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	September 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	☐		Smaller ~~reporting company~~ o Reporting Company	☐

			Emerging ~~growth company~~ oGrowth Company
		☐

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



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 ~~November 1, 2018~~October 31, 2019
Common stock, $1.00 par value	~~59,974,620~~61,454,071	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 ~~AltaGas.~~Black Hills Electric Generation. Colorado Electric ~~has~~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
City of Cheyenne	Cheyenne, 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~~temperatures 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
CT	Combustion turbine
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 prior to~~2028. On November 1, 2018, we completed settlement of the ~~successful remarketing on August 17, 2018.~~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~~
~~PCA~~	~~Power Cost Adjustment~~Nebraska Public Service Commission
PPA	Power Purchase Agreement
Pueblo Airport Generation Station	Two 100 MW combined cycle gas-fired power generation plants owned by Colorado IPP and located at a site shared with Colorado Electric. The plants commenced operation on January 1, 2012.
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
Tech Services	Non-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts.
Wind Capacity Factor	Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, 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~~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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2019			2018			2019			2018
	(in thousands, except per share amounts)												(in thousands, except per share amounts)

Revenue	$	321,979		$	335,611		$	1,253,072		$	1,224,968		$	325,548		$	321,979		$	1,257,246		$	1,253,072

Operating expenses:
Fuel, purchased power and cost of natural gas sold	80,244			86,281			432,544			404,222			73,090			80,244			411,695			432,544
Operations and maintenance	115,477			109,258			350,099			335,707			117,037			115,699			366,907			352,092
Depreciation, depletion and amortization	49,046			47,109			146,345			140,636			51,884			49,046			154,507			146,345
Taxes - property, production and severance	11,905			12,408			39,181			38,866
Other operating expenses	222			996			1,993			5,996
Taxes - property and production													12,986			11,905			39,454			39,181
Total operating expenses	256,894			256,052			970,162			925,427			254,997			256,894			972,563			970,162

Operating income	65,085			79,559			282,910			299,541			70,551			65,085			284,683			282,910

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(36,480		)	(35,287		)	(107,360		)	(105,417		)
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)													(36,200		)	(36,380		)	(108,232		)	(107,183		)
Allowance for funds used during construction - borrowed	701			753			1,345			2,061			2,200			701			4,555			1,345
Capitalized interest	100			64			177			197
Interest income	382			402			1,012			700			513			382			1,208			1,012
Allowance for funds used during construction - equity	193			696			503			1,982			311			193			486			503
Impairment of investment													(19,741		)	—			(19,741		)	—
Other income (expense), net	(703		)	189			(2,426		)	(6		)	269			(703		)	(431		)	(2,426		)
Total other income (expense), net	(35,807		)	(33,183		)	(106,749		)	(100,483		)
Total other income (expense)													(52,648		)	(35,807		)	(122,155		)	(106,749		)

Income before income taxes	29,278			46,376			176,161			199,058			17,903			29,278			162,528			176,161
Income tax benefit (expense)	(7,477		)	(13,478		)	11,784			(58,518		)	(2,508		)	(7,477		)	(22,078		)	11,784
Income from continuing operations	21,801			32,898			187,945			140,540			15,395			21,801			140,450			187,945
(Loss) from discontinued operations, net of tax	(857		)	(1,300		)	(5,627		)	(3,485		)
Net (loss) from discontinued operations													—			(857		)	—			(5,627		)
Net income	20,944			31,598			182,318			137,055			15,395			20,944			140,450			182,318
Net income attributable to noncontrolling interest	(3,994		)	(3,935		)	(10,447		)	(10,674		)	(3,655		)	(3,994		)	(10,319		)	(10,447		)
Net income available for common stock	$	16,950		$	27,663		$	171,871		$	126,381		$	11,740		$	16,950		$	130,131		$	171,871

Amounts attributable to common shareholders:
Net income from continuing operations	$	17,807		$	28,963		$	177,498		$	129,866		$	11,740		$	17,807		$	130,131		$	177,498
Net (loss) from discontinued operations	(857		)	(1,300		)	(5,627		)	(3,485		)	—			(857		)	—			(5,627		)
Net income available for common stock	$	16,950		$	27,663		$	171,871		$	126,381		$	11,740		$	16,950		$	130,131		$	171,871

Earnings per share of common stock:
Earnings (loss) per share, Basic -
Income from continuing operations, per share	$	0.33		$	0.54		$	3.33		$	2.44
(Loss) from discontinued operations, per share	(0.02		)	(0.02		)	(0.10		)	(0.06		)
Earnings per share, Basic ^(a)	$	0.32		$	0.52		$	3.22		$	2.38
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations													$	0.19		$	0.33		$	2.15		$	3.33
(Loss) from discontinued operations													—			(0.02		)	—			(0.10		)
Total earnings per share of common stock, Basic													$	0.19		$	0.32		$	2.15		$	3.22

Earnings (loss) per share, Diluted -
Income from continuing operations, per share	$	0.32		$	0.52		$	3.26		$	2.35
(Loss) from discontinued operations, per share	(0.02		)	(0.02		)	(0.10		)	(0.06		)
Earnings per share, Diluted ^(a)	$	0.31		$	0.50		$	3.15		$	2.29
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations													$	0.19		$	0.32		$	2.15		$	3.26
(Loss) from discontinued operations													—			(0.02		)	—			(0.10		)
Total earnings per share of common stock, Diluted													$	0.19		$	0.31		$	2.15		$	3.15

Weighted average common shares outstanding:
Basic	53,364			53,243			53,346			53,208			60,976			53,364			60,458			53,346
Diluted	54,819			55,432			54,508			55,254			61,104			54,819			60,578			54,508

Dividends declared per share of common stock	$	0.475		$	0.445		$	1.425		$	1.335

~~(a) EPS may not sum due to rounding.~~

~~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
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
(in thousands)

Net income $ 20,944
$ 31,598
$ 182,318
$ 137,055

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $10 and $17 for the three months ended September 30, 2018 and 2017 and $29 and $52 for the nine months ended September 30, 2018 and 2017, respectively) (34 ) (32 ) (104 ) (94 )
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(138) and $(145) for the three months ended September 30, 2018 and 2017 and $(409) and $(445) for the nine months ended September 30, 2018 and 2017, respectively) 483
269
1,456
797
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 September 30, 2018 and 2017 and $(456) and $(779) for the nine months ended September 30, 2018 and 2017, respectively) 560
464
1,682
1,449
Net unrealized gains (losses) on commodity derivatives (net of tax (expense) benefit of $0 and $94 for the three months ended September 30, 2018 and 2017 and $51 and $(442) for the nine months ended September 30, 2018 and 2017, respectively) 30
(160 ) (168 ) 755
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax (expense) benefit of $3 and $95 for the three months ended September 30, 2018 and 2017 and $(187) and $344 for the nine months ended September 30, 2018 and 2017, respectively) 21
(166 ) 615
(590 )
Other comprehensive income, net of tax 1,060
375
3,481
2,317

Comprehensive income 22,004
31,973
185,799
139,372
Less: comprehensive income attributable to noncontrolling interest (3,994 ) (3,935 ) (10,447 ) (10,674 )
Comprehensive income available for common stock $ 18,010
$ 28,038
$ 175,352
$ 128,698

~~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
September 30,
2018 December 31, 2017 September 30,
2017
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 10,001
$ 15,420
$ 13,449
Restricted cash 3,241
2,820
2,683
Accounts receivable, net 152,796
248,330
150,325
Materials, supplies and fuel 122,618
113,283
122,866
Derivative assets, current 1,392
304
433
Income tax receivable, net 11,025
—
—
Regulatory assets, current 48,302
81,016
61,023
Other current assets 32,691
25,367
25,586
Current assets held for sale 2,854
84,242
8,653
Total current assets 384,920
570,782
385,018

Investments 41,202
13,090
12,947

Property, plant and equipment 5,819,000
5,567,518
5,499,557
Less: accumulated depreciation and depletion (1,118,783 ) (1,026,088 ) (1,000,875 )
Total property, plant and equipment, net 4,700,217
4,541,430
4,498,682

Other assets:
Goodwill 1,299,454
1,299,454
1,299,454
Intangible assets, net 6,954
7,559
7,765
Regulatory assets, non-current 212,048
216,438
239,571
Other assets, non-current 17,143
10,149
11,626
Noncurrent assets held for sale —
—
108,685
Total other assets, non-current 1,535,599
1,533,600
1,667,101

TOTAL ASSETS $ 6,661,938
$ 6,658,902
$ 6,563,748

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
September 30,
2018 December 31, 2017 September 30,
2017
(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
Current liabilities:
Accounts payable $ 115,900
$ 160,887
$ 94,790
Accrued liabilities 201,353
219,462
206,779
Derivative liabilities, current 1,154
2,081
1,458
Accrued income taxes, net —
1,022
5,587
Regulatory liabilities, current 41,442
6,832
7,042
Notes payable 112,100
211,300
225,170
Current maturities of long-term debt 255,743
5,743
5,743
Current liabilities held for sale 2,538
41,774
7,701
Total current liabilities 730,230
649,101
554,270

Long-term debt 2,951,389
3,109,400
3,109,864

Deferred credits and other liabilities:
Deferred income tax liabilities, net 292,753
336,520
618,315
Regulatory liabilities, non-current 508,846
478,294
198,189
Benefit plan liabilities 151,613
159,646
149,803
Other deferred credits and other liabilities 105,928
105,735
113,996
Non-current liabilities held for sale —
—
23,329
Total deferred credits and other liabilities 1,059,140
1,080,195
1,103,632

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

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,863; 53,579,986; and 53,524,529 shares, respectively 53,662
53,580
53,525
Additional paid-in capital 1,157,214
1,150,285
1,147,922
Retained earnings 644,154
548,617
516,371
Treasury stock, at cost – 72,915; 39,064; and 41,457 shares, respectively (4,072 ) (2,306 ) (2,448 )
Accumulated other comprehensive income (loss) (37,703 ) (41,202 ) (32,566 )
Total stockholders’ equity 1,813,255
1,708,974
1,682,804
Noncontrolling interest 107,924
111,232
113,178
Total equity 1,921,179
1,820,206
1,795,982

TOTAL LIABILITIES AND TOTAL EQUITY $ 6,661,938
$ 6,658,902
$ 6,563,748



(unaudited)	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)

Net income	$	15,395		$	20,944		$	140,450		$	182,318

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $3, $10, $13 and $29, respectively)	(16		)	(34		)	(45		)	(104		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(92), $(138), $(197), and $(409), respectively)	(9		)	483			327			1,456
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(165), $(152), $(500), and $(456), respectively)	548			560			1,639			1,682
Net unrealized gains (losses) on commodity derivatives (net of tax of $35, $0, $100 and $51, respectively)	(115		)	30			(334		)	(168		)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(5), $3, $142 and $(187), respectively)	124			21			(366		)	615
Other comprehensive income, net of tax	532			1,060			1,221			3,481

Comprehensive income	15,927			22,004			141,671			185,799
Less: comprehensive income attributable to noncontrolling interest	(3,655		)	(3,994		)	(10,319		)	(10,447		)
Comprehensive income available for common stock	$	12,272		$	18,010		$	131,352		$	175,352

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) Nine Months Ended September 30,
2018 2017
Operating activities: (in thousands)
Net income $ 182,318
$ 137,055
Loss from discontinued operations, net of tax 5,627
3,485
Income from continuing operations 187,945
140,540
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 146,345
140,636
Deferred financing cost amortization 5,682
6,212
Stock compensation 7,544
7,594
Deferred income taxes (14,396 ) 65,536
Employee benefit plans 10,641
8,470
Other adjustments, net 7,668
(3,549 )
Changes in certain operating assets and liabilities:
Materials, supplies and fuel (8,380 ) (19,511 )
Accounts receivable, unbilled revenues and other operating assets 72,061
103,963
Accounts payable and other operating liabilities (86,604 ) (112,288 )
Regulatory assets - current 41,655
1,287
Regulatory liabilities - current 21,416
(4,328 )
Contributions to defined benefit pension plans (12,700 ) (27,700 )
Other operating activities, net 2,007
(1,410 )
Net cash provided by operating activities of continuing operations 380,884
305,452
Net cash provided by (used in) operating activities of discontinued operations (2,162 ) 13,978
Net cash provided by operating activities 378,722
319,430

Investing activities:
Property, plant and equipment additions (278,132 ) (238,840 )
Purchase of investment (24,429 ) —
Other investing activities 2,766
160
Net cash provided by (used in) investing activities of continuing operations (299,795 ) (238,680 )
Net cash provided by (used in) investing activities of discontinued operations 18,024
(17,298 )
Net cash provided by (used in) investing activities (281,771 ) (255,978 )

Financing activities:
Dividends paid on common stock (76,309 ) (71,334 )
Common stock issued 1,079
3,562
Net (payments) borrowings of short-term debt (99,200 ) 128,570
Long-term debt - issuances 700,000
—
Long-term debt - repayments (603,307 ) (104,307 )
Distributions to noncontrolling interest (13,755 ) (12,884 )
Other financing activities (10,457 ) (6,719 )
Net cash provided by (used in) financing activities (101,949 ) (63,112 )
Net change in cash, cash equivalents and restricted cash (4,998 ) 340
Cash, cash equivalents and restricted cash at beginning of period 18,240
15,792
Cash, cash equivalents and restricted cash at end of period $ 13,242
$ 16,132



(unaudited)	As of
	September 30, 2019			December 31, 2018
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13,087		$	20,776
Restricted cash	3,688			3,369
Accounts receivable, net	148,989			269,153
Materials, supplies and fuel	123,002			117,299
Derivative assets, current	412			1,500
Income tax receivable, net	12,931			12,978
Regulatory assets, current	46,206			48,776
Other current assets	29,106			29,982
Total current assets	377,421			503,833

Investments	21,583			41,013

Property, plant and equipment	6,567,229			6,000,015
Less: accumulated depreciation and depletion	(1,243,794		)	(1,145,136		)
Total property, plant and equipment, net	5,323,435			4,854,879

Other assets:
Goodwill	1,299,454			1,299,454
Intangible assets, net	13,566			14,337
Regulatory assets, non-current	214,152			235,459
Other assets, non-current	25,339			14,352
Total other assets, non-current	1,552,511			1,563,602

TOTAL ASSETS	$	7,274,950		$	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
	September 30, 2019			December 31, 2018
	(in thousands, except share amounts)
LIABILITIES AND TOTAL EQUITY
Current liabilities:
Accounts payable	$	145,085		$	210,609
Accrued liabilities	217,832			215,501
Derivative liabilities, current	2,396			947
Regulatory liabilities, current	25,168			29,810
Notes payable	294,900			185,620
Current maturities of long-term debt	5,743			5,743
Total current liabilities	691,124			648,230

Long-term debt	3,049,235			2,950,835

Deferred credits and other liabilities:
Deferred income tax liabilities, net	347,952			311,331
Regulatory liabilities, non-current	498,773			510,984
Benefit plan liabilities	134,150			145,147
Other deferred credits and other liabilities	120,820			109,377
Total deferred credits and other liabilities	1,101,695			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 61,480,640 and 60,048,567 shares, respectively	61,481			60,049
Additional paid-in capital	1,553,190			1,450,569
Retained earnings	742,138			700,396
Treasury stock, at cost – 26,572 and 44,253 shares, respectively	(1,636		)	(2,510		)
Accumulated other comprehensive income (loss)	(25,695		)	(26,916		)
Total stockholders’ equity	2,329,478			2,181,588
Noncontrolling interest	103,418			105,835
Total equity	2,432,896			2,287,423

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,274,950		$	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)	Nine Months Ended September 30,
	2019			2018
Operating activities:	(in thousands)
Net income	$	140,450		$	182,318
Loss from discontinued operations, net of tax	—			5,627
Income from continuing operations	140,450			187,945
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	154,507			146,345
Deferred financing cost amortization	6,326			5,682
Impairment of investment	19,741			—
Stock compensation	8,332			7,544
Deferred income taxes	24,381			(14,396		)
Employee benefit plans	7,965			10,641
Other adjustments, net	9,192			7,668
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	(4,126		)	(8,380		)
Accounts receivable, unbilled revenues and other operating assets	115,325			72,061
Accounts payable and other operating liabilities	(83,436		)	(86,604		)
Regulatory assets - current	12,455			41,655
Regulatory liabilities - current	(15,644		)	21,416
Contributions to defined benefit pension plans	(12,700		)	(12,700		)
Other operating activities, net	3,307			2,007
Net cash provided by operating activities of continuing operations	386,075			380,884
Net cash provided by (used in) operating activities of discontinued operations	—			(2,162		)
Net cash provided by operating activities	386,075			378,722

Investing activities:
Property, plant and equipment additions	(592,537		)	(278,132		)
Purchase of investment	—			(24,429		)
Other investing activities	(735		)	2,766
Net cash provided by (used in) investing activities of continuing operations	(593,272		)	(299,795		)
Net cash provided by investing activities of discontinued operations	—			18,024
Net cash provided by (used in) investing activities	(593,272		)	(281,771		)

Financing activities:
Dividends paid on common stock	(91,779		)	(76,309		)
Common stock issued	101,361			1,079
Net (payments) borrowings of short-term debt	109,280			(99,200		)
Long-term debt - issuances	400,000			700,000
Long-term debt - repayments	(304,307		)	(603,307		)
Distributions to noncontrolling interest	(12,736		)	(13,755		)
Other financing activities	(1,992		)	(10,457		)
Net cash provided by (used in) financing activities	199,827			(101,949		)
Net change in cash, cash equivalents and restricted cash	(7,370		)	(4,998		)
Cash, cash equivalents and restricted cash at beginning of period	24,145			18,240
Cash, cash equivalents and restricted cash at end of period	$	16,775		$	13,242

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
Net income (loss) available for common stock	—	—		—		—			—			11,740			—			3,655			15,395
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			532			—			532
Dividends on common stock ($0.505 per share)	—	—		—		—			—			(30,827		)	—			—			(30,827		)
Share-based compensation	18	—		1,213		(92		)	1,769			—			—			—			1,677
Issuance of common stock	389,237	390		—		—			29,611			—			—			—			30,001
Issuance costs	—	—		—		—			(398		)	—			—			—			(398		)
Implementation of ASU 2016-02 Leases	—	—		—		—			—			3			—			—			3
Distributions to noncontrolling interest	—	—		—		—			—			—			—			(3,485		)	(3,485		)
September 30, 2019	61,480,640	$	61,481	26,572		$	(1,636	)	$	1,553,190		$	742,138		$	(25,695	)	$	103,418		$	2,432,896

Table of Contents



	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
Net income (loss) available for common stock	—	—		—	—			—			16,950			—			3,994			20,944
Other comprehensive income (loss), net of tax	—	—		—	—			—			—			1,060			—			1,060
Dividends on common stock ($0.475 per share)	—	—		—	—			—			(25,430		)	—			—			(25,430		)
Share-based compensation	13	—		7,934	(430		)	2,107			—			—			—			1,677
Dividend reinvestment and stock purchase plan	—	—		—	—			1			—			—			—			1
Other stock transactions	—	—		—	—			159			(8		)	—			—			151
Distributions to noncontrolling interest	—	—		—	—			—			—			—			(3,757		)	(3,757		)
September 30, 2018	53,661,863	$	53,662	72,915	$	(4,072	)	$	1,157,214		$	644,154		$	(37,703	)	$	107,924		$	1,921,179

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s ~~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 September 30, 2018, we have sold nearly all of our oil~~At the time the assets were classified as held for sale, depreciation, depletion and ~~gas assets and we closed our oil and gas office~~amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in ~~August. Transaction closing for~~ the ~~last few assets and final accounting are expected within~~accompanying notes to the ~~fourth quarter.~~Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 1817 and Note 21 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 September 30, ~~2018~~,2019 and December 31, ~~2017, and~~ ~~September 30, 2017~~2018 financial ~~information and are of a normal recurring nature.~~information. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load ~~requirements, 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 nine months ended September 30, 2019 and September 30, 2018 ~~and~~ ~~September 30, 2017~~, and our financial condition as of September 30, ~~2018~~,2019 and December 31, ~~2017, and~~ ~~September 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. At this time, we do not believe the implementation of this standard will have a material impact on our financial position, results of operations or cash flows. We continue to develop our process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected, configured, and tested a new lease software solution and will be entering lease data into the new system in preparation for the January 1, 2019 standard adoption. 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.

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

In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19 in November 2018. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, and will be applied on a modified-retrospective basis through a cumulative-effect adjustment to retained earnings as of January 1, 2020. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

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 at January 1, 2019.

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 requires 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 nine months ended September 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 nine months ended September 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.



Three Months Ended September 30, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	162,214	$	89,810	$	—	$	14,992	$	(8,146	)	$	258,870
Transportation	—		29,019		—		—		(195		)	28,824
Wholesale	8,210		—		16,119		—		(14,414		)	9,915
Market - off-system sales	6,452		139		—		—		(1,488		)	5,103
Transmission/Other	14,274		10,965		—		—		(4,206		)	21,033
Revenue from contracts with customers	$	191,150	$	129,933	$	16,119	$	14,992	$	(28,449	)	$	323,745
Other revenues	234		811		9,692		560		(9,494		)	1,803
Total revenues	$	191,384	$	130,744	$	25,811	$	15,552	$	(37,943	)	$	325,548

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,992	$	(8,146	)	$	6,846
Services transferred over time	191,150		129,933		16,119		—		(20,303		)	316,899
Revenue from contracts with customers	$	191,150	$	129,933	$	16,119	$	14,992	$	(28,449	)	$	323,745


Three Months Ended September 30, 2018	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total		Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Customer types:	(in thousands)
Customer Types:
Retail	$	157,049	$	88,559	$	—	$	16,751	$	(7,941	)	$	254,418	$	157,049	$	88,559	$	—	$	16,751	$	(7,941	)	$	254,418
Transportation	—		30,079		—		—		(267		)	29,812		—		30,079		—		—		(267		)	29,812
Wholesale	8,255		—		14,485		—		(13,047		)	9,693		8,255		—		15,373		—		(13,935		)	9,693
Market - off-system sales	9,059		140		—		—		(1,349		)	7,850		9,059		140		—		—		(1,349		)	7,850
Transmission/Other	10,196		11,887		—		—		(3,693		)	18,390		10,196		11,887		—		—		(3,693		)	18,390
Revenue from contracts with customers	184,559		130,665		14,485		16,751		(26,297		)	320,163		$	184,559	$	130,665	$	15,373	$	16,751	$	(27,185	)	$	320,163
Other revenues	231		1,011		9,118		550		(9,094		)	1,816		231		1,011		9,118		550		(9,094		)	1,816
Total revenues	$	184,790	$	131,676	$	23,603	$	17,301	$	(35,391	)	$	321,979
Total Revenues														$	184,790	$	131,676	$	24,491	$	17,301	$	(36,279	)	$	321,979

Timing of revenue recognition:
Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	16,751	$	(7,941	)	$	8,810	$	—	$	—	$	—	$	16,751	$	(7,942	)	$	8,809
Services transferred over time	184,559		130,665		14,485		—		(18,356		)	311,353		184,559		130,665		15,373		—		(19,243		)	311,354
Revenue from contracts with customers	$	184,559	$	130,665	$	14,485	$	16,751	$	(26,297	)	$	320,163	$	184,559	$	130,665	$	15,373	$	16,751	$	(27,185	)	$	320,163

Table of Contents



Nine Months Ended September 30, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	455,409	$	567,715	$	—	$	43,249	$	(23,315	)	$	1,043,058
Transportation	—		102,159		—		—		(903		)	101,256
Wholesale	23,334		—		46,650		—		(40,923		)	29,061
Market - off-system sales	16,592		517		—		—		(5,047		)	12,062
Transmission/Other	42,865		35,767		—		—		(12,608		)	66,024
Revenue from contracts with customers	$	538,200	$	706,158	$	46,650	$	43,249	$	(82,796	)	$	1,251,461
Other revenues	2,465		1,135		29,114		1,777		(28,706		)	5,785
Total revenues	$	540,665	$	707,293	$	75,764	$	45,026	$	(111,502	)	$	1,257,246

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	43,249	$	(23,315	)	$	19,934
Services transferred over time	538,200		706,158		46,650		—		(59,481		)	1,231,527
Revenue from contracts with customers	$	538,200	$	706,158	$	46,650	$	43,249	$	(82,796	)	$	1,251,461



Nine Months Ended September 30, 2018	Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Customer Types:
Retail	$	449,482	$	565,816	$	—	$	49,653	$	(23,761	)	$	1,041,190
Transportation	—		100,760		—		—		(977		)	99,783
Wholesale	25,497		—		43,744		—		(39,457		)	29,784
Market - off-system sales	18,142		728		—		—		(5,531		)	13,339
Transmission/Other	36,622		36,230		—		—		(10,967		)	61,885
Revenue from contracts with customers	$	529,743	$	703,534	$	43,744	$	49,653	$	(80,693	)	$	1,245,981
Other revenues	2,218		3,106		27,429		1,675		(27,337		)	7,091
Total Revenues	$	531,961	$	706,640	$	71,173	$	51,328	$	(108,030	)	$	1,253,072

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	49,653	$	(23,761	)	$	25,892
Services transferred over time	529,743		703,534		43,744		—		(56,932		)	1,220,089
Revenue from contracts with customers	$	529,743	$	703,534	$	43,744	$	49,653	$	(80,693	)	$	1,245,981



(a)						Due to the changes in our segment disclosures discussed in Note 3, Power Generation Wholesale revenue was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $0.9 million and $2.6 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.

Nine Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total
Customer types: (in thousands)
Retail $ 449,482
$ 565,816
$ —
$ 49,653
$ (23,761 ) $ 1,041,190
Transportation —
100,760
—
—
(977 ) 99,783
Wholesale 25,497
—
41,161
—
(36,874 ) 29,784
Market - off-system sales 18,142
728
—
—
(5,531 ) 13,339
Transmission/Other 36,622
36,230
—
—
(10,967 ) 61,885
Revenue from contracts with customers 529,743
703,534
41,161
49,653
(78,110 ) 1,245,981
Other revenues 2,218
3,106
27,429
1,675
(27,337 ) 7,091
Total revenues $ 531,961
$ 706,640
$ 68,590
$ 51,328
$ (105,447 ) $ 1,253,072

Timing of revenue recognition:
Services transferred at a point in time $ —
$ —
$ —
$ 49,653
$ (23,761 ) $ 25,892
Services transferred over time 529,743
703,534
41,161
—
(54,349 ) 1,220,089
Revenue from contracts with customers $ 529,743
$ 703,534
$ 41,161
$ 49,653
$ (78,110 ) $ 1,245,981

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, derivative revenue under ASC 815 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 have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers and approximately $21 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.

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~~

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 require 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.




Three Months Ended September 30, 2019	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Segment:
Electric Utilities	$	185,811	$	234	$	5,339		$	—		$	191,384
Gas Utilities	129,385		810		549			—			130,744
Power Generation	1,703		531		14,415			9,162			25,811
Mining	6,846		228		8,146			332			15,552
Inter-company eliminations	—		—		(28,449		)	(9,494		)	(37,943		)
Total	$	323,745	$	1,803	$	—		$	—		$	325,548




Three Months Ended September 30, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Segment:
Electric Utilities	$	179,527	$	231	$	5,032		$	—		$	184,790
Gas Utilities	130,390		1,011		275			—			131,676
Power Generation ^(a)	1,437		348		13,936			8,770			24,491
Mining	8,809		226		7,942			324			17,301
Inter-company eliminations ^(a)	—		—		(27,185		)	(9,094		)	(36,279		)
Total	$	320,163	$	1,816	$	—		$	—		$	321,979

Power Generation ^(b)




Nine Months Ended September 30, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Segment:
Electric Utilities	$	513,270	$	2,218	$	16,473		$	—		$	531,961
Gas Utilities	702,532		3,106		1,002			—			706,640
Power Generation ^(a)	4,287		1,066		39,457			26,363			71,173
Mining	25,892		701		23,761			974			51,328
Inter-company eliminations ^(a)	—		—		(80,693		)	(27,337		)	(108,030		)
Total	$	1,245,981	$	7,091	$	—		$	—		$	1,253,072

~~Under our modified retrospective adoption~~

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

Segment:
Electric Utilities $ 181,238
$ 2,333
$ 27,324
Gas Utilities 142,821
73
(4,329 )

Power Generation ^(b)
1,810
21,117
6,155
Mining 9,742
7,751
3,477
Corporate and Other —
—
(3,664 )
Inter-company eliminations —
(31,274 ) —
Total $ 335,611
$ —
$ 28,963

Nine Months Ended September 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 Utilities $ 513,270
$ 2,218
$ 16,473
$ —
$ 531,961
$ 63,313
Gas Utilities ^(a)
702,532
3,106
1,002
—
706,640
93,182
Power Generation ^(b)
4,287
1,066
36,874
26,363
68,590
17,319
Mining 25,892
701
23,761
974
51,328
9,561
Corporate and Other —
—
—
—
—
(5,877 )
Inter-company eliminations —
—
(78,110 ) (27,337 ) (105,447 ) —
Total $ 1,245,981
$ 7,091
$ —
$ —
$ 1,253,072
$ 177,498

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

Segment:
Electric Utilities $ 518,925
$ 9,123
$ 68,386
Gas Utilities 674,161
90
41,409

Power Generation ^(b)
5,382
62,907
18,017
Mining 26,500
22,485
9,048

Corporate and Other ^(c)
—
—
(6,994 )
Inter-company eliminations —
(94,605 ) —
Total $ 1,224,968
$ —
$ 129,866




	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Adjusted operating income:
Electric Utilities ^(a)	$	50,653		$	43,393		$	125,219		$	123,073
Gas Utilities	4,736			4,240			116,607			116,168
Power Generation ^(a)	11,822			13,079			33,945			33,731
Mining	3,374			4,551			9,351			12,647
Corporate and Other ^(a)	(34		)	(178		)	(439		)	(2,709		)
Operating income	70,551			65,085			284,683			282,910

Interest expense, net	(33,487		)	(35,297		)	(102,469		)	(104,826		)
Impairment of investment	(19,741		)	—			(19,741		)	—
Other income (expense), net	580			(510		)	55			(1,923		)
Income tax benefit (expense) ^(b)	(2,508		)	(7,477		)	(22,078		)	11,784
Income from continuing operations	15,395			21,801			140,450			187,945
Net (loss) from discontinued operations	—			(857		)	—			(5,627		)
Net income	15,395			20,944			140,450			182,318
Net income attributable to noncontrolling interest	(3,655		)	(3,994		)	(10,319		)	(10,447		)
Net income available for common stock	$	11,740		$	16,950		$	130,131		$	171,871

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



Segment	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Electric Utilities	$	1.6		$	4.8
Power Generation	(1.4		)	(4.4		)
Corporate and Other	(0.2		)	(0.4		)
	$	—		$	—

Income tax benefit (expense) for the nine months ended September 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:	September 30, 2019		December 31, 2018
Segment:
Electric Utilities ^(a)	$	2,810,108	$	2,707,695
Gas Utilities	3,797,941		3,623,475
Power Generation ^(a)	414,526		342,085
Mining	78,073		80,594
Corporate and Other	174,302		209,478
Total assets	$	7,274,950	$	6,963,327

Total Assets (net of inter-company eliminations) as of: September 30, 2018 December 31, 2017 September 30, 2017
Segment:
Electric Utilities ^(a)
$ 2,853,414
$ 2,906,275
$ 2,911,919
Gas Utilities 3,433,316
3,426,466
3,288,104
Power Generation ^(a)
122,428
60,852
64,357
Mining 72,602
65,455
66,700
Corporate and Other 177,324
115,612
115,330
Discontinued operations 2,854
84,242
117,338
Total assets $ 6,661,938
$ 6,658,902
$ 6,563,748

~~__________~~___________

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
September 30, 2018	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
September 30, 2019										Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	43,108	$	31,381	$	(386	)	$	74,103	$	39,151	$	31,843	$	(500	)	$	70,494
Gas Utilities	48,638		24,768		(2,188		)	71,218		46,265		24,091		(2,490		)	67,866
Power Generation	1,696		—		—			1,696		2,733		—		—			2,733
Mining	3,749		—		—			3,749		1,804		—		—			1,804
Corporate	2,030		—		—			2,030		6,261		—		(169		)	6,092
Total	$	99,221	$	56,149	$	(2,574	)	$	152,796	$	96,214	$	55,934	$	(3,159	)	$	148,989

Accounts Unbilled Less Allowance for Accounts
September 30, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net
Electric Utilities $ 42,716
$ 29,762
$ (494 ) $ 71,984
Gas Utilities 49,842
24,516
(1,190 ) 73,168
Power Generation 1,010
—
—
1,010
Mining 3,534
—
—
3,534
Corporate 629
—
—
629
Total $ 97,731
$ 54,278
$ (1,684 ) $ 150,325

(5) REGULATORY ACCOUNTING

Deferred energy and fuel cost adjustments ^(a)

Deferred gas cost adjustments ^(a)

Gas price derivatives ^(a)

Deferred taxes on AFUDC^(b)

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) (e)}

Decommissioning costs ^(b)

Gas supply contract termination ^(a)

Other regulatory assets^(a)

Deferred energy and gas costs^(a)

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

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

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 -~~ ~~The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact~~

On June 13, 2019, we received approval from the ~~change in the federal tax rate from 35%~~WPSC to ~~21% (including the effects~~consolidate our Wyoming gas utility operations into a new utility entity. The Wyoming portion of ~~tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs.~~ Black Hills ~~has been collaborating with~~Gas Distribution, LLC, Cheyenne Light’s natural gas 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 have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimatedoperations (Cheyenne Gas and ~~recorded a reserve to revenue of approximately $6.0 million~~Northeast Wyoming), and ~~$29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers.~~

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

State Approximate 2018 Benefit for Customers Start Date for Customer Benefits
Arkansas $ 9.7 million October 2018
Colorado $ 10.8 million July 2018
Iowa $ 2.4 million June 2018
Kansas $ 1.9 million April 2018
Nebraska $ 3.8 million July 2018
South Dakota $ 7.7 million October 2018

~~In support of returning benefits to customers, the three rate review requests filed in 2017 for Arkansas Gas,~~ Wyoming Gas (Northwest Wyoming) were 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 4 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,~~filed with the WPSC ~~reached~~on November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a ~~bench~~ decision ~~approving our~~expected by the end of 2019.

South Dakota Electric and Wyoming ~~Gas (Northwest Wyoming) settlement~~Electric

~~Arkansas Gas~~Nebraska

~~Wyoming Electric~~

~~On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application~~be filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric will provide an aggregate $7.0 million in customer credits through the PCA mechanism in 2018, 2019 andby mid-year 2020 to ~~resolve all outstanding issues relating to~~consolidate the rates, tariffs and services of its current and prior PCA filings. The settlement also stipulates the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. As of September 30, 2018, we have recorded a liability of $4.5 million related to the PCA.2 existing gas distribution companies.



	September 30, 2019		December 31, 2018
Materials and supplies	$	81,382	$	75,081
Fuel - Electric Utilities	2,535		2,850
Natural gas in storage held for distribution	39,085		39,368
Total materials, supplies and fuel	$	123,002	$	117,299

September 30, 2018 December 31, 2017 September 30, 2017
Materials and supplies $ 73,777
$ 69,732
$ 70,284
Fuel - Electric Utilities 2,750
2,962
2,993
Natural gas in storage held for distribution 46,091
40,589
49,589
Total materials, supplies and fuel $ 122,618
$ 113,283
$ 122,866

September 30, 2018 December 31, 2017 September 30, 2017
Cost method investment $ 28,134
$ —
$ —
Cash surrender value of life insurance contracts 13,068
13,090
12,947
Total investments $ 41,202
$ 13,090
$ 12,947



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

Net income available for common stock	$	11,740	$	16,950	$	130,131	$	171,871

Weighted average shares - basic	60,976		53,364		60,458		53,346
Dilutive effect of:
Equity Units ^(a)	—		1,344		—		1,060
Equity compensation	128		111		120		102
Weighted average shares - diluted	61,104		54,819		60,578		54,508



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018

Equity compensation	2	12	4	15
Restricted Stock	—	—	1	—
Anti-dilutive shares	2	12	5	15

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017

Equity compensation 12
—
15
—
Anti-dilutive shares 12
—
15
—



	September 30, 2019				December 31, 2018
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	50,000	$	18,313	$	—	$	22,311
CP Program	244,900		—		185,620		—
Total	$	294,900	$	18,313	$	185,620	$	22,311

September 30, 2018 December 31, 2017 September 30, 2017
Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit
Revolving Credit Facility $ —
$ 15,203
$ —
$ 26,848
$ —
$ 25,391
CP Program 112,100
—
211,300
—
225,170
—
Total $ 112,100
$ 15,203
$ 211,300
$ 26,848
$ 225,170
$ 25,391

As of September 30, 2018 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio 61.4% Less than 65%

~~Current Maturities~~Debt Transaction

Subsequent Event - Debt Offering

Table of Contents

~~(10)~~

(9) EQUITY

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

Nine Months Ended September 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) 171,871
10,447
182,318
Other comprehensive income 3,481
—
3,481
Dividends on common stock (76,309 ) —
(76,309 )
Share-based compensation 4,871
—
4,871
Dividend reinvestment and stock purchase plan 220
—
220
Other stock transactions 147
—
147
Distribution to noncontrolling interest —
(13,755 ) (13,755 )
Balance at September 30, 2018 $ 1,813,255
$ 107,924
$ 1,921,179

Nine Months Ended September 30, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity
(in thousands)
Balance at December 31, 2016 $ 1,614,639
$ 115,495
$ 1,730,134
Net income (loss) 126,381
10,567
136,948
Other comprehensive income 2,317
—
2,317
Dividends on common stock (71,334 ) —
(71,334 )
Share-based compensation 5,853
—
5,853
Dividend reinvestment and stock purchase plan 2,300
—
2,300
Redeemable noncontrolling interest (886 ) —
(886 )
Cumulative effect of ASU 2016-09 implementation 3,714
—
3,714
Other stock transactions (180 ) —
(180 )
Distribution to noncontrolling interest —
(12,884 ) (12,884 )
Balance at September 30, 2017 $ 1,682,804
$ 113,178
$ 1,795,982

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 September 30, 2019, we issued a total of 389,237 shares of common ~~shares during~~stock under the ATM equity offering program for proceeds of $30 million, net of $0.3 million in commissions. During the nine months ended September 30, ~~2018 or September 30, 2017~~2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering ~~program.~~

~~Subsequent Event - Equity Units Settlement~~

~~On October 29, 2018, we announced the settlement rate~~program for the stock purchase contracts that are components of the Equity Units issued November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of Black Hills Corporation common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of Black Hills Corporation common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units.

~~Upon settlement of all outstanding stock purchase obligations, the Company received gross~~ proceeds of ~~approximately $299~~$99 million, net of $1.0 million in exchange for approximately 6.372 million shares of common stock. Proceeds will be used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt.

commissions. As of ~~November 1, 2018, after the Equity Units settlement, we had~~September 30, 2019, there were no shares ~~outstanding of approximately 59.97 million.~~that were sold, but not settled.

(1110) RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk and Credit Policies and Procedures as discussed in our ~~2017~~2018 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to, ~~the following market risks including,~~ but not limited ~~to:~~

~~Commodity~~to, commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain gas-fired generation ~~assets; and~~assets.

~~Interest rate risk associated with our variable rate debt.~~

Credit Risk

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

For ~~production and generation~~other than retail utility activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental ~~guarantees,~~guaranties, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 1211.

Utilities

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

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

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from October ~~2018~~2019 through ~~May 2020;~~October 2021; a portion of these swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with forward contracts to deliver gas to our Choice Gas Program customers. The ~~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.

Table of Contents

The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our utilities are composed of both long and short positions. We were in a net long position as of:



	September 30, 2019		December 31, 2018
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	2,350,000	15	4,000,000	24
Natural gas options purchased, net	8,580,000	6	4,320,000	13
Natural gas basis swaps purchased	2,090,000	15	3,960,000	24
Natural gas over-the-counter swaps, net ^(b)	5,460,000	25	3,660,000	24
Natural gas physical contracts, net ^(c)	23,459,639	6	18,325,852	30

September 30, 2018 December 31, 2017 September 30, 2017

Notional
(MMBtus)

Maximum
Term
(months)^(a)

Notional
(MMBtus)

Maximum
Term
(months)^(a)

Notional
(MMBtus)

Maximum
Term
(months)^(a)
Natural gas futures purchased 5,300,000
27 8,330,000
36 10,250,000
39
Natural gas options purchased, net 9,670,000
16 3,540,000
14 7,360,000
17
Natural gas basis swaps purchased 5,140,000
27 8,060,000
36 9,170,000
39
Natural gas over-the-counter swaps, net ^(b)
4,370,000
20 3,820,000
29 4,600,000
20
Natural gas physical contracts, net ^(c)
19,539,851
33 12,826,605
35 21,071,714
38

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of September 30, ~~2018~~, ~~2,236,000~~2019, 1,812,500 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.

Based on September 30, ~~2018~~2019 prices, a ~~$0.1~~$0.4 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, ~~2018,~~2019, the Company posted ~~$0.7~~$0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

~~Financing Activities~~

At September 30, 2018, we had no outstanding interest rate swap agreements. Our last interest rate swap agreement with a $50 million notional value, which was designated to borrowings on our Revolving Credit Facility, expired in January 2017.

~~Discontinued Operations~~

Our Oil and Gas segment was exposed to risks associated with changes in the market prices of oil and gas. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas assets, these activities were discontinued and there were no outstanding derivative agreements as of September 30, 2018 or December 31, 2017. At September 30, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 54,000 Bbls, crude oil option contracts with notional volumes of 9,000 Bbls and natural gas futures and swap contracts with notional volumes of 540,000 MMBtus.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, ~~2018~~2019 and ~~2017~~2018. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.



Three Months Ended September 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	(129		)
Total		$	(842	)



Three Months Ended September 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	$	(712	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(18		)
Total		$	(730	)

Table of Contents



Nine Months Ended September 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	$	(2,139	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	508
Total		$	(1,631	)



Nine Months Ended September 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	$	(2,138	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(802		)
Total		$	(2,940	)




	Three Months Ended September 30,
	2019			2018
	(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts	$	(150	)	$	30
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			712
Forward commodity contracts	129			18
Total other comprehensive income (loss) from hedging	$	692		$	760



	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts	$	(434	)	$	(219	)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	2,139			2,138
Forward commodity contracts	(508		)	802
Total other comprehensive income (loss) from hedging	$	1,197		$	2,721

Table of Contents

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.

Three Months Ended September 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 $ (712 ) Interest expense $ —
Commodity derivatives Fuel, purchased power and cost of natural gas sold (18 ) Fuel, purchased power and cost of natural gas sold —
Total $ (730 ) $ —




		Three Months Ended September 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	$	(20	)	$	(96	)
Commodity derivatives	Other income (expense), net	142			—
		$	122		$	(96	)

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

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

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

Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $ (713 ) Interest expense $ —
Commodity derivatives Net (loss) from discontinued operations 295
Net (loss) from discontinued operations —
Commodity derivatives Fuel, purchased power and cost of natural gas sold (34 ) Fuel, purchased power and cost of natural gas sold —
Total $ (452 ) $ —



		Nine Months Ended September 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	$	(1,180	)	$	929
Commodity derivatives	Other income (expense), net	$	142		$	—
		$	(1,038	)	$	929

Nine Months Ended September 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 $ (2,138 ) Interest expense $ —
Commodity derivatives Fuel, purchased power and cost of natural gas sold (802 ) Fuel, purchased power and cost of natural gas sold —
Total $ (2,940 ) $ —

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

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

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

Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps Interest expense $ (2,228 ) Interest expense $ —
Commodity derivatives Net (loss) from discontinued operations 954
Net (loss) from discontinued operations —
Commodity derivatives Fuel, purchased power and cost of natural gas sold (20 ) Fuel, purchased power and cost of natural gas sold —
Total $ (1,294 ) $ —

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 nine months ended September 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 September 30,
2018 2017
(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts $ 30
$ (254 )
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps 712
713
Forward commodity contracts 18
(261 )
Total other comprehensive income (loss) from hedging $ 760
$ 198

Nine Months Ended September 30,
2018 2017
(in thousands)
Increase (decrease) in fair value:
Forward commodity contracts $ (219 ) $ 1,197
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps 2,138
2,228
Forward commodity contracts 802
(934 )
Total other comprehensive income (loss) from hedging $ 2,721
$ 2,491

~~Derivatives Not Designated as Hedge Instruments~~

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.

Three Months Ended September 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 $ —
$ (53 )
Commodity derivatives Fuel, purchased power and cost of natural gas sold (96 ) (322 )
$ (96 ) $ (375 )

Nine Months Ended September 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 $ —
$ 90
Commodity derivatives Fuel, purchased power and cost of natural gas sold 929
(1,822 )
$ 929
$ (1,732 )

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory ~~assets~~asset or Regulatory liability accounts related to the hedges in our utilities were $4.3 million and $6.2 million ~~$12 million and $11 million at~~as of September 30, ~~2018,~~2019 and December 31, ~~2017 and September 30, 2017,~~2018, respectively.

(1211) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our ~~2017~~2018 Annual Report on Form 10-K filed with the SEC.

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

Valuation Methodologies for Derivatives

~~Discontinued Operations:~~

~~Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18.~~

~~Utilities Segments:~~

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

~~Corporate Activities:~~Nonrecurring Fair Value Measurement

AsA discussion of ~~September 30, 2018, we no longer have derivatives within~~the fair value of our ~~corporate activities as our last interest rate swaps matured~~investment in ~~January 2017.~~equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 21.

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. The following tables set forth by level within the fair value hierarchy present gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.



	As of September 30, 2019
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	2,750	$	—	$	(2,335	)	$	415
Total	$	—	$	2,750	$	—	$	(2,335	)	$	415

Liabilities:
Commodity derivatives — Utilities	$	—	$	6,080	$	—	$	(3,471	)	$	2,609
Total	$	—	$	6,080	$	—	$	(3,471	)	$	2,609

Table of Contents

As of September 30, 2018
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Utilities $ —
$ 5,882
$ —
$ (4,469 ) $ 1,413
Total $ —
$ 5,882
$ —
$ (4,469 ) $ 1,413

Liabilities:
Commodity derivatives — Utilities $ —
$ 10,033
$ —
$ (8,777 ) $ 1,256
Total $ —
$ 10,033
$ —
$ (8,777 ) $ 1,256



	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 September 30, 2017
Level 1 Level 2 Level 3
Cash Collateral and Counterparty
Netting
Total
(in thousands)
Assets:
Commodity derivatives — Utilities $ —
$ 2,880
$ —
$ (2,448 ) $ 432
Total $ —
$ 2,880
$ —
$ (2,448 ) $ 432

Liabilities:
Commodity derivatives — Utilities $ —
$ 12,647
$ —
$ (11,125 ) $ 1,522
Total $ —
$ 12,647
$ —
$ (11,125 ) $ 1,522

Fair Value Measures by Balance Sheet Classification

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

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

As of September 30, 2018
Balance Sheet Location
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
Commodity derivatives Derivative assets — current $ 142
$ —
Commodity derivatives Other assets, non-current 21
—
Commodity derivatives Derivative liabilities — current —
273
Commodity derivatives Other deferred credits and other liabilities —
10
Total derivatives designated as hedges $ 163
$ 283

Derivatives not designated as hedges:
Commodity derivatives Derivative assets — current $ 1,250
$ —
Commodity derivatives Derivative liabilities — current —
881
Commodity derivatives Other deferred credits and other liabilities —
92
Total derivatives not designated as hedges $ 1,250
$ 973



	Balance Sheet Location	September 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	2			18
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities — current	(427		)	(114		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(70		)	(4		)
Total derivatives designated as hedges		$	(495	)	$	315

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets — current	$	412		$	1,085
Noncurrent commodity derivatives	Other assets, non-current	1			1
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities — current	(1,969		)	(833		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(143		)	(56		)
Total derivatives not designated as hedges		$	(1,699	)	$	197

As of December 31, 2017
Balance Sheet Location
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
Commodity derivatives Derivative liabilities — current $ —
$ 817
Commodity derivatives Other deferred credits and other liabilities —
67
Total derivatives designated as hedges $ —
$ 884

Derivatives not designated as hedges:
Commodity derivatives Derivative assets — current $ 304
$ —
Commodity derivatives Derivative liabilities — current —
1,264
Commodity derivatives Other deferred credits and other liabilities —
111
Total derivatives not designated as hedges $ 304
$ 1,375

As of September 30, 2017
Balance Sheet Location
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
Commodity derivatives Derivative assets — current $ 2
$ —
Commodity derivatives Current assets held for sale 225
—
Commodity derivatives Derivative liabilities — current —
422
Commodity derivatives Current liabilities held for sale —
89
Commodity derivatives Other deferred credits and other liabilities —
49
Commodity derivatives Noncurrent liabilities held for sale —
10
Total derivatives designated as hedges $ 227
$ 570

Derivatives not designated as hedges:
Commodity derivatives Derivative assets — current $ 430
$ —
Commodity derivatives Derivative liabilities — current —
1,036
Commodity derivatives Other deferred credits and other liabilities —
15
Commodity derivatives Noncurrent liabilities held for sale —
15
Total derivatives not designated as hedges $ 430
$ 1,066

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our ~~2017~~2018 Annual Report on Form 10-K.

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:

September 30, 2018 December 31, 2017 September 30, 2017

Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Cash and cash equivalents ^(a)
$ 10,001
$ 10,001
$ 15,420
$ 15,420
$ 13,449
$ 13,449
Restricted cash ^(a)
$ 3,241
$ 3,241
$ 2,820
$ 2,820
$ 2,683
$ 2,683
Notes payable ^(b)
$ 112,100
$ 112,100
$ 211,300
$ 211,300
$ 225,170
$ 225,170
Long-term debt, including current maturities ^{(c) (d)}
$ 3,207,132
$ 3,289,770
$ 3,115,143
$ 3,350,544
$ 3,115,607
$ 3,362,971



	September 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^{(a) (b)}	$	3,054,978	$	3,424,747	$	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						Nine Months Ended							Three Months Ended						Nine Months Ended
		September 30, 2018			September 30, 2017			September 30, 2018			September 30, 2017				September 30, 2019			September 30, 2018			September 30, 2019			September 30, 2018
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(712	)	$	(713	)	$	(2,138	)	$	(2,228	)	Interest expense	$	(713	)	$	(712	)	$	(2,139	)	$	(2,138	)
Commodity contracts	Net (loss) from discontinued operations	—			295			—			954
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(18		)	(34		)	(802		)	(20		)	Fuel, purchased power and cost of natural gas sold	(129		)	(18		)	508			(802		)
		(730		)	(452		)	(2,940		)	(1,294		)		(842		)	(730		)	(1,631		)	(2,940		)
Income tax	Income tax benefit (expense)	149			154			643			435			Income tax benefit (expense)	170			149			358			643
Total reclassification adjustments related to cash flow hedges, net of tax		$	(581	)	$	(298	)	$	(2,297	)	$	(859	)		$	(672	)	$	(581	)	$	(1,273	)	$	(2,297	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	44		$	49		$	133		$	146		Operations and maintenance	$	20		$	44		$	59		$	133

Actuarial gain (loss)	Operations and maintenance	(621		)	(414		)	(1,865		)	(1,242		)	Operations and maintenance	(84		)	(621		)	(525		)	(1,865		)
		(577		)	(365		)	(1,732		)	(1,096		)		(64		)	(577		)	(466		)	(1,732		)
Income tax	Income tax benefit (expense)	128			128			380			393			Income tax benefit (expense)	89			128			184			380
Total reclassification adjustments related to defined benefit plans, net of tax		$	(449	)	$	(237	)	$	(1,352	)	$	(703	)		$	25		$	(449	)	$	(282	)	$	(1,352	)
Total reclassifications		$	(1,030	)	$	(535	)	$	(3,649	)	$	(1,562	)		$	(647	)	$	(1,030	)	$	(1,555	)	$	(3,649	)

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	—			(334		)	—			(334		)
Amounts reclassified from AOCI	1,639			(366		)	282			1,555
As of September 30, 2019	$	(15,668	)	$	(372	)	$	(9,655	)	$	(25,695	)


	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	—			(168		)	—			(168		)
Amounts reclassified from AOCI	1,682			615			1,352			3,649
Reclassifications of certain tax effects from AOCI	15			—			3			18
As of September 30, 2018	$	(17,884	)	$	(71	)	$	(19,748	)	$	(37,703	)

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 —
(168 ) —
(168 )
Amounts reclassified from AOCI 1,682
615
1,352
3,649
Reclassifications of certain tax effects from AOCI 15
—
3
18
Ending Balance September 30, 2018 $ (17,884 ) $ (71 ) $ (19,748 ) $ (37,703 )

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 —
755
—
755
Amounts reclassified from AOCI 1,449
(590 ) 703
1,562
Ending Balance September 30, 2017 $ (16,660 ) $ (68 ) $ (15,838 ) $ (32,566 )

(1514) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Nine Months Ended	September 30, 2019			September 30, 2018
	(in thousands)
Non-cash investing and financing activities —
Property, plant and equipment acquired with accrued liabilities	$	86,661		$	49,631

Cash (paid) refunded during the period —
Interest (net of amounts capitalized)	$	(99,375	)	$	(104,035	)
Income taxes	$	2,255		$	(14,842	)

Table of Contents

Nine Months Ended September 30, 2018 September 30, 2017
(in thousands)
Non-cash investing and financing activities —
Property, plant and equipment acquired with accrued liabilities $ 49,631
$ 33,409
Increase (decrease) in capitalized assets associated with asset retirement obligations $ 155
$ 1,362

Cash (paid) refunded during the period —
Interest (net of amounts capitalized) $ (104,035 ) $ (102,008 )
Income taxes (paid) refunded $ (14,842 ) $ 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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Service cost	$	1,346		$	1,708		$	4,037		$	5,125
Interest cost	4,344			3,867			13,031			11,602
Expected return on plan assets	(6,100		)	(6,185		)	(18,300		)	(18,555		)
Prior service cost	6			15			19			44
Net loss (gain)	941			2,158			2,822			6,473
Net periodic benefit cost	$	537		$	1,563		$	1,609		$	4,689

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017
Service cost $ 1,708
$ 1,759
$ 5,125
$ 5,276
Interest cost 3,867
3,880
11,602
11,640
Expected return on plan assets (6,185 ) (6,130 ) (18,555 ) (18,388 )
Prior service cost 15
15
44
44
Net loss (gain) 2,158
1,002
6,473
3,005
Net periodic benefit cost $ 1,563
$ 526
$ 4,689
$ 1,577

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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Service cost	$	454		$	573		$	1,362		$	1,718
Interest cost	560			521			1,683			1,563
Expected return on plan assets	(57		)	(57		)	(172		)	(170		)
Prior service cost (benefit)	(99		)	(99		)	(298		)	(297		)
Net loss (gain)	—			54			—			162
Net periodic benefit cost	$	858		$	992		$	2,575		$	2,976

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017
Service cost $ 573
$ 575
$ 1,718
$ 1,725
Interest cost 521
533
1,563
1,600
Expected return on plan assets (57 ) (79 ) (170 ) (237 )
Prior service cost (benefit) (99 ) (109 ) (297 ) (327 )
Net loss (gain) 54
125
162
375
Net periodic benefit cost $ 992
$ 1,045
$ 2,976
$ 3,136

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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Service cost	$	429	$	632	$	2,406	$	1,347
Interest cost	324		293		972		878
Prior service cost	—		—		1		1
Net loss (gain)	134		250		402		750
Net periodic benefit cost	$	887	$	1,175	$	3,781	$	2,976

Table of Contents

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017
Service cost $ 632
$ 612
$ 1,347
$ 2,048
Interest cost 293
319
878
957
Prior service cost —
—
1
1
Net loss (gain) 250
251
750
751
Net periodic benefit cost $ 1,175
$ 1,182
$ 2,976
$ 3,757

For the three and nine months ended September 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 nine months ended September 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 September 30, 2019		Nine Months Ended September 30, 2019		Anticipated for 2019		Anticipated for 2020
Defined Benefit Pension Plan	$	12,700	$	12,700	$	—	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,109	$	3,326	$	1,109	$	4,815
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	366	$	1,098	$	366	$	1,406

Contributions Made Contributions Made Additional Contributions Contributions
Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Anticipated for 2018 Anticipated for 2019
Defined Benefit Pension Plan $ 12,700
$ 12,700
$ —
$ 12,700
Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,234
$ 3,702
$ 1,234
$ 3,821
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 343
$ 1,029
$ 343
$ 1,623

(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 except for those described below.

~~Busch Ranch~~Future Purchase Agreement - Related Party

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 continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 additional years. A decision from FERC is pending.

~~Busch Ranch Wind Farm~~Platte River Power Authority PPAs

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

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

The following is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas. Colorado Electric has a 50% ownership interest in the wind farm. On September 20, 2018, Black Hills Electric Generation agreed toschedule of unconditional purchase ~~AltaGas’s 50% interest in Busch Ranch for $16 million. The purchase, which is subject to FERC approval, is expected to be finalized by the end of 2018.~~

~~Dividend Restrictions~~

~~Our Revolving Credit Facility and other debt~~ obligations ~~contain restrictions on the payment of cash dividends upon a default or event of default. As of~~ ~~September 30, 2018, we were in compliance with the debt covenants.~~

Due to our holding company structure, substantially all 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~~required under the ~~Federal~~25 MW Platte River Power ~~Act and settlement agreements with state regulatory jurisdictions and financing agreements. As~~Authority PPA as of September 30, ~~2018, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.~~2019 (in thousands):



2019	$	1,369
2020	$	5,475
2021	$	5,475
2022	$	5,475
2023	$	5,475
Thereafter	$	2,738

Table of Contents

~~(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. ~~As of~~We completed the divestiture in 2018. See Note 21 for more information.

(18) INCOME TAXES

Income tax benefit (expense) for the Three Months Ended September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. We expect to transfer any associated liabilities, and settle substantially all remaining liabilities by December 31, 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~~Three Months Ended September 30, 2018.

~~During~~Income tax benefit (expense) for the ~~nine~~three months ended September 30, ~~2018, we recorded $2.9~~2019 was $(2.5) million compared to $(7.5) million reported for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of ~~expenses comprised of royalty payments and reclamation costs related to final closing~~tax reform on deferred income taxes.

For the ~~sale of BHEP assets.~~

~~Total assets and liabilities of~~ ~~the Oil and Gas segment~~ atthree months ended September 30, ~~2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on~~2019 the accompanying Condensed Consolidated Balance Sheets due to the expected final disposals occurring by the end of 2018. Held for sale assets and liabilities at September 30, 2017 are classified as current and non-current (in thousands):

September 30, 2018 December 31, 2017 September 30, 2017
Other current assets $ 75
$ 10,360
$ 8,457
Derivative assets, current and noncurrent —
—
225
Deferred income tax assets, noncurrent, net

—
16,966
12,571
Property, plant and equipment, net 2,779
56,916
96,085
Other current liabilities (2,138 ) (18,966 ) (7,597 )
Derivative liabilities, current and noncurrent —
—
(114 )
Deferred income tax liabilities, noncurrent, net

(400 ) —
—
Other noncurrent liabilities —
(22,808 ) (23,319 )
Net assets (liabilities) $ 316
$ 42,468
$ 86,308

At ~~September 30, 2018~~, ~~December 31, 2017~~ ~~and~~ ~~September 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.~~

~~The Oil and Gas segment’s other current liabilities at~~ ~~September 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~~ ~~September 30, 2017~~ ~~consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at~~ ~~December 31, 2017~~ ~~and~~ ~~September 30, 2017~~ ~~consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas wells.~~

~~(19) INCOME TAXES~~

~~The~~ effective tax rate ~~differs from~~was 14.0% compared to 7.6% excluding the ~~federal statutory~~tax reform adjustments, for the same period in 2018. The higher effective tax rate ~~as follows:~~is primarily due to a prior year state tax benefit.

Three Months Ended September 30,
Tax (benefit) expense 2018 2017
Federal statutory rate 21.0 % 35.0 %
State income tax (net of federal tax effect) ^(a)
(6.3 ) (3.4 )
Percentage depletion in excess of cost (0.5 ) (0.9 )
Accounting for uncertain tax positions adjustment —
(0.6 )
Noncontrolling interest ^(b)
(1.3 ) (3.0 )
Tax credits ^(c)
(5.3 ) (1.6 )
Effective tax rate adjustment ^(d)
—
3.9
Flow-through adjustments (1.5 ) (1.6 )
TCJA change in estimate ^(e)
17.6
—
AFUDC equity (0.1 ) —
Other tax differences 1.9
1.3
25.5 % 29.1 %

~~__________~~


~~(a)~~	~~Adjustment to the deferred state rate and reduced state tax expense for the quarter.~~


~~(b)~~	~~The adjustment reflects the noncontrolling interest attributable to the sale in April 2016 of 49.9% of the membership interests of COIPP LLC.~~


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


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

~~(e)~~

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 September 30, 2018, we recorded an additional $5.3 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes.

Nine Months Ended September 30,
Tax (benefit) expense 2018 2017
Federal statutory rate 21.0 % 35.0 %
State income tax (net of federal tax effect) 0.4
0.3
Percentage depletion in excess of cost (0.4 ) (0.6 )
Accounting for uncertain tax positions adjustment —
(0.2 )
Noncontrolling interest (1.1 ) (1.9 )
IRC 172(f) carryback claim ^(a)
—
(1.0 )
Tax credits ^(b)
(2.6 ) (1.6 )
Effective tax rate adjustment —
0.3
Flow-through adjustments (0.8 ) (1.2 )
TCJA change in estimate ^(c)
4.3
—
AFUDC equity (0.1 ) —
Jurisdictional simplification project ^(d)
(28.1 ) —
Other tax differences 0.7
0.3
(6.7 )% 29.4 %

~~__________~~

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

~~(c)~~

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 nine months ended September 30, 2018, we recorded an additional $7.5 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes.


~~(d)~~	~~Tax benefit from legal restructuring associated with amortizable goodwill as part of 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, $49 million of deferred income tax assets, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to incomeIncome tax benefit (expense) onfor 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 - Deferred Taxes~~

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, which reflected our provisional estimate of the impact of the TCJA, under SEC Staff Accounting Bulletin No. 118. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuantNine Months Ended September 30, 2019 Compared to the TCJA. The amount of the settlements may change based on decisions and actions by the state regulatory commissions. In addition to current year utility revenue reserves as disclosed in Note 5, we recorded additional changes in estimates of the provisional amounts recorded at December 31, 2017, primarily related to bonus depreciation and other plant and property items, after filing our 2017 tax returns which increased tax expense by $5.3 million for the three months, and decreasedNine Months Ended September 30, 2018.

Income tax benefit ~~by $7.5 million~~(expense) for the nine months ended September 30, 2019 was $(22) million compared to $12 million reported for the same period in 2018. ~~We will continue~~The increase in tax expense was primarily due to ~~evaluate subsequent regulations, clarifications~~a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(7.5) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the nine months ended September 30, 2019 the effective tax rate was 13.6% compared to 17.1% excluding the legal entity restructuring and ~~interpretations~~tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $5.0 million of ~~the assumptions made, which could change our estimates~~federal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to ~~the TCJA, which we expect to finalize in the fourth quarter.~~tax reform.

~~(20)~~(19) ACCRUED LIABILITIES

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



	September 30, 2019		December 31, 2018
Accrued employee compensation, benefits and withholdings	$	57,313	$	63,742
Accrued property taxes	38,937		42,510
Customer deposits and prepayments	56,220		43,574
Accrued interest and contract adjustment payments	35,100		31,759
Other (none of which is individually significant)	30,262		33,916
Total accrued liabilities	$	217,832	$	215,501

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September 30, 2018 December 31, 2017 September 30, 2017
Accrued employee compensation, benefits and withholdings $ 57,600
$ 52,467
$ 52,841
Accrued property taxes 37,660
42,029
36,993
Customer deposits and prepayments 42,002
44,420
41,012
Accrued interest and contract adjustment payments 31,139
33,822
30,977
CIAC current portion 1,552
1,552
1,575
Other (none of which is individually significant) 31,400
45,172
43,381
Total accrued liabilities $ 201,353
$ 219,462
$ 206,779

(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 September 30, 2019		Nine Months Ended September 30, 2019
Operating lease cost	Operations and maintenance	$	380	$	1,076
Finance lease cost:
Amortization of right-of-use asset	Depreciation, depletion and amortization	28		72
Interest on lease liabilities	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	5		14
Total lease cost		$	413	$	1,162

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



	Balance Sheet Location	As of September 30, 2019
Assets:
Operating lease assets	Other assets, non-current	$	4,864
Finance lease assets	Other assets, non-current	493
Total lease assets		$	5,357

Liabilities:
Current:
Operating leases	Accrued liabilities	$	970
Finance lease	Accrued liabilities	80

Noncurrent:
Operating leases	Other deferred credits and other liabilities	4,252
Finance lease	Other deferred credits and other liabilities	419
Total lease liabilities		$	5,721

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



	Nine Months Ended September 30, 2019
Cash paid included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	895
Operating cash flows from finance lease	$	14
Financing cash flows from finance lease	$	66
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	2,775
Finance lease	$	67



	As of September 30, 2019
Weighted average remaining lease term (years):
Operating leases	8 years
Finance lease	4 years

Weighted average discount rate:
Operating leases	4.27	%
Finance lease	4.19	%

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



	Operating Leases		Finance Lease		Total
2019 ^(a)	$	368	$	32	$	400
2020	992		126		1,118
2021	855		126		981
2022	736		126		862
2023	714		126		840
Thereafter	2,682		10		2,692
Total lease payments^(b)	$	6,347	$	546	$	6,893
Less imputed interest	1,125		47		1,172
Present value of lease liabilities	$	5,222	$	499	$	5,721


(a)	Includes lease liabilities for the remaining three 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

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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 September 30, 2019		Nine Months Ended September 30, 2019
Operating lease income	Revenue	$	544	$	1,749

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



	Operating Leases
2019 ^(a)	$	551
2020	2,035
2021	1,857
2022	1,793
2023	1,799
Thereafter	55,481
Total lease receivables	$	63,516


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

(21) INVESTMENTS

In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested from our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.

During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three and nine months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment.

The following table presents the carrying value of our investments (in thousands) as of:



	September 30, 2019		December 31, 2018
Investment in privately held oil and gas company	$	8,359	$	28,100
Cash surrender value of life insurance contracts	12,907		12,812
Other investments	317		101
Total investments	$	21,583	$	41,013

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(22) SUBSEQUENT EVENTS

There are no subsequent events, other than those disclosed in Note ~~5 and Note 10.~~8.


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~~regulator-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~~extracts 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 nine months ended September 30, ~~2018~~2019 and ~~2017~~2018, and our financial condition as of September 30, ~~2018~~,2019 and December 31, ~~2017 and~~ ~~September 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 6658.

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.

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Results of Operations

Executive Summary, Significant Events and Overview



	Three Months Ended September 30,										Nine Months Ended September 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	$	11.7	$	0.19	$	17.8		$	0.32		$	130.1	$	2.15	$	177.5		$	3.26
Net (loss) from discontinued operations	—		—		(0.9		)	(0.02		)	—		—		(5.6		)	(0.10		)
Net income available for common stock	$	11.7	$	0.19	$	17.0		$	0.31		$	130.1	$	2.15	$	171.9		$	3.15

Three Months Ended September 30, ~~2018~~2019 Compared to Three Months Ended September 30, ~~2017.~~ Net income from continuing operations available for common stock for the three months ended September 30, 2018 was $18 million, or $0.32 per diluted share, compared to $29 million, or $0.52 per diluted share, reported for the same period in 2017. 2018.

The variance to the prior year included the following:

Electric Utilities’ ~~earnings decreased $5.7~~adjusted operating income increased $7.3 million primarily due ato the prior year Wyoming Electric PCA settlement, ~~agreement with the WPSC which decreased gross margins by $3.4 million, unfavorable~~warmer summer weather ~~compared to prior year,~~in Colorado and Wyoming, increased industrial demand, and increased rider revenues partially offset by higher operating expenses driven by outside services and employee ~~costs and $2.8 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes;~~costs;

Gas Utilities’ ~~earnings decreased $8.9~~adjusted operating income increased $0.5 million primarily due to ~~unfavorable weather compared to prior year, higher operating expenses driven by employee costs~~new rates, increased transport and ~~outside services~~transmission, and ~~$2.6 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes;~~

~~Power Generation’s earnings increased~~ ~~$0.5 million~~ ~~primarily due to the reduction in the federal tax rate from 35% to 21% from the TCJA; and~~

~~Corporate and Other expenses decreased~~ ~~$2.9 million~~ due to lower interest expense and higher prior year operating costs previously allocated to our Oil and Gas segment which were not reclassified to discontinued operations, largely allocated to operating segments in 2018.

Net income available for common stock for the three months ended September 30, 2018 was $17 million, or $0.31 per diluted share, compared to $28 million, or $0.50 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the three months ended September 30, 2018 was $(0.9) million, or $(0.02) per diluted share compared to $(1.3) million or $(0.02) per diluted share reported for the same period in 2017.

~~Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.~~ Net income from continuing operations available for common stock for the nine months ended September 30, 2018 was $177 million, or $3.26 per diluted share, compared to $130 million, or $2.35 per diluted share, reported for the same period in 2017. The variance to the prior year included the following:

~~Gas Utilities’ earnings increased $52 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 weather and increased sales of natural gas,~~customer growth partially offset by ~~an increase in operating expenses;~~

~~Electric Utilities’ earnings decreased $5.1 million~~lower heating demand from warmer weather, reduced irrigation demand due ~~primarily~~ to ~~a settlement agreement with the WPSC which decreased gross margins by $3.7 million; other variances to the prior year were due to~~heavy precipitation and higher operating expenses driven by outside services and employee ~~costs~~costs;

Power Generation’s adjusted operating income decreased $1.3 million primarily due to higher depreciation and ~~$3.2~~property taxes from new wind assets partially offset by higher revenue from increased wind MWh sold and higher PPA prices;


•	Mining’s adjusted operating income decreased $1.2 million primarily due to lower tons sold driven by unplanned generating facility outages partially offset by lower operating expenses;

A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company; and

A prior year $5.3 million income tax expense associated with changes in the ~~prior~~previously estimated impact of tax reform on deferred income ~~taxes, partially offset by higher rider revenues from recent transmission investments, higher power marketing and wholesale margins, and favorable weather;~~taxes.

~~Power Generation’s earnings decreased $0.7~~

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income increased $2.1 million primarily due to ~~higher operating expenses;~~

~~Mining earnings~~reduced power capacity charges, the prior year Wyoming Electric PCA settlement and increased ~~$0.5 million primarily due to higher coal sales from increased price per ton sold,~~rider revenues partially offset by higher operating expenses driven by outside services and ~~tax expense.~~employee costs;

~~Corporate~~Gas Utilities’ adjusted operating income increased $0.4 million primarily due to new rates offset by higher operating expenses driven by outside services and ~~other expenses decreased $1.1~~employee costs;

Power Generation’s adjusted operating income increased $0.2 million primarily due to higher ~~tax benefits recognized in the~~revenue from increased wind MWh sold partially offset by higher depreciation and property taxes from new wind assets;

Mining’s adjusted operating income decreased $3.3 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;

Corporate and Other expenses decreased $2.3 million primarily due to prior year expenses related to the oil and ~~higher prior year operating costs previously allocated to our Oil and Gas~~gas segment ~~which~~that were not reclassified to discontinued ~~operations, largely allocated~~operations;

A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company;


•	A prior year $49 million tax benefit resulting fromlegal entity restructuring partially offset by a prior year $7.5 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes; and

A lower current year effective tax rate primarily due to ~~operating segments in 2018.~~$5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to tax reform.

Net income available for common stock for the nine months ended September 30, 2018 was $172 million, or $3.15 per diluted share, compared to $126 million, or $2.29 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the nine months ended September 30, 2018 was $(5.6) million, or $(0.10) per diluted share compared to $(3.5) million or $(0.06) 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 September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Variance			2018			2017			Variance			2019			2018			Variance			2019			2018			Variance
Revenue
Revenue	$	357,370		$	366,885		$	(9,515	)	$	1,358,519		$	1,319,573		$	38,946		$	363,491		$	358,258		$	5,233		$	1,368,748		$	1,361,102		$	7,646
Inter-company eliminations	(35,391		)	(31,274		)	(4,117		)	(105,447		)	(94,605		)	(10,842		)	(37,943		)	(36,279		)	(1,664		)	(111,502		)	(108,030		)	(3,472		)
	$	321,979		$	335,611		$	(13,632	)	$	1,253,072		$	1,224,968		$	28,104		$	325,548		$	321,979		$	3,569		$	1,257,246		$	1,253,072		$	4,174
Net income (loss) from continuing operations available for common stock
Adjusted operating income ^(a)
Electric Utilities ^(b)	$	21,578		$	27,324		$	(5,746	)	$	63,313		$	68,386		$	(5,073	)	$	50,653		$	43,393		$	7,260		$	125,219		$	123,073		$	2,146
Gas Utilities ^{(a) (b)}	(13,277		)	(4,329		)	(8,948		)	93,182			41,409			51,773
Gas Utilities																			4,736			4,240			496			116,607			116,168			439
Power Generation ^(b)	6,691			6,155			536			17,319			18,017			(698		)	11,822			13,079			(1,257		)	33,945			33,731			214
Mining ^(b)	3,572			3,477			95			9,561			9,048			513			3,374			4,551			(1,177		)	9,351			12,647			(3,296		)
Corporate and Other																			(34		)	(178		)	144			(439		)	(2,709		)	2,270
Operating income																			70,551			65,085			5,466			284,683			282,910			1,773
	18,564			32,627			(14,063		)	183,375			136,860			46,515
Corporate and Other ^(b)	(757		)	(3,664		)	2,907			(5,877		)	(6,994		)	1,117
Net income from continuing operations	17,807			28,963			(11,156		)	177,498			129,866			47,632
(Loss) from discontinued operations, net of tax	(857		)	(1,300		)	443			(5,627		)	(3,485		)	(2,142		)
Interest expense, net																			(33,487		)	(35,297		)	1,810			(102,469		)	(104,826		)	2,357
Impairment of investment																			(19,741		)	—			(19,741		)	(19,741		)	—			(19,741		)
Other income (expense), net																			580			(510		)	1,090			55			(1,923		)	1,978
Income tax benefit (expense)																			(2,508		)	(7,477		)	4,969			(22,078		)	11,784			(33,862		)
Income from continuing operations																			15,395			21,801			(6,406		)	140,450			187,945			(47,495		)
Net (loss) from discontinued operations																			—			(857		)	857			—			(5,627		)	5,627
Net income																			15,395			20,944			(5,549		)	140,450			182,318			(41,868		)
Net income attributable to noncontrolling interest																			(3,655		)	(3,994		)	339			(10,319		)	(10,447		)	128
Net income available for common stock	$	16,950		$	27,663		$	(10,713	)	$	171,871		$	126,381		$	45,490		$	11,740		$	16,950		$	(5,210	)	$	130,131		$	171,871		$	(41,740	)

__________

(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 nine months ended September 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 three and nine months ended September 30, 2018 included approximately $5.3 million and $7.5 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes. The impact to our operating segments and Corporate and Other for the three and nine months ended September 30, 2018 was: Electric Utilities $2.8 million and $3.2 million; Gas Utilities $2.6 million and $2.6 million, Mining ($0.0) million and $0.5 million; Power Generation ($0.0) million and $0.7 million; and Corporate and Other ($0.1) million and $0.6 million, respectively.

Overview of Business Segments and Corporate Activity

Electric Utilities Segment

On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric will provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve several years of disputed issues related to PCA dockets before the commission. The settlement also stipulates that the adjustment for the variable cost segment of the Wygen I Power Purchase Agreement with Wyoming Electric (an affiliate company) will escalate by 3% annually through 2022.

~~On October 3, 2018, Colorado Electric set a new winter peak load of 313 MW, exceeding the previous summer peak of 310 MW set in February 2011.~~

Cooling degree days for the three and nine months ended September 30, ~~2018~~2019 were ~~9% higher~~27% and ~~29%~~14% higher than ~~the 30-year average (normal)~~normal compared to ~~15%~~9% and 29% higher than normal for the same periods in ~~2017.~~2018.

Heating degree days for the three and nine months ended September 30, ~~2018~~2019 were ~~20%~~36% lower and 5%6% higher than normal, compared to 8%20% and ~~11%~~3% 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 July 25, 2018,~~September 17, 2019, South Dakota Electric ~~placed in service~~completed construction on the ~~first 48-mile~~final 94-mile segment of a ~~$70 million,~~ 175-mile ~~230-kilovolt~~electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The ~~remaining~~first 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.

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

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

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

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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, industrial and governmental agency customers. The project is expected to be in service by the end of ~~2019.~~2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the SDPUC an amendment seeking approval to increase the generating capacity under the tariff for the South Dakota portion by 12.5 MW to a total of 32.5 MW.

Gas Utilities Segment

Heating degree days for the three and nine months ended September 30, 2019 were 62% lower and 7% higher than normal, compared to 27% lower and 0% higher than normal for the same periods in 2018.

Regulatory activity:


◦	On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two gas distribution companies in Nebraska. A rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services of its two existing gas distribution companies.

◦

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 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 future safety and integrity investments in its system. A settlement was recently reached with the intervening parties in the rate review filing and filed with the WPSC on November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a decision expected by the end of 2019. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional details.

◦

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs and services of its two existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A decision from the CPUC is expected by March 2020.

On ~~April 25, 2018, Colorado Electric received approval~~May 10, 2019, Wyoming Gas commenced construction on the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline will interconnect from a supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. Construction of the ~~CPUC to contract with Black Hills Electric Generation for~~pipeline is nearly complete and the ~~60 megawatt Busch Ranch II wind project. The~~ project ~~is currently under construction and~~ is expected to be in service by the end of ~~2019. This renewable energy will enable Colorado Electric to comply~~2019, with ~~Colorado's Renewable Energy Standard.~~the associated investment included in the Wyoming Gas rate review filed on June 3, 2019.

~~Gas Utilities~~Power Generation Segment

~~Rate Review updates:~~

On ~~October 5, 2018, Arkansas Gas received approval from the APSC~~August 2, 2019 Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for a general rate increase. The new rates will generate approximately $12 million of new revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.

On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received 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, were 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. New rates are inclusive of customer benefits related to the TCJA.

new 60 MW PPA. If approved, Black Hills 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~~will continue to ~~integrate thelegal entities that the Company has acquired in recent~~deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. ~~As a result of these transactions, additional deferred income tax assets of $49 million, related to goodwill that~~A decision from FERC is ~~amortizable for tax purposes, were recorded with a corresponding deferred tax benefit recorded on the Condensed Consolidated Statements of Income.~~

pending.

Heating degree days at the Gas Utilities for the three and nine months ended September 30, 2018 were 27% lower and comparable to the 30-year average (normal), respectively, compared to 22% and 12% lower than normal for the same periods in 2017.

~~Power Generation~~

On ~~April 25, 2018,~~March 11, 2019, Black Hills Electric Generation ~~was selected to provide~~commenced construction on the $71 million, 60 ~~megawatts of renewable energy to Colorado Electric from the~~MW Busch Ranch II ~~wind~~Wind Farm. The project ~~which~~ is expected to be fully in service by ~~the end of~~mid-November 2019.

Mining

In October, negotiations were completed for the price reopener in the contract with Wyodak Plant. The new price was reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton.

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Corporate and Other

On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of $299 million in exchange for approximately 6.372 million shares of common stock.

On October ~~11, 2018, Fitch~~15, 2019, Moody’s affirmed ~~Black Hills’~~South Dakota Electric’s credit rating at ~~BBB+ and maintained a Stable outlook.~~A1.

On ~~August 17, 2018,~~October 3, 2019, we completed a public debt offering of ~~$400~~$700 million ~~principal amount of 4.350%~~in senior unsecured notes. ~~The proceeds~~Proceeds were used to repay the ~~$299~~$400 million ~~principal amount~~Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.

During the nine months ended September 30, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for net proceeds of $99 million.

On August 29, 2019, Fitch affirmed our ~~RSNs~~BBB+ rating and maintained a Stable outlook.

On June 17, 2019, we amended our Corporate term loan due ~~2028~~July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

On ~~August 9, 2018,~~April 30, 2019, S&P ~~upgraded Black Hills’ credit rating to BBB+ with a Stable outlook and South Dakota Electric’s credit rating to A.~~

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 September 30, 2018, matures on July 30, 2020.~~

~~On July 19, 2018, Fitch~~ affirmed South Dakota Electric’s credit rating at 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 September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. 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.

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Electric Utilities

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 Variance 2018 2017 Variance
(in thousands)
Revenue ^(a)
$ 184,790
$ 183,571
$ 1,219
$ 531,961
$ 528,048
$ 3,913

Total fuel and purchased power 72,928
68,733
4,195
204,334
199,398
4,936

Gross margin ^(b)
111,862
114,838
(2,976 ) 327,627
328,650
(1,023 )

Operations and maintenance 45,307
40,204
5,103
135,501
125,302
10,199
Depreciation and amortization 24,720
23,446
1,274
73,873
69,427
4,446
Total operating expenses 70,027
63,650
6,377
209,374
194,729
14,645

Operating income 41,835
51,188
(9,353 ) 118,253
133,921
(15,668 )

Interest expense, net (12,923 ) (12,744 ) (179 ) (39,423 ) (39,049 ) (374 )
Other income (expense), net (450 ) 649
(1,099 ) (1,121 ) 1,579
(2,700 )
Income tax benefit (expense) (6,884 ) (11,769 ) 4,885
(14,396 ) (28,065 ) 13,669
Net income $ 21,578
$ 27,324
$ (5,746 ) $ 63,313
$ 68,386
$ (5,073 )



	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue	$	191,384	$	184,790	$	6,594		$	540,665	$	531,961	$	8,704

Total fuel and purchased power	71,593		74,638		(3,045		)	207,004		209,317		(2,313		)

Gross margin (non-GAAP)	119,791		110,152		9,639			333,661		322,644		11,017

Operations and maintenance	47,172		45,307		1,865			143,049		135,501		7,548
Depreciation and amortization	21,966		21,453		513			65,393		64,070		1,323
Total operating expenses	69,138		66,760		2,378			208,442		199,571		8,871

Adjusted operating income ^(a)	$	50,653	$	43,392	$	7,261		$	125,219	$	123,073	$	2,146

________________

(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 nine months ended September 30, 2018, ~~include Horizon Point shared facility revenues~~which resulted in an increase of ~~approximately $2.8~~$1.6 million and ~~$8.1~~$4.8 million, ~~respectively, which are allocated to all of our operating segments as facility expenses. This shared facility agreement is new in 2018 and 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 September 30, ~~2018~~2019 Compared to the Three Months Ended September 30, ~~2017~~: ~~Net income from continuing operations available for common stock for the Electric Utilities was $22 million for the three months ended~~ ~~September 30, 2018, compared to Net income from continuing operations available for common stock of $27 million for the three months ended~~ ~~September 30, 2017, as a result of:~~2018:

Gross margin for the three months ended September 30, ~~2018 decreased $3.0 million compared to the same period in the prior year~~2019 increased as a result ~~of:~~of the following:

(in millions)
TCJA revenue reserve $ (5.7 )
Wyoming Electric PCA Stipulation (3.4 )
Weather (0.8 )
Commercial and industrial demand (0.4 )
Horizon Point shared facility revenue ^(b)
2.8
Power Marketing, ancillary wheeling and Tech Services 2.6
Residential customer growth 1.0
Rider recovery 0.9
Total (decrease) in Gross margin ^(a)
$ (3.0 )



	(in millions)
Prior year Wyoming Electric PCA Stipulation settlement	$	3.4
Weather	1.8
Increased industrial demand	1.7
Reduction in power capacity charges	1.7
Rider recovery	1.3
Other	(0.3		)
Total increase in Gross margin (non-GAAP)	$	9.6

~~________________~~


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


~~(b)~~	~~Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results.~~

Operations and maintenance expense increased primarily due to ~~$1.2~~$1.0 million of higher ~~facility~~employee costs ~~$1.3~~and $0.6 million of higher outside services ~~primarily from distribution and transmission line surveying expenses and $1.5 million higher employee related expenses driven primarily by labor and benefits.~~expenses.

~~Depreciation and amortization~~ ~~increased primarily due to a higher asset base driven by the prior year additions~~

Table of ~~Horizon Point and the Teckla-Lange transmission line.~~Contents

~~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, partially offset by $2.8 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

Results of Operations for the Electric Utilities for the Nine Months Ended September 30, ~~2018~~2019 Compared to the Nine Months Ended September 30, ~~2017~~: ~~Net income from continuing operations available for common stock for the Electric Utilities was $63 million for the nine months ended~~ ~~September 30, 2018, compared to Net income from continuing operations available for common stock of $68 million for the nine months ended~~ ~~September 30, 2017, as a result of:~~2018:

Gross margin for the nine months ended September 30, ~~2018 decreased $1.0 million compared to the same period in the prior year~~2019 increased as a result ~~of:~~of the following:

(in millions)
TCJA revenue reserve $ (17.2 )
Wyoming Electric PCA Stipulation (3.7 )
Horizon Point shared facility revenue ^(b)
8.1
Rider recovery 5.0
Weather 2.6
Power Marketing, ancillary wheeling and Tech Services 2.3
Residential customer growth 1.5
Commercial and industrial demand 0.4
Total (decrease) in Gross margin ^(a)
$ (1.0 )



	(in millions)
Reduction in power capacity charges	$	4.9
Prior year Wyoming Electric PCA Stipulation settlement	3.7
Rider recovery	2.0
Decreased residential customer usage	(0.9		)
Decreased commercial and industrial demand	(0.2		)
Weather	(0.1		)
Other	1.6
Total increase in Gross margin (non-GAAP)	$	11.0

~~________________~~


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


~~(b)~~	~~Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results.~~

Operations and maintenance expense increased primarily due to ~~$2.8~~$3.6 million of higher ~~vegetation management expenses, $3.6 million of shared facility costs and $1.5 million of outside service costs primarily from distribution and transmission line surveying expenses. Higher~~ employee costs and ~~property taxes comprise the remainder~~$3.4 million of ~~the increase compared to the same period in the prior year.~~higher outside services expenses.

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.~~expenditures.

~~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, partially offset by $3.2 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.

Operating Statistics


	Electric Revenue (in thousands)								Quantities sold (MWh)				Electric Revenue (in thousands)								Quantities sold (MWh)
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,		Nine Months Ended September 30,
	2018		2017		2018		2017		2018	2017	2018	2017	2019		2018		2019		2018		2019	2018	2019	2018
Residential	$	58,122	$	55,866	$	163,979	$	158,017	372,623	369,466	1,084,531	1,038,437	$	58,919	$	58,122	$	162,257	$	163,979	384,735	372,623	1,075,394	1,084,531
Commercial	65,794		68,044		192,680		195,495		550,791	557,975	1,560,911	1,547,254	65,732		65,794		186,434		192,680		560,547	550,791	1,556,449	1,560,911
Industrial	31,939		30,564		93,959		91,583		429,133	406,946	1,248,438	1,192,316	33,937		31,939		98,074		93,959		462,809	429,133	1,335,260	1,248,438
Municipal	4,582		4,958		13,389		13,934		43,972	47,389	122,953	125,065	4,792		4,582		13,184		13,389		46,106	43,972	121,025	122,953
Subtotal Retail Revenue - Electric	160,437		159,432		464,007		459,029		1,396,519	1,381,776	4,016,833	3,903,072	163,380		160,437		459,949		464,007		1,454,197	1,396,519	4,088,128	4,016,833
Contract Wholesale	8,256		8,048		25,497		22,593		221,327	185,723	677,163	537,720	8,211		8,256		23,335		25,497		229,369	221,327	646,611	677,163
Off-system/Power Marketing Wholesale	9,059		5,932		18,142		15,110		206,791	159,425	514,686	477,283	6,452		9,059		16,592		18,142		160,357	206,791	436,298	514,686
Other	7,038		10,159		24,315		31,316		—	—	—	—	13,341		7,038		40,789		24,315		—	—	—	—
Total Revenue and Energy Sold	184,790		183,571		531,961		528,048		1,824,637	1,726,924	5,208,682	4,918,075	191,384		184,790		540,665		531,961		1,843,923	1,824,637	5,171,037	5,208,682
Other Uses, Losses or Generation, net	—		—		—		—		121,478	134,595	337,939	354,572	—		—		—		—		112,172	121,478	299,038	337,939
Total Revenue and Energy	184,790		183,571		531,961		528,048		1,946,115	1,861,519	5,546,621	5,272,647	191,384		184,790		540,665		531,961		1,956,095	1,946,115	5,470,075	5,546,621
Less cost of fuel and purchased power(a)	72,928		68,733		204,334		199,398						71,593		74,638		207,004		209,317
Gross Margin ^(a)	$	111,862	$	114,838	$	327,627	$	328,650
Gross Margin (non-GAAP) ^(a)													$	119,791	$	110,152	$	333,661	$	322,644

________________


(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 nine months ended September 30, 2018, which resulted in an increase of $1.6 million and $4.8 million, respectively. There were corresponding decreases to Gross margin for each period.

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Three Months Ended September 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)											$	70,771	$	68,052	$	41,916	$	38,449	634,098	610,079
South Dakota Electric	$	78,067	$	73,939	$	52,860	$	51,096	874,962	835,285	77,022		78,067		55,217		52,860		835,725	874,962
Wyoming Electric	38,671		40,670		18,843		22,990		461,074	434,945	43,591		38,671		22,658		18,843		486,272	461,074
Colorado Electric	68,052		68,962		40,159		40,752		610,079	591,289
Total Electric Revenue, Gross Margin, and Quantities Sold	$	184,790	$	183,571	$	111,862	$	114,838	1,946,115	1,861,519
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold											$	191,384	$	184,790	$	119,791	$	110,152	1,956,095	1,946,115




Nine Months Ended September 30,	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(a)
	2019		2018		2019		2018		2019	2018
Colorado Electric ^(b)	$	186,030	$	188,937	$	104,411	$	105,997	1,611,126	1,639,607
South Dakota Electric	225,309		222,558		162,390		154,158		2,438,366	2,541,082
Wyoming Electric	129,326		120,466		66,860		62,489		1,420,583	1,365,932
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	540,665	$	531,961	$	333,661	$	322,644	5,470,075	5,546,621

________________


(a)	~~Non-GAAP measure~~


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

Nine Months Ended September 30, Electric Revenue (in thousands)
Gross Margin ^(a) (in thousands)

Quantities Sold (MWh) ^(b)
2018 2017 2018 2017 2018 2017
South Dakota Electric $ 222,558
$ 213,785
$ 154,158
$ 149,182
2,541,082
2,399,995
Wyoming Electric 120,466
123,299
62,489
68,215
1,365,932
1,298,009
Colorado Electric 188,937
190,964
110,980
111,253
1,639,607
1,574,643
Total Electric Revenue, Gross Margin, and Quantities Sold $ 531,961
$ 528,048
$ 327,627
$ 328,650
5,546,621
5,272,647

~~________________~~


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

(b)

~~Total MWh includes Other Uses, Losses or Generation, net,~~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 nine months ended September 30, 2018, which ~~are approximately 5%, 6%,~~resulted in a decrease of $(1.6) million and ~~7% for South Dakota Electric, Wyoming Electric, and Colorado Electric,~~$(4.8) million, respectively.


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,
Quantities Generated and Purchased (MWh)	2018	2017	2018	2017	2019	2018	2019	2018

Coal-fired	608,417	625,590	1,772,750	1,663,935	564,220	608,417	1,621,355	1,772,750
Natural Gas and Oil	199,351	156,465	345,978	249,065	234,366	199,351	445,498	345,978
Wind	54,450	38,773	196,932	167,429	55,407	54,450	167,331	196,932
Total Generated	862,218	820,828	2,315,660	2,080,429	853,993	862,218	2,234,184	2,315,660
Purchased	1,083,897	1,040,691	3,230,961	3,192,218	1,102,102	1,083,897	3,235,891	3,230,961
Total Generated and Purchased	1,946,115	1,861,519	5,546,621	5,272,647	1,956,095	1,946,115	5,470,075	5,546,621



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

Colorado Electric	3,156	(6	)%	9%	2,901	(14	)%
South Dakota Electric	5,370	20	%	8%	4,972	11	%
Wyoming Electric	4,677	5	%	9%	4,285	(9	)%
Combined^(a)	4,198	6	%	8%	3,888	(3	)%

Cooling Degree Days:
Colorado Electric	1,226	37	%	(13)%	1,404	57	%
South Dakota Electric	404	(36	)%	(17)%	488	(23	)%
Wyoming Electric	462	33	%	7%	430	24	%
Combined^(a)	791	14	%	(12)%	895	29	%

Coal-fired plants ^(a)

~~Regulatory Matters~~

Other — non-regulated services ^(a)



	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue:
Natural gas - regulated	$	117,549	$	117,070	$	479		$	651,366	$	648,550	$	2,816
Other - non-regulated services	13,195		14,606		(1,411		)	55,927		58,090		(2,163		)
Total revenue	130,744		131,676		(932		)	707,293		706,640		653

Cost of sales:
Natural gas - regulated	28,154		30,612		(2,458		)	280,312		298,149		(17,837		)
Other - non-regulated services	4,870		5,514		(644		)	16,975		15,716		1,259
Total cost of sales	33,024		36,126		(3,102		)	297,287		313,865		(16,578		)

Gross margin (non-GAAP)	97,720		95,550		2,170			410,006		392,775		17,231

Operations and maintenance	70,170		69,746		424			225,239		212,319		12,920
Depreciation and amortization	22,814		21,564		1,250			68,160		64,288		3,872
Total operating expenses	92,984		91,310		1,674			293,399		276,607		16,792

Adjusted operating income	$	4,736	$	4,240	$	496		$	116,607	$	116,168	$	439



	(in millions)
New rates	$	3.0
Customer growth - distribution	0.8
Increased transport and transmission	0.7
Weather ^(a)	(3.4		)
Other	1.1
Total increase in Gross margin (non-GAAP)	$	2.2

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

Total increase (decrease) in Gross margin ^(a)

~~Interest expense, netincreased~~ ~~due to higher corporate allocations from financing activities compared to the same period in the prior year.~~

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

(in millions)
Weather $ 7.6
Customer growth - distribution 3.6
Mark-to-market gains on non-utility natural gas commodity contracts 2.9
Rate review and rider recovery 2.8
Natural gas volumes sold 1.9
Transportation and Transmission 0.9
Non-utility - Tech Services and appliance repair 0.8
Other 0.5
TCJA revenue reserve (13.5 )
Total increase (decrease) in Gross margin ^(a)
$ 7.5



	(in millions)
New rates	$	15.5
Customer growth - distribution	3.7
Increased transport and transmission	1.8
Decreased mark-to-market on non-utility natural gas commodity contracts	(2.7		)
Excess deferred taxes returned to customers	(2.5		)
Weather	(0.6		)
Other	2.0
Total increase in Gross margin (non-GAAP)	$	17.2

~~________________~~



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

Residential	$	57,244	$	58,221	$	43,441	$	42,598	3,599,549	3,708,196
Commercial	19,629		19,639		11,589		10,880		2,298,919	2,278,304
Industrial	8,770		8,258		2,493		2,028		2,960,930	2,304,098
Other ^(a)	2,499		487		2,499		487		—	—
Total Distribution	88,142		86,605		60,022		55,993		8,859,398	8,290,598

Transportation and Transmission	29,407		30,465		29,373		30,465		31,538,815	29,808,567

Total Regulated	117,549		117,070		89,395		86,458		40,398,213	38,099,165

Non-regulated Services	13,195		14,606		8,325		9,092

Total Gas Revenue & Gross Margin (non-GAAP)	$	130,744	$	131,676	$	97,720	$	95,550

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
September 30, Nine Months Ended
September 30,
Gas Utilities Quantities Sold & Transported (Dth) 2018 2017 2018 2017

Residential 3,708,196
3,682,944
42,642,021
36,052,414
Commercial 2,278,304
2,445,847
20,842,996
18,111,118
Industrial 2,304,098
2,722,173
5,235,417
4,690,092
Total Distribution Quantities Sold 8,290,598
8,850,964
68,720,434
58,853,624

Transportation and Transmission 29,808,567
30,577,487
107,388,321
102,314,665

Total Quantities Sold & Transported 38,099,165
39,428,451
176,108,755
161,168,289




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

Arkansas	$	127,014	$	116,226	$	79,148	$	65,803	21,061,567	21,183,322
Colorado	135,816		125,898		73,022		66,917		23,050,638	19,301,834
Iowa	105,736		111,968		50,773		49,630		28,834,731	28,527,522
Kansas	77,609		81,880		42,385		40,896		24,336,744	23,391,905
Nebraska	183,827		196,307		111,828		117,925		57,815,316	58,223,856
Wyoming	77,291		74,361		52,850		51,604		26,506,059	25,480,316
Total Gas Revenue & Gross Margin (non-GAAP)	$	707,293	$	706,640	$	410,006	$	392,775	181,605,055	176,108,755

Three Months Ended September 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)
12 (72)% (20)% 15 (66)%
Colorado 109 (49)% (42)% 187 (13)%
Nebraska 101 (7)% 53% 66 (40)%
Iowa 128 (7)% 42% 90 (35)%
Kansas ^(a)
54 (2)% 46% 37 (32)%
Wyoming 236 (23)% (23)% 307 1%
Combined ^(b)
109 (27)% (7)% 117 (22)%



	Three Months Ended September 30,
	2019			2018
Heating Degree Days	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal
Arkansas ^(a)	—	(100)%	(100)%	12	(72)%
Colorado	68	(68)%	(38)%	109	(49)%
Iowa	43	(69)%	(66)%	128	(7)%
Kansas ^(a)	—	(101)%	(100)%	54	(2)%
Nebraska	22	(80)%	(78)%	101	(7)%
Wyoming	183	(37)%	(22)%	236	(23)%
Combined ^(b)	53	(62)%	(51)%	109	(27)%

Nine Months Ended September 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)
2,460
(1 )% 35% 1,826
(26 )%
Colorado 3,548
(14 )% —% 3,541
(14 )%
Nebraska 4,016
6 % 22% 3,280
(13 )%
Iowa 4,460
6 % 22% 3,641
(13 )%
Kansas ^(a)
3,032
2 % 17% 2,584
(13 )%
Wyoming 4,552
(4 )% 2% 4,468
(5 )%
Combined ^(b)
4,008
— % 14% 3,521
(12 )%




	Nine Months Ended September 30,
	2019			2018
Heating Degree Days:	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal
Arkansas ^(a)	2,347	(5)%	(5)%	2,460	(1)%
Colorado	4,115	—%	16%	3,548	(14)%
Iowa	4,611	10%	3%	4,460	6%
Kansas ^(a)	3,204	8%	6%	3,032	2%
Nebraska	4,169	10%	4%	4,016	6%
Wyoming	5,093	9%	12%	4,552	(4)%
Combined ^(b)	4,297	7%	7%	4,008	—%

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 Variance 2018 2017 Variance
(in thousands)
Revenue ^(a)
$ 23,603
$ 22,927
$ 676
$ 68,590
$ 68,289
$ 301

Operations and maintenance 7,434
7,646
(212 ) 25,520
24,228
1,292
Depreciation and amortization ^(a)
1,692
1,036
656
4,927
3,312
1,615
Total operating expense 9,126
8,682
444
30,447
27,540
2,907

Operating income 14,477
14,245
232
38,143
40,749
(2,606 )

Interest expense, net (1,264 ) (724 ) (540 ) (3,753 ) (2,015 ) (1,738 )
Other income (expense), net (34 ) (5 ) (29 ) (75 ) (36 ) (39 )
Income tax (expense) benefit (2,494 ) (3,426 ) 932
(6,549 ) (10,114 ) 3,565

Net income 10,685
10,090
595
27,766
28,584
(818 )
Net income attributable to noncontrolling interest (3,994 ) (3,935 ) (59 ) (10,447 ) (10,567 ) 120
Net income available for common stock $ 6,691
$ 6,155
$ 536
$ 17,319
$ 18,017
$ (698 )



	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue	$	25,811	$	24,491	$	1,320		$	75,764	$	71,173	$	4,591

Operations and maintenance	9,229		7,434		1,795			27,750		25,520		2,230
Depreciation and amortization	4,760		3,978		782			14,069		11,922		2,147
Total operating expense	13,989		11,412		2,577			41,819		37,442		4,377

Adjusted operating income ^(a)	$	11,822	$	13,079	$	(1,257	)	$	33,945	$	33,731	$	214

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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Contracted power plant fleet availability:
Coal-fired plant	98.0	%	97.9	%	95.2	%	93.9	%
Natural gas-fired plants ^(a)	97.6	%	99.3	%	98.4	%	99.4	%
Wind ^(b)	81.9	%	N/A		93.4	%	N/A
Total availability	93.6	%	98.9	%	96.5	%	98.0	%

Wind capacity factor ^(b)	15.0	%	N/A		22.1	%	N/A

Three Months Ended September 30, Nine Months Ended September 30,

2018 2017 Variance 2018 2017 Variance

(in thousands)
Revenue $ 17,301
$ 17,493
$ (192 ) $ 51,328
$ 48,985
$ 2,343

Operations and maintenance 10,761
11,235
(474 ) 32,807
32,162
645
Depreciation, depletion and amortization 1,989
2,004
(15 ) 5,874
6,231
(357 )
Total operating expenses 12,750
13,239
(489 ) 38,681
38,393
288

Operating income 4,551
4,254
297
12,647
10,592
2,055

Interest expense, net (51 ) (47 ) (4 ) (384 ) (146 ) (238 )
Other income (expense), net (70 ) 567
(637 ) (190 ) 1,644
(1,834 )
Income tax benefit (expense) (858 ) (1,297 ) 439
(2,512 ) (3,042 ) 530

Net income $ 3,572
$ 3,477
$ 95
$ 9,561
$ 9,048
$ 513



	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Variance			2019		2018		Variance
	(in thousands)
Revenue	$	15,552	$	17,301	$	(1,749	)	$	45,026	$	51,328	$	(6,302	)

Operations and maintenance	9,900		10,761		(861		)	28,988		32,807		(3,819		)
Depreciation, depletion and amortization	2,278		1,989		289			6,687		5,874		813
Total operating expenses	12,178		12,750		(572		)	35,675		38,681		(3,006		)

Adjusted operating income	$	3,374	$	4,551	$	(1,177	)	$	9,351	$	12,647	$	(3,296	)

Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 Variance 2018 2017 Variance
(in thousands)
Operating (loss) ^(a)
$ (16 ) $ (1,401 ) $ 1,385
$ (2,301 ) $ (7,183 ) $ 4,882

Other income (expense):
Interest (expense) income, net ^(a)
(626 ) (1,028 ) 402
(1,810 ) (2,331 ) 521
Other income (expense), net 520
(31 ) 551
702
(869 ) 1,571
Income tax benefit (expense) (635 ) (1,204 ) 569
(2,468 ) 3,389
(5,857 )

Net income (loss) $ (757 ) $ (3,664 ) $ 2,907
$ (5,877 ) $ (6,994 ) $ 1,117



	Three Months Ended September 30,								Nine Months Ended September 30,
	2019			2018			Variance		2019			2018			Variance
	(in thousands)
Adjusted operating income (loss) ^(a)	$	(34	)	$	(178	)	$	144	$	(439	)	$	(2,709	)	$	2,270

~~Results of Operations for Corporate and Other for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017:~~ Net loss from continuing operations available for common stock for Corporate and Other was $(0.8) million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $(3.7) million for the three months ended September 30, 2017. The variance was driven by higher prior year operating costs previously allocated to our Oil and Gas segment in 2017, which were not reclassified to discontinued operations in 2017, and are allocated to our operating segments in 2018. Income tax benefit (expense) increased in the current year due to higher state income tax expense.

Impairment of Investment

Income Tax Benefit (Expense)

Income tax benefit (expense) for the three months ended September 30, 2019 was $(2.5) million compared to $(7.5) million for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

For the three months ended September 30, 2019 the effective tax rate was 14.0% compared to 7.6% excluding the tax reform adjustments, for the same period in 2018. The higher effective tax rate is primarily due to a prior year state tax benefit.

Impairment of Investment

Income Tax Benefit (Expense)

Income tax benefit (expense) for the nine months ended September 30, ~~2018,~~2019 was $(22) million compared to ~~Net loss from continuing operations available for common stock of $(7.0)~~$12 million reported for the ~~nine months ended September 30, 2017.~~same period in 2018. The ~~variance to the prior year was driven by higher prior year operating costs previously allocated to our Oil and Gas segment which were not reclassified to discontinued operations~~increase in ~~2017, which are allocated to our operating segments in 2018 and transition and acquisition expenses which occurred 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 million comprised primarily of benefits~~resulting from ~~a carryback claim for specified liability losses involving prior tax years and current year tax expense.~~

~~Discontinued Operations~~

~~Results of Discontinued Operations for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017:~~ ~~Net loss from discontinued operations was $(5.6) million for~~For the nine months ended September 30, ~~2018,~~2019 the effective tax rate was 13.6% compared to ~~Net loss from discontinued operations of $(3.5) million~~17.1% excluding the legal entity restructuring and tax reform adjustments, for the same period in ~~2017.~~2018. The ~~variance to the prior year~~lower effective tax rate is ~~driven by lower revenues~~primarily due to ~~property sales~~$5.0 million of federal production tax credits and ~~higher losses on sales of operating~~related state investment tax credits associated with new wind assets, ~~partially offset by lower oil and gas operating expenses and lower employee costs. Current year depreciation expense is representative of the~~a $1.0 million tax benefit for deferred tax amortization ~~of the remaining book value of accounting software. Depreciation and depletion expense was recorded in the prior year under full cost accounting, which ceased November 1, 2017 due~~related to ~~reclassification to assets held for sale.~~tax reform.

Critical Accounting Estimates

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 September 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 seven states and ~~liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related~~are working with FERC regarding returning benefits to our regulated utilities and is reclassified to a regulatory liability. During the nine months ended September 30, 2018, we recorded approximately $16 million of additional regulatory liability associated with TJCA related items. 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 $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~~nine months ended September 30, 2019 (in thousands):


Cash provided by (used in):	2018			2017			Increase (Decrease)			2019			2018			Variance
Operating activities	$	378,722		$	319,430		$	59,292		$	386,075		$	378,722		$	7,353
Investing activities	$	(281,771	)	$	(255,978	)	$	(25,793	)	$	(593,272	)	$	(281,771	)	$	(311,501	)
Financing activities	$	(101,949	)	$	(63,112	)	$	(38,837	)	$	199,827		$	(101,949	)	$	301,776

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

Operating Activities

Investing Activities

Financing Activities

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

For the Nine Months Ended September 30, 2018
Maximum amount outstanding - commercial paper (based on daily outstanding balances) $ 231
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances) $ —
Average amount outstanding - commercial paper (based on daily outstanding balances) $ 135
Average amount outstanding - revolving credit facility (based on daily outstanding balances) $ —
Weighted average interest rates - commercial paper 2.16 %
Weighted average interest rates - revolving credit facility — %



	For the Nine Months Ended September 30, 2019
Maximum amount outstanding - short-term borrowing (based on daily outstanding balances)	$	295
Average amount outstanding - short-term borrowing (based on daily outstanding balances)	$	171
Weighted average interest rates - short-term borrowing	2.59		%

Covenant Requirements

~~Financing Activities~~

~~On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued~~

~~Future Financing Plans~~

~~Dividend Restrictions~~

~~There~~Financing Activities

Future Financing Plans



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



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

Capital Requirements

Capital Expenditures

Nine Months Ended September 30, 2019 ^(a)

Power Generation ^(d)

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

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

(c) Planned capital expenditures increased for ~~2018,~~ 2019 ~~and 2020 increased~~through 2023 primarily due to ~~higher~~increased programmatic safety, reliability and integrity spending.

~~(d) Planned capital expenditures for 2018 increased due to purchase of AltaGas’s interest in Busch Ranch I.~~

Contractual Obligations

New Accounting Pronouncements

Table of Contents

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 nine months ended September 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:

September 30, 2018 December 31, 2017 September 30, 2017
Net derivative (liabilities) assets $ (1,869 ) $ (6,644 ) $ (6,541 )
Cash collateral offset in Derivatives 4,308
7,694
5,452
Cash collateral included in Other current assets 4,677
562
2,841
Net asset (liability) position $ 7,116
$ 1,612
$ 1,752

~~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 September 30, 2018, December 31, 2017 and September 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 September 30, ~~2018~~.2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 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 September 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 nine months ended September 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).
	Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on October 4, 2019).

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*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 filed on ~~July 31, 2018)~~June 17, 2019).

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

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

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

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

Exhibit 95	Mine Safety and Health Administration Safety Data.

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

104	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit ~~101~~	~~Financial Statements for XBRL Format.~~101)

__________


*	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:	November ~~6, 2018~~5, 2019

7061



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 Nine Months Ended September 30, 2018 and 2017~~		5

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

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

	Condensed Consolidated Statements of Cash Flows ~~- unaudited~~
	~~Nine Months Ended September 30, 2018 and 2017~~		9

	~~Notes to~~ Condensed Consolidated ~~Financial~~ Statements ~~- unaudited~~of Equity		10
	Notes to Condensed Consolidated Financial Statements		12
	Note 1. Management’s Statement		12
	Note 2. Revenue		14
	Note 3. Business Segment Information		16
	Note 4. Accounts Receivable		19
	Note 5. Regulatory Accounting		20
	Note 6. Materials, Supplies and Fuel		21
	Note 7. Earnings Per Share		22
	Note 8. Notes Payable, Current Maturities and Debt		22
	Note 9. Equity		24
	Note 10. Risk Management Activities		24
	Note 11. Fair Value Measurements		27
	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		33
	Note 18. Income Taxes		33
	Note 19. Accrued Liabilities		33
	Note 20. Leases		34
	Note 21. Investments		36
	Note 22. Subsequent Events		37
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		4037
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		58
Item 4.	Controls and Procedures		59

~~Item 3.~~				~~Quantitative and Qualitative Disclosures about Market Risk~~	66

~~Item 4.~~	~~Controls and Procedures~~		67

PART II.	OTHER INFORMATION		67

Item 1.	Legal Proceedings		6759
Item 4.	Mine Safety Disclosures		59
Item 6.	Exhibits		59

~~Item 1A.~~	~~Risk Factors~~		67Signatures

~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~		67

~~Item 4.~~	~~Mine Safety Disclosures~~		67

~~Item 5.~~	~~Other Information~~		67

~~Item 6.~~	~~Exhibits~~		68

	~~Signatures~~		7061


	September 30, 2018			December 31, 2017			September 30, 2017			September 30, 2019			December 31, 2018
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	29,976		$	20,187		$	20,559		$	31,832		$	29,661
Deferred gas cost adjustments ^(a)	720			31,844			12,833			3,899			3,362
Gas price derivatives ^(a)	6,192			11,935			11,297			4,296			6,201
Deferred taxes on AFUDC^(b)	7,804			7,847			15,645			7,691			7,841
Employee benefit plans ^(c)	106,734			109,235			105,671			107,921			110,524
Environmental^(a)	972			1,031			1,051			917			959
Asset retirement obligations^(a)	526			517			514
Loss on reacquired debt^(a)	21,431			20,667			21,067			19,710			21,001
Renewable energy standard adjustment ^(a)	1,131			1,088			1,956			2,871			1,722
Deferred taxes on flow through accounting^{(c) (e)}	29,342			26,978			41,900
Deferred taxes on flow through accounting^(c)										37,609			31,044
Decommissioning costs ^(b)	11,052			13,287			13,989			11,206			11,700
Gas supply contract termination ^(a)	15,745			20,001			21,402			9,953			14,310
Other regulatory assets^(a)	28,725			32,837			32,710			22,453			45,910
Total regulatory assets	260,350			297,454			300,594			260,358			284,235
Less current regulatory assets	(48,302		)	(81,016		)	(61,023		)	(46,206		)	(48,776		)
Regulatory assets, non-current	$	212,048		$	216,438		$	239,571		$	214,152		$	235,459

Regulatory liabilities
Deferred energy and gas costs^(a)	$	15,980		$	3,427		$	3,780		$	9,919		$	6,991
Employee benefit plan costs and related deferred taxes^{(c) (e)}	39,332			40,629			66,620
Employee benefit plan costs and related deferred taxes^(c)										42,737			42,533
Cost of removal^(a)	146,177			130,932			125,360			162,169			150,123
Excess deferred income taxes ^{(c) (d)}	316,625			301,553			52
Excess deferred income taxes ^(c)										286,587			310,562
TCJA revenue reserve	20,592			—			—			2,770			18,032
Other regulatory liabilities^(c)	11,582			8,585			9,419			19,759			12,553
Total regulatory liabilities	550,288			485,126			205,231			523,941			540,794
Less current regulatory liabilities	(41,442		)	(6,832		)	(7,042		)	(25,168		)	(29,810		)
Regulatory liabilities, non-current	$	508,846		$	478,294		$	198,189		$	498,773		$	510,984



(unaudited)	As of
	September 30, 2018			December 31, 2017			September 30, 2017
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,001		$	15,420		$	13,449
Restricted cash	3,241			2,820			2,683
Accounts receivable, net	152,796			248,330			150,325
Materials, supplies and fuel	122,618			113,283			122,866
Derivative assets, current	1,392			304			433
Income tax receivable, net	11,025			—			—
Regulatory assets, current	48,302			81,016			61,023
Other current assets	32,691			25,367			25,586
Current assets held for sale	2,854			84,242			8,653
Total current assets	384,920			570,782			385,018

Investments	41,202			13,090			12,947

Property, plant and equipment	5,819,000			5,567,518			5,499,557
Less: accumulated depreciation and depletion	(1,118,783		)	(1,026,088		)	(1,000,875		)
Total property, plant and equipment, net	4,700,217			4,541,430			4,498,682

Other assets:
Goodwill	1,299,454			1,299,454			1,299,454
Intangible assets, net	6,954			7,559			7,765
Regulatory assets, non-current	212,048			216,438			239,571
Other assets, non-current	17,143			10,149			11,626
Noncurrent assets held for sale	—			—			108,685
Total other assets, non-current	1,535,599			1,533,600			1,667,101

TOTAL ASSETS	$	6,661,938		$	6,658,902		$	6,563,748



Three Months Ended September 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Three Months Ended September 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Segment:
Electric Utilities	$	181,238	$	2,333		$	27,324
Gas Utilities	142,821		73			(4,329		)
Power Generation ^(b)	1,810		21,117			6,155
Mining	9,742		7,751			3,477
Corporate and Other	—		—			(3,664		)
Inter-company eliminations	—		(31,274		)	—
Total	$	335,611	$	—		$	28,963




Nine Months Ended September 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 Utilities	$	513,270	$	2,218	$	16,473		$	—		$	531,961		$	63,313
Gas Utilities ^(a)	702,532		3,106		1,002			—			706,640			93,182
Power Generation ^(b)	4,287		1,066		36,874			26,363			68,590			17,319
Mining	25,892		701		23,761			974			51,328			9,561
Corporate and Other	—		—		—			—			—			(5,877		)
Inter-company eliminations	—		—		(78,110		)	(27,337		)	(105,447		)	—
Total	$	1,245,981	$	7,091	$	—		$	—		$	1,253,072		$	177,498




Nine Months Ended September 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Nine Months Ended September 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net income (loss) from continuing operations
Segment:
Electric Utilities	$	518,925	$	9,123		$	68,386
Gas Utilities	674,161		90			41,409
Power Generation ^(b)	5,382		62,907			18,017
Mining	26,500		22,485			9,048
Corporate and Other ^(c)	—		—			(6,994		)
Inter-company eliminations	—		(94,605		)	—
Total	$	1,224,968	$	—		$	129,866


(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)~~	~~The variance to the prior periods is primarily due to the decrease in federal income tax from 35% to 21% as a result of the TCJA.~~



State	Approximate 2018 Benefit for Customers			Start Date for Customer Benefits
Arkansas	$	9.7	million	October 2018
Colorado	$	10.8	million	July 2018
Iowa	$	2.4	million	June 2018
Kansas	$	1.9	million	April 2018
Nebraska	$	3.8	million	July 2018
South Dakota	$	7.7	million	October 2018


(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.



Yes	x	No o



Yes	x	No o



Yeso	☐	No x



	As of September 30, 2018	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	61.4%	Less than	65%



	As of September 30, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	2,880	$	—	$	(2,448	)	$	432
Total	$	—	$	2,880	$	—	$	(2,448	)	$	432

Liabilities:
Commodity derivatives — Utilities	$	—	$	12,647	$	—	$	(11,125	)	$	1,522
Total	$	—	$	12,647	$	—	$	(11,125	)	$	1,522



As of September 30, 2018
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	142	$	—
Commodity derivatives	Other assets, non-current	21		—
Commodity derivatives	Derivative liabilities — current	—		273
Commodity derivatives	Other deferred credits and other liabilities	—		10
Total derivatives designated as hedges		$	163	$	283

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	1,250	$	—
Commodity derivatives	Derivative liabilities — current	—		881
Commodity derivatives	Other deferred credits and other liabilities	—		92
Total derivatives not designated as hedges		$	1,250	$	973



	Three Months Ended September 30,
Tax (benefit) expense	2018		2017
Federal statutory rate	21.0	%	35.0	%
State income tax (net of federal tax effect) ^(a)	(6.3	)	(3.4	)
Percentage depletion in excess of cost	(0.5	)	(0.9	)
Accounting for uncertain tax positions adjustment	—		(0.6	)
Noncontrolling interest ^(b)	(1.3	)	(3.0	)
Tax credits ^(c)	(5.3	)	(1.6	)
Effective tax rate adjustment ^(d)	—		3.9
Flow-through adjustments	(1.5	)	(1.6	)
TCJA change in estimate ^(e)	17.6		—
AFUDC equity	(0.1	)	—
Other tax differences	1.9		1.3
	25.5	%	29.1	%



	(in millions)
TCJA revenue reserve	$	(5.7	)
Wyoming Electric PCA Stipulation	(3.4		)
Weather	(0.8		)
Commercial and industrial demand	(0.4		)
Horizon Point shared facility revenue ^(b)	2.8
Power Marketing, ancillary wheeling and Tech Services	2.6
Residential customer growth	1.0
Rider recovery	0.9
Total (decrease) in Gross margin ^(a)	$	(3.0	)



	(in millions)
TCJA revenue reserve	$	(17.2	)
Wyoming Electric PCA Stipulation	(3.7		)
Horizon Point shared facility revenue ^(b)	8.1
Rider recovery	5.0
Weather	2.6
Power Marketing, ancillary wheeling and Tech Services	2.3
Residential customer growth	1.5
Commercial and industrial demand	0.4
Total (decrease) in Gross margin ^(a)	$	(1.0	)



	Three Months Ended September 30,							Three Months Ended September 30,
Degree Days		2018			2017				2019			2018
	Actual	Variance from 30-Year Average		Actual Variance to Prior Year	Actual	Variance from 30-Year Average		Actual	Variance from Normal		Actual Variance to Prior Year	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric								4	(96	)%	(89)%	35	(64	)%
South Dakota Electric	236	5	%	17%	202	(10	)%	175	(22	)%	(26)%	236	5	%
Wyoming Electric	248	(19	)%	(15)%	292	(4	)%	120	(77	)%	(52)%	248	(19	)%
Colorado Electric	35	(64	)%	(60)%	87	(11	)%
Combined^(a)	147	(20	)%	(13)%	168	(8	)%	86	(36	)%	(41)%	147	(20	)%

Cooling Degree Days:
Colorado Electric								1,079	58	%	19%	910	33	%
South Dakota Electric	356	(33	)%	(40)%	595	11	%	366	(31	)%	3%	356	(33	)%
Wyoming Electric	328	10	%	(15)%	388	30	%	433	45	%	32%	328	10	%
Colorado Electric	910	33	%	16%	784	14	%
Combined^(a)	603	9	%	(6)%	640	15	%	705	27	%	17%	603	9	%


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



Electric Utilities Power Plant Availability	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Coal-fired plants ^(a)	94.6	%	95.7	%	90.0	%	94.0	%
Natural gas-fired plants and Other plants ^(b)	89.6	%	97.0	%	89.8	%	97.2	%
Wind	93.7	%	96.9	%	95.0	%	96.9	%
Total availability	91.5	%	96.6	%	90.3	%	96.1	%

Wind capacity factor	33.8	%	33.1	%	37.1	%	41.8	%


(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 and Wygen IIIII and unplanned outages at Wyodak Plant and Wygen III.


~~(a)~~	The three and nine months ended September 30, 2018 include certain non-utility 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.


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



	(in millions)
Weather	$	(2.3	)
TCJA revenue reserve	(2.2		)
Rate review and rider recovery	(0.3		)
Non-utility - Tech Services and appliance repair	1.2
Customer growth - distribution	0.8
Mark-to-market gains on non-utility natural gas commodity contracts	0.4
Other	0.3
Total increase (decrease) in Gross margin ^(a)	$	(2.1	)


(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 Generating Station.