	$	6,626,989	$	7,081,453	$	6,963,327

___________

(a)

Due to the changes toin our segment performance measure, Electric Utilities Total assets were recast as of December 31, 2018 and March 31, 2018 which resulted in changes of ($188) million and ($261) million, respectively. Power Generation Total Assets were recast as of December 31, 2018, and March 31, 2018 which resulted in changes of $188 million and $261 million, respectively. The impact todisclosures, Electric Utilities and Power Generation Total ~~Assets~~assets were revised as of ~~March~~December 31, ~~2019, was~~2018 which resulted in an increase (decrease) of ($~~186)~~188) million and ~~$186~~$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		Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2019	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
June 30, 2019										Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	45,764	$	31,075	$	(535	)	$	76,304	$	39,982	$	31,573	$	(526	)	$	71,029
Gas Utilities	138,005		62,566		(4,008		)	196,563		67,686		23,753		(4,391		)	87,048
Power Generation	3,167		—		—			3,167		2,867		—		—			2,867
Mining	2,791		—		—			2,791		2,505		—		—			2,505
Corporate	3,946		—		(169		)	3,777		3,233		—		(169		)	3,064
Total	$	193,673	$	93,641	$	(4,712	)	$	282,602	$	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

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

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(5) REGULATORY ACCOUNTING

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


	March 31, 2019			December 31, 2018			March 31, 2018			June 30, 2019			December 31, 2018
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	35,512		$	29,661		$	25,056		$	34,257		$	29,661
Deferred gas cost adjustments ^(a)	5,124			3,362			2,118			2,342			3,362
Gas price derivatives ^(a)	3,939			6,201			11,045			3,945			6,201
Deferred taxes on AFUDC^(b)	7,771			7,841			7,808			7,716			7,841
Employee benefit plans ^(c)	111,724			110,524			109,999			109,899			110,524
Environmental^(a)	945			959			1,012			931			959
Loss on reacquired debt^(a)	20,570			21,001			20,267			20,140			21,001
Renewable energy standard adjustment ^(a)	1,533			1,722			1,600			1,994			1,722
Deferred taxes on flow through accounting^(c)	33,226			31,044			28,014			36,552			31,044
Decommissioning costs ^(b)	11,694			11,700			12,552			11,518			11,700
Gas supply contract termination ^(a)	12,866			14,310			18,590			11,413			14,310
Other regulatory assets^(a)	41,803			45,910			29,171			42,342			45,910
Total regulatory assets	286,707			284,235			267,232			283,049			284,235
Less current regulatory assets	(54,303		)	(48,776		)	(54,492		)	(48,925		)	(48,776		)
Regulatory assets, non-current	$	232,404		$	235,459		$	212,740		$	234,124		$	235,459

Regulatory liabilities
Deferred energy and gas costs^(a)	$	19,018		$	6,991		$	20,194		$	16,808		$	6,991
Employee benefit plan costs and related deferred taxes^(c)	42,207			42,533			40,332			41,814			42,533
Cost of removal^(a)	154,170			150,123			139,002			158,477			150,123
Excess deferred income taxes ^(c)	307,894			310,562			310,622			307,871			310,562
TCJA revenue reserve	16,549			18,032			15,239			11,436			18,032
Other regulatory liabilities^(c)	17,421			12,553			12,472			18,150			12,553
Total regulatory liabilities	557,259			540,794			537,861			554,556			540,794
Less current regulatory liabilities	(45,777		)	(29,810		)	(42,499		)	(39,642		)	(29,810		)
Regulatory liabilities, non-current	$	511,482		$	510,984		$	495,362		$	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 ~~utilities into a new public utility entity. The filing also requests~~companies in Nebraska. A rate review is expected to ~~merge~~be filed in 2020 to consolidate the ~~terms~~rates, tariffs and ~~conditions~~services of ~~the~~its two existing ~~tariffs of the two utilities into a single tariff.~~

~~Wyoming~~

~~On March 6, 2019, Wyoming Gas filed an application with the WPSC requesting to merge its four~~natural gas distribution ~~utilities into a new public utility entity. The filing also requests the new entity adopt the terms and conditions of the existing tariffs.~~

companies.

Colorado

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate ~~the base rate areas,~~rates, tariffs, ~~terms~~ and ~~conditions and adjustment clauses~~services of its two ~~legacy utilities.~~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.

(6) MATERIALS, SUPPLIES AND FUEL

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


	March 31, 2019		December 31, 2018		March 31, 2018		June 30, 2019		December 31, 2018
Materials and supplies	$	76,728	$	75,081	$	72,045	$	80,639	$	75,081
Fuel - Electric Utilities	2,485		2,850		2,903		2,350		2,850
Natural gas in storage held for distribution	8,463		39,368		7,097		19,841		39,368
Total materials, supplies and fuel	$	87,676	$	117,299	$	82,045	$	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 March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018

Net income available for common stock	$	103,808	$	133,004	$	14,583	$	21,917	$	118,391	$	154,921

Weighted average shares - basic	59,920		53,319		60,467		53,355		60,195		53,337
Dilutive effect of:
Equity Units ^(a)	—		733		—		1,057		—		904
Equity compensation	140		70		139		108		138		120
Weighted average shares - diluted	60,060		54,122		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 ~~are~~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 March 31,		Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018	2019	2018

Equity compensation	6	71	—	15	—	17
Anti-dilutive shares	6	71	—	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:


	March 31, 2019				December 31, 2018				March 31, 2018				June 30, 2019				December 31, 2018
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	14,006	$	—	$	22,310	$	—	$	15,830	$	—	$	10,429	$	—	$	22,311
CP Program	164,650		—		185,620		—		164,200		—		102,500		—		185,620		—
Total	$	164,650	$	14,006	$	185,620	$	22,310	$	164,200	$	15,830	$	102,500	$	10,429	$	185,620	$	22,311

~~Revolving Credit Facility and CP Program~~

~~On July 30, 2018, we amended and restated our~~Our $750 million corporate Revolving Credit Facility ~~maintaining total commitments of $750 million and extending the term~~extends through July 30, 2023 with two, one year extension options (subject to consent from lenders). This facility ~~is similar to the former revolving credit facility, which~~ 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~~.$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 ~~March 31,~~June 30, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at ~~March 31,~~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 ~~three~~six months ended ~~March 31,~~June 30, 2019 were ~~$21 million and our notes outstanding as of March 31, 2019 were $165~~$83 million. ~~As of March 31,~~At June 30, 2019, the weighted average interest rate on CP Program borrowings was ~~2.70%~~2.60%. ~~As of March 31, 2019, we had outstanding letters of credit of totaling approximately $14 million.~~

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.

~~Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter:~~

As of March 31, 2019 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio 58.1% Less than 65%

As of ~~March 31,~~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 ~~covenant.~~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

~~A summary of the changes in equity is as follows:~~

Three Months Ended March 31, 2019 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 (loss) 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 )
Cumulative effect of ASU 2016-02, Leases implementation
—
—
—
—
—
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

Three Months Ended March 31, 2018 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 (loss) 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

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 ~~March 31,~~June 30, 2019, we issued a total of ~~280,497~~658,598 shares of common stock under the ATM equity offering program for ~~$20~~proceeds of $49 million, net of ~~$0.2~~$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 ~~March 31,~~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 ~~April~~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:


	March 31, 2019		December 31, 2018		March 31, 2018		June 30, 2019		December 31, 2018
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	3,120,000	21	4,000,000	24	6,760,000	33	2,480,000	18	4,000,000	24
Natural gas options purchased, net	1,150,000	10	4,320,000	13	170,000	11	2,160,000	9	4,320,000	13
Natural gas basis swaps purchased	3,020,000	21	3,960,000	24	6,770,000	33	2,360,000	18	3,960,000	24
Natural gas over-the-counter swaps, net ^(b)	3,316,000	26	3,660,000	24	2,760,000	26	6,020,000	23	3,660,000	24
Natural gas physical contracts, net ^(c)	2,786,980	12	18,325,852	30	386,250	32	1,717,075	9	18,325,852	30

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of ~~March 31,~~June 30, 2019,, ~~534,000~~ 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 ~~March 31,~~June 30, 2019 prices, a ~~$0.1~~$0.4 million ~~loss~~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 ~~March 31,~~June 30, 2019, the Company posted ~~$0.2~~$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 ~~March 31,~~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 March 31, 2019
Three Months Ended June 30, 2019					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				Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income
Interest rate swaps	Interest expense	$	(713	)		Interest expense	$	(713	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	554				Fuel, purchased power and cost of natural gas sold	83
Total		$	(159	)			$	(630	)

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Three Months Ended March 31, 2018
Three Months Ended June 30, 2018					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				Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income
Interest rate swaps	Interest expense	$	(713	)		Interest expense	$	(713	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(621		)		Fuel, purchased power and cost of natural gas sold	(163		)
Total		$	(1,334	)			$	(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 ~~March 31,~~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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	Three Months Ended March 31,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)						(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts	$	234		$	(297	)	$	(284	)	$	(249	)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			713			1,426			1,426
Forward commodity contracts	(554		)	621			(637		)	784
Total other comprehensive income (loss) from hedging	$	393		$	1,037		$	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 ~~March 31,~~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


		Three Months Ended March 31,					Six Months Ended June 30,
		2019		2018			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		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	$	25	$	254	Fuel, purchased power and cost of natural gas sold	$	(1,160	)	$	1,025
		$	25	$	254		$	(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 ~~assets~~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 ~~$11 million at March 31, 2019,~~ December ~~31, 2018 and March~~ 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 March 31, 2019											As of June 30, 2019
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total		Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)											(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	1,375	$	—	$	(388	)	$	987	$	—	$	986	$	—	$	(575	)	$	411
Total	$	—	$	1,375	$	—	$	(388	)	$	987	$	—	$	986	$	—	$	(575	)	$	411

Liabilities:
Commodity derivatives — Utilities	$	—	$	4,122	$	—	$	(4,009	)	$	113	$	—	$	5,567	$	—	$	(3,945	)	$	1,622
Total	$	—	$	4,122	$	—	$	(4,009	)	$	113	$	—	$	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

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

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

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	March 31, 2019			December 31, 2018			March 31, 2018			Balance Sheet Location	June 30, 2019			December 31, 2018
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets — current	$	131		$	415		$	—		Derivative assets — current	$	—		$	415
Noncurrent commodity derivatives	Other assets, non-current	9			18			—			Other assets, non-current	4			18
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities — current	(11		)	(114		)	(394		)	Derivative liabilities — current	(449		)	(114		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	—			(4		)	(29		)	Other deferred credits and other liabilities	(58		)	(4		)
Total derivatives designated as hedges		$	129		$	315		$	(423	)		$	(503	)	$	315

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets — current	$	801		$	1,085		$	295		Derivative assets — current	$	405		$	1,085
Noncurrent commodity derivatives	Other assets, non-current	46			1			—			Other assets, non-current	2			1
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities — current	(84		)	(833		)	(497		)	Derivative liabilities — current	(1,042		)	(833		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(18		)	(56		)	(164		)	Other deferred credits and other liabilities	(73		)	(56		)
Total derivatives not designated as hedges		$	745		$	197		$	(366	)		$	(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

~~The estimated fair values of our~~Other financial instruments ~~excluding derivatives~~for which ~~are presented in Note 11,~~the carrying value did not equal fair value were as follows (in thousands) as of:

March 31, 2019 December 31, 2018 March 31, 2018

Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Cash and cash equivalents ^(a)
$ 12,225
$ 12,225
$ 20,776
$ 20,776
$ 30,947
$ 30,947
Restricted cash ^(a)
$ 3,494
$ 3,494
$ 3,369
$ 3,369
$ 2,958
$ 2,958
Notes payable ^(b)
$ 164,650
$ 164,650
$ 185,620
$ 185,620
$ 164,200
$ 164,200
Long-term debt, including current maturities ^{(c) (d)}
$ 2,956,042
$ 3,137,538
$ 2,956,578
$ 3,039,108
$ 3,114,530
$ 3,265,965



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


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


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


~~(d)~~(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						Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended							Three Months Ended						Six Months Ended
		March 31, 2019			March 31, 2018				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	)	Interest expense	$	(713	)	$	(713	)	$	(1,426	)	$	(1,426	)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	554			(621		)	Fuel, purchased power and cost of natural gas sold	83			(163		)	637			(784		)
		(159		)	(1,334		)		(630		)	(876		)	(789		)	(2,210		)
Income tax	Income tax benefit (expense)	35			297			Income tax benefit (expense)	153			197			188			494
Total reclassification adjustments related to cash flow hedges, net of tax		$	(124	)	$	(1,037	)		$	(477	)	$	(679	)	$	(601	)	$	(1,716	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	19		$	45		Operations and maintenance	$	20		$	44		$	39		$	89

Actuarial gain (loss)	Operations and maintenance	(220		)	(622		)	Operations and maintenance	(221		)	(622		)	(441		)	(1,244		)
		(201		)	(577		)		(201		)	(578		)	(402		)	(1,155		)
Income tax	Income tax benefit (expense)	48			126			Income tax benefit (expense)	47			126			95			252
Total reclassification adjustments related to defined benefit plans, net of tax		$	(153	)	$	(451	)		$	(154	)	$	(452	)	$	(307	)	$	(903	)
Total reclassifications		$	(277	)	$	(1,488	)		$	(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			Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2018	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)
Other comprehensive income (loss)
before reclassifications	—			180			—			180			—			(219		)	—			(219		)
Amounts reclassified from AOCI	550			(426		)	153			277			1,091			(490		)	307			908
As of March 31, 2019	$	(16,757	)	$	82		$	(9,784	)	$	(26,459	)
As of June 30, 2019													$	(16,216	)	$	(381	)	$	(9,630	)	$	(26,227	)


	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total			Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
Balance as of December 31, 2017	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)
Other comprehensive income (loss)
before reclassifications	—			(228		)	—			(228		)	—			(198		)	—			(198		)
Amounts reclassified from AOCI	561			476			451			1,488			1,122			594			903			2,619
Reclassifications of certain tax effects from AOCI	15			—			3			18			15			—			3			18
As of March 31, 2018	$	(19,005	)	$	(270	)	$	(20,649	)	$	(39,924	)
As of June 30, 2018													$	(18,444	)	$	(122	)	$	(20,197	)	$	(38,763	)

(14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


Three Months Ended	March 31, 2019			March 31, 2018
Six Months Ended							June 30, 2019			June 30, 2018
	(in thousands)						(in thousands)
Non-cash investing and financing activities —
Property, plant and equipment acquired with accrued liabilities	$	56,571		$	21,708		$	83,486		$	37,168

Cash (paid) refunded during the period —
Interest (net of amounts capitalized)	$	(30,672	)	$	(36,928	)	$	(67,624	)	$	(67,119	)
Income taxes	$	8		$	(14,336	)	$	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 March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018
Service cost	$	1,346		$	1,708		$	1,345		$	1,709		$	2,691		$	3,417
Interest cost	4,343			3,867			4,344			3,868			8,687			7,735
Expected return on plan assets	(6,100		)	(6,185		)	(6,100		)	(6,185		)	(12,200		)	(12,370		)
Prior service cost	6			15			7			14			13			29
Net loss (gain)	941			2,158			940			2,157			1,881			4,315
Net periodic benefit cost	$	536		$	1,563		$	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 March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018
Service cost	$	454		$	573		$	454		$	572		$	908		$	1,145
Interest cost	560			521			563			521			1,123			1,042
Expected return on plan assets	(57		)	(57		)	(58		)	(56		)	(115		)	(113		)
Prior service cost (benefit)	(99		)	(99		)	(100		)	(99		)	(199		)	(198		)
Net loss (gain)	—			54			—			54			—			108
Net periodic benefit cost	$	858		$	992		$	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 March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Service cost^(a)	$	1,285	$	280	$	692	$	435	$	1,977	$	715
Interest cost	324		293		324		292		648		585
Prior service cost					1		1		1		1
Net loss (gain)	134		250		134		250		268		500
Net periodic benefit cost	$	1,743	$	823	$	1,151	$	978	$	2,894	$	1,801

~~__________~~


~~(a)~~	~~The increase in service cost for the three months ended March 31, 2019 compared to the same period in 2018 is primarily driven by market returns.~~

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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		Additional Contributions		Contributions		Contributions Made				Additional Contributions		Contributions
	Three Months Ended March 31, 2019		Anticipated for 2019		Anticipated for 2020		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	$	—	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,109	$	3,326	$	4,271	$	1,108	$	2,217	$	2,217	$	4,271
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	366	$	1,097	$	1,562	$	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.

~~Dividend Restrictions~~Platte River Power Authority PPAs

~~Our Revolving Credit Facility and other debt obligations contain restrictions on the payment~~On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase up to 60 MW of ~~cash dividends~~wind energy upon construction completion of a ~~default or event of default. As of March~~new wind project, which is expected in mid-2020. This agreement will expire May 31, ~~2019, we were in compliance with the debt covenants.~~2030.

~~Due~~On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to ~~our holding company structure, substantially all~~purchase 25 MW of ~~our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders~~unit contingent energy. This agreement is ~~derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.~~effective September 1, 2019 and will expire June 30, 2024.

~~Our utilities are generally limited in the amount~~The following is a schedule of ~~dividends allowed to be paid to us as a utility holding company~~unconditional purchase obligations required under the ~~Federal~~25 MW Platte River Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of March 31, 2019, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.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 ~~have been~~were classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale” and “Current liabilities held for sale”, respectively. Prior periods relating to our discontinued operations ~~have~~were also ~~been~~ reclassified to reflect consistency within our condensed consolidated financial statements.

Oil and Gas Segment

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

~~Total assets and liabilities of~~ ~~our Oil and Gas segment~~ at March 31, 2018 were classified as Current assets held for sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the final disposals occurring in 2018.

As of
(in thousands) March 31, 2018
Other current assets $ 4,332
Deferred income tax assets, noncurrent, net

3,739
Property, plant and equipment, net 16,653
Other current liabilities (17,233 )
Other noncurrent liabilities (7,677 )
Net (liabilities) $ (186 )

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(18) INCOME TAXES

Income tax benefit (expense)~~, net~~ 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 ~~March 31,~~June 30, 2019 was ~~$(17)~~$(2.3) million compared to ~~$26~~$(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:~~


•	Ato 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 current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).

~~Prior year tax benefit related to legal restructuring~~

~~As part of the Company’s ongoing efforts to continue to integrate thelegal entities that the Company acquired in recent years, certain~~ legal entity restructuring ~~transactions occurred on March 31, 2018. As~~partially offset by a ~~result of these transactions, $49~~prior year $(2.3) million ~~of deferred~~ income tax assets, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to Income tax benefit (expense) on the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.

~~Prior year TCJA expense~~

On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. During the three months ended March 31, 2018, we recorded approximately $2.3 million of additional tax expense associated with changes in the prior estimated ~~impacts~~impact of ~~TCJA~~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 ~~items.~~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:


	March 31, 2019		December 31, 2018		March 31, 2018		June 30, 2019		December 31, 2018
Accrued employee compensation, benefits and withholdings	$	48,078	$	63,742	$	46,262	$	50,996	$	63,742
Accrued property taxes	43,662		42,510		42,912		34,966		42,510
Customer deposits and prepayments	39,125		43,574		35,748		40,716		43,574
Accrued interest and contract adjustment payments	35,149		31,759		30,426		32,213		31,759
CIAC current portion	1,485		1,485		1,552		1,485		1,485
Other (none of which is individually significant)	28,573		32,431		37,140		28,141		32,431
Total accrued liabilities	$	196,072	$	215,501	$	194,040	$	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 ~~lease~~ 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 March 31, 2019		Income Statement Location	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	Operations and maintenance	$	311	Operations and maintenance	$	385	$	696
Finance lease cost:
Amortization of right-of-use asset	Depreciation, depletion and amortization	17		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)	3		Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	6		9
Total lease cost		$	331		$	418	$	749

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


	Balance Sheet Location	As of March 31, 2019		Balance Sheet Location	As of June 30, 2019
Assets:
Operating lease assets	Other assets, non-current	$	5,331	Other assets, non-current	$	5,161
Finance lease assets	Other assets, non-current	481		Other assets, non-current	521
Total lease assets		$	5,812		$	5,682

Liabilities:
Current:
Operating leases	Accrued liabilities	$	974	Accrued liabilities	$	1,003
Finance leases	Accrued liabilities	92
Finance lease				Accrued liabilities	106

Noncurrent:
Operating leases	Other deferred credits and other liabilities	4,563		Other deferred credits and other liabilities	4,470
Finance leases	Other deferred credits and other liabilities	391
Finance lease				Other deferred credits and other liabilities	419
Total lease liabilities		$	6,020		$	5,998

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


	Three Months Ended March 31, 2019		Six Months Ended June 30, 2019
Cash paid included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	246	$	528
Operating cash flows from finance lease	$	3	$	9
Financing cash flows from finance lease	$	15	$	40
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	2,328	$	2,738
Finance leases	$	—
Finance lease			$	67

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	As of ~~March 31,~~June 30, 2019
Weighted average remaining lease term (years):
Operating leases	8 years
Finance ~~leases~~lease	5 years

Weighted average discount rate:
Operating leases	~~4.23~~4.25	%
Finance ~~leases~~lease	~~4.21~~4.20	%

As of ~~March 31,~~June 30, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):


	Operating Leases		Finance Leases		Total		Operating Leases		Finance Lease		Total
2019 ^(a)	$	952	$	83	$	1,035	$	705	$	63	$	768
2020	936		111		1,047		976		126		1,102
2021	820		111		931		858		126		984
2022	698		111		809		736		126		862
2023	699		110		809		708		126		834
Thereafter	2,653		9		2,662		2,654		10		2,664
Total lease payments^(b)	$	6,758	$	535	$	7,293	$	6,637	$	577	$	7,214
Less imputed interest	1,221		52		1,273		1,164		52		1,216
Present value of lease liabilities	$	5,537	$	483	$	6,020	$	5,473	$	525	$	5,998


(a)	Includes lease liabilities for the remaining ~~nine~~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 March 31, 2019
Operating lease income Revenue $ 638



	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 ~~March 31,~~June 30, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):


	Operating Leases		Operating Leases
2019 ^(a)	$	1,652	$	1,085
2020	2,010		2,010
2021	1,843		1,843
2022	1,793		1,793
2023	1,799		1,799
Thereafter	55,481		55,481
Total lease receivables	$	64,578	$	64,011


(a)	Includes lease receivables for the remaining ~~nine~~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.

~~Accounting standards for presentation of segments requires an approach based on the way~~Effective January 1, 2019, we ~~organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance. We have~~ changed our measure of segment performance ~~metrics and concluded that adjusted operating income, instead of net income available for common stock that 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 profit and adjust operating income~~presented. See Note 3 for ~~the power sales agreement as an executory contract and not a capital lease.~~

more information.

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 ~~three~~six months ended ~~March 31,~~June 30, 2019 and 2018, and our financial condition as of ~~March 31,~~June 30, 2019 ~~December 31, 2018~~ and ~~March~~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 5357.

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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 ~~March 31,~~June 30, 2019 Compared to Three Months Ended ~~March 31,~~June 30, 2018. Net income from continuing operations available for common stock for the three months ended March 31, 2019 was $104 million, or $1.73 per diluted share, compared to $135 million, or $2.50 per diluted share, reported for the same period in 2018.

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income ~~increased $2.5~~decreased $7.7 million primarily due to ~~favorable winter~~cooler spring weather compared to prior year ~~partially offset by~~and higher operating expenses driven by outside services and employee costs;

Gas Utilities’ adjusted operating income ~~increased~~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~~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 ~~expenses~~income decreased $2.1 million primarily due to lower tons sold driven by ~~outside services~~planned and ~~employee costs;~~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:~~


◦	Aby 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 current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).

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.

Net income available for common stock for the three months ended March 31, 2019 was $104 million, or $1.73 per diluted share, compared to $133 million, or $2.46 per diluted share reported for the same period in 2018. (Loss) from discontinued operations for the three months ended March 31, 2018 was $(2.3) million or $(0.04). There was no (Loss) from discontinued operations for the three months ended March 31, 2019.

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


	Three Months Ended March 31,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Variance			2019			2018			Variance			2019			2018			Variance
Revenue
Revenue	$	635,681		$	611,966		$	23,715		$	369,576		$	390,879		$	(21,303	)	$	1,005,257		$	1,002,844		$	2,413
Inter-company eliminations	(37,871		)	(36,577		)	(1,294		)	(35,688		)	(35,175		)	(513		)	(73,559		)	(71,751		)	(1,808		)
	$	597,810		$	575,389		$	22,421		$	333,888		$	355,704		$	(21,816	)	$	931,698		$	931,093		$	605
Adjusted operating income ^(a)
Electric Utilities	$	41,020		$	38,480		$	2,540		$	33,546		$	41,200		$	(7,654	)	$	74,566		$	79,680		$	(5,114	)
Gas Utilities	103,314			95,443			7,871			8,557			16,485			(7,928		)	111,871			111,928			(57		)
Power Generation	11,967			11,776			191			10,156			8,877			1,279			22,123			20,652			1,471
Mining	4,337			4,271			66			1,640			3,825			(2,185		)	5,977			8,096			(2,119		)
Corporate and Other	(507		)	(1,696		)	1,189			102			(836		)	938			(405		)	(2,531		)	2,126
Operating income	160,131			148,274			11,857			54,001			69,551			(15,550		)	214,132			217,825			(3,693		)

Interest expense, net	(34,717		)	(34,995		)	278			(34,265		)	(34,534		)	269			(68,982		)	(69,529		)	547
Other income (expense), net	(789		)	(104		)	(685		)	264			(1,309		)	1,573			(525		)	(1,413		)	888
Income tax benefit (expense) ^{(b) (c)}	(17,263		)	25,802			(43,065		)
Income tax benefit (expense)										(2,307		)	(6,541		)	4,234			(19,570		)	19,261			(38,831		)
Income from continuing operations	107,362			138,977			(31,615		)	17,693			27,167			(9,474		)	125,055			166,144			(41,089		)
Net (loss) from discontinued operations	—			(2,343		)	2,343			—			(2,427		)	2,427			—			(4,770		)	4,770
Net income	107,362			136,634			(29,272		)	17,693			24,740			(7,047		)	125,055			161,374			(36,319		)
Net income attributable to noncontrolling interest	(3,554		)	(3,630		)	76			(3,110		)	(2,823		)	(287		)	(6,664		)	(6,453		)	(211		)
Net income available for common stock	$	103,808		$	133,004		$	(29,196	)	$	14,583		$	21,917		$	(7,334	)	$	118,391		$	154,921		$	(36,530	)

Amounts attributable to common shareholders:
Net income from continuing operations available for common stock	$	103,808		$	135,347		$	(31,539	)
Net (loss) from discontinued operations	—			(2,343		)	2,343
Net income available for common stock	$	103,808		$	133,004		$	(29,196	)

__________

(a)

~~Due~~In 2019, we changed our measure of segment performance to ~~changes to~~adjusted operating income, which impacted our segment ~~performance measure, Adjusted operating income was recast~~disclosures for all periods presented. See Note 3 of the ~~three months ended March 31, 2018~~Notes to Condensed Consolidated Financial Statements for ~~Electric Utilities and Power Generation segments and Corporate and Other. These changes had no impact on our consolidated financial results. See segment discussions in the sections below for more~~additional information.


~~(b)~~	Income tax benefit (expense) for the three months ended March 31, 2019 included a $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).


~~(c)~~	~~Income tax benefit (expense) for the three months ended March 31, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring and $2.3 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.~~

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 ~~colder winter~~cooler spring weather during the three and six months ended ~~March 31,~~June 30, 2019 compared to the same ~~period~~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 ~~March 31,~~June 30, 2019 were 7%12% and 8% higher than normal, compared to 1%12% lower and 7% higher than normal for the same ~~period~~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 ~~March 31,~~June 30, 2019 compared to the same ~~period~~periods in 2018. Heating degree days for the three and six months ended ~~March 31,~~June 30, 2019 were ~~11%~~5% and 10% higher than normal, compared to 2%1% lower and 1% higher than normal for the same ~~period~~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 ~~consolidate~~merge its two natural gas distribution ~~utilities into a new public utility entity. The filing also requests~~companies in Nebraska. A rate review is expected to be filed in 2020 to consolidate the ~~terms~~rates, tariffs and ~~conditions~~services of ~~the~~its two existing ~~tariffs of the two utilities into a single tariff.~~


◦	~~On March 6, 2019, Wyoming Gas filed an application with the WPSC to consolidate its four~~natural gas distribution ~~utilities into a new public utility entity. The filing also requests the new entity adopt the terms and conditions of the existing tariffs.~~companies.

◦

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate ~~the base rate areas,~~rates, tariffs ~~terms~~ and ~~conditions and adjustment clauses~~services of its two ~~legacy utilities.~~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-megawatt~~60 MW Busch Ranch II Wind Farm. The wind ~~farm is expected~~generation project remains on schedule to be ~~completed and~~ 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 April 30, 2019, S&P affirmed South Dakota Electric’s credit rating at A.

~~During the three months ended March 31, 2019, we issued a total of 280,497 shares of common stock for net proceeds of approximately $20 million through our ATM equity offering program.~~

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 March 31,						Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance		2019		2018		Variance			2019		2018		Variance
	(in thousands)						(in thousands)
Revenue	$	182,927	$	173,555	$	9,372	$	166,354	$	173,616	$	(7,262	)	$	349,281	$	347,171	$	2,110

Total fuel and purchased power	73,283		68,738		4,545		62,128		65,942		(3,814		)	135,411		134,680		731

Gross margin (non-GAAP)	109,644		104,817		4,827		104,226		107,674		(3,448		)	213,870		212,491		1,379

Operations and maintenance	47,144		45,093		2,051		48,734		45,101		3,633			95,878		90,194		5,684
Depreciation and amortization	21,480		21,244		236		21,947		21,373		574			43,427		42,617		810
Total operating expenses	68,624		66,337		2,287		70,681		66,474		4,207			139,305		132,811		6,494

Adjusted operating income ^(a)	$	41,020	$	38,480	$	2,540	$	33,545	$	41,200	$	(7,655	)	$	74,565	$	79,680	$	(5,115	)

________________

(a)

Due to the changes toin our segment ~~performance measure,~~disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Electric Utilities Adjusted operating income was ~~recast~~revised for the three and six months ended June 30, 2018, which resulted in ~~a change~~an increase of ~~$1.7 million. The impact to Adjusted operating income for the three months ended March 31, 2019 was ($5.4) million. There was no impact on our consolidated Operating income.~~$1.6 million and $3.3 million, respectively.

Results of Operations for the Electric Utilities for the Three Months Ended ~~March 31,~~June 30, 2019 Compared to the Three Months Ended ~~March 31,~~June 30, 2018:

Gross margin for the three months ended ~~March 31,~~June 30, 2019 ~~increased~~decreased as a result of the following:

(in millions)
Reduction in purchased power capacity charges $ 1.6
Off-system power marketing 1.3
Weather 0.6
Rider recovery 0.4
Residential customer growth 0.3
Other 0.6
Total increase in Gross margin (non-GAAP) $ 4.8



	(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 ~~higher outside services expenses and~~$1.5 million of higher employee costs driven by ~~labor~~additional headcount and ~~benefits.~~

~~Depreciation and amortization~~ ~~was comparable~~$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)		Electric Revenue (in thousands)								Quantities sold (MWh)
	Three Months Ended March 31,				Three Months Ended March 31,		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		2019	2018	2019	2018
Residential	$	57,638	$	55,741	389,178	383,270	$	45,700	$	50,116	$	103,338	$	105,857	301,481	328,638	690,659	711,908
Commercial	60,963		61,984		505,573	500,136	59,739		64,902		120,702		126,886		490,329	509,984	995,902	1,010,120
Industrial	32,440		30,800		426,614	400,709	31,697		31,220		64,137		62,020		445,837	418,596	872,451	819,305
Municipal	4,139		4,141		36,636	36,324	4,253		4,666		8,392		8,807		38,283	42,657	74,919	78,981
Subtotal Retail Revenue - Electric	155,180		152,666		1,358,001	1,320,439	141,389		150,904		296,569		303,570		1,275,930	1,299,875	2,633,931	2,620,314
Contract Wholesale	8,343		9,050		223,020	237,704	6,781		8,191		15,124		17,241		194,222	218,132	417,242	455,836
Off-system/Power Marketing Wholesale	6,692		4,144		140,850	129,041	3,448		4,939		10,140		9,083		135,091	178,854	275,941	307,895
Other	12,712		7,695		—	—	14,736		9,582		27,448		17,277		—	—	—	—
Total Revenue and Energy Sold	182,927		173,555		1,721,871	1,687,184	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	—		—		97,000	90,855	—		—		—		—		89,866	125,606	186,866	216,461
Total Revenue and Energy	182,927		173,555		1,818,871	1,778,039	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)	73,283		68,738				62,128		65,942		135,411		134,680
Gross Margin (non-GAAP) ^(a)	$	109,644	$	104,817			$	104,226	$	107,674	$	213,870	$	212,491

________________

(a)

Due to the changes toin our segment ~~performance measure, Fuel~~disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, cost of fuel and purchased power was ~~recast~~revised for the three and six months ended ~~March 31,~~June 30, 2018, which resulted in ~~a change~~an increase of ~~$1.6 million. The impact to Fuel~~$1.7 million and ~~purchased power for the three months ended March 31, 2019 was $8.7 million.~~$3.3 million, respectively. There were corresponding ~~changes~~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)
	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(a)		2019		2018		2019		2018		2019	2018
Three Months Ended March 31,	2019		2018		2019		2018		2019	2018
Colorado Electric ^(b)	$	59,847	$	58,353	$	31,444	$	31,746	491,682	487,000	$	55,412	$	62,532	$	31,051	$	35,801	485,346	542,528
South Dakota Electric	79,041		73,815		56,308		51,376		845,001	828,177	69,246		70,676		50,865		49,922		757,640	837,943
Wyoming Electric	44,039		41,387		21,892		21,695		482,188	462,862	41,696		40,408		22,310		21,951		452,123	441,996
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	182,927	$	173,555	$	109,644	$	104,817	1,818,871	1,778,039	$	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 toin our segment ~~performance measure,~~disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Gross margin was ~~recast~~revised for the three and six months ended ~~March 31,~~June 30, 2018, which resulted in a ~~change~~decrease of ~~($1.6) million. The impact to Gross margin for the three months ended March 31, 2019 was ($8.7) million.~~$(1.7) million and $(3.3) million, respectively.


	Three Months Ended March 31,		Three Months Ended June 30,		Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2019	2018	2019	2018	2019	2018

Coal-fired	585,295	595,600	471,840	568,733	1,057,135	1,164,333
Natural Gas and Oil	124,657	41,323	86,475	105,304	211,132	146,627
Wind	55,419	73,981	56,505	68,501	111,924	142,482
Total Generated	765,371	710,904	614,820	742,538	1,380,191	1,453,442
Purchased	1,053,500	1,067,135	1,080,289	1,079,929	2,133,789	2,147,064
Total Generated and Purchased	1,818,871	1,778,039	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 March 31,
Quantities Generated and Purchased (MWh)	2019	2018
Generated:
			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	100,530	92,048	603	(5	)%	31%	460	(27	)%
South Dakota Electric	457,369	412,194	1,279	25	%	23%	1,037	1	%
Wyoming Electric	207,472	206,662	1,359	12	%	29%	1,053	(14	)%
Total Generated	765,371	710,904
Purchased:
Combined^(a)			986	12	%	27%	777	(12	)%

Cooling Degree Days:
Colorado Electric	391,152	394,952	147	(30	)%	(70)%	494	136	%
South Dakota Electric	387,632	415,983	38	(62	)%	(71)%	132	33	%
Wyoming Electric	274,716	256,200	29	(42	)%	(72)%	102	104	%
Total Purchased	1,053,500	1,067,135

Total Generated and Purchased	1,818,871	1,778,039
Combined^(a)			86	(38	)%	(71)%	292	109	%


	Three Months Ended March 31,							Six Months Ended June 30,
	2019				2018			2019				2018
Heating Degree Days	Actual	Variance from Normal		Actual Variance to Prior Year	Actual	Variance from Normal		Actual	Variance from Normal		Actual Variance to Prior Year	Actual	Variance from Normal

Colorado Electric	2,549	(4	)%	6%	2,406	(9	)%	3,152	(4	)%	10%	2,866	12	%
South Dakota Electric	3,916	22	%	6%	3,699	15	%	5,195	23	%	10%	4,736	12	%
Wyoming Electric	3,198	—	%	7%	2,984	(7	)%	4,557	3	%	13%	4,037	(9	)%
Combined^(a)	3,147	7	%	6%	2,964	1	%	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 March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Coal-fired plants(a)	96.2	%	95.0	%	79.2	%	91.2	%	87.7	%	93.1	%
Natural gas-fired plants and Other plants(b)	90.7	%	96.5	%	89.3	%	98.1	%	90.0	%	97.2	%
Wind	96.8	%	97.1	%	94.5	%	96.7	%	95.6	%	96.9	%
Total availability	92.9	%	96.1	%	86.4	%	95.8	%	89.7	%	95.9	%

Wind capacity factor	42.6	%	50.4	%	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.

~~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 of this Quarterly Report on Form 10-Q 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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Gas Utilities


	Three Months Ended March 31,							Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance			2019		2018		Variance			2019		2018		Variance
	(in thousands)							(in thousands)
Revenue:
Natural gas - regulated	$	383,875	$	370,268	$	13,607		$	149,942	$	161,212	$	(11,270	)	$	533,817	$	531,480	$	2,337
Other - non-regulated services	27,205		27,076		129			15,527		16,408		(881		)	42,732		43,484		(752		)
Total revenue	411,080		397,344		13,736			165,469		177,620		(12,151		)	576,549		574,964		1,585

Cost of sales:
Natural gas - regulated	201,050		205,084		(4,034		)	51,108		62,453		(11,345		)	252,158		267,537		(15,379		)
Other - non-regulated services	6,229		4,601		1,628			5,876		5,601		275			12,105		10,202		1,903
Total cost of sales	207,279		209,685		(2,406		)	56,984		68,054		(11,070		)	264,263		277,739		(13,476		)

Gross margin (non-GAAP)	203,801		187,659		16,142			108,485		109,566		(1,081		)	312,286		297,225		15,061

Operations and maintenance	77,938		70,906		7,032			77,130		71,667		5,463			155,068		142,573		12,495
Depreciation and amortization	22,549		21,310		1,239			22,797		21,414		1,383			45,346		42,724		2,622
Total operating expenses	100,487		92,216		8,271			99,927		93,081		6,846			200,414		185,297		15,117

Adjusted operating income	$	103,314	$	95,443	$	7,871		$	8,558	$	16,485	$	(7,927	)	$	111,872	$	111,928	$	(56	)

Results of Operations for the Gas Utilities for the Three Months Ended ~~March 31,~~June 30, 2019 Compared to the Three Months Ended ~~March 31,~~June 30, 2018:

Gross margin for the three months ended ~~March 31,~~June 30, 2019 ~~increased~~decreased as a result of:

(in millions)
New rates $ 8.9
Weather ^(a)
5.2
Customer growth - distribution 1.8
Transport and transmission 1.7
Other 0.9
Excess deferred taxes returned to customers (2.4 )
Total increase in Gross margin (non-GAAP) $ 16.1



	(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) ~~Heating degree days at the Gas Utilities~~Weather impacts for the three months ended ~~March 31,~~June 30, 2019 ~~were 11% higher than normal~~ compared to ~~2% higher than normal in~~ the same period in the prior ~~year.~~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 ~~$3.3~~$2.8 million of higher outside services expenses and ~~$2.3~~$1.6 million of higher employee costs driven by ~~labor, benefits~~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)		Gas Revenue (in thousands)				Gross Margin(non-GAAP)(in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,		Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2019			2018			2019			2018			2019	2018	2019		2018		2019		2018		2019	2018

Residential	$	241,129		$	234,751		$	105,057		$	96,777		32,838,018	30,096,237	$	85,093	$	91,000	$	52,670	$	52,697	7,919,158	8,837,588
Commercial	96,139			95,005			35,158			32,203			14,990,848	13,949,121	30,984		34,031		14,926		14,807		4,194,879	4,615,571
Industrial	6,014			5,982			2,017			1,674			1,182,527	1,183,617	3,980		6,565		1,320		1,639		997,942	1,747,702
Other ^(a)	(4,354		)	(7,531		)	(4,354		)	(7,531		)	—	—	887		255		887		255		—	—
Total Distribution	338,928			328,207			137,878			123,123			49,011,393	45,228,975	120,944		131,851		69,803		69,398		13,111,979	15,200,861

Transportation and Transmission	44,947			42,061			44,947			42,061			46,316,160	44,733,475	28,998		29,361		29,031		29,361		32,767,310	32,846,279

Total Regulated	383,875			370,268			182,825			165,184			95,327,553	89,962,450	149,942		161,212		98,834		98,759		45,879,289	48,047,140

Non-regulated Services	27,205			27,076			20,976			22,475					15,527		16,408		9,651		10,807

Total Gas Revenue & Gross Margin (non-GAAP)	$	411,080		$	397,344		$	203,801		$	187,659				$	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)	~~Includes~~ ~~reserve to~~Other revenue ~~to reflect~~reflects the ~~reduction~~impact of ~~the lower federal income tax rate from~~revenue reserved in accordance with the TCJA ~~on our existing rate tariffs.~~.


	Revenue (in thousands)				Gross Margin (non-GAAP)(in thousands)				Gas Utilities Quantities Sold & Transported (Dth)		Revenue (in thousands)				Gross Margin (non-GAAP)(in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,		Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended June 30,
	2019		2018		2019		2018		2019	2018	2019		2018		2019		2018		2019	2018

Arkansas	$	79,391	$	70,388	$	44,282	$	35,917	12,424,196	11,878,626	$	26,236	$	27,095	$	18,617	$	16,471	4,542,917	5,282,607
Colorado	76,471		71,398		37,600		33,145		13,176,925	11,703,351	36,713		32,138		19,755		18,562		6,067,353	4,705,454
Iowa	65,641		67,884		23,050		22,426		15,663,687	15,502,989	23,714		27,102		14,588		14,648		7,484,272	7,429,328
Kansas	41,217		42,381		18,119		17,897		10,443,270	10,297,328	17,379		21,002		11,957		11,870		6,290,716	6,929,756
Nebraska	108,797		106,761		56,073		53,860		28,999,018	27,987,224	39,315		48,993		27,709		32,801		14,816,996	16,405,326
Wyoming	39,563		38,532		24,677		24,414		14,620,457	12,592,932	22,112		21,290		15,859		15,214		6,677,035	7,294,669
Total Gas Revenue & Gross Margin (non-GAAP)	$	411,080	$	397,344	$	203,801	$	187,659	95,327,553	89,962,450	$	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 March 31,					Three Months Ended June 30,
	2019			2018		2019			2018
Heating Degree Days	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal
Arkansas ^(a)	2,101	—%	3%	2,048	(3)%	246	(25)%	(39)%	400	21%
Colorado	3,030	3%	12%	2,704	(8)%	1,017	6%	38%	735	(23)%
Iowa	3,830	14%	8%	3,531	5%	738	8%	(8)%	801	17%
Kansas ^(a)	2,779	13%	13%	2,470	—%	425	(5)%	(16)%	508	14%
Nebraska	3,483	15%	9%	3,207	6%	664	5%	(6)%	708	12%
Wyoming	3,513	10%	8%	3,244	1%	1,397	15%	30%	1,072	(12)%
Combined ^(b)	3,449	11%	9%	3,159	2%	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 ~~of this Quarterly Report on Form 10-Q~~ 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 March 31,						Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance		2019		2018		Variance			2019		2018		Variance
	(in thousands)						(in thousands)
Revenue	$	25,245	$	23,939	$	1,306	$	24,708	$	22,744	$	1,964		$	49,953	$	46,682	$	3,271

Operations and maintenance	8,688		8,127		561		9,833		9,959		(126		)	18,521		18,086		435
Depreciation and amortization	4,590		4,036		554		4,719		3,908		811			9,309		7,944		1,365
Total operating expense	13,278		12,163		1,115		14,552		13,867		685			27,830		26,030		1,800

Adjusted operating income ^(a)	$	11,967	$	11,776	$	191	$	10,156	$	8,877	$	1,279		$	22,123	$	20,652	$	1,471

________________

(a)

Due to the changes toin our segment ~~performance measure,~~disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Power Generation Adjusted operating income was ~~recast~~revised for the three and six months ended ~~March 31,~~June 30, 2018, which resulted in a ~~change~~decrease of ~~($1.6) million. The impact to Adjusted operating income for the three months ended March 31, 2019 was $0.7 million. There was no impact on our consolidated Operating income.~~$(1.4) million and $(3.0) million, respectively.

Results of Operations for Power Generation for the Three and Six Months Ended ~~March 31,~~June 30, 2019 Compared to the Three and Six Months Ended ~~March 31,~~June 30, 2018: Revenue increased in the current year due to increased wind ~~megawatt hours~~MWh sold and higher ~~power purchase agreement~~PPA prices. Operating expenses increased in the current year due to higher ~~employee costs~~depreciation and ~~higher depreciation~~property taxes from new wind assets.

The following table summarizes MWh for our Power Generation segment:


	Three Months Ended March 31,		Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018	2019	2018
Quantities Sold, Generated and Purchased (MWh) ^(a)
Sold
Black Hills Colorado IPP ^(b)	205,973	232,375	210,316	208,888	416,289	441,263
Black Hills Wyoming ^(c)	164,049	165,601	149,713	144,460	313,762	310,061
Black Hills Electric Generation ^(d)	12,864	—	47,796	—	81,549	—
Total Sold	382,886	397,976	407,825	353,348	811,600	751,324

Generated
Black Hills Colorado IPP ^(b)	205,973	232,375	210,316	208,888	416,289	441,263
Black Hills Wyoming ^(c)	132,593	134,029	132,189	128,819	264,782	262,848
Black Hills Electric Generation ^(d)	12,864	—	47,796	—	81,549	—
Total Generated	351,430	366,404	390,301	337,707	762,620	704,111

Purchased
Black Hills Wyoming ^(c)	25,579	31,917	13,761	17,122	39,340	49,039
Total Purchased	25,579	31,917	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 ~~primarily~~ by Black Hills Electric Generation’s acquisition of ~~a 50% ownership interest in Busch Ranch I on December 11, 2018.~~new wind assets.

Table of Contents

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


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Contracted power plant fleet availability:
Coal-fired plant	94.8	%	94.7	%	95.8	%	89.1	%	95.3	%	91.9	%
Natural gas-fired plants(a)	95.6	%	99.5	%	88.7	%	99.5	%	92.1	%	99.5	%
Wind ^(a)(b)	90.4	%	N/A		94.1	%	N/A		92.3	%	N/A
Total availability	94.1	%	98.3	%	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 acquired a 50% ownership interest in Busch Ranch I on December 11, 2018.~~Generation’s acquisition of new wind assets.

Mining


	Three Months Ended March 31,							Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Variance			2019		2018		Variance			2019		2018		Variance
	(in thousands)							(in thousands)
Revenue	$	16,429	$	17,128	$	(699	)	$	13,045	$	16,899	$	(3,854	)	$	29,474	$	34,027	$	(4,553	)

Operations and maintenance	9,913		10,922		(1,009		)	9,175		11,124		(1,949		)	19,088		22,046		(2,958		)
Depreciation, depletion and amortization	2,179		1,935		244			2,230		1,950		280			4,409		3,885		524
Total operating expenses	12,092		12,857		(765		)	11,405		13,074		(1,669		)	23,497		25,931		(2,434		)

Adjusted operating income	$	4,337	$	4,271	$	66		$	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 March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
Tons of coal sold	997		1,078		754		963		1,751		2,041
Cubic yards of overburden moved	1,994		2,022		2,045		2,380		4,039		4,402

Revenue per ton	$	15.87	$	15.89	$	16.48	$	16.97	$	16.14	$	16.12

Results of Operations for Mining for the Three Months Ended ~~March 31,~~June 30, 2019 Compared to the Three Months Ended ~~March 31,~~June 30, 2018:

Current year revenue decreased due to 8%22% fewer tons sold driven primarily by a planned ~~outage at the Wyodak power plant.~~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 March 31,
2,019 2.018 Variance
(in thousands)
Adjusted operating (loss) ^(a)
$ (507 ) $ (1,696 ) $ 1,189



	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 toin our segment ~~performance measure,~~disclosures as discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Corporate and Other Adjusted operating ~~loss~~income (loss) was ~~recast~~revised for the three and six months ended ~~March 31,~~June 30, 2018, which ~~results~~resulted in a ~~change~~decrease of ~~($0.1) million. The impact to Adjusted operating loss for the three months ended March 31, 2019 was $4.7 million. There was no impact on our consolidated Operating income.~~$(0.2) million and $(0.3) million, respectively.

Results of Operations for Corporate and Other for the Three and Six Months Ended ~~March 31,~~June 30, 2019 Compared to the Three and Six Months Ended ~~March 31,~~June 30, 2018:

The variance in Adjusted operating ~~loss~~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) ~~benefit~~

~~Interest Expense~~

~~Interest expense, net~~ for the ~~three months ended March 31,~~Three Months Ended June 30, 2019 ~~was $35 million compared~~Compared to ~~$35 million for~~ the ~~same period in 2018.~~

~~Other (Expense) Income~~

~~Other (expense) income, net for the three months ended March 31, 2019 was $(0.8) million compared to $(0.1) million for the same period in~~Three Months Ended June 30, 2018.

Income Tax Benefit (Expense)

Income tax benefit (expense)~~, net~~ for the three months ended ~~March 31,~~June 30, 2019 was ~~$(17)~~$(2.3) million compared to ~~$26~~$(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:~~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.

•

~~A prior year $49 million tax benefit resulting fromlegal entity restructuring partially offset by:~~

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.


◦	~~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 current year $3.4 million increase in income tax benefit from forecasted federal production tax credits and state investment tax credits as well as $1.8 million of income tax benefit for deferred tax amortization related to tax reform (which is offset by reduced revenue at our utilities).

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

~~OVERVIEW~~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.

Our Company requires significant cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate. As discussed in more detail below under income taxes, we expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers.

The most significant uses of cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the summer construction season.

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.

~~Significant Factors Affecting Liquidity~~

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies, and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.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 ~~March 31,~~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. ~~This~~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 ~~three~~six months ended ~~March 31~~June 30, 2019 (in thousands):


Cash provided by (used in):	2019			2018			Variance			2019			2018			Variance
Operating activities	$	175,893		$	169,875		$	6,018		$	289,779		$	310,701		$	(20,922	)
Investing activities	$	(145,027	)	$	(73,554	)	$	(71,473	)	$	(317,297	)	$	(163,526	)	$	(153,771	)
Financing activities	$	(39,292	)	$	(80,656	)	$	41,364		$	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 ~~$176~~$290 million for the ~~three~~six months ended ~~March 31,~~June 30, 2019, compared to net cash provided by operating activities of ~~$170~~$311 million for the same period in 2018 for ~~an increase~~a decrease of $6$21 million. The variance was primarily attributable to:

Cash earnings (income from continuing operations plus non-cash adjustments) were ~~$18~~$13 million higher for the ~~three~~six months ended ~~March 31,~~June 30, 2019 compared to the same period in the prior year;

Net cash ~~outflows~~inflows from changes in operating assets and liabilities were ~~$15~~$14 million for the ~~three~~six months ended ~~March 31,~~June 30, 2019, compared to net cash ~~outflows~~inflows of $1$47 million in the same period in the prior year. This ~~$14~~$33 million ~~increase~~decrease was primarily due to:


◦	Cash inflows increased by approximately $7$46 million primarily as a result of higher collections of accounts receivable, partially offset by higher materials inventory ~~and natural gas in storage~~to support capital projects for the ~~three~~six months ended ~~March 31,~~June 30, 2019 compared to the same period in the prior year;


◦	Cash outflows ~~decreased~~increased by approximately ~~$29~~$11 million as a result of ~~increases~~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 ~~$53~~$66 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments ~~and~~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 ~~$145~~$317 million for the ~~three~~six months ended ~~March 31,~~June 30, 2019, compared to net cash used in investing activities of ~~$74~~$164 million for the same period in 2018 for a variance of ~~$71~~$154 million. The variance was primarily attributable to:

Capital expenditures of approximately ~~$144~~$318 million for the ~~three~~six months ended ~~March 31,~~June 30, 2019 compared to ~~$70~~$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 ~~increased programmatic spending~~the 35-mile Natural Bridge pipeline project at our Gas ~~and Electric Utilities;~~Utilities segment; and

A $24 million investment made in the prior year partially offset by ~~a $20~~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 ~~used in~~provided by financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2019 was ~~$39~~$14 million, compared to ~~$81~~$154 million of net cash used in financing activities for the same period in 2018 for a variance of ~~$41~~$167 million. This variance is primarily due to:

~~Lower current year net repayments of short-term borrowings of $26~~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 ~~$20~~$69 million through our ATM equity offering program; ~~and~~

$~~4.9~~10 million of higher current year dividend ~~payments.~~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 ~~$30~~$61 million for the ~~three~~six months ended ~~March 31,~~June 30, 2019, or $0.505 per share per quarter. On ~~April 29,~~July 31, 2019, our board of directors declared a quarterly dividend of $0.505 per share payable ~~June~~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.

~~Debt~~

Financing Transactions and Short-Term Liquidity

~~Our principal sources to meet day-to-day operating cash requirements are cash from operations, our CP Program and our corporate Revolving Credit Facility.~~

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which 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. See Note 8 for more information.

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			Current		Revolver Borrowings at		CP Program Borrowings at		Letters of Credit at		Available Capacity at
Credit Facility	Expiration	Capacity		March 31, 2019				March 31, 2019				Expiration	Capacity		June 30, 2019				June 30, 2019
Revolving Credit Facility	July 30, 2023	$	750	$	—	$	165	$	14	$	571	July 30, 2023	$	750	$	—	$	103	$	10	$	637

The weighted average interest rate on CP Program borrowings at ~~March 31,~~June 30, 2019 was ~~2.71%~~2.60%. Revolving Credit Facility and CP Program financing activity for the ~~three~~six months ended ~~March 31,~~June 30, 2019 was (dollars in millions):


	For the Three Months Ended March 31, 2019			For the Six Months Ended June 30, 2019
Maximum amount outstanding - commercial paper (based on daily outstanding balances)	$	237		$	237
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances)	$	—		$	—
Average amount outstanding - commercial paper (based on daily outstanding balances)	$	172		$	160
Average amount outstanding - revolving credit facility (based on daily outstanding balances)	$	—		$	—
Weighted average interest rates - commercial paper	2.70		%	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. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness (which includes letters of credit and certain guarantees issued), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests in subsidiaries. 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 ~~March 31,~~June 30, 2019.

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

~~Financing Activities~~

~~Financing activities for the three months ended March 31, 2019 consisted~~ See Note 8 of the ~~following:~~

We issued a total of 280,497 shares of common stock under the ATM equity offering program for $20 million, net of $0.2 million in commissions. As of March 31, 2019, there were no shares that were sold, but not settled.

~~Short-term borrowings from our CP Program.~~

~~Future Financing Plans~~

~~Evaluating refinancing options for our $200 million senior notes due July 15, 2020 and the $300 million Corporate term loan due July 30, 2020.~~

~~Continue our ATM equity offering program~~Notes to ~~issue an additional $60 to $80 million of common stock for the remainder of 2019.~~

~~Dividend Restrictions~~

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.

As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. See Note 16Condensed Consolidated Financial Statements for more information.

Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants.

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 ~~March 31,~~June 30, 2019, we were in compliance with these covenants.

~~There~~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 ~~other material changes in~~shares that were sold, but not settled.

Short-term borrowings from our ~~financing transactions and short-term liquidity from those reported in Item 7~~CP Program.

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Future Financing Plans

Evaluate refinancing options for our ~~2018~~ ~~Annual Report on Form 10-K filed with the SEC.~~$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 ~~March 31,~~June 30, 2019:



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

__________


(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 ~~March 31,~~June 30, 2019:



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

__________


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


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


(c)	On ~~October 11, 2018,~~July 23, 2019, Fitch affirmed A rating.

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Capital Requirements

Capital Expenditures


	Actual		Planned										Actual		Planned
Capital Expenditures by Segment	Three Months Ended March 31, 2019 ^(a)		2019^(b)		2020		2021		2022		2023		Six Months Ended June 30, 2019 ^(a)		2019^(b)		2020		2021		2022		2023
(in millions)
Electric Utilities ^(c)	$	35	$	205	$	221	$	203	$	170	$	137	$	87	$	205	$	221	$	203	$	170	$	137
Gas Utilities ^(c)	58		464		323		289		277		274		185		464		323		289		277		274
Power Generation	28		84		9		8		10		4		41		84		9		8		10		4
Mining	4		8		7		11		10		7		5		8		7		11		10		7
Corporate and Other	7		16		22		8		5		7		14		16		22		8		5		7
	$	132	$	777	$	582	$	519	$	472	$	429	$	332	$	777	$	582	$	519	$	472	$	429

__________

(a) Expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2019 include the impact of accruals for property, plant and equipment.

(b) Includes actual capital expenditures for the ~~three~~six months ended ~~March 31,~~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.~~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.

~~Guarantees~~

Off-Balance Sheet Commitments

There have been no significant changes to ~~guarantees~~off-balance sheet commitments from those previously disclosed in ~~Note 20~~Item 7 of ~~the Notes to the Consolidated Financial Statements in~~ our 2018 Annual Report on Form ~~10-K.~~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

~~Utilities~~

Our utility customers are exposed to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, optionsInformation regarding our quantitative and ~~basis swaps to reduce our customers’ underlying exposure to these fluctuations. We also reduce the commodity price~~qualitative disclosures about market risk is disclosed in ~~the unregulated area~~Item 7A of our ~~business by using over-the-counter~~Annual Report on Form 10-K. During the six months ended June 30, 2019, there were no material changes to our quantitative and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales. The fair value of our utilities’ derivative contracts is summarized below (in thousands) as of:

March 31, 2019 December 31, 2018 March 31, 2018
Net derivative (liabilities) assets $ (2,203 ) $ (2,214 ) $ (6,002 )
Cash collateral offset in Derivatives 3,621
4,386
5,078
Cash collateral included in Other current assets 1,717
2,880
2,020
Net asset (liability) position $ 3,135
$ 5,052
$ 1,096
qualitative disclosures about market risk.

~~Financing Activities~~

From time-to-time, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. At March 31, 2019, December 31, 2018 and March 31, 2018, we had no outstanding interest rate swap agreements.

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 ~~March 31,~~June 30, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at ~~March 31,~~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 ~~March 31,~~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 1A.~~	~~Risk Factors~~

~~There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2018 Annual Report on Form 10-K filed with the SEC.~~


~~ITEM 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~

~~There were no unregistered securities sold during the three months ended March 31, 2019.~~


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 5.~~	~~Other Information~~

~~None.~~


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:	~~May 3,~~August 6, 2019

5760



	As of March 31, 2019	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	58.1%	Less than	65%



	(in millions)
Reduction in purchased power capacity charges	$	1.6
Off-system power marketing	1.3
Weather	0.6
Rider recovery	0.4
Residential customer growth	0.3
Other	0.6
Total increase in Gross margin (non-GAAP)	$	4.8



	Three Months Ended March 31,
	2,019			2.018			Variance
	(in thousands)
Adjusted operating (loss) ^(a)	$	(507	)	$	(1,696	)	$	1,189