SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



x☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended	June 30, ~~2018~~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



	Large ~~accelerated filer~~ Accelerated Filer	x		Accelerated ~~filer~~ o Filer	☐

	Non-accelerated ~~filer~~ o Filer	~~(Do not check if a smaller reporting company)~~☐		Smaller Reporting Company	☐

			~~Smaller reporting company~~ o
Emerging Growth Company
			~~Emerging growth company~~ o ☐

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



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



Class	Outstanding at July 31, ~~2018~~2019
Common stock, $1.00 par value	~~53,594,876~~61,063,230	shares

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)
~~APSC~~	~~Arkansas Public Service Commission~~
Arkansas Gas	Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc.
ASC	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
ATM	At-the-market equity offering program
Availability	The availability factor of a power plant is the percentage of the time that it is available to provide energy.
~~Bbl~~	~~Barrel~~
BHC	Black Hills Corporation; the Company
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility companies
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
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 ~~Electric,~~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 and including the aggregate outstanding amount of RSNs)~~interest) plus ~~Consolidated Indebtedness~~consolidated indebtedness (including letters of credit and certain guarantees ~~issued and excluding RSNs)~~issued) as defined within the current Revolving Credit ~~Agreement.~~Facility.
~~CDD~~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 over a 30-year average.~~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 ~~has~~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
~~HDD~~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 over a 30-year average.~~
~~Horizon Point~~	~~Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.~~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)
~~LIBOR~~	~~London Interbank Offered Rate~~
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)
~~OCA~~NPSC	~~Office of Consumer Advocate~~
~~Peak View Wind Project~~	~~$109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm~~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.
~~RMNG~~	Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy)
RSNs	Remarketable junior subordinated notes, issued on November 23, 2015 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
~~VIE~~Tech Services	~~Variable interest entity~~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)

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017			2019			2018			2019			2018
	(in thousands, except per share amounts)												(in thousands, except per share amounts)

Revenue	$	355,704		$	341,829		$	931,093		$	889,357		$	333,888		$	355,704		$	931,698		$	931,093

Operating expenses:
Fuel, purchased power and cost of natural gas sold	104,661			98,164			352,300			317,941			89,826			104,661			338,605			352,300
Operations and maintenance	118,282			111,897			234,378			226,449			124,931			118,282			248,844			234,378
Depreciation, depletion and amortization	48,709			46,825			97,299			93,527			51,595			48,709			102,623			97,299
Taxes - property, production and severance	13,976			13,072			27,276			26,458
Taxes - property and production													13,142			13,976			26,661			27,276
Other operating expenses	525			2,075			2,015			5,000			393			525			833			2,015
Total operating expenses	286,153			272,033			713,268			669,375			279,887			286,153			717,566			713,268

Operating income	69,551			69,796			217,825			219,982			54,001			69,551			214,132			217,825

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(35,425		)	(35,072		)	(70,880		)	(70,130		)
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)													(36,058		)	(35,365		)	(72,032		)	(70,803		)
Allowance for funds used during construction - borrowed	511			822			644			1,308			1,397			511			2,355			644
Capitalized interest	60			58			77			133
Interest income	320			257			630			298			396			320			695			630
Allowance for funds used during construction - equity	242			794			310			1,286			127			242			175			310
Other income (expense), net	(1,551		)	(76		)	(1,723		)	(195		)	137			(1,551		)	(700		)	(1,723		)
Total other income (expense), net	(35,843		)	(33,217		)	(70,942		)	(67,300		)
Total other income (expense)													(34,001		)	(35,843		)	(69,507		)	(70,942		)

Income before income taxes	33,708			36,579			146,883			152,682			20,000			33,708			144,625			146,883
Income tax benefit (expense)	(6,541		)	(10,652		)	19,261			(45,040		)	(2,307		)	(6,541		)	(19,570		)	19,261
Income from continuing operations	27,167			25,927			166,144			107,642			17,693			27,167			125,055			166,144
(Loss) from discontinued operations, net of tax	(2,427		)	(616		)	(4,770		)	(2,185		)
Net (loss) from discontinued operations													—			(2,427		)	—			(4,770		)
Net income	24,740			25,311			161,374			105,457			17,693			24,740			125,055			161,374
Net income attributable to noncontrolling interest	(2,823		)	(3,116		)	(6,453		)	(6,739		)	(3,110		)	(2,823		)	(6,664		)	(6,453		)
Net income available for common stock	$	21,917		$	22,195		$	154,921		$	98,718		$	14,583		$	21,917		$	118,391		$	154,921

Amounts attributable to common shareholders:
Net income from continuing operations	$	24,344		$	22,811		$	159,691		$	100,903		$	14,583		$	24,344		$	118,391		$	159,691
Net (loss) from discontinued operations	(2,427		)	(616		)	(4,770		)	(2,185		)	—			(2,427		)	—			(4,770		)
Net income available for common stock	$	21,917		$	22,195		$	154,921		$	98,718		$	14,583		$	21,917		$	118,391		$	154,921

Earnings per share of common stock:
Earnings (loss) per share, Basic -
Income from continuing operations, per share	$	0.46		$	0.43		$	2.99		$	1.90
(Loss) from discontinued operations, per share	(0.05		)	(0.01		)	(0.09		)	(0.04		)
Earnings per share, Basic	$	0.41		$	0.42		$	2.90		$	1.86
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations													$	0.24		$	0.46		$	1.97		$	2.99
(Loss) from discontinued operations													—			(0.05		)	—			(0.09		)
Total earnings per share of common stock, Basic													$	0.24		$	0.41		$	1.97		$	2.90

Earnings (loss) per share, Diluted -
Income from continuing operations, per share	$	0.45		$	0.41		$	2.94		$	1.83
(Loss) from discontinued operations, per share	(0.05		)	(0.01		)	(0.09		)	(0.04		)
Earnings per share, Diluted	$	0.40		$	0.40		$	2.85		$	1.79
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations													$	0.24		$	0.45		$	1.96		$	2.94
(Loss) from discontinued operations													—			(0.05		)	—			(0.09		)
Total earnings per share of common stock, Diluted													$	0.24		$	0.40		$	1.96		$	2.85

Weighted average common shares outstanding:
Basic	53,355			53,229			53,337			53,191			60,467			53,355			60,195			53,337
Diluted	54,520			55,384			54,361			55,179			60,606			54,520			60,333			54,361

Dividends declared per share of common stock	$	0.475		$	0.445		$	0.950		$	0.890

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

~~BLACK HILLS CORPORATION~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

(unaudited) Three Months Ended
June 30, Six Months Ended
June 30,
2018 2017 2018 2017
(in thousands)

Net income $ 24,740
$ 25,311
$ 161,374
$ 105,457

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $9 and $18 for the three months ended June 30, 2018 and 2017 and $19 and $35 for the six months ended June 30, 2018 and 2017, respectively) (35 ) (31 ) (70 ) (62 )
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(135) and $(146) for the three months ended June 30, 2018 and 2017 and $(271) and $(300) for the six months ended June 30, 2018 and 2017, respectively) 487
268
973
528
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(152) and $(249) for the three months ended June 30, 2018 and 2017 and $(304) and $(530) for the six months ended June 30, 2018 and 2017, respectively) 561
464
1,122
985
Net unrealized gains (losses) on commodity derivatives (net of tax (expense) benefit of $(18) and $(194) for the three months ended June 30, 2018 and 2017 and $51 and $(536) for the six months ended June 30, 2018 and 2017, respectively) 30
331
(198 ) 915
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax (expense) benefit of $(45) and $143 for the three months ended June 30, 2018 and 2017 and $(190) and $249 for the six months ended June 30, 2018 and 2017, respectively) 118
(243 ) 594
(424 )
Other comprehensive income, net of tax 1,161
789
2,421
1,942

Comprehensive income 25,901
26,100
163,795
107,399
Less: comprehensive income attributable to noncontrolling interest (2,823 ) (3,116 ) (6,453 ) (6,739 )
Comprehensive income available for common stock $ 23,078
$ 22,984
$ 157,342
$ 100,660

~~See Note~~ 14 ~~for additional disclosures.~~

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

~~BLACK HILLS CORPORATION~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

(unaudited) As of
June 30,
2018 December 31, 2017 June 30,
2017
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 8,630
$ 15,420
$ 11,528
Restricted cash 3,084
2,820
2,534
Accounts receivable, net 175,612
248,330
166,760
Materials, supplies and fuel 95,454
113,283
95,488
Derivative assets, current 666
304
639
Income tax receivable, net 11,653
—
—
Regulatory assets, current 50,565
81,016
53,061
Other current assets 31,431
25,367
20,768
Current assets held for sale 3,557
84,242
8,478
Total current assets 380,652
570,782
359,256

Investments 41,148
13,090
12,761

Property, plant and equipment 5,702,065
5,567,518
5,423,160
Less: accumulated depreciation and depletion (1,087,689 ) (1,026,088 ) (964,549 )
Total property, plant and equipment, net 4,614,376
4,541,430
4,458,611

Other assets:
Goodwill 1,299,454
1,299,454
1,299,454
Intangible assets, net 7,155
7,559
7,972
Regulatory assets, non-current 210,137
216,438
244,099
Other assets, non-current 17,207
10,149
13,594
Noncurrent assets held for sale —
—
113,999
Total other assets, non-current 1,533,953
1,533,600
1,679,118

TOTAL ASSETS $ 6,570,129
$ 6,658,902
$ 6,509,746

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS OF COMPREHENSIVE INCOME

~~(Continued)~~

(unaudited) As of
June 30,
2018 December 31, 2017 June 30,
2017
(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
Current liabilities:
Accounts payable $ 104,718
$ 160,887
$ 99,296
Accrued liabilities 190,339
219,462
191,806
Derivative liabilities, current 485
2,081
676
Accrued income taxes, net —
1,022
5,160
Regulatory liabilities, current 52,102
6,832
17,305
Notes payable 121,800
211,300
107,975
Current maturities of long-term debt 255,743
5,743
5,743
Current liabilities held for sale 5,448
41,774
10,904
Total current liabilities 730,635
649,101
438,865

Long-term debt 2,858,068
3,109,400
3,160,302

Deferred credits and other liabilities:
Deferred income tax liabilities, net 289,814
336,520
609,843
Regulatory liabilities, non-current 497,929
478,294
199,005
Benefit plan liabilities 162,199
159,646
176,102
Other deferred credits and other liabilities 104,951
105,735
112,550
Non-current liabilities held for sale —
—
23,048
Total deferred credits and other liabilities 1,054,893
1,080,195
1,120,548

Commitments and contingencies (See Notes 9, 11, 16, 17)

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,850; 53,579,986; and 53,513,521 shares, respectively 53,662
53,580
53,514
Additional paid-in capital 1,154,947
1,150,285
1,145,493
Retained earnings 652,642
548,617
512,498
Treasury stock, at cost – 64,981; 39,064; and 39,329 shares, respectively (3,642 ) (2,306 ) (2,325 )
Accumulated other comprehensive income (loss) (38,763 ) (41,202 ) (32,941 )
Total stockholders’ equity 1,818,846
1,708,974
1,676,239
Noncontrolling interest 107,687
111,232
113,792
Total equity 1,926,533
1,820,206
1,790,031

TOTAL LIABILITIES AND TOTAL EQUITY $ 6,570,129
$ 6,658,902
$ 6,509,746



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

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

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

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

See Note 13 for additional disclosures.

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

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED ~~STATEMENTS OF CASH FLOWS~~BALANCE SHEETS

(unaudited) Six Months Ended June 30,
2018 2017
Operating activities: (in thousands)
Net income $ 161,374
$ 105,457
Loss from discontinued operations, net of tax 4,770
2,185
Income from continuing operations 166,144
107,642
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 97,299
93,527
Deferred financing cost amortization 3,694
4,138
Stock compensation 5,221
6,589
Deferred income taxes (21,419 ) 52,385
Employee benefit plans 6,911
5,717
Other adjustments, net 4,884
(6,445 )
Changes in certain operating assets and liabilities:
Materials, supplies and fuel 18,492
7,753
Accounts receivable, unbilled revenues and other operating assets 50,711
94,591
Accounts payable and other operating liabilities (96,394 ) (117,134 )
Regulatory assets - current 55,637
3,086
Regulatory liabilities - current 19,990
5,908
Other operating activities, net (1,372 ) (125 )
Net cash provided by operating activities of continuing operations 309,798
257,632
Net cash provided by operating activities of discontinued operations 903
5,237
Net cash provided by operating activities 310,701
262,869

Investing activities:
Property, plant and equipment additions (156,748 ) (154,294 )
Purchase of investment (24,429 ) —
Other investing activities (373 ) 238
Net cash provided by (used in) investing activities of continuing operations (181,550 ) (154,056 )
Net cash provided by (used in) investing activities of discontinued operations 18,024
(9,474 )
Net cash provided by (used in) investing activities (163,526 ) (163,530 )

Financing activities:
Dividends paid on common stock (50,879 ) (47,544 )
Common stock issued 1,074
2,965
Net (payments) borrowings of short-term debt (89,500 ) 11,375
Long-term debt - repayments (2,871 ) (52,871 )
Distributions to noncontrolling interest (9,998 ) (8,335 )
Other financing activities (1,527 ) (6,659 )
Net cash provided by (used in) financing activities (153,701 ) (101,069 )
Net change in cash, cash equivalents and restricted cash (6,526 ) (1,730 )
Cash, cash equivalents and restricted cash at beginning of period 18,240
15,792
Cash, cash equivalents and restricted cash at end of period $ 11,714
$ 14,062



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

Investments	41,271			41,013

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

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

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

~~See Note~~ 15 ~~for supplemental disclosure of cash flow information.~~

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)



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

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

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

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

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

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

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



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

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

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

See Note 14 for supplemental disclosure of cash flow information.

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY



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



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

Table of Contents

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s ~~2017~~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,”~~“Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our ~~2017~~2018 Annual Report on Form 10-K filed with the SEC.

Segment Reporting

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

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

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. The Oil and Gas segment assets and liabilities ~~are~~were classified as held for sale and the results of operations ~~are~~were shown in income (loss) from discontinued operations, ~~excluding~~except for certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. ~~As of June 30, 2018, we have sold nearly all oil~~At the time the assets were classified as held for sale, depreciation, depletion and ~~gas assets. Transaction closing for~~amortization expenses were no longer recorded. Unless otherwise noted, the ~~last few assets and final accounting are expected within~~amounts presented in the ~~third quarter. The closing of~~accompanying notes to the ~~oil and gas office will occur in August.~~Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 1817 for more information on discontinued operations.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, ~~2018~~,2019 and December 31, ~~2017, and~~ ~~June 30, 2017~~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, as well as changes in market prices.~~requirements. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2019 and June 30, 2018 ~~and~~ ~~June 30, 2017~~, and our financial condition as of June 30, ~~2018~~,2019 and December 31, ~~2017, and~~ ~~June 30, 2017~~,2018 are not necessarily indicative of the results of operations and financial condition to be expected ~~as of or~~ for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

~~Cash and Cash Equivalents and Restricted Cash~~

~~For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.~~

~~Investments~~

We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared.

Recently Issued Accounting Standards

~~Leases, ASU 2016-02~~

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~, which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.

We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance and the impact of this new standard on our financial position, results of operations and cash flows. We are finalizing the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and configured a new lease software solution that we are currently testing. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification.

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

~~In August 2017, the FASB issued ASU 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.~~ This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

Simplifying the Test for Goodwill Impairment, ~~ASU~~ 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment ~~(Topic 350)~~ by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December ~~15,~~1, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this ~~standard~~guidance to have any impact on our financial position, results of operations or cash flows.

Table of Contents

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

~~Revenue from Contracts with Customers,~~Leases, ASU ~~2014-09~~2016-02

~~Effective January 1, 2018, we adopted~~In February 2016, the FASB issued ASU ~~2014-09,~~ ~~Revenue from Contracts with Customers~~2016-02, Leases (Topic ~~606)~~,842) to increase transparency and ~~its related amendments (collectively known as ASC 606).~~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 ~~this~~the new standard, ~~revenue is recognized when a customer obtains control~~disclosures are required to meet the objective of ~~promised goods or services in an amount that reflects~~enabling users of financial statements to assess the ~~consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature,~~ amount, timing and uncertainty of ~~revenue and~~ cash flows arising from ~~contracts~~leases.

We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with ~~customers.~~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 ~~applied~~also elected the ~~five-step method outlined~~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 ~~ASU to all in-scope revenue~~

~~streams~~recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and ~~elected the modified retrospective implementation method. Implementation~~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. ~~Implementation~~

Table of ~~the standard did not have a significant impact on the measurement or recognition~~Contents

(2) REVENUE

Revenue Recognition

As of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.

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

~~Effective~~ January 1, 2018, we adopted ASU ~~2017-07,~~ ~~Compensation – Retirement Benefits~~2014-09, Revenue from Contracts with Customers (Topic ~~715): Improving the Presentation of Net Periodic Pension Cost~~606), and ~~Net Periodic Post-Retirement Benefit Cost~~its related amendments (collectively known as ASC 606). The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the six months ended June 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

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

~~Effective January 1, 2018, we adopted ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force).~~ This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

~~Statement of Cash Flows: Restricted Cash, ASU 2016-18~~

~~Effective January 1, 2018, we adopted ASU 2016-18,~~ ~~Statement of Cash Flows (Topic 230): Restricted Cash.~~ This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.

~~(2) REVENUE~~

Revenue ~~Recognition~~

~~Revenues are~~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. ~~Our primary types of revenue contracts are:~~

~~Regulated natural gas and electric utility services tariffs~~ - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs.

~~Power sales agreements~~ - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered.

~~Coal supply agreements~~ - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered.

~~Other non-regulated services~~ - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided.

The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and six months ended June 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.



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

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


Three Months Ended June 30, 2018	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total		Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Customer Types:
Retail	$	145,377	$	135,863	$	—	$	16,345	$	(7,979	)	$	289,606	$	145,377	$	135,863	$	—	$	16,345	$	(7,979	)	$	289,606
Transportation	—		29,011		—		—		(301		)	28,710		—		29,011		—		—		(301		)	28,710
Wholesale	8,191		—		12,743		—		(11,613		)	9,321		8,191		—		13,603		—		(12,473		)	9,321
Market - off-system sales	4,938		162		—		—		(1,660		)	3,440
Market - Off-System Sales														4,938		162		—		—		(1,660		)	3,440
Transmission/Other	13,356		11,672		—		—		(3,644		)	21,384		13,356		11,672		—		—		(3,644		)	21,384
Revenue from contracts with customers	171,862		176,708		12,743		16,345		(25,197		)	352,461		$	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	$	21,884	$	16,899	$	(34,315	)	$	355,704
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:
Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	16,345	$	(7,978	)	$	8,367	$	—	$	—	$	—	$	16,345	$	(7,978	)	$	8,367
Services transferred over time	171,862		176,708		12,743		—		(17,219		)	344,094		171,862		176,708		13,603		—		(18,079		)	344,094
Revenue from contracts with customers	$	171,862	$	176,708	$	12,743	$	16,345	$	(25,197	)	$	352,461
Revenue from Contracts with Customers														$	171,862	$	176,708	$	13,603	$	16,345	$	(26,057	)	$	352,461

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



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

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



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

Table of Contents

Six Months Ended June 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total
Customer types: (in thousands)
Retail $ 292,434
$ 477,257
$ —
$ 32,902
$ (15,821 ) $ 786,772
Transportation —
70,681
—
—
(710 ) 69,971
Wholesale 17,241
—
26,676
—
(23,826 ) 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
26,676
32,902
(51,814 ) 925,816
Other revenues 1,987
2,096
18,311
1,125
(18,242 ) 5,277
Total revenues $ 347,171
$ 574,964
$ 44,987
$ 34,027
$ (70,056 ) $ 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
26,676
—
(35,994 ) 908,734
Revenue from contracts with customers $ 345,184
$ 572,868
$ 26,676
$ 32,902
$ (51,814 ) $ 925,816

The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.

~~Revenue Not in Scope of ASC 606~~

Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues.

~~Significant Judgments and Estimates~~

~~TCJA Revenue Reserve~~

The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and recorded a reserve to revenue of approximately $8.0 million and $23 million during the three and six months ended June 30, 2018, respectively. As of June 30, 2018, $3.3 million has been returned to customers and approximately $19 million remains in reserve.

~~Unbilled Revenue~~

Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends.

Contract Balances

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

~~Practical Expedients~~

Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

(3) BUSINESS SEGMENT INFORMATION

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

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

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

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

Segment information and Corporate and Other ~~included in the accompanying Condensed Consolidated Statements of Income were~~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

Table of Contents


Three Months Ended June 30, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues			Net income (loss) from continuing operations
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Six Months Ended June 30, 2019																	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
																	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Segment:
Electric	$	166,565	$	1,754	$	5,297		$	—		$	173,616		$	21,890
Gas	176,399		912		309			—			177,620			(1,161		)
Electric Utilities																	$	335,803	$	2,231	$	11,247		$	—		$	349,281
Gas Utilities																	574,803		324		1,422			—			576,549
Power Generation ^(b)(a)	1,130		348		11,613			8,793			21,884			4,772			4,022		870		26,509			18,552			49,953
Mining	8,367		229		7,978			325			16,899			3,005			13,088		557		15,169			660			29,474
Corporate and Other	—		—		—			—			—			(4,162		)
Inter-company eliminations	—		—		(25,197		)	(9,118		)	(34,315		)	—
Inter-company eliminations ^(a)																	—		—		(54,347		)	(19,212		)	(73,559		)
Total	$	352,461	$	3,243	$	—		$	—		$	355,704		$	24,344		$	927,716	$	3,982	$	—		$	—		$	931,698




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

~~Under our modified retrospective adoption~~

Three Months Ended June 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations

Segment:

Electric^.
$ 165,517
$ 2,936
$ 18,832
Gas 166,439
8
(272 )

Power Generation ^(b)
1,470
20,325
5,332
Mining 8,403
6,543
2,681
Corporate and Other —
—
(3,762 )
Inter-company eliminations —
(29,812 ) —
Total $ 341,829
$ —
$ 22,811

Six Months Ended June 30, 2018
External Operating
Revenue
Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric $ 333,743
$ 1,987
$ 11,441
$ —
$ 347,171
$ 41,735
Gas ^(a)
572,141
2,096
727
—
574,964
106,459
Power Generation ^(b)
2,850
718
23,826
17,593
44,987
10,628
Mining 17,082
476
15,820
649
34,027
5,989
Corporate and Other —
—
—
—
—
(5,120 )
Inter-company eliminations —
—
(51,814 ) (18,242 ) (70,056 ) —
Total $ 925,816
$ 5,277
$ —
$ —
$ 931,093
$ 159,691

Six Months Ended June 30, 2017 External Operating Revenue
Inter-company
Operating
Revenue
Net income (loss) from continuing operations

Segment:
Electric $ 337,687
$ 6,790
$ 41,062
Gas 531,340
17
45,738

Power Generation ^(b)
3,572
41,790
11,862
Mining 16,758
14,734
5,571

Corporate and Other ^(c)
—
—
(3,330 )
Inter-company eliminations —
(63,331 ) —
Total $ 889,357
$ —
$ 100,903




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

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

~~Net~~Due to the changes in our segment disclosures, Adjusted operating income ~~from continuing operations available~~was revised for ~~common stock~~the three and six months ended June 30, 2018, which resulted in an increase (decrease) as follows (in millions):



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

Income tax benefit (expense) for the six months ended June 30, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring. See Note ~~19 Income Taxes of the Notes to Condensed Consolidated Financial Statements~~18 for more information.



Total assets (net of inter-company eliminations) as of:	June 30, 2019		December 31, 2018
Segment:
Electric Utilities ^(a)	$	2,777,803	$	2,707,695
Gas Utilities	3,645,840		3,623,475
Power Generation ^(a)	379,140		342,085
Mining	62,491		80,594
Corporate and Other	216,179		209,478
Total assets	$	7,081,453	$	6,963,327

Total Assets (net of inter-company eliminations) as of: June 30, 2018 December 31, 2017 June 30, 2017
Segment:
Electric ^(a)
$ 2,902,925
$ 2,906,275
$ 2,901,570
Gas 3,367,247
3,426,466
3,242,461
Power Generation ^(a)
49,628
60,852
66,292
Mining 68,154
65,455
67,365
Corporate and Other 178,618
115,612
109,581
Discontinued operations 3,557
84,242
122,477
Total assets $ 6,570,129
$ 6,658,902
$ 6,509,746

~~__________~~___________

Table of Contents

(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
June 30, 2018	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
June 30, 2019										Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	44,577	$	34,940	$	(503	)	$	79,014	$	39,982	$	31,573	$	(526	)	$	71,029
Gas Utilities	70,244		23,557		(3,517		)	90,284		67,686		23,753		(4,391		)	87,048
Power Generation	1,681		—		—			1,681		2,867		—		—			2,867
Mining	3,158		—		—			3,158		2,505		—		—			2,505
Corporate	1,475		—		—			1,475		3,233		—		(169		)	3,064
Total	$	121,135	$	58,497	$	(4,020	)	$	175,612	$	116,273	$	55,326	$	(5,086	)	$	166,513

Accounts Unbilled Less Allowance for Accounts
June 30, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net
Electric Utilities $ 41,635
$ 33,686
$ (466 ) $ 74,855
Gas Utilities 62,908
26,584
(2,535 ) 86,957
Power Generation 877
—
—
877
Mining 2,904
—
—
2,904
Corporate 1,167
—
—
1,167
Total $ 109,491
$ 60,270
$ (3,001 ) $ 166,760

(5) REGULATORY ACCOUNTING

Deferred energy and fuel cost adjustments ^(a)

Deferred gas cost adjustments ^(a)

Gas price derivatives ^(a)

Deferred taxes on AFUDC^{(b) (f)}

Employee benefit plans ^(c)

Asset retirement obligations^(a)

Loss on reacquired debt^(a)

Renewable energy standard adjustment ^(a)

Deferred taxes on flow through accounting^{(c) (f)}

Gas supply contract termination ^(a)

Other regulatory assets^(a)

Deferred energy and gas costs^(a)

Employee benefit plan costs and related deferred taxes^{(c) (f)}

Excess deferred income taxes ^{(c) (d)}

TCJA revenue reserve ^(e)

Other regulatory liabilities^(c)

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our ~~2017~~2018 Annual Report on Form 10-K.

~~TCJA revenue reserve -~~Renewable Ready Service Tariffs and Corriedale Wind Energy Project

~~A list of states where benefits to customers of federal tax reform have been approved is summarized below.~~

State Approximate Annual Benefit for Customers Start Date for Customer Benefits
Colorado $ 10.8 million July 2018
Iowa $ 2.2 million June 2018
Kansas $ 1.9 million April 2018
Nebraska $ 3.8 million July 2018

~~In support of returning benefits to customers, the three rate review requests filed in late 2017 for Arkansas Gas,~~ 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 ~~Rocky Mountain Natural Gas (a pipeline system~~services of its four existing gas distribution territories in ~~Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below.~~

On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We expect the final order in the third quarter of 2018. The settlement provides for $1.0 million of new ~~revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, will be effective September 1, 2018.~~

Blockchain Interruptible Service Tariff



	June 30, 2019		December 31, 2018
Materials and supplies	$	80,639	$	75,081
Fuel - Electric Utilities	2,350		2,850
Natural gas in storage held for distribution	19,841		39,368
Total materials, supplies and fuel	$	102,830	$	117,299

June 30, 2018 December 31, 2017 June 30, 2017
Materials and supplies $ 73,075
$ 69,732
$ 68,759
Fuel - Electric Utilities 2,821
2,962
3,106
Natural gas in storage held for distribution 19,558
40,589
23,623
Total materials, supplies and fuel $ 95,454
$ 113,283
$ 95,488

June 30, 2018 December 31, 2017 June 30, 2017
Cost method investment $ 28,134
$ —
$ —
Cash surrender value of life insurance contracts 13,014
13,090
12,761
Total investments $ 41,148
$ 13,090
$ 12,761



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018

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

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



	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018

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

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017

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



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

June 30, 2018 December 31, 2017 June 30, 2017
Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit
Revolving Credit Facility $ —
$ 11,448
$ —
$ 26,848
$ —
$ 24,540
CP Program 121,800
—
211,300
—
107,975
—
Total $ 121,800
$ 11,448
$ 211,300
$ 26,848
$ 107,975
$ 24,540

~~Revolving Credit Facility and CP Program~~

As of June 30, 2018 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio 58% Less than 65%

~~Current Maturities~~

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

Six Months Ended June 30, 2018 Total Stockholders’ Equity Noncontrolling Interest Total Equity
(in thousands)
Balance at December 31, 2017 $ 1,708,974
$ 111,232
$ 1,820,206
Net income (loss) 154,921
6,453
161,374
Other comprehensive income (loss) 2,421
—
2,421
Dividends on common stock (50,879 ) —
(50,879 )
Share-based compensation 3,194
—
3,194
Dividend reinvestment and stock purchase plan 219
—
219
Other stock transactions (4 ) —
(4 )
Distribution to noncontrolling interest —
(9,998 ) (9,998 )
Balance at June 30, 2018 $ 1,818,846
$ 107,687
$ 1,926,533

Six Months Ended June 30, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity
(in thousands)
Balance at December 31, 2016 $ 1,614,639
$ 115,495
$ 1,730,134
Net income (loss) 98,718
6,632
105,350
Other comprehensive income (loss) 1,942
—
1,942
Dividends on common stock (47,544 ) —
(47,544 )
Share-based compensation 4,133
—
4,133
Dividend reinvestment and stock purchase plan 1,530
—
1,530
Redeemable noncontrolling interest (886 ) —
(886 )
Cumulative effect of ASU 2016-09 implementation 3,714
—
3,714
Other stock transactions (7 ) —
(7 )
Distribution to noncontrolling interest —
(8,335 ) (8,335 )
Balance at June 30, 2017 $ 1,676,239
$ 113,792
$ 1,790,031

At-the-Market Equity Offering Program

~~On August 4, 2017, we renewed our~~Our ATM equity offering program ~~which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which~~ allows us to sell shares of our common stock ~~is the same as the prior program other than the~~with an aggregate value ~~increased from $200 million~~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. ~~We did not issue any~~During the three months ended June 30, 2019, we issued a total of 658,598 shares of common ~~shares during~~stock under the ATM equity offering program for proceeds of $49 million, net of $0.5 million in commissions. During the six months ended June 30, ~~2018 and June 30, 2017~~2019, we issued a total of 939,095 shares of common stock under the ATM equity offering ~~program.~~program for proceeds of $69 million, net of $0.7 million in commissions. As of June 30, 2019, there were no shares that were sold, but not settled.

~~Noncontrolling Interest~~

June 30, 2018 December 31, 2017 June 30, 2017
(in thousands)
Assets
Current assets $ 11,462
$ 14,837
$ 12,042
Property, plant and equipment of variable interest entities, net $ 203,308
$ 208,595
$ 214,239

Liabilities
Current liabilities $ 2,946
$ 4,565
$ 2,651

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

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

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from July ~~2018~~2019 through May ~~2020. A~~2021; a portion of ~~our over-the-counter~~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 ~~effective portion of the~~ gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance ~~Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income.~~Sheets. Effectiveness of our ~~hedging~~hedged position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.



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

Natural gas over-the-counter swaps, net ^(b)

Natural gas physical contracts, net ^(c)

~~Financing Activities~~

~~Discontinued Operations~~



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



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



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



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




	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



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

Derivatives Not Designated as Hedge Instruments

Three Months Ended June 30, 2018
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)

Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)

Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $ (713 ) Interest expense $ —
Commodity derivatives Fuel, purchased power and cost of natural gas sold (163 ) Fuel, purchased power and cost of natural gas sold —
Total $ (876 ) $ —




		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 June 30, 2017
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)

Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)

Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $ (713 ) Interest expense $ —
Commodity derivatives Net (loss) from discontinued operations 430
Net (loss) from discontinued operations —
Commodity derivatives Fuel, purchased power and cost of natural gas sold (44 ) Fuel, purchased power and cost of natural gas sold —
Total $ (327 ) $ —



		Six Months Ended June 30,
		2019			2018
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives	Fuel, purchased power and cost of natural gas sold	$	(1,160	)	$	1,025
		$	(1,160	)	$	1,025

Six Months Ended June 30, 2018
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)

Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)

Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $ (1,426 ) Interest expense $ —
Commodity derivatives Fuel, purchased power and cost of natural gas sold (784 ) Fuel, purchased power and cost of natural gas sold —
Total $ (2,210 ) $ —

Six Months Ended June 30, 2017
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
(Settlements)

Location of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)

Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $ (1,515 ) Interest expense $ —
Commodity derivatives Net (loss) from discontinued operations 659
Net (loss) from discontinued operations —
Commodity derivatives Fuel, purchased power and cost of natural gas sold 14
Fuel, purchased power and cost of natural gas sold —
Total $ (842 ) $ —

The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017. The amounts included in the tables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred.

Three Months Ended June 30,
2018 2017
(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts $ 48
$ 525
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps 713
713
Forward commodity contracts 163
(386 )
Total other comprehensive income (loss) from hedging $ 924
$ 852

Six Months Ended June 30,
2018 2017
(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts $ (249 ) $ 1,451
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps 1,426
1,515
Forward commodity contracts 784
(673 )
Total other comprehensive income (loss) from hedging $ 1,961
$ 2,293

~~Derivatives Not Designated as Hedge Instruments~~

Three Months Ended June 30,
2018 2017
Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives Net (loss) from discontinued operations $ —
$ 26
Commodity derivatives Fuel, purchased power and cost of natural gas sold 771
(691 )
$ 771
$ (665 )

Six Months Ended June 30,
2018 2017
Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives Net (loss) from discontinued operations $ —
$ 143
Commodity derivatives Fuel, purchased power and cost of natural gas sold 1,025
(1,500 )
$ 1,025
$ (1,357 )

Derivative Financial Instruments

Valuation Methodologies for Derivatives

Recurring Fair Value Measurements



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

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

As of June 30, 2018
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Utilities $ —
$ 1,035
$ —
$ (363 ) $ 672
Total $ —
$ 1,035
$ —
$ (363 ) $ 672

Liabilities:
Commodity derivatives — Utilities $ —
$ 9,808
$ —
$ (9,144 ) $ 664
Total $ —
$ 9,808
$ —
$ (9,144 ) $ 664



	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 December 31, 2017
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Utilities $ —
$ 1,586
$ —
$ (1,282 ) $ 304
Total $ —
$ 1,586
$ —
$ (1,282 ) $ 304

Liabilities:
Commodity derivatives — Utilities $ —
$ 13,756
$ —
$ (11,497 ) $ 2,259
Total $ —
$ 13,756
$ —
$ (11,497 ) $ 2,259

As of June 30, 2017
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Utilities $ —
$ 1,622
$ —
$ (977 ) $ 645
Total $ —
$ 1,622
$ —
$ (977 ) $ 645

Liabilities:
Commodity derivatives — Utilities $ —
$ 12,331
$ —
$ (11,568 ) $ 763
Total $ —
$ 12,331
$ —
$ (11,568 ) $ 763

Fair Value Measures by Balance Sheet Classification

As of June 30, 2018
Balance Sheet Location
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
Commodity derivatives Derivative assets — current $ 128
$ —
Commodity derivatives Other assets, non-current 6
—
Commodity derivatives Derivative liabilities — current —
305
Commodity derivatives Other deferred credits and other liabilities —
16
Total derivatives designated as hedges $ 134
$ 321

Derivatives not designated as hedges:
Commodity derivatives Derivative assets — current $ 538
$ —
Commodity derivatives Other assets, non-current —
—
Commodity derivatives Derivative liabilities — current —
180
Commodity derivatives Other deferred credits and other liabilities —
163
Total derivatives not designated as hedges $ 538
$ 343



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

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

As of June 30, 2017
Balance Sheet Location
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
Commodity derivatives Derivative assets — current $ 39
$ —
Commodity derivatives Current assets held for sale 509
—
Commodity derivatives Noncurrent assets held for sale 31
—
Commodity derivatives Derivative liabilities — current —
140
Commodity derivatives Other deferred credits and other liabilities —
32
Commodity derivatives Current liabilities held for sale —
27
Total derivatives designated as hedges $ 579
$ 199

Derivatives not designated as hedges:
Commodity derivatives Derivative assets — current $ 600
$ —
Commodity derivatives Other assets, non-current 6
—
Commodity derivatives Derivative liabilities — current —
536
Commodity derivatives Other deferred credits and other liabilities —
55
Commodity derivatives Current liabilities held for sale —
17
Total derivatives not designated as hedges $ 606
$ 608

Table of Contents

(1312) FAIR VALUE OF FINANCIAL INSTRUMENTS

~~The estimated fair values of our~~Other financial instruments ~~excluding derivatives~~for which ~~are presented in Note 12,~~the carrying value did not equal fair value were as follows (in thousands) as of:

June 30, 2018 December 31, 2017 June 30, 2017

Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Cash and cash equivalents ^(a)
$ 8,630
$ 8,630
$ 15,420
$ 15,420
$ 11,528
$ 11,528
Restricted cash ^(a)
$ 3,084
$ 3,084
$ 2,820
$ 2,820
$ 2,534
$ 2,534
Notes payable ^(b)
$ 121,800
$ 121,800
$ 211,300
$ 211,300
$ 107,975
$ 107,975
Long-term debt, including current maturities ^{(c) (d)}
$ 3,113,811
$ 3,234,780
$ 3,115,143
$ 3,350,544
$ 3,166,045
$ 3,377,891



	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.


(1413)	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						Six Months Ended							Three Months Ended						Six Months Ended
		June 30, 2018			June 30, 2017			June 30, 2018			June 30, 2017				June 30, 2019			June 30, 2018			June 30, 2019			June 30, 2018
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(713	)	$	(1,426	)	$	(1,515	)	Interest expense	$	(713	)	$	(713	)	$	(1,426	)	$	(1,426	)
Commodity contracts	Net (loss) from discontinued operations	—			430			—			659
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(163		)	(44		)	(784		)	14			Fuel, purchased power and cost of natural gas sold	83			(163		)	637			(784		)
		(876		)	(327		)	(2,210		)	(842		)		(630		)	(876		)	(789		)	(2,210		)
Income tax	Income tax benefit (expense)	197			106			494			281			Income tax benefit (expense)	153			197			188			494
Total reclassification adjustments related to cash flow hedges, net of tax		$	(679	)	$	(221	)	$	(1,716	)	$	(561	)		$	(477	)	$	(679	)	$	(601	)	$	(1,716	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	44		$	49		$	89		$	97		Operations and maintenance	$	20		$	44		$	39		$	89

Actuarial gain (loss)	Operations and maintenance	(622		)	(414		)	(1,244		)	(828		)	Operations and maintenance	(221		)	(622		)	(441		)	(1,244		)
		(578		)	(365		)	(1,155		)	(731		)		(201		)	(578		)	(402		)	(1,155		)
Income tax	Income tax benefit (expense)	126			128			252			265			Income tax benefit (expense)	47			126			95			252
Total reclassification adjustments related to defined benefit plans, net of tax		$	(452	)	$	(237	)	$	(903	)	$	(466	)		$	(154	)	$	(452	)	$	(307	)	$	(903	)
Total reclassifications		$	(1,131	)	$	(458	)	$	(2,619	)	$	(1,027	)		$	(631	)	$	(1,131	)	$	(908	)	$	(2,619	)

Table of Contents

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



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


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

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

Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total
Balance as of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 )
Other comprehensive income (loss)
before reclassifications —
915
—
915
Amounts reclassified from AOCI 985
(424 ) 466
1,027
Ending Balance June 30, 2017 $ (17,124 ) $ 258
$ (16,075 ) $ (32,941 )

(1514) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



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

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

Table of Contents

Six Months Ended June 30, 2018 June 30, 2017
(in thousands)
Non-cash investing and financing activities —
Property, plant and equipment acquired with accrued liabilities $ 37,168
$ 31,579

Cash (paid) refunded during the period —
Interest (net of amounts capitalized) $ (67,119 ) $ (65,820 )
Income taxes (paid) refunded $ (14,837 ) $ 1

(1615) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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



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

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017
Service cost $ 1,709
$ 1,759
$ 3,417
$ 3,517
Interest cost 3,868
3,880
7,735
7,760
Expected return on plan assets (6,185 ) (6,129 ) (12,370 ) (12,258 )
Prior service cost 14
15
29
29
Net loss (gain) 2,157
1,001
4,315
2,003
Net periodic benefit cost $ 1,563
$ 526
$ 3,126
$ 1,051

Defined Benefit Postretirement Healthcare Plans

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



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

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017
Service cost $ 572
$ 575
$ 1,145
$ 1,150
Interest cost 521
534
1,042
1,067
Expected return on plan assets (56 ) (79 ) (113 ) (158 )
Prior service cost (benefit) (99 ) (109 ) (198 ) (218 )
Net loss (gain) 54
125
108
250
Net periodic benefit cost $ 992
$ 1,046
$ 1,984
$ 2,091

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

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



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

Table of Contents

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017
Service cost $ 435
$ 609
$ 715
$ 1,436
Interest cost 292
319
585
638
Prior service cost 1
—
1
1
Net loss (gain) 250
250
500
500
Net periodic benefit cost $ 978
$ 1,178
$ 1,801
$ 2,575

For the three and six months ended June 30, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net, on the Condensed Consolidated Statements of Income. For the three and six months ended June 30, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Consolidated Statements of Income. See Note 1 for additional information.

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. ~~On July 25, 2018, we made a contribution of approximately $13 million (included in the table below) to the Defined Benefit Pension Plan.~~ Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in ~~2018~~2019 and anticipated contributions for ~~2018~~2019 and ~~2019~~2020 are as follows (in thousands):



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

Contributions Made Contributions Made Additional Contributions Contributions
Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 Anticipated for 2018 Anticipated for 2019
Defined Benefit Pension Plan $ —
$ —
$ 12,700
$ 12,700
Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,234
$ 2,468
$ 2,468
$ 4,802
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 343
$ 686
$ 686
$ 1,921

(1716) 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 ~~2017~~2018 Annual Report on Form ~~10-K.~~10-K except for those described below.

~~Dividend Restrictions~~Platte River Power Authority PPAs

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

On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase 25 MW of unit contingent energy. This agreement is effective September 1, 2019 and ~~other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of~~ will expire June 30, ~~2018, we were in compliance with the debt covenants.~~2024.

~~Due to our holding company structure, substantially all~~The following is a schedule of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders 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.

~~Our utilities are generally limited to the amount 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 June 30, 2018, 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

~~(18)~~(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. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent 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. AsWe completed the divestiture in 2018.

Table of Contents

(18) INCOME TAXES

Income tax benefit (expense) for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018 ~~we have sold nearly all oil and gas assets. Transaction closing~~

Income tax benefit (expense) for the ~~last few assets~~three months ended June 30, 2019 was $(2.3) million compared to $(6.5) million reported for the same period in 2018. The decrease is driven by a lower 2019 forecasted annual effective tax rate primarily due to an increase of federal production tax credits and ~~final accounting are expected within~~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 ~~third quarter. The closing of the oil and gas office will occur in August. We expect to transfer any associated liabilities, and settle substantially all remaining liabilities by September~~Six Months Ended June 30, ~~2018.~~

In the process of divesting our Oil and Gas segment, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent sales of assets and pending sale transactions of our other properties.

There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made and how they compared with the additional property sales occurring after December 31, 2017.

~~At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million. There were no further adjustments made~~2019 Compared to the ~~fair value of our held for sale assets at~~Six Months Ended June 30, 2018.

~~During~~Income tax benefit (expense) for the six months ended June 30, ~~2018, we recorded $2.2~~2019 was $(20) million compared to $19 million reported for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(2.3) million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

For the six months ended June 30, 2019 the effective tax rate was 13.5% compared to 19.0% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $3.5 million of ~~expenses comprised of royalty payments~~federal production tax credits and ~~reclamation costs~~related state investment credits associated with new wind assets, a $1.7 million tax benefit for deferred tax amortization related to ~~final closing on the sale of BHEP assets, which are presented as Loss on the sale of assets in the table below.~~tax reform and a $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

Total assets and liabilities of BHEP at June 30, 2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the expected final disposals occurring by September 30, 2018. Held for sale assets and liabilities at June 30, 2017 are classified as current and non-current (in thousands) as of.

June 30, 2018 December 31, 2017 June 30, 2017
Other current assets $ 378
$ 10,360
$ 8,193
Derivative assets, current and noncurrent —
—
541
Deferred income tax assets, noncurrent, net

—
16,966
20,654
Property, plant and equipment, net 3,179
56,916
93,089
Other current liabilities (4,295 ) (18,966 ) (10,860 )
Derivative liabilities, current and noncurrent —
—
(44 )
Deferred income tax liabilities, noncurrent, net

(1,153 ) —
—
Other noncurrent liabilities —
(22,808 ) (23,048 )
Net assets (liabilities) $ (1,891 ) $ 42,468
$ 88,525

At ~~June 30, 2018~~, ~~December 31, 2017~~ ~~and~~ ~~June 30, 2017, the Oil and Gas segment’s net deferred tax assets and liabilities were primarily comprised of basis differences on oil and gas properties.~~

~~BHEP’s other current liabilities at~~ ~~June 30, 2018~~ ~~consisted primarily of accrued royalties, payroll and property taxes. Current liabilities at~~ ~~December 31, 2017~~ ~~consisted primarily of a liability contingent on final approval from the Bureau of Indian Affairs on the Jicarilla property sale, accrued royalties, payroll and property taxes. Current liabilities at~~ ~~June 30, 2017~~ ~~consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at~~ ~~December 31, 2017~~ ~~and~~ ~~June 30, 2017~~ ~~consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas wells.~~

~~Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Condensed Consolidated Statements of Income were as follows (in thousands) for the period ended:~~

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 2018 2017
Revenue $ 1,284
$ 6,149
$ 5,199
$ 12,624

Operations and maintenance 2,718
5,491
8,407
12,696
Loss (gain) on sale of assets 1,991
(249 ) 2,203
(249 )
Depreciation, depletion and amortization —
1,838
1,300
3,783
Total operating expenses 4,709
7,080
11,910
16,230

Operating (loss) (3,425 ) (931 ) (6,711 ) (3,606 )

Other income (expense), net 90
65
119
138
Income tax benefit (expense) 908
250
1,822
1,283

(Loss) from discontinued operations $ (2,427 ) $ (616 ) $ (4,770 ) $ (2,185 )

(19) ~~INCOME TAXES~~

~~The effective tax rate differs from the federal statutory rate as follows:~~

Three Months Ended June 30,
Tax (benefit) expense 2018 2017
Federal statutory rate 21.0 % 35.0 %
State income tax (net of federal tax effect) 1.7
(0.1 )
Percentage depletion in excess of cost (0.4 ) (1.2 )
Noncontrolling interest ^(a)
(1.0 ) (3.1 )
Tax credits ^(b)
(2.1 ) (3.6 )
Effective tax rate adjustment ^(c)
—
4.4
Flow-through adjustments (0.7 ) (2.6 )
TCJA change in estimate ^(d)
0.3
—
AFUDC equity (0.1 ) (0.6 )
Other tax differences 0.7
0.9
19.4 % 29.1 %

~~__________~~


~~(a)~~	~~The adjustment reflects the non-controlling interest attributable to the sale of 49.9% of the membership interests of COIPP LLC in April 2016.~~


~~(b)~~	~~The tax credits are due to the production tax credits for the Peak View wind farm.~~


~~(c)~~	~~Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270.~~


~~(d)~~	The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended June 30, 2018, certain estimated items associated with the revaluation have been updated.

Six Months Ended June 30,
Tax (benefit) expense 2018 2017
Federal statutory rate 21.0 % 35.0 %
State income tax (net of federal tax effect) 1.7
1.0
Percentage depletion in excess of cost (0.4 ) (0.6 )
Noncontrolling interest (1.0 ) (1.6 )
IRC 172(f) carryback claim ^(a)
—
(1.3 )
Tax credits (2.1 ) (1.8 )
Effective tax rate adjustment —
(0.8 )
Flow-through adjustments (0.7 ) (1.0 )
TCJA change in estimate ^(b)
1.6
—
AFUDC equity (0.1 ) —
Jurisdictional simplification project ^(c)
(33.7 ) —
Other tax differences 0.6
0.4
(13.1 )% 29.3 %

~~__________~~

~~(a)~~

During the first quarter of 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased.


~~(b)~~	The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the six months ended June 30, 2018, certain estimated items associated with the revaluation have been updated.


~~(c)~~	~~Tax benefit from legal restructuring associated with amortizable goodwill as part of ongoing jurisdictional simplification.~~

~~Tax benefit related to legal restructuring~~

~~As part of the Company’s ongoing efforts to continue to integrate the~~legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018. As a result of these transactions, additional deferred income tax assets of $49 million, 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.

~~TCJA~~

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.

~~(20)~~ ACCRUED LIABILITIES

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



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

Table of Contents

June 30, 2018 December 31, 2017 June 30, 2017
Accrued employee compensation, benefits and withholdings $ 49,225
$ 52,467
$ 44,658
Accrued property taxes 34,664
42,029
32,440
Customer deposits and prepayments 36,993
44,420
41,068
Accrued interest and contract adjustment payments 33,767
33,822
33,914
CIAC current portion 1,552
1,552
1,575
Other (none of which is individually significant) 34,138
45,172
38,151
Total accrued liabilities $ 190,339
$ 219,462
$ 191,806

(20) LEASES

Lessee

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

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



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

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



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

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

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

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



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

Table of Contents



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

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

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



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


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


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

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



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

Lessor

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

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



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

Table of Contents

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



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


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

(21) SUBSEQUENT EVENTS

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


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

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

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately ~~210,000~~212,000 customers in Colorado, Montana, South Dakota ~~Wyoming, Colorado~~ and ~~Montana.~~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 ~~1,042,000~~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~~as-available basis.

Our Gas Utilities also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately ~~52,000~~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 ~~63,000~~62,000 and ~~31,000~~28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

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

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

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load ~~requirements, as well as changes in market prices.~~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 and~~ six months ended June 30, ~~2018~~2019 and ~~2017~~2018, and our financial condition as of June 30, ~~2018~~,2019 and December 31, ~~2017 and~~ ~~June 30, 2017~~,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 6457.

Table of Contents

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

Results of Operations

Executive Summary, Significant Events and Overview



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

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

Three Months Ended June 30, ~~2018~~2019 Compared to Three Months Ended June 30, ~~2017.~~ Net income from continuing operations available for common stock for the three months ended June 30, 2018 was $24 million, or $0.45 per diluted share, compared to $23 million, or $0.41 per diluted share, reported for the same period in 2017. 2018.

The variance to the prior year included the following:

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

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

Power Generation’s adjusted operating income increased ~~$3.1~~$1.3 million ~~driven~~ primarily ~~by recent transmission investments,~~due to higher ~~commercial~~revenue from increased wind MWh sold and ~~industrial demand, and favorable weather,~~higher power purchase agreement prices partially offset by higher ~~operating expenses;~~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;

~~Gas Utilities’ earnings~~Corporate and Other expenses decreased $0.9 million primarily due to ~~higher operating~~prior year expenses ~~partially offset by favorable weather~~related to the oil and ~~increased sales of natural gas;~~

~~The Mining segment’s earnings increased $0.3 million primarily due~~gas segment that were not reclassified to ~~higher sales, partially offset by higher operating expenses;~~discontinued operations; and

~~Power Generation’s earnings decreased~~ ~~$0.6~~A current year $1.6 million ~~primarily due~~ flow-through discrete tax benefit related to ~~higher maintenance expenses.~~

repair costs and certain indirect costs.

Net income available for common stock for the three months ended June 30, 2018 was $22 million, or $0.40 per diluted share, compared to $22 million, or $0.40 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the three months ended June 30, 2018 was $(2.4) million, or $(0.05) per diluted share compared to $(0.6) million or $(0.01) per diluted share reported for the same period in 2017.

Six Months Ended June 30, ~~2018~~2019 Compared to Six Months Ended June 30, ~~2017.~~ Net income from continuing operations available for common stock for the six months ended June 30, 2018 was $160 million, or $2.94 per diluted share, compared to $101 million, or $1.83 per diluted share, reported for the same period in 2017. 2018.

The variance to the prior year included the following:

~~Gas~~Electric Utilities’ ~~earnings increased $61~~adjusted operating income decreased $5.1 million primarily due to ~~the recognition of a deferred tax benefit of $49 million resulting fromlegal entity restructuring associated with amortizable goodwill for tax purposes; earnings also benefited from colder winter~~cooler spring weather compared to prior year and ~~increased sales of natural gas;~~

~~Electric Utilities’ earnings increased $0.7 million driven primarily by recent transmission investments, higher commercial and industrial demand, and favorable weather, partially offset by~~ higher operating ~~expenses;~~expenses driven by outside services and employee costs;

~~Corporate and other expenses increased $1.8~~Gas Utilities’ adjusted operating income decreased $0.1 million primarily due to higher ~~tax benefits recognized in the~~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 ~~a reduction in corporate~~higher depreciation from new wind assets;

Mining’s adjusted operating ~~expenses; and~~

~~Power Generation’s earnings~~income decreased ~~$1.2~~$2.1 million primarily due to lower ~~MWh~~tons sold driven by planned and ~~higher~~unplanned generating facility outages partially offset by lower operating ~~expenses.~~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 fromlegal entity restructuring partially offset by a prior year $2.3 million income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes; and

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

Net income available for common stock for the six months ended June 30, 2018 was $155 million, or $2.85 per diluted share, compared to $99 million, or $1.79 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the six months ended June 30, 2018 was $(4.8) million, or $(0.09) per diluted share compared to $(2.2) million or $(0.04) per diluted share reported for the same period in 2017.

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


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Variance			2018			2017			Variance			2019			2018			Variance			2019			2018			Variance
Revenue
Revenue	$	390,019		$	371,641		$	18,378		$	1,001,149		$	952,688		$	48,461		$	369,576		$	390,879		$	(21,303	)	$	1,005,257		$	1,002,844		$	2,413
Inter-company eliminations	(34,315		)	(29,812		)	(4,503		)	(70,056		)	(63,331		)	(6,725		)	(35,688		)	(35,175		)	(513		)	(73,559		)	(71,751		)	(1,808		)
	$	355,704		$	341,829		$	13,875		$	931,093		$	889,357		$	41,736		$	333,888		$	355,704		$	(21,816	)	$	931,698		$	931,093		$	605
Net income (loss) from continuing operations available for common stock
Adjusted operating income ^(a)
Electric Utilities ^(b)	$	21,890		$	18,832		$	3,058		$	41,735		$	41,062		$	673		$	33,546		$	41,200		$	(7,654	)	$	74,566		$	79,680		$	(5,114	)
Gas Utilities ^(a)	(1,161		)	(272		)	(889		)	106,459			45,738			60,721			8,557			16,485			(7,928		)	111,871			111,928			(57		)
Power Generation ^(b)	4,772			5,332			(560		)	10,628			11,862			(1,234		)	10,156			8,877			1,279			22,123			20,652			1,471
Mining ^(b)	3,005			2,681			324			5,989			5,571			418			1,640			3,825			(2,185		)	5,977			8,096			(2,119		)
Corporate and Other																			102			(836		)	938			(405		)	(2,531		)	2,126
Operating income																			54,001			69,551			(15,550		)	214,132			217,825			(3,693		)
	28,506			26,573			1,933			164,811			104,233			60,578
Corporate and Other ^(b)	(4,162		)	(3,762		)	(400		)	(5,120		)	(3,330		)	(1,790		)
Net income from continuing operations	24,344			22,811			1,533			159,691			100,903			58,788
(Loss) from discontinued operations, net of tax	(2,427		)	(616		)	(1,811		)	(4,770		)	(2,185		)	(2,585		)
Interest expense, net																			(34,265		)	(34,534		)	269			(68,982		)	(69,529		)	547
Other income (expense), net																			264			(1,309		)	1,573			(525		)	(1,413		)	888
Income tax benefit (expense)																			(2,307		)	(6,541		)	4,234			(19,570		)	19,261			(38,831		)
Income from continuing operations																			17,693			27,167			(9,474		)	125,055			166,144			(41,089		)
Net (loss) from discontinued operations																			—			(2,427		)	2,427			—			(4,770		)	4,770
Net income																			17,693			24,740			(7,047		)	125,055			161,374			(36,319		)
Net income attributable to noncontrolling interest																			(3,110		)	(2,823		)	(287		)	(6,664		)	(6,453		)	(211		)
Net income available for common stock	$	21,917		$	22,195		$	(278	)	$	154,921		$	98,718		$	56,203		$	14,583		$	21,917		$	(7,334	)	$	118,391		$	154,921		$	(36,530	)

__________

(a)

~~Net~~In 2019, we changed our measure of segment performance to adjusted operating income, ~~(loss) from continuing operations~~which impacted our segment disclosures for ~~the six months ended June 30, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring.~~all periods presented. See Note 193 of the Notes to Condensed Consolidated Financial Statements for ~~more~~additional information.

~~(b)~~

Net income (loss) from continuing operations for the six months ended June 30, 2018 included approximately $2.3 million of income tax expense recorded primarily as a result of an increase to a valuation allowance associated with tax reform related changes in estimated future taxable income. The impact to our operating segments and Corporate and Other was: Electric Utilities $0.4 million; Mining $0.5 million; Power Generation $0.7 million; and Corporate and Other $0.7 million.

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.

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.

Table of Contents

Electric Utilities experienced ~~hotter summer~~cooler spring weather during the three and six months ended June 30, ~~2018~~2019 compared to the ~~three and six months ended June 30, 2017.~~same periods in 2018. Cooling degree days for the three and six months ended June 30, ~~2018~~2019 were ~~109% higher~~38% lower than ~~the 30-year average (normal)~~normal compared to ~~14%~~109% higher than normal for the same periods in ~~2017.~~2018.

Heating degree days for the three and six months ended June 30, ~~2018~~2019 were 12% and 8% higher than normal, compared to 12% lower and 7% higher than normal ~~compared to 9% and 11% lower than normal~~ for the same periods in ~~2017.~~2018.

~~Wyoming Electric and Colorado Electric set new summer peak loads:~~

~~On July 10, 2018, Wyoming Electric set a new all-time peak load of 254 MW, exceeding the previous summer peak of 249 MW set in July 2017.~~

~~On June 27, 2018, Colorado Electric set a new all-time peak load of 413 MW, exceeding the previous summer peak of 412 MW set in July 2016.~~

On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation to purchase 60 megawatts of wind energy through a 25-year power purchase agreement. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard.

~~On July 25, 2018,~~ South Dakota Electric ~~placed in service the first 48-mile segment of~~continued construction on a ~~$70 million,~~ 175-mile ~~230-kilovolt~~electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The ~~remaining~~94-mile final segment of the transmission line is expected to be in service byin the ~~end~~fall of 2019.

Gas Utilities Segment

~~Rate Review updates:~~

On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We expect the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, will be effective September 1, 2018.

In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action. The settlement included $1.1 million in annual revenue increases and an extension of SSIR to recover costs from 2018 through 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt.

Arkansas Gas filed a rate review in December 2017 with the APSC requesting $30 million of annual revenue to recover more than $160 million of new infrastructure investment. The revenue request was subsequently adjusted to $19 million primarily related to a lower corporate income tax rate of 21%. The APSC previously issued a procedural schedule for the rate review. To date, testimony has been filed by the intervenors and Arkansas Gas filed rebuttal testimony on June 26, 2018. The APSC issued an order on July 26 requiring investor owned utilities to provide within 30 days their plans to return tax reform benefits to customers. Arkansas Gas is reviewing the order and its impacts to customers and may amend its current rate review if necessary. A final order and new rates are expected to be effective in the fourth quarter of 2018.

Wyoming Gas filed for a CPCN on May 18, 2018 with the WPSC to construct a new $54 million, 35-mile natural gas pipeline (Natural Bridge Pipeline) to enhance reliability of supply for approximately 57,000 customers in its Casper division in central Wyoming.

~~Certain legal entity restructuring transactions occurred on March 31, 2018 as part of the Company’s ongoing efforts to continue to integrate the~~legal entities that the Company has acquired in recent years. As a result of these transactions, additional deferred income tax assets of $49 million, related to goodwill that is amortizable for tax purposes, were recorded with a corresponding deferred tax benefit recorded on the Condensed Consolidated Statements of Income.

Gas Utilities experienced colder winter and spring weather during the three and six months ended June 30, ~~2018~~2019 compared to the ~~three and six months ended June 30, 2017.~~same periods in 2018. Heating degree days for the three and six months ended June 30, ~~2018~~2019 were 5% and 10% higher than normal, compared to 1% lower and 1% higher ~~than the 30-year average (normal) compared to 9% and 12% lower~~ than normal for the same periods in ~~2017.~~2018.

~~Power Generation~~Regulatory activity:

◦

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


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

◦

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

On ~~April 25, 2018, Black Hills Electric Generation was selected~~May 10, 2019, Wyoming Gas commenced construction on the $54 million, 35-mile Natural Bridge pipeline project to ~~provide 60 megawatts of renewable energy to Colorado Electric~~enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline will interconnect from a ~~new wind project through a 25-year power purchase agreement.~~supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. The ~~$71 million Busch Ranch II wind project~~pipeline is expected to be in service byin 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 ~~end~~$71 million, 60 MW Busch Ranch II Wind Farm. The wind generation project remains on schedule to be in service in the fall of 2019.

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Corporate and Other

On July 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 the banks increasing or providing new commitments, to increase total commitments of the facility up to $1.0 billion.

~~On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at June 30, 2018, matures on July 30, 2020.~~

~~On July 19, 2018,~~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 ~~March 8, 2018,~~June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt.

On April 30, 2019, S&P affirmed ~~Black Hills’~~South Dakota Electric’s credit rating at ~~BBB and revised the outlook to Positive.~~A.

~~Discontinued Operations~~

On ~~November 1, 2017, the BHC Board of Directors approved~~February 28, 2019, S&P affirmed our BBB+ rating and maintained a complete divestiture of our Oil and Gas segment. As of June 30, 2018, we have sold nearly all oil and gas assets. Transaction closing for the last few assets and final accounting are expected within the third quarter. The closing of the oil and gas office will occur in August. See Note 18 of the Notes to Condensed Consolidated Financial Statements for more information.Stable outlook.

Operating Results

A discussion of operating results from our segments and Corporate activities ~~follows.~~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 ~~purchases~~ 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.

Table of Contents

Electric Utilities

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 Variance 2018 2017 Variance
(in thousands)
Revenue ^(a)
$ 173,616
$ 168,453
$ 5,163
$ 347,171
$ 344,477
$ 2,694

Total fuel and purchased power 64,283
62,265
2,018
131,406
130,665
741

Gross margin ^(b)
109,333
106,188
3,145
215,765
213,812
1,953

Operations and maintenance 45,101
44,315
786
90,194
85,098
5,096
Depreciation and amortization 24,640
23,120
1,520
49,153
45,981
3,172
Total operating expenses 69,741
67,435
2,306
139,347
131,079
8,268

Operating income 39,592
38,753
839
76,418
82,733
(6,315 )

Interest expense, net (13,209 ) (12,893 ) (316 ) (26,500 ) (26,305 ) (195 )
Other income (expense), net (490 ) 590
(1,080 ) (671 ) 930
(1,601 )
Income tax benefit (expense) (4,003 ) (7,618 ) 3,615
(7,512 ) (16,296 ) 8,784
Net income $ 21,890
$ 18,832
$ 3,058
$ 41,735
$ 41,062
$ 673



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

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

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

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

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

________________

(a)

~~The~~Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Electric Utilities Adjusted operating income was revised for the three and six months ended June 30, 2018, ~~include Horizon Point shared facility revenues~~which resulted in an increase of ~~approximately $2.7~~$1.6 million and ~~$5.3~~$3.3 million, ~~respectively, which are allocated to all of our operating segments as facility expenses. This shared facility agreement has no impact on BHC’s consolidated operating results.~~


~~(b)~~	~~Non-GAAP measure~~respectively.

Results of Operations for the Electric Utilities for the Three Months Ended June 30, ~~2018~~2019 Compared to the Three Months Ended June 30, ~~2017~~: ~~Net income from continuing operations available for common stock for the Electric Utilities was $22 million~~2018:

Gross margin for the three months ended June 30, ~~2018, compared to Net income from continuing operations available for common stock of $19 million for the three months ended~~ ~~June 30, 2017~~,2019 decreased as a result ~~of:~~of the following:

~~Gross margin~~



	(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 a $1.7 million increase in residential margins from warmer weather in the current year, higher rider revenues of $2.3 million primarily related to transmission investment recovery, higher commercial and industrial demand of $1.1 million and higher non-energy revenue of $2.9 million primarily from Horizon Point shared facility revenue (this shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results). These increases were partially offset by a $5.3 million reserve to revenue to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs.

~~Operations and maintenance~~ ~~increased primarily due to higher facility costs of $1.3 million, partially offset by lower vegetation management expenses compared to the same period in the prior year.~~

~~Depreciation and amortization~~ ~~increased primarily due to a higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line.~~

~~Interest expense, net~~ ~~was comparable to the same period in the prior year.~~

~~Other income (expense), net~~ decreased due to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.

~~Income tax benefit (expense): The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.~~

~~Results of Operations for the Electric Utilities for the Six Months Ended~~ ~~June 30, 2018~~ ~~Compared to the Six Months Ended~~ ~~June 30, 2017~~: ~~Net income from continuing operations available for common stock for the Electric Utilities was $42 million for the six months ended~~ ~~June 30, 2018, compared to Net income from continuing operations available for common stock of $41 million for the six months ended~~ ~~June 30, 2017, as a result of:~~

~~Gross margin~~ increased primarily due to a $3.3 million increase in residential margins from favorable weather in the current year, higher rider revenues of $3.5 million primarily related to transmission investment recovery, higher commercial and industrial demand of $0.6 million and higher non-energy revenue of $5.7 million primarily from Horizon Point shared facility revenue (this shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results). These increases were partially offset by an $11 million reserve to revenue to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs.

~~Operations and maintenance~~ ~~increased primarily due to $2.1~~$1.5 million of higher ~~vegetation management expenses~~employee costs driven by additional headcount and ~~$2.6~~$1.2 million of ~~shared facility costs. Higher employee costs and property taxes~~higher outside services expenses. Various other expenses comprise the remainder of the increase compared to the same period in the prior year.

~~Depreciation~~

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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 ~~amortization~~maintenance increased primarily due to a$2.8 million of higher ~~asset base~~outside services expenses and $2.6 million of higher employee costs driven by ~~the prior year additions of Horizon Point and the Teckla-Lange transmission line.~~additional headcount.

~~Interest expense, net~~ ~~was comparable to the same period in the prior year.~~

Operating Statistics


	Electric Revenue (in thousands)								Quantities sold (MWh)				Electric Revenue (in thousands)								Quantities sold (MWh)
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,
	2018		2017		2018		2017		2018	2017	2018	2017	2019		2018		2019		2018		2019	2018	2019	2018
Residential	$	50,116	$	47,933	$	105,857	$	102,151	328,638	306,866	711,908	668,971	$	45,700	$	50,116	$	103,338	$	105,857	301,481	328,638	690,659	711,908
Commercial	64,902		63,938		126,886		127,451		509,984	485,205	1,010,120	989,279	59,739		64,902		120,702		126,886		490,329	509,984	995,902	1,010,120
Industrial	31,220		30,736		62,020		61,019		418,596	394,796	819,305	785,370	31,697		31,220		64,137		62,020		445,837	418,596	872,451	819,305
Municipal	4,666		4,676		8,807		8,976		42,657	40,704	78,981	77,676	4,253		4,666		8,392		8,807		38,283	42,657	74,919	78,981
Subtotal Retail Revenue - Electric	150,904		147,283		303,570		299,597		1,299,875	1,227,571	2,620,314	2,521,296	141,389		150,904		296,569		303,570		1,275,930	1,299,875	2,633,931	2,620,314
Contract Wholesale	8,191		6,702		17,241		14,545		218,132	165,881	455,836	351,997	6,781		8,191		15,124		17,241		194,222	218,132	417,242	455,836
Off-system/Power Marketing Wholesale	4,939		3,668		9,083		9,178		178,854	130,423	307,895	317,858	3,448		4,939		10,140		9,083		135,091	178,854	275,941	307,895
Other	9,582		10,800		17,277		21,157		—	—	—	—	14,736		9,582		27,448		17,277		—	—	—	—
Total Revenue and Energy Sold	173,616		168,453		347,171		344,477		1,696,861	1,523,875	3,384,045	3,191,151	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	—		—		—		—		125,606	116,642	216,461	219,977	—		—		—		—		89,866	125,606	186,866	216,461
Total Revenue and Energy	173,616		168,453		347,171		344,477		1,822,467	1,640,517	3,600,506	3,411,128	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)	64,283		62,265		131,406		130,665						62,128		65,942		135,411		134,680
Gross Margin ^(a)	$	109,333	$	106,188	$	215,765	$	213,812
Gross Margin (non-GAAP) ^(a)													$	104,226	$	107,674	$	213,870	$	212,491

________________


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

Table of Contents



Three Months Ended June 30,	Electric Revenue (in thousands)				Gross Margin ^(a) (in thousands)				Quantities Sold (MWh) ^(b)		Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(a)
	2018		2017		2018		2017		2018	2017	2019		2018		2019		2018		2019	2018
Colorado Electric ^(b)											$	55,412	$	62,532	$	31,051	$	35,801	485,346	542,528
South Dakota Electric	$	70,676	$	66,052	$	49,922	$	47,441	837,943	718,878	69,246		70,676		50,865		49,922		757,640	837,943
Wyoming Electric	40,408		40,351		21,951		22,439		441,996	423,157	41,696		40,408		22,310		21,951		452,123	441,996
Colorado Electric	62,532		62,050		37,460		36,308		542,528	498,482
Total Electric Revenue, Gross Margin, and Quantities Sold	$	173,616	$	168,453	$	109,333	$	106,188	1,822,467	1,640,517
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold											$	166,354	$	173,616	$	104,226	$	107,674	1,695,109	1,822,467




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

________________


(a)	~~Non-GAAP measure~~


~~(b)~~	Total MWh ~~includes Other Uses, Losses or Generation, net, which are approximately 7%, 6%, and 7%~~ for ~~South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively.~~

Six Months Ended June 30, Electric Revenue (in thousands)
Gross Margin ^(a) (in thousands)

Quantities Sold (MWh) ^(b)
2018 2017 2018 2017 2018 2017
South Dakota Electric $ 144,491
$ 139,846
$ 101,298
$ 98,086
1,666,120
1,564,710
Wyoming Electric 81,795
82,629
43,646
45,225
904,858
863,064
Colorado Electric 120,885
122,002
70,821
70,501
1,029,528
983,354
Total Electric Revenue, Gross Margin, and Quantities Sold $ 347,171
$ 344,477
$ 215,765
$ 213,812
3,600,506
3,411,128

~~________________~~


~~(a)~~	~~Non-GAAP measure~~


~~(b)~~	~~Total MWh~~2019 includes Other Uses, Losses or Generation, net, which are approximately 5%, 6%5%, and 7%6% for Colorado Electric, South Dakota Electric, ~~Wyoming Electric,~~ and ~~Colorado~~Wyoming Electric, respectively.


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


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended June 30,		Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2018	2017	2018	2017	2019	2018	2019	2018

Coal-fired	568,733	466,265	1,164,333	1,038,345	471,840	568,733	1,057,135	1,164,333
Natural Gas and Oil	105,304	64,071	146,627	92,600	86,475	105,304	211,132	146,627
Wind	68,501	58,113	142,482	128,656	56,505	68,501	111,924	142,482
Total Generated	742,538	588,449	1,453,442	1,259,601	614,820	742,538	1,380,191	1,453,442
Purchased	1,079,929	1,052,068	2,147,064	2,151,527	1,080,289	1,079,929	2,133,789	2,147,064
Total Generated and Purchased	1,822,467	1,640,517	3,600,506	3,411,128	1,695,109	1,822,467	3,513,980	3,600,506



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

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

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

Coal-fired plants ^(a)

Other — non-regulated services ^(a)



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

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

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

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

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



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

(a) Weather impacts for the three months ended June 30, ~~2017, as a result of:~~

~~Interest expense, net~~ ~~was comparable to the same period in the prior year.~~

~~Other income (expense), net~~ ~~decreased from the prior year due primarily to the presentation change~~

~~Gross margin~~



	(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



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

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

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

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

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

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

Gross Margin ^(a)(in thousands)

Gross Margin (non-GAAP)(in thousands)

~~Includes~~ ~~current year 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.~~.

Gross Margin ^(a)(in thousands)

Gross Margin (non-GAAP)(in thousands)

Gas Utilities Quantities Sold & Transported (Dth)

Three Months Ended
June 30, Six Months Ended
June 30,
Gas Utilities Quantities Sold & Transported (Dth) 2018 2017 2018 2017

Residential 8,837,588
7,101,336
38,933,825
32,369,470
Commercial 4,615,571
3,960,957
18,564,692
15,665,271
Industrial 1,747,702
1,041,032
2,931,319
1,967,919
Total Distribution Quantities Sold 15,200,861
12,103,325
60,429,836
50,002,660

Transportation and Transmission 32,846,279
30,924,304
77,579,754
71,737,178

Total Quantities Sold & Transported 48,047,140
43,027,629
138,009,590
121,739,838




	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

Three Months Ended June 30,
Degree Days 2018 2017
Heating Degree Days: Actual
Variance
from 30-Year
Average
Actual Variance to Prior Year Actual
Variance
from 30-Year
Average
Arkansas ^(a)
400 21% 65% 242 (27)%
Colorado 735 (23)% (17)% 889 (7)%
Nebraska 708 12% 25% 567 (11)%
Iowa 801 17% 29% 619 (10)%
Kansas ^(a)
508 14% 14% 445 —%
Wyoming 1,072 (12)% (9)% 1,177 (4)%
Combined ^(b)
740 (1)% 8% 686 (9)%



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

Six Months Ended June 30,
Degree Days 2018 2017
Heating Degree Days: Actual
Variance
from 30-Year
Average
Actual Variance to Prior Year Actual
Variance
from 30-Year
Average
Arkansas ^(a)
2,448
1 % 35% 1,811
(26 )%
Colorado 3,439
(12 )% 3% 3,354
(14 )%
Nebraska 3,915
7 % 22% 3,214
(12 )%
Iowa 4,332
7 % 22% 3,551
(13 )%
Kansas ^(a)
2,978
2 % 17% 2,547
(13 )%
Wyoming 4,316
(2 )% 4% 4,161
(6 )%
Combined ^(b)
3,899
1 % 15% 3,404
(12 )%




	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%

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 Variance 2018 2017 Variance
(in thousands)
Revenue ^(a)
$ 21,884
$ 21,795
$ 89
$ 44,987
$ 45,362
$ (375 )

Operations and maintenance 9,959
8,528
1,431
18,086
16,582
1,504
Depreciation and amortization ^(a)
1,633
1,069
564
3,235
2,276
959
Total operating expense 11,592
9,597
1,995
21,321
18,858
2,463

Operating income 10,292
12,198
(1,906 ) 23,666
26,504
(2,838 )

Interest expense, net (1,316 ) (704 ) (612 ) (2,489 ) (1,291 ) (1,198 )
Other income (expense), net (47 ) (13 ) (34 ) (41 ) (31 ) (10 )
Income tax (expense) benefit (1,334 ) (3,033 ) 1,699
(4,055 ) (6,688 ) 2,633

Net income 7,595
8,448
(853 ) 17,081
18,494
(1,413 )
Net income attributable to noncontrolling interest (2,823 ) (3,116 ) 293
(6,453 ) (6,632 ) 179
Net income available for common stock $ 4,772
$ 5,332
$ (560 ) $ 10,628
$ 11,862
$ (1,234 )



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

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

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

Quantities Sold, Generated and Purchased

Black Hills Colorado IPP ^(b)

Black Hills Wyoming ^(c)

Black Hills Colorado IPP ^(b)

Black Hills Wyoming ^(c)



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

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

Three Months Ended June 30, Six Months Ended June 30,

2018 2017 Variance 2018 2017 Variance

(in thousands)
Revenue $ 16,899
$ 14,946
$ 1,953
$ 34,027
$ 31,492
$ 2,535

Operations and maintenance 11,124
9,833
1,291
22,046
20,927
1,119
Depreciation, depletion and amortization 1,950
2,062
(112 ) 3,885
4,227
(342 )
Total operating expenses 13,074
11,895
1,179
25,931
25,154
777

Operating income 3,825
3,051
774
8,096
6,338
1,758

Interest expense, net (233 ) (74 ) (159 ) (333 ) (99 ) (234 )
Other income (expense), net (94 ) 536
(630 ) (120 ) 1,077
(1,197 )
Income tax benefit (expense) (493 ) (832 ) 339
(1,654 ) (1,745 ) 91

Net income $ 3,005
$ 2,681
$ 324
$ 5,989
$ 5,571
$ 418



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

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

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

Three Months Ended June 30, Six Months Ended June 30,
2018 2017 Variance 2018 2017 Variance
(in thousands)
Operating (loss) ^(a)
$ (645 ) $ (2,423 ) $ 1,778
$ (2,285 ) $ (5,782 ) $ 3,497

Other income (expense):
Interest (expense) income, net ^(a)
(519 ) (653 ) 134
(1,184 ) (1,303 ) 119
Other income (expense), net 240
(171 ) 411
182
(838 ) 1,020
Income tax benefit (expense) (3,238 ) (515 ) (2,723 ) (1,833 ) 4,593
(6,426 )

Net income (loss) $ (4,162 ) $ (3,762 ) $ (400 ) $ (5,120 ) $ (3,330 ) $ (1,790 )



	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

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

Income tax benefit (expense) for the three months ended June 30, ~~2018,~~2019 was $(2.3) million compared to ~~Net income from continuing operations available for common stock of $(3.8)~~$(6.5) million for the ~~three months ended June 30, 2017.~~same period in 2018. The ~~variance was~~decrease is driven by ~~higher prior~~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 ~~operating~~$1.6 million flow-through discrete tax benefit related to repair costs ~~previously allocated to BHEP which were not reclassified to discontinued operations.~~and certain indirect costs.

Income tax benefit (expense) for the six months ended June 30, ~~2018,~~2019 was $(20) million compared to ~~Net loss from continuing operations available for common stock of $(3.3)~~$19 million for the ~~six months ended June 30, 2017.~~same period in 2018. The variance to the prior year was driven by higher prior year operating costs previously allocated to BHEP which were not reclassified to discontinued operations and transition and acquisition expenses which occurredincrease in ~~the prior year. The variance in Income~~ tax ~~benefit (expense)~~expense was primarily due to a prior year $49 million tax benefit ~~of $1.4~~resulting from legal entity restructuring and partially offset by a prior year $(2.3) million ~~comprised primarily of benefits from a carryback claim for specified liability losses involving prior tax years, current year~~income tax expense ~~driven primarily by the adjustment to the projected annual effective tax rate compared to a tax benefit recorded~~associated with changes in the prior ~~year, and approximately $0.6 million~~estimated impact of ~~current year~~ tax ~~expense recorded pursuant to the TCJA.~~reform on deferred income taxes.

~~Discontinued Operations~~

Critical Accounting Estimates

Table of Contents

Liquidity and Capital Resources

~~OVERVIEW~~

~~Our Company requires significant cash to support~~There have been no material changes in Liquidity and ~~grow~~Capital Resources from those reported in Item 7 of 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 complying2018 Annual Report on Form 10-K filed with the ~~TCJA and the impact of providing TCJA benefits to customers.~~SEC except as described below.

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.Collateral Requirements

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.

Our utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At June 30, ~~2018,~~2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Income Tax

The TCJA ~~legislation was signed into law on December 22, 2017. The new tax law~~ required revaluation ~~at December 31, 2017~~ of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. ~~As a result of the revaluation, deferred tax assets~~We have reached agreements with regulators in six states and ~~liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related~~are working with regulators in our seventh state, as well as FERC regarding returning benefits to our regulated utilities and is reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining life of the related assets as specifically prescribed in the TCJA.

~~We expect an increase in~~customers. Our working capital requirements increased as a result of complying with the TCJA and providing the ~~impact~~benefits of ~~providing~~the TCJA ~~benefits~~ to customers. ~~We estimate the lower tax rate~~These agreements will negatively impact ~~the Company’s~~our cash flows by approximately ~~$35~~$40 million to $45 million ~~annually~~per year for each of the next several years. ~~Each of our utilities is working with their respective regulators to address the impact of tax reform and the appropriate benefit to customers. See Note 5 for more information on regulatory matters.~~

Cash Flow Activities

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


Cash provided by (used in):	2018			2017			Increase (Decrease)			2019			2018			Variance
Operating activities	$	310,701		$	262,869		$	47,832		$	289,779		$	310,701		$	(20,922	)
Investing activities	$	(163,526	)	$	(163,530	)	$	4		$	(317,297	)	$	(163,526	)	$	(153,771	)
Financing activities	$	(153,701	)	$	(101,069	)	$	(52,632	)	$	13,617		$	(153,701	)	$	167,318

Year-to-Date ~~2018~~2019 Compared to Year-to-Date ~~2017~~2018

Operating Activities

Investing Activities

Financing Activities

Table of Contents

Dividends

Dividends paid on our common stock totaled ~~$51~~$61 million for the six months ended June 30, ~~2018,~~2019, or ~~$0.475~~$0.505 per share per quarter. On July ~~25, 2018,~~31, 2019, our board of directors declared a quarterly dividend of ~~$0.475~~$0.505 per share payable September 1, ~~2018,~~2019, equivalent to an annual dividend of ~~$1.90~~$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 9 for more information.

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. See Note 9 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		June 30, 2018				June 30, 2018				Expiration	Capacity		June 30, 2019				June 30, 2019
Revolving Credit Facility	July 30, 2023	$	750	$	—	$	122	$	11	$	617	July 30, 2023	$	750	$	—	$	103	$	10	$	637

Covenant Requirements

~~Financing Activities~~

~~Financing activities for the six months ended June 30, 2018 consisted of short-term borrowings from our CP Program. On August 4, 2017, we renewed the ATM equity offering program which reset the size~~2019. See Note 8 of the ~~ATM equity offering program~~Notes to ~~an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program for the six months ended June 30, 2018.~~

In connection with the optional remarketing of the RSNs, we also expect to undertake a series of transactions that may result in the exchange or modification of the RSNs, which would result in modification of the interest rate, maturity, covenants, seniority, and other terms, and may also include the issuance of additional senior unsecured notes of the same series as the RSNs as so modified. We anticipate using any net proceeds from the issuance of any such additional senior unsecured notes to pay down debt and for general corporate purposes.

~~Dividend Restrictions~~

~~There~~Financing Activities

Future Financing Plans



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



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

Table of Contents

Capital Requirements

Capital Expenditures

~~Actual and forecasted capital requirements are as follows (in thousands):~~

Expenditures for the Total Total Total

Six Months Ended June 30, 2018 ^(a)

2018 Planned
Expenditures ^(b)

2019 Planned
Expenditures

2020 Planned
Expenditures
Electric Utilities $ 55,729
$ 149,000
$ 193,000
$ 141,000
Gas Utilities ^(d)
98,691
268,000
328,000
245,000
Power Generation ^(c)
1,721
32,000
56,000
5,000
Mining 6,210
19,000
7,000
7,000
Corporate and Other 5,075
10,000
13,000
8,000
$ 167,426
$ 478,000
$ 597,000
$ 406,000



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

__________

(a) Expenditures for the six months ended June 30, ~~2018~~2019 include the impact of accruals for property, plant and equipment.

(b) Includes actual capital expenditures for the six months ended June 30, ~~2018.~~2019.

(c) Planned capital expenditures increased for ~~2018 and~~ 2019 ~~increased~~through 2023 primarily due to ~~the Busch Ranch II wind project.~~increased programmatic integrity spending.

~~(d) Planned capital expenditures for 2018 and 2019 increased due to the Natural Bridge Pipeline project.~~

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 ~~2017~~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 Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC except for the items described in Note 208 of the Notes to ~~the~~Condensed Consolidated Financial Statements in ~~our 2017 Annual~~this Quarterly Report on Form ~~10-K.~~10-Q.

New Accounting Pronouncements

Other than the pronouncements reported in our ~~2017~~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 ~~2017~~2018 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our ~~2017~~2018 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

~~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, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. We also reduce the commodity price risk in the unregulated area of our business by using over-the-counter 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:

June 30, 2018 December 31, 2017 June 30, 2017
Net derivative (liabilities) assets $ (5,117 ) $ (6,644 ) $ (7,075 )
Cash collateral offset in Derivatives 3,997
7,694
6,950
Cash collateral included in Other current assets 1,913
562
2,339
Net asset (liability) position $ 793
$ 1,612
$ 2,214

~~Financing Activities~~

Historically, 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 June 30, 2018, December 31, 2017 and June 30, 2017, 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 June 30, ~~2018~~.2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, ~~2018.~~2019.

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

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, ~~2018,~~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.

Table of Contents

BLACK HILLS CORPORATION

Part II — Other Information


ITEM 1.	Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our ~~2017~~2018 Annual Report on Form 10-K and Note 1716 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1716 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 2017 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 six months ended June 30, 2018.~~


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*	Junior Subordinated Indenture dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on November 23, 2015).
	~~First Supplemental Indenture dated as of November 23, 2015 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on November 23, 2015).~~



Exhibit 4.5*	Purchase Contract and Pledge Agreement dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as purchase contract agent, collateral agent, custodial agent and securities intermediary (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on November 23, 2015).

Exhibit 4.6*	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	~~Third Amended and Restated Credit Agreement~~First Amendment dated as of ~~July 30, 2018, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1~~June 17, 2019 to ~~the Registrant’s Form 8-K filed on July 31, 2018).~~

~~Exhibit 10.2~~	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 ~~10.2~~10.1 to the Registrant’s Form ~~8-K~~8–K filed on ~~July 31, 2018)~~June 17, 2019).

~~Exhibit 12~~	~~Computation of Ratio of Earnings to Fixed Charges~~

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.

~~Exhibit 101~~101.INS	~~Financial Statements for~~ XBRL ~~Format.~~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.

Table of Contents

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/ ~~David~~Linden R. ~~Emery~~Evans
		~~David~~Linden R. ~~Emery, Chairman~~Evans, President and
		Chief Executive Officer

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

Dated:	August ~~7, 2018~~6, 2019

6960



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



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 and Six Months Ended June 30, 2018 and 2017~~		5

	Condensed Consolidated Statements of Comprehensive Income ~~- unaudited~~
	~~Three and Six Months Ended June 30, 2018 and 2017~~		6

	Condensed Consolidated Balance Sheets ~~- unaudited~~
	~~June 30, 2018, December 31, 2017 and June 30, 2017~~		7

	Condensed Consolidated Statements of Cash Flows ~~- unaudited~~
	~~Six Months Ended June 30, 2018 and 2017~~		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		4136
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~~	65

~~Item 4.~~	~~Controls and Procedures~~		66

PART II.	OTHER INFORMATION		66

Item 1.	Legal Proceedings		6658
Item 4.	Mine Safety Disclosures		58
Item 6.	Exhibits		58

~~Item 1A.~~	~~Risk Factors~~		66Signatures

~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~		66

~~Item 4.~~	~~Mine Safety Disclosures~~		66

~~Item 5.~~	~~Other Information~~		66

~~Item 6.~~	~~Exhibits~~		67

	~~Signatures~~		6960


	Maximum Amortization (in years)	June 30, 2018			December 31, 2017			June 30, 2017			June 30, 2019			December 31, 2018
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	1	$	26,725		$	20,187		$	20,761		$	34,257		$	29,661
Deferred gas cost adjustments ^(a)	1	962			31,844			8,962			2,342			3,362
Gas price derivatives ^(a)	3	9,120			11,935			11,159			3,945			6,201
Deferred taxes on AFUDC^{(b) (f)}	45	7,813			7,847			15,322
Deferred taxes on AFUDC^(b)											7,716			7,841
Employee benefit plans ^(c)	12	108,366			109,235			107,419			109,899			110,524
Environmental^(a)	subject to approval	1,000			1,031			1,070			931			959
Asset retirement obligations^(a)	44	523			517			510
Loss on reacquired debt^(a)	28	19,868			20,667			21,466			20,140			21,001
Renewable energy standard adjustment ^(a)	subject to approval	1,179			1,088			768			1,994			1,722
Deferred taxes on flow through accounting^{(c) (f)}	54	28,193			26,978			40,586
Decommissioning costs	10	11,806			13,287			14,681
Deferred taxes on flow through accounting^(c)											36,552			31,044
Decommissioning costs ^(b)											11,518			11,700
Gas supply contract termination ^(a)	4	17,171			20,001			22,793			11,413			14,310
Other regulatory assets^(a)	30	27,976			32,837			31,663			42,342			45,910
Total regulatory assets		260,702			297,454			297,160			283,049			284,235
Less current regulatory assets		(50,565		)	(81,016		)	(53,061		)	(48,925		)	(48,776		)
Regulatory assets, non-current		$	210,137		$	216,438		$	244,099		$	234,124		$	235,459

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	27,188		$	3,427		$	13,693		$	16,808		$	6,991
Employee benefit plan costs and related deferred taxes^{(c) (f)}	12	39,820			40,629			67,297
Employee benefit plan costs and related deferred taxes^(c)											41,814			42,533
Cost of removal^(a)	44	141,954			130,932			125,598			158,477			150,123
Excess deferred income taxes ^{(c) (d)}	40	310,132			301,553			56
TCJA revenue reserve ^(e)	subject to approval	19,312			—			—
Excess deferred income taxes ^(c)											307,871			310,562
TCJA revenue reserve											11,436			18,032
Other regulatory liabilities^(c)	25	11,625			8,585			9,666			18,150			12,553
Total regulatory liabilities		550,031			485,126			216,310			554,556			540,794
Less current regulatory liabilities		(52,102		)	(6,832		)	(17,305		)	(39,642		)	(29,810		)
Regulatory liabilities, non-current		$	497,929		$	478,294		$	199,005		$	514,914		$	510,984



(unaudited)	As of
	June 30, 2018			December 31, 2017			June 30, 2017
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	8,630		$	15,420		$	11,528
Restricted cash	3,084			2,820			2,534
Accounts receivable, net	175,612			248,330			166,760
Materials, supplies and fuel	95,454			113,283			95,488
Derivative assets, current	666			304			639
Income tax receivable, net	11,653			—			—
Regulatory assets, current	50,565			81,016			53,061
Other current assets	31,431			25,367			20,768
Current assets held for sale	3,557			84,242			8,478
Total current assets	380,652			570,782			359,256

Investments	41,148			13,090			12,761

Property, plant and equipment	5,702,065			5,567,518			5,423,160
Less: accumulated depreciation and depletion	(1,087,689		)	(1,026,088		)	(964,549		)
Total property, plant and equipment, net	4,614,376			4,541,430			4,458,611

Other assets:
Goodwill	1,299,454			1,299,454			1,299,454
Intangible assets, net	7,155			7,559			7,972
Regulatory assets, non-current	210,137			216,438			244,099
Other assets, non-current	17,207			10,149			13,594
Noncurrent assets held for sale	—			—			113,999
Total other assets, non-current	1,533,953			1,533,600			1,679,118

TOTAL ASSETS	$	6,570,129		$	6,658,902		$	6,509,746



Three Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Three Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Segment:
Electric^.	$	165,517	$	2,936		$	18,832
Gas	166,439		8			(272		)
Power Generation ^(b)	1,470		20,325			5,332
Mining	8,403		6,543			2,681
Corporate and Other	—		—			(3,762		)
Inter-company eliminations	—		(29,812		)	—
Total	$	341,829	$	—		$	22,811




Six Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Six Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Segment:
Electric	$	337,687	$	6,790		$	41,062
Gas	531,340		17			45,738
Power Generation ^(b)	3,572		41,790			11,862
Mining	16,758		14,734			5,571
Corporate and Other ^(c)	—		—			(3,330		)
Inter-company eliminations	—		(63,331		)	—
Total	$	889,357	$	—		$	100,903


~~(b)~~	~~Net income from continuing operations available for common stock for the~~ ~~three~~ ~~and six months ended June 30, 2018 and June 30, 2017 reflects net income attributable to noncontrolling interests of $2.8 million and $6.5 million, and $3.1 million and $6.6 million, respectively.~~


(a)	~~Recovery~~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.


~~(e)~~	~~As of June 30, 2018, the amortization periods are yet to be determined and subject to approval by our regulators.~~


~~(f)~~	~~The variance to the prior periods is primarily due to the TCJA.~~



State	Approximate Annual Benefit for Customers			Start Date for Customer Benefits
Colorado	$	10.8	million	July 2018
Iowa	$	2.2	million	June 2018
Kansas	$	1.9	million	April 2018
Nebraska	$	3.8	million	July 2018



Yes	x	No o



Yes	x	No o



Yeso	☐	No x


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



	As of June 30, 2018	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	58%	Less than	65%


(b)	As of June 30, ~~2018~~, ~~2,452,000~~2019, 2,130,000 MMBtus were designated as cash flow ~~hedges for the natural gas over-the-counter swaps purchased.~~ hedges.


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



	As of December 31, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	1,586	$	—	$	(1,282	)	$	304
Total	$	—	$	1,586	$	—	$	(1,282	)	$	304

Liabilities:
Commodity derivatives — Utilities	$	—	$	13,756	$	—	$	(11,497	)	$	2,259
Total	$	—	$	13,756	$	—	$	(11,497	)	$	2,259



	As of June 30, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	1,622	$	—	$	(977	)	$	645
Total	$	—	$	1,622	$	—	$	(977	)	$	645

Liabilities:
Commodity derivatives — Utilities	$	—	$	12,331	$	—	$	(11,568	)	$	763
Total	$	—	$	12,331	$	—	$	(11,568	)	$	763



As of June 30, 2018
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	128	$	—
Commodity derivatives	Other assets, non-current	6		—
Commodity derivatives	Derivative liabilities — current	—		305
Commodity derivatives	Other deferred credits and other liabilities	—		16
Total derivatives designated as hedges		$	134	$	321

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	538	$	—
Commodity derivatives	Other assets, non-current	—		—
Commodity derivatives	Derivative liabilities — current	—		180
Commodity derivatives	Other deferred credits and other liabilities	—		163
Total derivatives not designated as hedges		$	538	$	343



	Three Months Ended June 30,
Tax (benefit) expense	2018		2017
Federal statutory rate	21.0	%	35.0	%
State income tax (net of federal tax effect)	1.7		(0.1	)
Percentage depletion in excess of cost	(0.4	)	(1.2	)
Noncontrolling interest ^(a)	(1.0	)	(3.1	)
Tax credits ^(b)	(2.1	)	(3.6	)
Effective tax rate adjustment ^(c)	—		4.4
Flow-through adjustments	(0.7	)	(2.6	)
TCJA change in estimate ^(d)	0.3		—
AFUDC equity	(0.1	)	(0.6	)
Other tax differences	0.7		0.9
	19.4	%	29.1	%


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



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

Wind capacity factor	34.8	%	41.7	%	38.7	%	46.1	%


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


~~(a)~~	~~2017~~2019 included planned outages at Neil Simpson II ~~Wygen II~~ and Wygen ~~III.~~


~~(a)~~	~~The three~~III and six months ended June 30, 2018 include certain BHES trading activities which are reported on a net basis. These trading activities are presented on a gross basis in the prior year. This change in presentation had no impact on gross margin.unplanned outages at Wyodak Plant.


(b)	~~Non-GAAP measure~~2019 included planned outages at Neil Simpson CT and Lange CT.


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


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


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


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


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


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