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~~
AOCI		Accumulated Other Comprehensive Income (Loss)

Arkansas Gas		Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills ~~Gas Inc.~~Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
~~ASC~~

ASC		Accounting Standards Codification
ASU		Accounting Standards Update issued by the FASB
ATM		At-the-market equity offering program
~~Availability~~
Availability		The availability factor of a power plant is the percentage of the time that it is available to provide energy.
~~BHC~~
BHC		Black Hills Corporation; the Company



Black Hills Colorado IPP		Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric Generation		Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.
Black Hills Energy		The name used to conduct the business of our utility companies












Black Hills Energy Services		Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings		Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power		Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy). Also known as South Dakota Electric.
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~~






CARES Act		Coronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which is a ~~29 MW wind farm near Pueblo, Colorado, jointly owned~~ ~~by Colorado Electric~~tax and ~~Black Hills Electric Generation. Colorado Electric~~spending package intended to provide additional economic relief and ~~Black~~ ~~Hills Electric Generation each have a 50% ownership interest in~~address the ~~wind farm.~~ impact of the COVID-19 pandemic.
~~Busch Ranch II~~		Busch Ranch II wind project will be a 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement.
~~CAPP~~		~~Customer Appliance Protection Plan~~
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, ~~(doing business as Black Hills Energy and~~ providing electric ~~service)~~
~~Choice Gas Program~~	~~The unbundling of~~service in the ~~natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution and~~Cheyenne, Wyoming ~~Gas distribute the gas and Black Hills Energy Services, Wyoming Gas and Black Hills Gas Distribution are Choice Gas suppliers.~~
~~CIAC~~	~~Contribution In Aid of Construction~~
~~City of Gillette~~	~~Gillette, Wyoming~~
~~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~~area (doing business as Black Hills Energy) . Also known as Wyoming Electric.

Choice Gas Program		Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.

City of Colorado Springs		Colorado Springs, Colorado
City of Gillette		Gillette, Wyoming


Colorado Electric		Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas		Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
~~Colorado IPP~~		~~Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation~~
Consolidated Indebtedness to Capitalization Ratio		Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated ~~net-worth~~net worth (excluding noncontrolling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)		A cooling degree day is equivalent to each degree that the average of the high and low 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.
~~CPCN~~Corriedale		~~Certificate of Public Convenience~~Wind project near Cheyenne, Wyoming, that will be a 52.5 MW wind farm jointly owned by South Dakota Electric and ~~Necessity~~Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program.

Table of Contents


COVID-19			The official name for the 2019 novel coronavirus disease announced on February 11, 2020, by the World Health Organization, that is causing a global pandemic

CP Program			Commercial Paper Program
CPUC			Colorado Public Utilities Commission
CT			~~Combustion turbine~~
~~CVA~~
CVA			Credit Valuation Adjustment
~~Dodd-Frank~~
Dodd-Frank			Dodd-Frank Wall Street Reform and Consumer Protection Act

~~Table of Contents~~


DRSPP			Dividend Reinvestment and Stock Purchase Plan
Dth			Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
~~Equity Unit~~			Each Equity Unit had a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs that were formerly due 2028. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.
~~FASB~~




FASB			Financial Accounting Standards Board
FERC			United States Federal Energy Regulatory Commission
Fitch			Fitch Ratings Inc.
GAAP			Accounting principles generally accepted in the United States of America




Heating Degree Day (HDD)			A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness ~~of weather~~ and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
~~IPP~~HomeServe			Repair service plans offered to electric and natural gas residential customers that cover parts and labor to repair electrical, gas, heating, cooling, and water systems.
ICFR			Internal Controls over Financial Reporting
Iowa Gas			Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP			Independent power producer
IRS			United States Internal Revenue Service

Kansas Gas			Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy)
~~MMBtu~~






MMBtu			Million British thermal units
~~Moody’s~~
Moody’s			Moody’s Investors Service, Inc.
MW			~~Megawatts~~
~~MWh~~MW			~~Megawatt-hours~~Megawatts
MWh			Megawatt-hours
Nebraska Gas			Black Hills Nebraska Gas, ~~Utility Company,~~ LLC, ~~a direct,~~an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy)
~~NPSC~~




NPSC			Nebraska Public Service Commission
~~PPA~~



OCA			Office of Consumer Advocate


OCI			Other Comprehensive Income
PPA			Power Purchase Agreement
PRPA			Platte River Power Authority
PSA			Power Sales Agreement
Pueblo Airport Generation ~~Station~~			~~Two 100~~420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and ~~located at a site shared with Colorado Electric.~~operates this facility. The plants commenced operation on January 1, 2012.
Renewable Advantage			A 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. If approved by the CPUC, the project would be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project would be placed in service in 2023.
Renewable Ready			Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.
Revolving Credit Facility			Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018, and now terminates on July 30, 2023.
~~RSNs~~			~~Remarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.~~

Table of Contents


SDPUC			South Dakota Public Utilities Commission
SEC			~~U. S.~~United States Securities and Exchange Commission

Service Guard Comfort Plan			New plan that will consolidate Service Guard and Customer Appliance Protection Plan (CAPP) and provide similar home appliance repair services through on-going monthly service agreements to residential utility customers.
S&P			Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
South Dakota Electric			Black Hills Power, ~~which includes operations~~Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming ~~and Montana~~(doing business as Black Hills Energy).
SSIR			System Safety and Integrity Rider
~~TCJA~~

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.


Utilities			Black Hills’ Electric and Gas Utilities
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 (doing business as Black Hills Energy)
Wygen I			A mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5% of the plant and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wyodak Plant			Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by ~~Black Hills Energy~~ South ~~Dakota.~~Dakota Electric. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric			~~Includes~~ Cheyenne ~~Light’s~~Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric ~~utility operations~~ service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas			Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended September 30,						Nine Months Ended September 30,						(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018				2020		2019		2020		2019
	(in thousands, except per share amounts)													(in thousands, except per share amounts)

Revenue	$	325,548		$	321,979		$	1,257,246		$	1,253,072		Revenue	$	326,914	$	333,888	$	863,964	$	931,698

Operating expenses:													Operating expenses:
Fuel, purchased power and cost of natural gas sold	73,090			80,244			411,695			432,544			Fuel, purchased power and cost of natural gas sold	71,629		90,200		259,508		339,942
Operations and maintenance	117,037			115,699			366,907			352,092			Operations and maintenance	117,308		124,950		242,774		248,534
Depreciation, depletion and amortization	51,884			49,046			154,507			146,345			Depreciation, depletion and amortization	56,663		51,595		113,065		102,623
Taxes - property and production	12,986			11,905			39,454			39,181			Taxes - property and production	14,381		13,142		28,499		26,467

Total operating expenses	254,997			256,894			972,563			970,162			Total operating expenses	259,981		279,887		643,846		717,566

Operating income	70,551			65,085			284,683			282,910			Operating income	66,933		54,001		220,118		214,132

Other income (expense):													Other income (expense):
Interest charges -

Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(36,200		)	(36,380		)	(108,232		)	(107,183		)	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(35,765)		(34,660)		(71,546)		(69,676)
Allowance for funds used during construction - borrowed	2,200			701			4,555			1,345
Interest income	513			382			1,208			1,012			Interest income	220		396		548		695
Allowance for funds used during construction - equity	311			193			486			503
Impairment of investment	(19,741		)	—			(19,741		)	—			Impairment of investment	—		—		(6,859)		—
Other income (expense), net	269			(703		)	(431		)	(2,426		)	Other income (expense), net	(1,863)		263		490		(526)
Total other income (expense)	(52,648		)	(35,807		)	(122,155		)	(106,749		)	Total other income (expense)	(37,408)		(34,001)		(77,367)		(69,507)

Income before income taxes	17,903			29,278			162,528			176,161			Income before income taxes	29,525		20,000		142,751		144,625
Income tax benefit (expense)	(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		)
Income tax (expense)													Income tax (expense)	(4,831)		(2,307)		(20,833)		(19,570)
Net income	15,395			20,944			140,450			182,318			Net income	24,694		17,693		121,918		125,055
Net income attributable to noncontrolling interest	(3,655		)	(3,994		)	(10,319		)	(10,447		)	Net income attributable to noncontrolling interest	(3,728)		(3,110)		(7,778)		(6,664)
Net income available for common stock	$	11,740		$	16,950		$	130,131		$	171,871		Net income available for common stock	$	20,966	$	14,583	$	114,140	$	118,391

Amounts attributable to common shareholders:
Net income from continuing operations	$	11,740		$	17,807		$	130,131		$	177,498
Net (loss) from discontinued operations	—			(857		)	—			(5,627		)
Net income available for common stock	$	11,740		$	16,950		$	130,131		$	171,871

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 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
Earnings per share of common stock:													Earnings per share of common stock:
Earnings per share, Basic													Earnings per share, Basic	$	0.34	$	0.24	$	1.84	$	1.97
Earnings per share, Diluted													Earnings per share, Diluted	$	0.33	$	0.24	$	1.83	$	1.96

Weighted average common shares outstanding:													Weighted average common shares outstanding:
Basic	60,976			53,364			60,458			53,346			Basic	62,573		60,467		62,175		60,195
Diluted	61,104			54,819			60,578			54,508			Diluted	62,617		60,606		62,230		60,333

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 COMPREHENSIVE INCOME


(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)

Net income	$	24,694	$	17,693	$	121,918	$	125,055

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (net of tax of $0,$0, $(17) and $0, respectively)	—		—		55		—
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $6, $5, $13 and $10, respectively)	(19)		(15)		(42)		(29)
Reclassification adjustments of benefit plan liability - net gain (net of tax of $(182), $(52), $(277) and $(105), respectively)	415		169		917		336
Derivative instruments designated as cash flow hedges:
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(170), $(172), $(340) and $(335), respectively)	543		541		1,086		1,091
Net unrealized gains (losses) on commodity derivatives (net of tax of $14, $119, $68 and $65, respectively)	(45)		(399)		(220)		(219)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(16), $19, $(131), and $147, respectively)	54		(64)		425		(490)
Other comprehensive income, net of tax	948		232		2,221		689

Comprehensive income	25,642		17,925		124,139		125,744
Less: comprehensive income attributable to noncontrolling interest	(3,728)		(3,110)		(7,778)		(6,664)
Comprehensive income available for common stock	$	21,914	$	14,815	$	116,361	$	119,080

(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 1311 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 BALANCE SHEETS


(unaudited)	As of
	June 30, 2020		December 31, 2019
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	31,608	$	9,777
Restricted cash and equivalents	4,105		3,881
Accounts receivable, net	170,980		255,805
Materials, supplies and fuel	105,987		117,172
Derivative assets, current	1,581		342
Income tax receivable, net	20,118		16,446
Regulatory assets, current	51,745		43,282
Other current assets	27,981		26,479
Total current assets	414,105		473,184

Investments	15,438		21,929

Property, plant and equipment	6,954,274		6,784,679
Less: accumulated depreciation and depletion	(1,251,075)		(1,281,493)
Total property, plant and equipment, net	5,703,199		5,503,186

Other assets:
Goodwill	1,299,454		1,299,454
Intangible assets, net	12,536		13,266
Regulatory assets, non-current	220,567		228,062
Other assets, non-current	24,633		19,376
Total other assets, non-current	1,557,190		1,560,158

TOTAL ASSETS	$	7,689,932	$	7,558,457

(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

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

(Continued)


(unaudited)	As of
	June 30, 2020		December 31, 2019
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	118,942	$	193,523
Accrued liabilities	201,667��		226,767
Derivative liabilities, current	621		2,254
Regulatory liabilities, current	59,428		33,507
Notes payable	—		349,500
Current maturities of long-term debt	4,307		5,743
Total current liabilities	384,965		811,294

Long-term debt, net of current maturities	3,532,887		3,140,096

Deferred credits and other liabilities:
Deferred income tax liabilities, net	388,962		360,719
Regulatory liabilities, non-current	506,393		503,145
Benefit plan liabilities	142,580		154,472
Other deferred credits and other liabilities	119,649		124,662
Total deferred credits and other liabilities	1,157,584		1,142,998

Commitments and contingencies (See Notes 7, 9, 12, 13)

Equity:
Stockholders’ equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 62,772,996 and 61,480,658 shares, respectively	62,773		61,481
Additional paid-in capital	1,654,563		1,552,788
Retained earnings	826,269		778,776
Treasury stock, at cost – 26,399 and 3,956 shares, respectively	(1,879)		(267)
Accumulated other comprehensive income (loss)	(28,434)		(30,655)
Total stockholders’ equity	2,513,292		2,362,123
Noncontrolling interest	101,204		101,946
Total equity	2,614,496		2,464,069

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,689,932	$	7,558,457

(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.

Table of Contents

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


(unaudited)	Nine Months Ended September 30,						(unaudited)	Six Months Ended June 30,
	2019			2018				2020		2019
Operating activities:	(in thousands)						Operating activities:	(in thousands)
Net income	$	140,450		$	182,318		Net income	$	121,918	$	125,055
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:							Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	154,507			146,345			Depreciation, depletion and amortization	113,065		102,623
Deferred financing cost amortization	6,326			5,682			Deferred financing cost amortization	4,246		4,219
Impairment of investment	19,741			—			Impairment of investment	6,859		—
Stock compensation	8,332			7,544			Stock compensation	1,113		7,093
Deferred income taxes	24,381			(14,396		)	Deferred income taxes	26,401		21,935
Employee benefit plans	7,965			10,641			Employee benefit plans	5,656		5,683
Other adjustments, net	9,192			7,668			Other adjustments, net	3,679		8,991
Changes in certain operating assets and liabilities:							Changes in certain operating assets and liabilities:
Materials, supplies and fuel	(4,126		)	(8,380		)	Materials, supplies and fuel	7,503		14,911
Accounts receivable, unbilled revenues and other operating assets	115,325			72,061
Accounts payable and other operating liabilities	(83,436		)	(86,604		)
Accounts receivable and other current assets							Accounts receivable and other current assets	73,302		99,925
Accounts payable and other current liabilities							Accounts payable and other current liabilities	(63,085)		(107,563)
Regulatory assets - current	12,455			41,655			Regulatory assets - current	21,887		16,116
Regulatory liabilities - current	(15,644		)	21,416			Regulatory liabilities - current	314		(6,348)
Contributions to defined benefit pension plans	(12,700		)	(12,700		)	Contributions to defined benefit pension plans	(12,700)		—
Other operating activities, net	3,307			2,007			Other operating activities, net	(1,152)		(2,861)
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			Net cash provided by operating activities	309,006		289,779

Investing activities:							Investing activities:
Property, plant and equipment additions	(592,537		)	(278,132		)	Property, plant and equipment additions	(348,313)		(317,686)
Purchase of investment	—			(24,429		)
Other investing activities	(735		)	2,766			Other investing activities	(1,412)		389
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		)
Net cash (used in) investing activities							Net cash (used in) investing activities	(349,725)		(317,297)

Financing activities:							Financing activities:
Dividends paid on common stock	(91,779		)	(76,309		)	Dividends paid on common stock	(66,440)		(60,952)
Common stock issued	101,361			1,079			Common stock issued	99,435		71,759
Net (payments) borrowings of short-term debt	109,280			(99,200		)	Net (payments) borrowings of short-term debt	(349,500)		(83,120)
Long-term debt - issuances	400,000			700,000			Long-term debt - issuances	400,000		400,000
Long-term debt - repayments	(304,307		)	(603,307		)	Long-term debt - repayments	(5,727)		(302,871)
Distributions to noncontrolling interest	(12,736		)	(13,755		)	Distributions to noncontrolling interest	(8,520)		(9,251)
Other financing activities	(1,992		)	(10,457		)	Other financing activities	(6,474)		(1,948)
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
Net cash provided by financing activities							Net cash provided by financing activities	62,774		13,617

Net change in cash, restricted cash and cash equivalents							Net change in cash, restricted cash and cash equivalents	22,055		(13,901)

Cash, restricted cash and cash equivalents at beginning of period							Cash, restricted cash and cash equivalents at beginning of period	13,658		24,145
Cash, restricted cash and cash equivalents at end of period							Cash, restricted cash and cash equivalents at end of period	$	35,713	$	10,244

Supplemental cash flow information:							Supplemental cash flow information:
Cash (paid) refunded during the period:							Cash (paid) refunded during the period:
Interest (net of amounts capitalized)							Interest (net of amounts capitalized)	$	(67,449)	$	(67,624)
Income taxes							Income taxes	$	1,896	$	1,790
Non-cash investing and financing activities:							Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at June 30							Accrued property, plant and equipment purchases at June 30	$	59,916	$	83,486

~~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.

Table of Contents

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, 2019	61,480,658	$	61,481	3,956	$	(267)	$	1,552,788	$	778,776	$	(30,655)	$	101,946	$	2,464,069
Net income available for common stock	—	—		—	—		—		93,174		—		4,050		97,224
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		1,273		—		1,273


Dividends on common stock ($0.535 per share)	—	—		—	—		—		(32,902)		—		—		(32,902)
Share-based compensation	69,378	69		20,700	(1,658)		2,263		—		—		—		674

Issuance of common stock	1,222,942	1,223		—	—		98,777		—		—		—		100,000
Issuance costs	—	—		—	—		(967)		—		—		—		(967)


Implementation of ASU 2016-13 Financial Instruments - - Credit Losses	—	—		—	—		—		(207)		—		—		(207)


Distributions to noncontrolling interest	—	—		—	—		—		—		—		(4,741)		(4,741)
March 31, 2020	62,772,978	$	62,773	24,656	$	(1,925)	$	1,652,861	$	838,841	$	(29,382)	$	101,255	$	2,624,423
Net income available for common stock	—	—		—	—		—		20,966		—		3,728		24,694
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		948		—		948


Dividends on common stock ($0.535 per share)	—	—		—	—		—		(33,538)		—		—		(33,538)
Share-based compensation	18	—		1,743	46		1,781		—		—		—		1,827


Issuance costs	—	—		—	—		(79)		—		—		—		(79)





Distributions to noncontrolling interest	—	—		—	—		—		—		—		(3,779)		(3,779)
June 30, 2020	62,772,996	$	62,773	26,399	$	(1,879)	$	1,654,563	$	826,269	$	(28,434)	$	101,204	$	2,614,496


	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, 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

(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

~~Table of Contents~~

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s ~~2018~~2019 Annual Report on Form 10-K)

(1) Management’s Statement

(1~~) MANAGEMENT’S STATEMENT~~

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with ~~accounting principles generally accepted in the United States of America~~GAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes ~~thereto~~ included in our ~~2018~~2019 Annual Report on Form 10-K filed with the SEC.

Segment Reporting

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

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

On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, except for certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 17 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~~June 30, ~~2019~~ ~~and~~2020, December 31, ~~2018~~2019 and June 30, 2019 financial information. Certain industries in which we operate are highly seasonal and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for 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~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~September~~June 30, ~~2018~~,2019, and our financial condition as of ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018~~2019 are not necessarily indicative of the results of operations and financial condition to be expected for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Reclassification

We changed certain classifications of operating expenses on the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2019 to conform with current year presentation. The prior year reclassifications, which are shown in the table below, did not impact previously reported operating income or net income.


	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(in millions)
Fuel, purchased power and cost of natural gas sold	$	0.4	$	1.3
Operations and maintenance	—		(0.3)
Taxes - property and production	—		(0.2)
Other operating expenses	(0.4)		(0.8)
	$	—	$	—

Table of Contents

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of its employees and the communities in which it operates while assuring the continuity of its business operations.

The Company’s Condensed Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that for the three and six months ended June 30, 2020, there were no material adverse impacts on the Company’s results of operations.

Change in Accounting Principle - Pension Accounting Asset Method

Effective January 1, 2020, we changed our method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and change to fair value for the liability-hedging assets (fixed income). See Note 12 for additional information.

Recently Issued Accounting Standards

Simplifying the Accounting for Income Taxes, ASU 2019-12

In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes, as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.

Recently Adopted Accounting Standards

Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-13

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 ASUs 2018-19, 2019-04, 2019-05, 2019-10, and 2019-11. 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.

We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for credit losses, primarily associated with the inclusion of expected losses on unbilled revenue. The cumulative effect of the adoption, net of tax impact, was $0.2 million, which was recorded as an adjustment to retained earnings.

Simplifying the Test for Goodwill Impairment, ASU 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. ~~The new~~We adopted this standard ~~is effective for interim and annual reporting periods beginning after December~~prospectively on January 1, ~~2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption~~2020. Adoption of this guidance, in conjunction with the annual goodwill impairment test as of October 1, 2020, is not expected to have ~~any~~an impact on our financial position, results of operations or cash flows.

Table of Contents

Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15

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

In ~~June 2016,~~August 2018, the FASB issued ASU ~~2016-13, Financial Instruments --~~2018-15, ~~Credit Losses: Measurement of Credit Losses on Financial Instrument~~Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contracts,, which ~~was subsequently amended by ASU 2018-19~~aligns the requirements for recording implementation costs incurred 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~~a hosting arrangement that is ~~based~~a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. We adopted this standard prospectively 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~~

~~Leases, ASU 2016-02~~

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

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

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

~~Table of Contents~~

(2) ~~REVENUE~~

Revenue ~~Recognition~~

Our revenue contracts generally provide for performance obligations that: are fulfilled and transfer control to customers over time; represent a series of ~~January 1, 2018, we adopted ASU 2014-09,~~ ~~Revenue~~distinct services that are substantially the same; involve the same pattern of transfer to the customer; and provide a right to consideration from ~~Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized~~our customers in an amount that ~~reflects~~corresponds directly with the ~~consideration~~value to the customer for the performance completed to date. Therefore, we ~~expect~~recognize revenue in the amount to ~~receive in exchange for goods or services, when control of the promised goods or services is transferred~~which we have a right to ~~our customers.~~invoice. 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~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018.~~2019. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended June 30, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	141,804	$	120,594	$	—	$	14,846	$	(7,916)	$	269,328
Transportation	—		30,792		—		—		(138)		30,654
Wholesale	3,470		—		25,718		—		(24,476)		4,712
Market - off-system sales	3,538		23		—		—		(1,580)		1,981
Transmission/Other	12,761		9,189		—		—		(4,432)		17,518
Revenue from contracts with customers	$	161,573	$	160,598	$	25,718	$	14,846	$	(38,542)	$	324,193
Other revenues	1,627		512		404		570		(392)		2,721
Total revenues	$	163,200	$	161,110	$	26,122	$	15,416	$	(38,934)	$	326,914

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,846	$	(7,916)	$	6,930
Services transferred over time	161,573		160,598		25,718		—		(30,626)		317,263
Revenue from contracts with customers	$	161,573	$	160,598	$	25,718	$	14,846	$	(38,542)	$	324,193

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

Timing of Revenue Recognition:
Services transferred at a point in time $ —
$ —
$ —
$ 16,751
$ (7,942 ) $ 8,809
Services transferred over time 184,559
130,665
15,373
—
(19,243 ) 311,354
Revenue from contracts with customers $ 184,559
$ 130,665
$ 15,373
$ 16,751
$ (27,185 ) $ 320,163

Table of Contents


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

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


Six Months Ended June 30, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer types:	(in thousands)
Retail	$	290,444	$	418,841	$	—	$	29,249	$	(15,755)	$	722,779
Transportation	—		74,900		—		—		(277)		74,623
Wholesale	9,022		—		51,185		—		(48,088)		12,119
Market - off-system sales	8,405		161		—		—		(4,219)		4,347
Transmission/Other	27,618		21,761		—		—		(8,845)		40,534
Revenue from contracts with customers	$	335,489	$	515,663	$	51,185	$	29,249	$	(77,184)	$	854,402
Other revenues	1,850		6,220		903		1,372		(783)		9,562
Total revenues	$	337,339	$	521,883	$	52,088	$	30,621	$	(77,967)	$	863,964

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	29,249	$	(15,755)	$	13,494
Services transferred over time	335,489		515,663		51,185		—		(61,429)		840,908
Revenue from contracts with customers	$	335,489	$	515,663	$	51,185	$	29,249	$	(77,184)	$	854,402

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

Table of Contents


Nine Months Ended September 30, 2018	Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Six Months Ended June 30, 2019														Six Months Ended June 30, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues		Total
Customer Types:														Customer Types:
Retail	$	449,482	$	565,816	$	—	$	49,653	$	(23,761	)	$	1,041,190	Retail	$	293,195	$	477,905	$	—	$	28,257	$	(15,169)	$	784,188
Transportation	—		100,760		—		—		(977		)	99,783		Transportation	—		73,140		—		—		(708)		72,432
Wholesale	25,497		—		43,744		—		(39,457		)	29,784		Wholesale	15,124		—		30,531		—		(26,509)		19,146
Market - off-system sales	18,142		728		—		—		(5,531		)	13,339		Market - off-system sales	10,140		378		—		—		(3,559)		6,959
Transmission/Other	36,622		36,230		—		—		(10,967		)	61,885		Transmission/Other	28,591		24,802		—		—		(8,402)		44,991
Revenue from contracts with customers	$	529,743	$	703,534	$	43,744	$	49,653	$	(80,693	)	$	1,245,981	Revenue from contracts with customers	$	347,050	$	576,225	$	30,531	$	28,257	$	(54,347)	$	927,716
Other revenues	2,218		3,106		27,429		1,675		(27,337		)	7,091		Other revenues	2,231		324		19,422		1,217		(19,212)		3,982
Total Revenues	$	531,961	$	706,640	$	71,173	$	51,328	$	(108,030	)	$	1,253,072	Total Revenues	$	349,281	$	576,549	$	49,953	$	29,474	$	(73,559)	$	931,698

Timing of Revenue Recognition:														Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	49,653	$	(23,761	)	$	25,892	Services transferred at a point in time	$	—	$	—	$	—	$	28,257	$	(15,169)	$	13,088
Services transferred over time	529,743		703,534		43,744		—		(56,932		)	1,220,089		Services transferred over time	347,050		576,225		30,531		—		(39,178)		914,628
Revenue from contracts with customers	$	529,743	$	703,534	$	43,744	$	49,653	$	(80,693	)	$	1,245,981	Revenue from contracts with customers	$	347,050	$	576,225	$	30,531	$	28,257	$	(54,347)	$	927,716

~~(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.

Contract Balances

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

~~Table of Contents~~.

(3~~) BUSINESS SEGMENT INFORMATION~~

(3) Business Segment Information

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.

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.

~~Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments~~Segment and Corporate and Other ~~included the impacts~~information is as follows (in thousands):


Three Months Ended June 30, 2020	External Operating Revenue							Inter-company Operating Revenue					Total Revenues
			Contract Customers		Other Revenues					Contract Customers	Other Revenues
Segment:
Electric Utilities	$	156,197	$	1,627		$	5,376	$	—		$	163,200
Gas Utilities	159,824		512			774		—			161,110
Power Generation	1,242		349			24,476		55			26,122
Mining	6,930		233			7,916		337			15,416
Inter-company eliminations	—		—			(38,542)		(392)			(38,934)
Total	$	324,193	$	2,721		$	—	$	—		$	326,914

Table of ~~finance lease accounting relating to~~Contents



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



Six Months Ended June 30, 2020	External Operating Revenue							Inter-company Operating Revenue					Total Revenues
			Contract Customers		Other Revenues					Contract Customers	Other Revenues
Segment:
Electric Utilities	$	323,700	$	1,850		$	11,789	$	—		$	337,339
Gas Utilities	514,111		6,220			1,552		—			521,883
Power Generation	3,097		792			48,088		111			52,088
Mining	13,494		700			15,755		672			30,621
Inter-company eliminations	—		—			(77,184)		(783)			(77,967)
Total	$	854,402	$	9,562		$	—	$	—		$	863,964



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

Table of Contents



	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Adjusted operating income ^(a):
Electric Utilities	$	33,993	$	33,546	$	69,643	$	74,566
Gas Utilities	18,209		8,557		121,106		111,871
Power Generation	11,402		10,156		22,751		22,123
Mining	3,358		1,640		6,487		5,977
Corporate and Other	(29)		102		131		(405)
Operating income	66,933		54,001		220,118		214,132

Interest expense, net	(35,545)		(34,264)		(70,998)		(68,981)
Impairment of investment	—		—		(6,859)		—
Other income (expense), net	(1,863)		263		490		(526)
Income tax (expense)	(4,831)		(2,307)		(20,833)		(19,570)
Net income	24,694		17,693		121,918		125,055
Net income attributable to noncontrolling interest	(3,728)		(3,110)		(7,778)		(6,664)
Net income available for common stock	$	20,966	$	14,583	$	114,140	$	118,391

__________

(a) Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment).

~~The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with~~Black Hills Colorado IPP on an accrual basis rather than as a finance lease. ~~Effective January 1, 2019, we changed how we account for this PPA at the~~This presentation of segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no revisions to Gas Utilities and Mining segments and this change had no effect on ourinformation does not impact consolidated ~~revenues, fuel and purchased power cost, operating income or total assets.~~financial results.

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

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

~~Table of Contents~~

Nine 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 $ 521,614
$ 2,465
$ 16,586
$ —
$ 540,665
Gas Utilities 704,188
1,134
1,971
—
707,293
Power Generation 5,725
1,401
40,924
27,714
75,764
Mining 19,934
785
23,315
992
45,026
Inter-company eliminations —
—
(82,796 ) (28,706 ) (111,502 )
Total $ 1,251,461
$ 5,785
$ —
$ —
$ 1,257,246

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

~~(a)~~

Due to the changes in our segment disclosures, Power Generation Inter-company Operating Revenue for Contract Customers 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 were offset by changes to Inter-company eliminations within Corporate and Other and there was no impact on our consolidated Total revenues.

~~Table of Contents~~

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

~~___________~~


~~(a)~~	Due to the changes in our segment disclosures, Adjusted operating income was revised for 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 )
$ —
$ —


~~(b)~~	~~Income tax benefit (expense) for the nine months ended September 30, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring. See Note 18 for more information.~~

Segment ~~information~~ and Corporate and Other balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):


Total assets (net of inter-company eliminations) as of:	June 30, 2020		December 31, 2019
Segment:
Electric Utilities	$	2,982,841	$	2,900,983
Gas Utilities	4,052,860		4,032,339
Power Generation	407,107		417,715
Mining	79,774		77,175
Corporate and Other	167,350		130,245
Total assets	$	7,689,932	$	7,558,457

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

~~___________~~


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

~~Table of Contents~~

(4) Selected Balance Sheet Information

(4~~) ACCOUNTS RECEIVABLE~~

Accounts Receivable and Allowance for Credit Losses

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:


	June 30, 2020		December 31, 2019
Accounts receivable, trade	$	122,650	$	144,747
Unbilled revenue	55,915		113,502
Less: Allowance for credit losses	(7,585)		(2,444)
Accounts receivable, net	$	170,980	$	255,805

Accounts Unbilled Less Allowance for Accounts
September 30, 2019 Receivable, Trade Revenue Doubtful Accounts Receivable, net
Electric Utilities $ 39,151
$ 31,843
$ (500 ) $ 70,494
Gas Utilities 46,265
24,091
(2,490 ) 67,866
Power Generation 2,733
—
—
2,733
Mining 1,804
—
—
1,804
Corporate 6,261
—
(169 ) 6,092
Total $ 96,214
$ 55,934
$ (3,159 ) $ 148,989

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

Table of Contents

Changes to allowance for credit losses for the six months ended June 30, 2020 and 2019, respectively, were as follows (in thousands):


	Balance at Beginning of Year		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions		Balance at June 30,
2020	$	2,444	$	6,715	$	2,203	$	(3,777)	$	7,585
2019	$	3,209	$	4,913	$	1,870	$	(4,906)	$	5,086

Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the six months ended June 30, 2020 by $2.0 million.

The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 9.

Materials, Supplies and Fuel

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


	June 30, 2020		December 31, 2019
Materials and supplies	$	92,284	$	82,809
Fuel - Electric Utilities	3,574		2,425
Natural gas in storage	10,129		31,938
Total materials, supplies and fuel	$	105,987	$	117,172

Accrued Liabilities

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


	June 30, 2020		December 31, 2019
Accrued employee compensation, benefits and withholdings	$	59,701	$	62,837
Accrued property taxes	36,832		44,547
Customer deposits and prepayments	45,143		54,728
Accrued interest	31,757		31,868
Other (none of which is individually significant)	28,234		32,787
Total accrued liabilities	$	201,667	$	226,767

Table of Contents

(5) ~~REGULATORY ACCOUNTING~~

Regulatory Matters

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


								June 30, 2020		December 31, 2019
	September 30, 2019			December 31, 2018
Regulatory assets							Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	31,832		$	29,661		Deferred energy and fuel cost adjustments ^(a)	$	36,900	$	34,088
Deferred gas cost adjustments ^(a)	3,899			3,362			Deferred gas cost adjustments ^(a)	226		1,540
Gas price derivatives ^(a)	4,296			6,201			Gas price derivatives ^(a)	662		3,328
Deferred taxes on AFUDC^(b)	7,691			7,841			Deferred taxes on AFUDC^(b)	7,715		7,790
Employee benefit plans ^(c)	107,921			110,524			Employee benefit plans ^(c)	115,416		115,900
Environmental^(a)	917			959			Environmental^(a)	1,426		1,454

Loss on reacquired debt^(a)	19,710			21,001			Loss on reacquired debt^(a)	23,820		24,777
Renewable energy standard adjustment ^(a)	2,871			1,722			Renewable energy standard adjustment ^(a)	1		1,622
Deferred taxes on flow through accounting^(c)	37,609			31,044			Deferred taxes on flow through accounting^(c)	44,940		41,220
Decommissioning costs ^(b)	11,206			11,700			Decommissioning costs ^(b)	9,854		10,670
Gas supply contract termination ^(a)	9,953			14,310			Gas supply contract termination ^(a)	5,521		8,485
Other regulatory assets^(a)	22,453			45,910			Other regulatory assets^(a)	25,831		20,470
Total regulatory assets	260,358			284,235			Total regulatory assets	272,312		271,344
Less current regulatory assets	(46,206		)	(48,776		)	Less current regulatory assets	(51,745)		(43,282)
Regulatory assets, non-current	$	214,152		$	235,459		Regulatory assets, non-current	$	220,567	$	228,062

Regulatory liabilities							Regulatory liabilities
Deferred energy and gas costs^(a)	$	9,919		$	6,991		Deferred energy and gas costs^(a)	$	28,279	$	17,278
Employee benefit plan costs and related deferred taxes^(c)	42,737			42,533			Employee benefit plan costs and related deferred taxes^(c)	41,025		43,349
Cost of removal^(a)	162,169			150,123			Cost of removal^(a)	168,137		166,727

Excess deferred income taxes ^(c)	286,587			310,562			Excess deferred income taxes ^(c)	288,796		285,438
TCJA revenue reserve	2,770			18,032			TCJA revenue reserve	3,027		3,418
Other regulatory liabilities^(c)	19,759			12,553			Other regulatory liabilities^(c)	36,557		20,442
Total regulatory liabilities	523,941			540,794			Total regulatory liabilities	565,821		536,652
Less current regulatory liabilities	(25,168		)	(29,810		)	Less current regulatory liabilities	(59,428)		(33,507)
Regulatory liabilities, non-current	$	498,773		$	510,984		Regulatory liabilities, non-current	$	506,393	$	503,145

__________


~~(a)~~	~~We are allowed recovery of costs, but we are not allowed a rate of return.~~


~~(b)~~	~~In addition to recovery of costs, we are allowed a rate of return.~~


~~(c)~~	~~In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.~~

(a) 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.

Table of Contents

Regulatory ~~Matters~~Activity

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our ~~2018~~2019 Annual Report on Form 10-K.

~~Table of Contents~~

~~Regulatory Activity~~

~~Wyoming~~Nebraska Gas

Jurisdictional Consolidation and Rate Review

On June 13, 2019, we received approval from the WPSC to consolidate our Wyoming gas utility operations into a new utility entity. The Wyoming portion of Black Hills Gas Distribution, LLC, Cheyenne Light’s natural gas utility operations (Cheyenne Gas and Northeast Wyoming), and Wyoming Gas (Northwest Wyoming) were combined into a new company called Black Hills Wyoming Gas, LLC. On June 3, 2019, Wyoming1, 2020, Nebraska Gas filed a rate review ~~application~~ with the WPSC to consolidate the rates, tariffs and services of its 4 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.

~~South Dakota Electric and Wyoming Electric~~

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 2 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 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.

~~Nebraska~~

~~On October 29, 2019, Nebraska Gas received approval from~~ the NPSC to ~~merge its 2 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 2 existing gas distribution ~~companies.~~territories. The rate review requests $17 million in new revenue, as well as renewal and expansion of the SSIR, to recover investments in safety, reliability and system integrity. The rate review requests a capital structure of 50% equity and 50% debt and a return on equity of 10% for investments Nebraska Gas made in its natural gas pipeline system. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review. New rates are expected to be effective in early 2021.

~~Kansas~~

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

Black Hills Wyoming and Wyoming Electric

Wygen I FERC Filing

On ~~April 30,~~June 1, 2020, Black Hills Wyoming and Wyoming Electric filed a settlement agreement with the FERC. The agreement represents a resolution of all issues in the joint application filed with the FERC on August 2, 2019 for approval of a new 60 MW PPA. On July 10, 2020, a judge certified the ~~WPSC~~settlement to the FERC and a decision is expected by the end of 2020. If approved, Wyoming ~~Electric’s application~~Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement would commence on January 1, 2022, replacing the existing PPA, and would continue for ~~a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne~~11 years.

Colorado Gas

Jurisdictional Consolidation and ~~Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state.~~Rate Review

~~Colorado~~

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its 2 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.~~territories. Colorado Gas is also ~~requesting~~requested a new rider mechanism to recover future safety and integrity investments in its system. ~~A decision from~~On April 14, 2020 the CPUC ~~is expected~~deliberated on the application and on May 19, 2020 issued a final order. The order denied the system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020. In accordance with the final order, Colorado Gas will file a new system integrity rider proposal prior to the end of 2020. Colorado Gas also plans to file a new rate review by ~~March~~the end of 2020.

Table of Contents

(6) Earnings Per Share

(6) ~~MATERIALS, SUPPLIES AND FUEL~~

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

September 30, 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

(7) ~~EARNINGS PER SHARE~~

A reconciliation of share amounts used to compute ~~Earnings (loss)~~earnings per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019

Net income available for common stock	$	20,966	$	14,583	$	114,140	$	118,391

Weighted average shares - basic	62,573		60,467		62,175		60,195
Dilutive effect of:
Equity compensation	44		139		55		138
Weighted average shares - diluted	62,617		60,606		62,230		60,333

Earnings per share of common stock:
Earnings per share, Basic	$	0.34	$	0.24	$	1.84	$	1.97
Earnings per share, Diluted	$	0.33	$	0.24	$	1.83	$	1.96

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

~~__________~~


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

The following ~~outstanding~~ securities were excluded infrom the ~~computation of~~ diluted ~~net income (loss)~~earnings per share ascomputation because of their ~~inclusion would have been~~ anti-dilutive nature (in thousands):


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019

Equity compensation	29	—	26	—
Restricted stock	76	—	36	—

Anti-dilutive shares	105	—	62	—

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

(8) ~~NOTES PAYABLE, CURRENT MATURITIES AND DEBT~~

(7) Notes Payable, Current Maturities and Debt

We had the following ~~notes payable~~short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:


	June 30, 2020						December 31, 2019
	Balance Outstanding		Letters of Credit ^(a)		Balance Outstanding		Letters of Credit ^(a)
Revolving Credit Facility	$	—	$	11,999	$	—	$	30,274
CP Program	—		—		349,500		—
Total	$	—	$	11,999	$	349,500	$	30,274

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
_______________

(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit

Facility.

~~Table~~For the six months ended June 30, 2020, we utilized a combination of ~~Contents~~

~~Our~~our $750 million corporate Revolving Credit Facility extends through July 30, 2023 with 2, one year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at September 30, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at September 30, 2019.

~~We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the~~ Revolving Credit Facility and ~~the~~ CP Program ~~either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not~~ to ~~exceed 397 days from the date of issuance~~meet our business needs and ~~bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and~~support our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.

capital investment plan. Our net short-term borrowings (payments) during the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 were ~~$109~~$(350) million. ~~At September 30, 2019, the weighted average interest rate on short-term borrowings was 2.43%.~~

Table of Contents

Debt Covenants

Under our Revolving Credit Facility and term loan ~~agreements,~~agreement, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) ~~Consolidated Indebtedness,~~consolidated indebtedness, which includes letters of credit and certain guarantees issued, by (ii) ~~Capital,~~capital, which includes ~~Consolidated Indebtedness~~consolidated indebtedness plus ~~Net Worth,~~consolidated net worth, which excludes noncontrolling interest in subsidiaries. AsSubject to applicable cure periods, a violation of ~~September 30, 2019,~~any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

Our Revolving Credit Facility and term loans require compliance with the following financial covenant, which we were in compliance with ~~these covenants.~~at June 30, 2020:

As of June 30, 2020

Covenant Requirement

Consolidated Indebtedness to Capitalization Ratio

58.7%

Less than

65%

Debt ~~Transaction~~Offering

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan.

~~Subsequent Event - Debt Offering~~

~~On October 3, 2019,~~2020, we completed a public debt offering ~~of $700 million principal amount in senior unsecured notes. The debt offering~~which consisted of $400 million of ~~3.05%~~2.50% 10-year senior unsecured notes due ~~October~~June 15, ~~2029~~2030. The proceeds were used to repay short-term debt and ~~$300~~for working capital and general corporate purposes.

South Dakota Electric Series 94A Debt

On March 24, 2020, South Dakota Electric paid off its $2.9 million, Series 94A variable rate notes due June 1, 2024. These notes were tendered by the sole investor on March 17, 2020.

(8) Equity

February 2020 Equity Issuance

On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of ~~3.875% 30-year senior notes due October 15, 2049 (together~~issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the ~~“Notes”).~~SEC.

Shelf Registration, DRSPP and ATM Activity

On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The ~~proceeds of the Notes were used for the following:~~

~~Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021;~~

~~Retire the $200 million 5.875% senior notes due July 15, 2020; and~~

~~Repay a portion of short-term debt.~~

~~Table of Contents~~

~~(9) EQUITY~~

~~At-the-Market Equity Offering Program~~

~~Our~~renewed ATM ~~equity offering~~ program, which allows us to sell shares of our common stock, ~~with an~~is the same as the prior program other than the aggregate value ~~of up~~increased from $300 million to ~~$300 million. The~~$400 million and a forward sales option was incorporated. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August ~~4, 2017.~~3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC.

We did not issue any common shares under the ATM during the three and six months ended June 30, 2020. During the three months ended ~~September~~June 30, 2019, we issued a total of ~~389,237~~0.7 million shares of common stock under the ATM ~~equity offering program~~ for proceeds of ~~$30~~$49 million, net of ~~$0.3~~$0.5 million in ~~commissions.~~issuance costs. During the ~~nine~~six months ended ~~September~~June 30, 2019, we issued a total of ~~1,328,332~~0.9 million shares of common stock under the ATM ~~equity offering program~~ for proceeds of ~~$99~~$69 million, net of ~~$1.0~~$0.7 million in ~~commissions. As~~issuance costs.

Table of ~~September 30, 2019, there were no shares that were sold, but not settled.~~Contents

(9) Risk Management and Derivatives

(10~~) RISK MANAGEMENT ACTIVITIES~~

Market and Credit Risk Disclosures

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

Market Risk

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

•Commodity price risk associated with our retail natural gas, wholesale electric power marketing activities and our fuel procurement for ~~certain~~several of our gas-fired generation ~~assets.~~assets which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand;

•Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic;

Credit Risk

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

For ~~other than retail utility~~production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental ~~guaranties, prepayments,~~guarantees, cash collateral requirements, 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~~customers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified.

We continue to monitor COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify estimated future financial impacts to the allowance for credit losses. During the three and six months ended June 30, 2020, the potential economic impact of the COVID-19 pandemic was considered in forward looking projections related to write-off and recovery rates, and resulted in increases to the allowance for credit losses and bad debt expense of $1.5 million and $2.0 million, respectively. See Note 4 for further information.

Derivatives and Hedging Activity

Our derivative and hedging activities ~~recorded~~included 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 1110.

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), and natural gas sold by our Gas Utilities, 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.

Table of Contents

For our regulated ~~utilities’~~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 the state utility 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~~risk 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 2019~~July 2020 through ~~October 2021; a~~May 2022. A portion of ~~these~~our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price 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.~~Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our ~~hedged~~hedging position is evaluated at ~~inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.~~least quarterly.

~~Table of Contents~~

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


		June 30, 2020			December 31, 2019
	Units	Notional Amounts	Maximum Term (months)^(a)	Notional Amounts	Maximum Term (months)^(a)
Natural gas futures purchased	MMBtus	660,000	9	1,450,000	12
Natural gas options purchased, net	MMBtus	950,000	9	3,240,000	3
Natural gas basis swaps purchased	MMBtus	520,000	6	1,290,000	12
Natural gas over-the-counter swaps, net ^(b)	MMBtus	6,480,000	23	4,600,000	24
Natural gas physical contracts, net ^(c)	MMBtus	8,085,376	9	13,548,235	12
Electric wholesale contracts ^(c)	MWh	141,225	6	—	0

__________


~~(a)~~	(a) Term reflects the maximum forward period hedged.


~~(b)~~	~~As of September 30, 2019, 1,812,500 MMBtus were designated as cash flow hedges.~~


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

~~Based on September~~(b) As of June 30, ~~2019 prices, a $0.4 million gain would be realized, reported in pre-tax earnings~~2020, 1,776,900 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c) Volumes exclude contracts that qualify for the normal purchases 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.~~normal sales exception.

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~~June 30, ~~2019,~~2020, the Company posted $0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.

~~Cash Flow~~Derivatives 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. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements that allow us to settle positive and negative positions.

Table of Contents

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


	Balance Sheet Location	June 30, 2020		December 31, 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	66	$	1
Noncurrent commodity derivatives	Other assets, non-current	83		3
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(324)		(490)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	—		(29)
Total derivatives designated as hedges		$	(175)	$	(515)

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	1,515	$	341
Noncurrent commodity derivatives	Other assets, non-current	191		2
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(297)		(1,764)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(15)		(63)
Total derivatives not designated as hedges		$	1,394	$	(1,484)

Derivatives Designated as Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income isand Condensed Consolidated Statements of Income are presented below for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018.~~2019. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


	Three Months Ended June 30,							Three Months Ended June 30,
	2020		2019			2020		2019
Derivatives in Cash Flow Hedging Relationships	Amount of (Gain)/Loss Recognized in OCI					Income Statement Location		Amount of Gain/(Loss) Reclassified from AOCI into Income
	(in thousands)							(in thousands)
Interest rate swaps	$	713	$	713	Interest expense	$	(713)	$	(713)
Commodity derivatives	11		(601)		Fuel, purchased power and cost of natural gas sold	(70)		83
Total	$	724	$	112		$	(783)	$	(630)

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 )


	Six Months Ended June 30,							Six Months Ended June 30,
	2020		2019			2020		2019
Derivatives in Cash Flow Hedging Relationships	Amount of (Gain)/Loss Recognized in OCI					Income Statement Location		Amount of Gain/(Loss) Reclassified from AOCI into Income
	(in thousands)							(in thousands)
Interest rate swaps	$	1,426	$	1,426	Interest expense	$	(1,426)	$	(1,426)
Commodity derivatives	268		(921)		Fuel, purchased power and cost of natural gas sold	(556)		637
Total	$	1,694	$	505		$	(1,982)	$	(789)

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

Based on June 30, 2020 prices, a $0.2 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.

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 )

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, 2019 and 2018.

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~~Hedges

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~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018 (in thousands).~~2019. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.



		Three Months Ended June 30,
		2020		2019
Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives - Electric	Fuel, purchased power and cost of natural gas sold	$	(204)	$	—
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	449		(1,185)
		$	245	$	(1,185)

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 )


		Six Months Ended June 30,
		2020		2019
Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain/(Loss) on Derivatives Recognized in Income
		(in thousands)
Commodity derivatives - Electric	Fuel, purchased power and cost of natural gas sold	$	1,158	$	—
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	1,215		(1,160)
		$	2,373	$	(1,160)

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

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. ~~However, there~~There is no earnings impact for our Gas Utilities because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset or Regulatory liability accounts related to the hedges in our ~~utilities~~Gas Utilities were ~~$4.3~~$0.7 million and ~~$6.2~~$3.3 million as of ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018,~~2019, respectively.

For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.

(11~~) FAIR VALUE MEASUREMENTS~~

~~Derivative Financial Instruments~~

(10) Fair Value Measurements

~~The accounting guidance for~~

We use the following fair value ~~measurements requires certain disclosures about~~hierarchy for determining inputs for our financial instruments. Our assets and liabilities ~~measured at fair value. This guidance establishes a hierarchical framework~~ for ~~disclosing the observability~~financial instruments are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis;

Level 2 — Pricing inputs ~~utilized in measuring~~include quoted prices for identical or similar assets and liabilities atin active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means; and

Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair ~~value.~~ value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Table of Contents

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. ~~For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2018 Annual Report on Form 10-K filed with the SEC.~~

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

~~Valuation Methodologies for~~ Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities ~~Segments,~~segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for wholesale electric energy and 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 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.

~~Nonrecurring Fair Value Measurement~~

~~A discussion of~~ For additional information, see Note 1 to the ~~fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is~~Consolidated Financial Statements included in ~~Note 21.~~our 2019 Annual Report on Form 10-K filed with the SEC.


	As of June 30, 2020
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	—	$	1,114	$	—	$	(417)	$	697
Commodity derivatives — Electric Utilities	—		1,158		—		—		1,158
Total	$	—	$	2,272	$	—	$	(417)	$	1,855

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	1,553	$	—	$	(917)	$	636
Total	$	—	$	1,553	$	—	$	(917)	$	636

~~Recurring Fair Value Measurements~~


	As of December 31, 2019
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting		Total
	(in thousands)
Assets:
Commodity derivatives — Gas Utilities	$	—	$	1,433	$	—	$	(1,085)	$	348
Total	$	—	$	1,433	$	—	$	(1,085)	$	348

Liabilities:
Commodity derivatives — Gas Utilities	$	—	$	5,254	$	—	$	(2,909)	$	2,345
Total	$	—	$	5,254	$	—	$	(2,909)	$	2,345

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

Pension and Postretirement Plan Assets

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

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

~~Fair Value Measures by Balance Sheet Classification~~

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

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

Balance Sheet Location 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

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our ~~2018~~2019 Annual Report on Form 10-K.

~~Table~~ The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of ~~Contents~~our pension plan assets or defined benefit obligations. See Note 12

for additional information.

(12~~) FAIR VALUE OF FINANCIAL INSTRUMENTS~~

Nonrecurring Fair Value Measurement

A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 15.

Other Fair Value Measures

The following table presents the carrying amounts and fair values of financial instruments ~~for which the carrying value did~~ not ~~equal~~recorded at fair value ~~were as follows~~on the Condensed Consolidated Balance Sheets (in thousands) as of:

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


	June 30, 2020						December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^(a)	$	3,537,194	$	4,051,912	$	3,145,839	$	3,479,367

__________


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


~~(b)~~	(a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified as Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.

Table of Contents


( (11) Other Comprehensive Income (Loss) 13)	~~OTHER COMPREHENSIVE INCOME (LOSS)~~

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

The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Condensed Consolidated Statements of Income for the period (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 June 30,						Six Months Ended June 30,
		September 30, 2019			September 30, 2018			September 30, 2019			September 30, 2018									2020	2019				2020	2019
Gains and (losses) on cash flow hedges:														Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(712	)	$	(2,139	)	$	(2,138	)	Interest rate swaps	Interest expense	$	(713)	$	(713)		$	(1,426)	$	(1,426)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(129		)	(18		)	508			(802		)	Commodity contracts	Fuel, purchased power and cost of natural gas sold	(70)		83			(556)		637
		(842		)	(730		)	(1,631		)	(2,940		)			(783)		(630)			(1,982)		(789)
Income tax	Income tax benefit (expense)	170			149			358			643			Income tax	Income tax benefit (expense)	186		153			471		188
Total reclassification adjustments related to cash flow hedges, net of tax		$	(672	)	$	(581	)	$	(1,273	)	$	(2,297	)	Total reclassification adjustments related to cash flow hedges, net of tax		$	(597)	$	(477)		$	(1,511)	$	(601)

Amortization of components of defined benefit plans:														Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	20		$	44		$	59		$	133		Prior service cost	Operations and maintenance	$	25	$	20		$	55	$	39

Actuarial gain (loss)	Operations and maintenance	(84		)	(621		)	(525		)	(1,865		)	Actuarial gain (loss)	Operations and maintenance	(597)		(221)			(1,194)		(441)
		(64		)	(577		)	(466		)	(1,732		)			(572)		(201)			(1,139)		(402)
Income tax	Income tax benefit (expense)	89			128			184			380			Income tax	Income tax benefit (expense)	176		47			264		95
Total reclassification adjustments related to defined benefit plans, net of tax		$	25		$	(449	)	$	(282	)	$	(1,352	)	Total reclassification adjustments related to defined benefit plans, net of tax		$	(396)	$	(154)		$	(875)	$	(307)
Total reclassifications		$	(647	)	$	(1,030	)	$	(1,555	)	$	(3,649	)	Total reclassifications		$	(993)	$	(631)		$	(2,386)	$	(908)

~~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, 2019	$	(15,122)	$	(456)	$	(15,077)	$	(30,655)
Other comprehensive income (loss)
before reclassifications	—		(220)		55		(165)
Amounts reclassified from AOCI	1,087		424		875		2,386
As of June 30, 2020	$	(14,035)	$	(252)	$	(14,147)	$	(28,434)


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

Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total
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 )

Table of Contents

(12) Employee Benefit Plans

(14~~) 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~~

Change in Accounting Principle - Pension Accounting Asset Method

(15~~) EMPLOYEE BENEFIT PLANS~~

Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will use a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.

We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a decrease to prior service costs, as recorded in Other income (expense), net, of $0.6 million, an increase in Income tax expense of $0.2 million and an increase to Net income of $0.4 million within the accompanying Condensed Consolidated Statements of Income for the six months ended June 30, 2020.

Funding Status of Employee Benefit Plans

Based on the fair value of assets and estimated discount rate used to value benefit obligations as of June 30, 2020, we estimate the unfunded status of our employee benefit plans to be approximately $50 million compared to $51 million at December 31, 2019. In 2012, we froze our pension plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio.As a result, recent capital markets volatility driven by the COVID-19 pandemic has not materially affected our unfunded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.

Defined Benefit Pension Plan

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	1,353	$	1,345	$	2,706	$	2,691
Interest cost	3,356		4,344		6,713		8,687
Expected return on plan assets	(5,648)		(6,100)		(11,296)		(12,200)
Prior service cost	—		7		—		13
Net loss (gain)	2,093		940		4,186		1,881
Net periodic benefit cost	$	1,154	$	536	$	2,309	$	1,072

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

Table of Contents

Defined Benefit Postretirement Healthcare ~~Plans~~Plan

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	514	$	454	$	1,028	$	908
Interest cost	413		563		825		1,123
Expected return on plan assets	(46)		(58)		(91)		(115)
Prior service (benefit)	(137)		(100)		(274)		(199)
Net loss (gain)	5		—		10		—
Net periodic benefit cost	$	749	$	859	$	1,498	$	1,717

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

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	1,817	$	692	$	447	$	1,977
Interest cost	275		324		550		648
Prior service cost	—		1		—		1
Net loss (gain)	426		134		852		268
Net periodic benefit cost	$	2,518	$	1,151	$	1,849	$	2,894

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~~

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in ~~2019~~the first six months of 2020 and anticipated contributions for ~~2019~~2020 and ~~2020~~2021 are as follows (in thousands):


	Contributions Made		Additional Contributions		Contributions
	Six Months Ended June 30, 2020		Anticipated for 2020		Anticipated for 2021
Defined Benefit Pension Plan	$	12,700	$	—	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	2,670	$	2,671	$	5,364
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	710	$	710	$	1,614

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

(16~~) COMMITMENTS AND CONTINGENCIES~~

Table of Contents

Electric Utilities

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)~~	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, which resulted in an increase of $1.6 million and $4.8 million, respectively.


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	163,200	$	166,354	$	(3,154)	$	337,339	$	349,281	$	(11,942)

Total fuel and purchased power	59,053		62,128		(3,075)		123,513		135,411		(11,898)

Gross margin (non-GAAP)	104,147		104,226		(79)		213,826		213,870		(44)

Operations and maintenance	47,031		48,733		(1,702)		97,530		95,877		1,653
Depreciation and amortization	23,123		21,947		1,176		46,653		43,427		3,226
Total operating expenses	70,154		70,680		(526)		144,183		139,304		4,879

Adjusted operating income	$	33,993	$	33,546	$	447	$	69,643	$	74,566	$	(4,923)

~~Results of Operations for the Electric Utilities for the~~

Three Months Ended ~~September~~June 30, ~~2019~~2020 Compared to the Three Months Ended ~~September~~June 30, ~~2018:~~2019:

Gross margin for the three months ended ~~September~~June 30, ~~2019 increased~~2020 decreased as a result of the following:


	(in millions)
COVID-19 impacts ^(a)	$	(1.5)
Rider recovery and true-up ^(b)	(1.3)
Weather	2.4
Other	0.3
Total decrease in Gross margin (non-GAAP)	$	(0.1)

(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) The impacts to Electric Utilities gross margin from COVID-19 were driven by reduced commercial volumes partially offset by higher residential usage.

(b) Gross margin decreased due to a $2.5 million rider true-up, which was partially offset by $1.2 million of increased rider recovery.

Operations and maintenance expense ~~increased~~decreased primarily due to ~~$1.0~~lower generation expenses driven by timing of planned outages and lower employee costs. COVID-19 impacts to operations and maintenance expense included $1.6 million of ~~higher employee costs~~expenses related to the sequestration of essential employees and ~~$0.6~~$0.5 million of ~~higher~~additional bad debt expense which were offset by $2.0 million of lower travel, training and outside services related expenses.

~~Table of Contents~~

~~Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:~~

~~Gross margin~~ ~~for the nine months ended September 30, 2019 increased as a result of the following:~~

(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

~~Operations and maintenance expense~~ ~~increased primarily due to $3.6 million of higher employee costs and $3.4 million of higher outside services expenses.~~

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

~~Operating Statistics~~

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,
2019 2018 2019 2018 2019 2018 2019 2018
Residential $ 58,919
$ 58,122
$ 162,257
$ 163,979
384,735
372,623
1,075,394
1,084,531
Commercial 65,732
65,794
186,434
192,680
560,547
550,791
1,556,449
1,560,911
Industrial 33,937
31,939
98,074
93,959
462,809
429,133
1,335,260
1,248,438
Municipal 4,792
4,582
13,184
13,389
46,106
43,972
121,025
122,953
Subtotal Retail Revenue - Electric 163,380
160,437
459,949
464,007
1,454,197
1,396,519
4,088,128
4,016,833
Contract Wholesale 8,211
8,256
23,335
25,497
229,369
221,327
646,611
677,163
Off-system/Power Marketing Wholesale 6,452
9,059
16,592
18,142
160,357
206,791
436,298
514,686
Other 13,341
7,038
40,789
24,315
—
—
—
—
Total Revenue and Energy Sold 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 —
—
—
—
112,172
121,478
299,038
337,939
Total Revenue and Energy 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)
71,593
74,638
207,004
209,317

Gross Margin (non-GAAP) ^(a)
$ 119,791
$ 110,152
$ 333,661
$ 322,644

~~________________~~


~~(a)~~	Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, cost of fuel and purchased power was revised for the three and 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.

Table of Contents

Three 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)
$ 70,771
$ 68,052
$ 41,916
$ 38,449
634,098
610,079
South Dakota Electric 77,022
78,067
55,217
52,860
835,725
874,962
Wyoming Electric 43,591
38,671
22,658
18,843
486,272
461,074
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)~~	~~Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 6%, 5%, and 6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, respectively.~~


~~(b)~~	Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Gross margin was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(1.6) million and $(4.8) million, respectively.

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

Coal-fired 564,220
608,417
1,621,355
1,772,750
Natural Gas and Oil 234,366
199,351
445,498
345,978
Wind 55,407
54,450
167,331
196,932
Total Generated 853,993
862,218
2,234,184
2,315,660
Purchased 1,102,102
1,083,897
3,235,891
3,230,961
Total Generated and Purchased 1,956,095
1,946,115
5,470,075
5,546,621

Three Months Ended
September 30, Nine Months Ended
September 30,
Quantities Generated and Purchased (MWh) 2019 2018 2019 2018
Generated:
Colorado Electric 149,509
163,276
341,925
388,251
South Dakota Electric 489,042
469,680
1,262,336
1,293,713
Wyoming Electric 215,442
229,262
629,923
633,696
Total Generated 853,993
862,218
2,234,184
2,315,660
Purchased:
Colorado Electric 484,589
446,803
1,269,201
1,251,356
South Dakota Electric 346,683
405,282
1,176,030
1,247,369
Wyoming Electric 270,830
231,812
790,660
732,236
Total Purchased 1,102,102
1,083,897
3,235,891
3,230,961

Total Generated and Purchased 1,956,095
1,946,115
5,470,075
5,546,621

~~Table of Contents~~

Three Months Ended September 30,
Degree Days 2019 2018
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 175
(22 )% (26)% 236
5 %
Wyoming Electric 120
(77 )% (52)% 248
(19 )%
Combined^(a)
86
(36 )% (41)% 147
(20 )%

Cooling Degree Days:
Colorado Electric 1,079
58 % 19% 910
33 %
South Dakota Electric 366
(31 )% 3% 356
(33 )%
Wyoming Electric 433
45 % 32% 328
10 %
Combined^(a)
705
27 % 17% 603
9 %

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 %

~~__________~~


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


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

~~Table of Contents~~

~~Gas Utilities~~

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

~~Results of Operations for the Gas Utilities for the Three~~Six Months Ended ~~September~~June 30, ~~2019~~2020 Compared to the ~~Three~~Six Months Ended ~~September~~June 30, ~~2018:~~2019:

Gross margin for the ~~three~~six months ended ~~September~~June 30, ~~2019 increased~~2020 remained constant as a result ~~of:~~of the following:


	(in millions)
COVID-19 impacts ^(a)	$	(1.5)
Off-system power marketing	(1.2)
Rider recovery and true-up ^(b)	(0.3)
Mark-to-market on wholesale energy contracts	1.2
Weather	0.6
Residential customer growth	0.4
Other	0.8
Total change in Gross margin (non-GAAP)	$	—

(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~~The impacts ~~for the three months ended September 30, 2019 compared~~ to ~~the same period in the prior year include~~Electric Utilities gross margin from COVID-19 were driven by reduced ~~heating demand~~commercial volumes partially offset by higher residential usage.

(b) Gross margin decreased due to ~~warmer temperatures and reduced irrigation loads to agriculture customers in our Nebraska Gas service territory due to higher precipitation.~~a $2.5 million rider true-up, which was mostly offset by $2.2 million of increased rider recovery.

Operations and maintenance expense increased primarily due to ~~higher employee costs~~$1.4 million of expenses related to the municipalization efforts in Pueblo, Colorado. COVID-19 impacts to operations and ~~higher~~maintenance expense included $1.6 million of expenses related to the sequestration of essential employees and $0.6 million of additional bad debt expense which were offset by $2.0 million of lower travel, training and outside services related expenses.

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

Operating Statistics


	Electric Revenue											Quantities Sold
	(in thousands)											(MWh)
	Three Months Ended June 30,						Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,
	2020		2019		2020		2019		2020	2019	2020	2019

Residential	$	50,148	$	45,700	$	104,653	$	103,338	334,682	301,481	707,832	690,659
Commercial	56,400		59,739		114,223		120,702		459,632	490,329	953,940	995,902
Industrial	31,896		31,697		64,065		64,137		459,533	445,837	920,165	872,451
Municipal	4,020		4,253		7,898		8,392		38,372	38,283	74,771	74,919
Subtotal Retail Revenue - Electric	142,464		141,389		290,839		296,569		1,292,219	1,275,930	2,656,708	2,633,931
Contract Wholesale ^(a)	3,470		6,781		9,023		15,124		87,253	194,222	219,031	417,242
Off-system/Power Marketing Wholesale	3,537		3,448		8,404		10,140		136,311	135,091	302,096	275,941
Other	13,729		14,736		29,073		27,448		—	—	—	—
Total Revenue and Energy Sold	163,200		166,354		337,339		349,281		1,515,783	1,605,243	3,177,835	3,327,114
Other Uses, Losses or Generation, net ^(b)	—		—		—		—		85,185	89,866	176,056	186,866
Total Revenue and Energy	163,200		166,354		337,339		349,281		1,600,968	1,695,109	3,353,891	3,513,980
Less cost of fuel and purchased power	59,053		62,128		123,513		135,411
Gross Margin (non-GAAP)	$	104,147	$	104,226	$	213,826	$	213,870

Table of Contents


	Electric Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(b)
Three Months Ended June 30,	2020		2019		2020		2019		2020	2019
Colorado Electric	$	57,897	$	55,412	$	32,455	$	31,051	547,814	485,346
South Dakota Electric ^(a)	62,587		69,246		49,973		50,865		570,528	757,640
Wyoming Electric	42,716		41,696		21,719		22,310		482,626	452,123
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	163,200	$	166,354	$	104,147	$	104,226	1,600,968	1,695,109

~~Results of Operations~~



	Electric Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(b)
Six Months Ended June 30,	2020		2019		2020		2019		2020	2019
Colorado Electric	$	116,455	$	115,259	$	64,725	$	62,495	1,098,585	977,028
South Dakota Electric ^(a)	134,198		148,287		105,597		107,173		1,255,752	1,602,641
Wyoming Electric	86,686		85,735		43,504		44,202		999,554	934,311
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	337,339	$	349,281	$	213,826	$	213,870	3,353,891	3,513,980

________________

(a) Revenue and purchased power for the ~~Gas Utilities~~three and six months ended June 30, 2020 as well as associated quantities, for certain wholesale contracts have been presented on a net basis. Amounts for the ~~Nine~~three and six months ended June 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.

(b) Includes company uses, line losses, and excess exchange production.


	Three Months Ended June 30,			Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2020	2019	2020	2019

Coal-fired	572,030	471,840	1,119,859	1,057,135
Natural Gas and Oil	86,798	86,475	254,542	211,132
Wind	63,628	56,505	137,178	111,924
Total Generated	722,456	614,820	1,511,579	1,380,191

Purchased ^(a)	878,512	1,080,289	1,842,312	2,133,789
Total Generated and Purchased	1,600,968	1,695,109	3,353,891	3,513,980


	Three Months Ended June 30,			Six Months Ended June 30,
Quantities Generated and Purchased (MWh)	2020	2019	2020	2019
Generated:
Colorado Electric	80,456	91,886	174,507	192,416
South Dakota Electric	442,566	315,925	915,532	773,294
Wyoming Electric	199,434	207,009	421,540	414,481
Total Generated	722,456	614,820	1,511,579	1,380,191
Purchased:
Colorado Electric	467,358	393,460	924,078	784,612
South Dakota Electric ^(a)	127,962	441,715	340,220	829,347
Wyoming Electric	283,192	245,114	578,014	519,830
Total Purchased	878,512	1,080,289	1,842,312	2,133,789

Total Generated and Purchased	1,600,968	1,695,109	3,353,891	3,513,980

________________

(a) Purchased power quantities for the three and six months ended June 30, 2020, for certain wholesale contracts have been presented on a net basis. Amounts for the three and six months ended June 30, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.

Table of Contents



	Three Months Ended June 30,
Degree days	2020				2019
	Actual	Variance from Normal		Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	518	(18)	%	603	(5)	%
South Dakota Electric	1,127	10	%	1,279	25	%
Wyoming Electric	1,149	(4)	%	1,359	12	%
Combined^(a)	853	(3)	%	986	12	%

Cooling Degree Days:
Colorado Electric	382	83	%	147	(30)	%
South Dakota Electric	120	21	%	38	(62)	%
Wyoming Electric	101	102	%	29	(42)	%
Combined^(a)	236	69	%	86	(38)	%


	Six Months Ended June 30,
Degree days	2020				2019
	Actual	Variance from Normal		Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	2,974	(9)	%	3,152	(4)	%
South Dakota Electric	4,238	—	%	5,195	23	%
Wyoming Electric	4,148	(1)	%	4,557	3	%
Combined^(a)	3,642	(4)	%	4,132	8	%

Cooling Degree Days:
Colorado Electric	382	83	%	147	(30)	%
South Dakota Electric	120	21	%	38	(62)	%
Wyoming Electric	101	102	%	29	(42)	%
Combined^(a)	236	69	%	86	(38)	%

____________________

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


	Three Months Ended June 30,						Six Months Ended June 30,
Contracted Power Plant Fleet Availability ^(a)	2020		2019		2020		2019
Coal-fired plants ^(b)	94.1	%	79.2	%	92.5	%	87.7	%
Natural gas-fired plants and Other plants^(c)	78.3	%	89.3	%	80.9	%	90.0	%
Wind	98.1	%	94.5	%	98.6	%	95.6	%
Total Availability	85.0	%	86.4	%	86.0	%	89.7	%

Wind Capacity Factor	39.0	%	34.8	%	42.3	%	38.7	%

____________________

(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.

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

Table of Contents

Gas Utilities


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue:
Natural gas - regulated	$	148,432	$	149,942	$	(1,510)	$	484,329	$	533,817	$	(49,488)
Other - non-regulated services	12,678		15,527		(2,849)		37,554		42,732		(5,178)
Total revenue	161,110		165,469		(4,359)		521,883		576,549		(54,666)

Cost of sales:
Natural gas - regulated	42,910		51,108		(8,198)		196,909		252,158		(55,249)
Other - non-regulated services	1,712		5,876		(4,164)		3,074		12,105		(9,031)
Total cost of sales	44,622		56,984		(12,362)		199,983		264,263		(64,280)

Gross margin (non-GAAP)	116,488		108,485		8,003		321,900		312,286		9,614

Operations and maintenance	72,415		77,131		(4,716)		149,709		155,069		(5,360)
Depreciation and amortization	25,864		22,797		3,067		51,085		45,346		5,739
Total operating expenses	98,279		99,928		(1,649)		200,794		200,415		379

Adjusted operating income	$	18,209	$	8,557	$	9,652	$	121,106	$	111,871	$	9,235

Three Months Ended ~~September~~June 30, ~~2019~~2020 Compared to the ~~Nine~~Three Months Ended ~~September~~June 30, ~~2018:~~2019:

Gross margin for the ~~nine~~three months ended ~~September~~June 30, ~~2019~~2020 increased as a result of:

(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



	(in millions)
New rates	$	3.6
Weather	2.8
Mark-to-market on non-utility natural gas commodity contracts	1.6
Customer growth - distribution	0.6
COVID-19 impacts ^(a)	(0.9)
Decreased transport and transmission	(0.8)
Other	1.1
Total increase in Gross margin (non-GAAP)	$	8.0

____________________

(a) The impacts to Gas Utilities gross margin from COVID-19 were primarily driven by reduced volumes from certain industrial and transport customers.

Operations and maintenance expense ~~increased~~decreased primarily due to ~~$7.2~~$1.5 million of ~~higher outside services expenses, $4.1 million of higher~~lower employee costs and ~~$1.3~~$1.5 million of ~~higher property taxes due~~lower outside service expenses. COVID-19 impacts to ~~a higher asset base driven~~operations and maintenance expense included $1.4 million of lower travel, training and outside services related expenses which were partially offset by $1.0 million of additional bad debt expense. Various other expenses comprised the remainder of the difference when compared to the same period in the prior ~~and current year capital expenditures.~~year.

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

Table of Contents

Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019:

Gross margin for the six months ended June 30, 2020 increased as a result of:


	(in millions)
New rates	$	9.2
Prior year amortization of excess deferred income taxes	2.7
Customer growth - distribution	2.1
Mark-to-market on non-utility natural gas commodity contracts	2.4
Weather	(7.6)
COVID-19 impacts ^(a)	(0.9)
Other	1.7
Total increase in Gross margin (non-GAAP)	$	9.6

____________________

(a) The impacts to Gas Utilities gross margin from COVID-19 were primarily driven by reduced volumes from certain industrial and transport customers.

Operations and maintenance expense decreased primarily due to $3.4 million of lower outside services expenses, $1.9 million of lower employee costs partially offset by $0.9 million of higher property taxes due to a higher asset base. COVID-19 impacts to operations and maintenance expense included $1.4 million of lower travel, training and outside services related expenses which were offset by $1.4 million of additional bad debt expense. Various other expenses comprised the remainder of the difference when compared to the same period in the prior year.

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

Operating Statistics


	Gas Revenue (in thousands)						Gross Margin(non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended June 30,						Three Months Ended June 30,				Three Months Ended June 30,
	2020		2019		2020		2019		2020	2019

Residential	$	83,240	$	85,093	$	56,368	$	52,670	8,501,835	7,919,158
Commercial	27,441		30,984		15,336		14,926		3,965,529	4,194,879
Industrial	6,059		3,980		2,140		1,320		2,036,553	997,942
Other	828		887		827		887		—	—
Total Distribution	117,568		120,944		74,671		69,803		14,503,917	13,111,979

Transportation and Transmission	30,864		28,998		30,851		29,031		30,243,501	32,767,310

Total Regulated	148,432		149,942		105,522		98,834		44,747,418	45,879,289

Non-regulated Services	12,678		15,527		10,966		9,651

Total Gas Revenue & Gross Margin (non-GAAP)	$	161,110	$	165,469	$	116,488	$	108,485

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

Table of Contents



	Gas Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Six Months Ended June 30,						Six Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		2020	2019

Residential	$	290,471	$	326,222	$	159,489	$	157,727	36,732,630	40,757,176
Commercial	107,677		127,123		48,855		50,084		16,800,332	19,185,727
Industrial	11,259		9,994		4,183		3,337		3,097,605	2,180,469
Other	(415)		(3,467)		(415)		(3,467)		—	—
Total Distribution	408,992		459,872		212,112		207,681		56,630,567	62,123,372

Transportation and Transmission	75,337		73,945		75,308		73,978		75,299,008	79,083,470

Total Regulated	484,329		533,817		287,420		281,659		131,929,575	141,206,842

Non-regulated Services	37,554		42,732		34,480		30,627

Total Gas Revenue & Gross Margin (non-GAAP)	$	521,883	$	576,549	$	321,900	$	312,286

Gas 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

Residential $ 383,466
$ 383,972
$ 201,168
$ 192,072
44,356,725
42,642,021
Commercial 146,752
148,675
61,673
57,890
21,484,646
20,842,996
Industrial 18,764
20,805
5,830
5,341
5,141,399
5,235,417
Other ^(a)
(968 ) (6,789 ) (968 ) (6,789 ) —
—
Total Distribution 548,014
546,663
267,703
248,514
70,982,770
68,720,434

Transportation and Transmission 103,352
101,887
103,351
101,887
110,622,285
107,388,321

Total Regulated 651,366
648,550
371,054
350,401
181,605,055
176,108,755

Non-regulated Services 55,927
58,090
38,952
42,374

Total Gas Revenue & Gross Margin $ 707,293
$ 706,640
$ 410,006
$ 392,775



	Gas Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended June 30,						Three Months Ended June 30,				Three Months Ended June 30,
	2020		2019		2020		2019		2020	2019

Arkansas Gas	$	28,733	$	26,236	$	21,906	$	18,617	4,906,236	4,542,917
Colorado Gas	28,613		36,713		18,807		19,755		5,046,844	6,067,353
Iowa Gas	21,407		23,714		14,355		14,588		5,521,119	7,484,272
Kansas Gas	18,486		17,379		12,460		11,957		6,722,914	6,290,716
Nebraska Gas	40,466		39,315		30,719		27,709		13,822,478	14,816,996
Wyoming Gas	23,405		22,112		18,241		15,859		8,727,827	6,677,035
Total Gas Revenue & Gross Margin (non-GAAP)	$	161,110	$	165,469	$	116,488	$	108,485	44,747,418	45,879,289


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



	Gas Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Six Months Ended June 30,						Six Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		2020	2019

Arkansas Gas	$	103,578	$	105,627	$	70,761	$	62,899	15,869,184	16,967,113
Colorado Gas	101,219		113,184		56,813		57,355		18,143,249	19,244,278
Iowa Gas	76,231		89,355		35,683		37,638		19,801,392	23,147,959
Kansas Gas	51,980		58,596		31,063		30,076		16,637,772	16,733,986
Nebraska Gas	124,132		148,112		82,385		83,782		40,331,514	43,816,014
Wyoming Gas	64,743		61,675		45,195		40,536		21,146,464	21,297,492
Total Gas Revenue & Gross Margin (non-GAAP)	$	521,883	$	576,549	$	321,900	$	312,286	131,929,575	141,206,842

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

Arkansas $ 21,387
$ 18,743
$ 16,249
$ 13,415
4,094,454
4,022,089
Colorado 22,632
22,362
15,667
15,210
3,806,360
2,893,029
Iowa 16,381
16,982
13,135
12,556
5,686,772
5,595,205
Kansas 19,013
18,497
12,309
11,129
7,602,758
6,164,821
Nebraska 35,715
40,553
28,046
31,264
13,999,302
13,831,306
Wyoming 15,616
14,539
12,314
11,976
5,208,567
5,592,715
Total Gas Revenue & Gross Margin (non-GAAP) $ 130,744
$ 131,676
$ 97,720
$ 95,550
40,398,213
38,099,165

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

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

Table of Contents

Power Generation


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	26,122	$	24,708	$	1,414	$	52,088	$	49,953	$	2,135

Fuel expense	2,087		2,024		63		4,372		4,650		(278)
Operations and maintenance	7,350		7,809		(459)		14,347		13,871		476
Depreciation and amortization	5,283		4,719		564		10,618		9,309		1,309
Total operating expense	14,720		14,552		168		29,337		27,830		1,507

Adjusted operating income	$	11,402	$	10,156	$	1,246	$	22,751	$	22,123	$	628

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

~~________________~~


~~(a)~~	Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Power Generation Adjusted operating income was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(1.4) million and $(4.4) million, respectively.

~~Results of Operations for Power Generation for the~~ Three ~~and Nine~~ Months Ended ~~September~~June 30, ~~2019~~2020 Compared to the Three ~~and Nine~~ Months Ended ~~September~~June 30, ~~2018:~~2019:

Revenue increased in the current year driven primarily by increased MWh sold from new wind assets and additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased primarily due to ~~increased~~higher depreciation from new wind ~~MWh sold~~assets and ~~higher PPA prices. Operating~~COVID-19 impacts of $0.4 million of expenses related to the sequestration of essential employees partially offset by lower maintenance costs due to a prior year planned outage at Pueblo Airport Generation.

Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019:

Revenue increased in the current year driven by an increase in MWh sold from new wind assets and additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased primarily due to higher depreciation ~~and property taxes~~ from new wind assets. COVID-19 impacts to operations and maintenance expense included $0.4 million of expenses related to the sequestration of essential employees.

Table of Contents

The following table summarizes MWh for our Power Generation segment:


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
Quantities Sold, Generated and Purchased (MWh) ^(a)
Sold
Black Hills Colorado IPP	263,701	210,316	528,926	416,289
Black Hills Wyoming ^(b)	156,866	149,713	313,218	313,762
Black Hills Electric Generation	92,629	47,796	189,908	81,549
Total Sold	513,196	407,825	1,032,052	811,600

Generated
Black Hills Colorado IPP	263,701	210,316	528,926	416,289
Black Hills Wyoming ^(b)	142,747	132,189	269,232	264,782
Black Hills Electric Generation	92,629	47,796	189,908	81,549
Total Generated	499,077	390,301	988,066	762,620

Purchased

Black Hills Wyoming ^(b)	14,160	13,761	44,093	39,340

Total Purchased	14,160	13,761	44,093	39,340

___________

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

(b) 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.


	Three Months Ended June 30,						Six Months Ended June 30,
Contracted Power Plant Fleet Availability ^(a)	2020		2019		2020		2019

Coal-fired plant	98.2	%	95.8	%	93.7	%	95.3	%
Natural gas-fired plants ^(b)	99.7	%	88.7	%	99.6	%	92.1	%
Wind	93.1	%	94.1	%	94.0	%	92.3	%
Total Availability	97.0	%	91.5	%	96.6	%	92.8	%

Wind Capacity Factor	27.5	%	23.1	%	28.9	%	25.7	%

___________

(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.

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

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

Sold
Black Hills Colorado IPP ^(b)
275,867
304,102
692,156
745,365
Black Hills Wyoming ^(c)
162,668
160,011
476,430
470,072
Black Hills Electric Generation ^(d)
30,912
—
112,461
—
Total Sold 469,447
464,113
1,281,047
1,215,437

Generated
Black Hills Colorado IPP ^(b)
275,867
304,102
692,156
745,365
Black Hills Wyoming ^(c)
142,219
144,476
407,001
407,324
Black Hills Electric Generation ^(d)
30,912
—
112,461
—
Total Generated 448,998
448,578
1,211,618
1,152,689

Purchased
Black Hills Wyoming ^(c)
16,865
16,685
56,205
65,724
Total Purchased 16,865
16,685
56,205
65,724

~~____________~~


~~(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.~~

Table of Contents

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

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

~~____________~~


~~(a)~~	~~2019 included a planned outage at Pueblo Airport Generating Station.~~


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

Mining


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Revenue	$	15,416	$	13,045	$	2,371	$	30,621	$	29,474	$	1,147

Operations and maintenance	9,732		9,175		557		19,558		19,088		470
Depreciation, depletion and amortization	2,326		2,230		96		4,576		4,409		167
Total operating expenses	12,058		11,405		653		24,134		23,497		637

Adjusted operating income	$	3,358	$	1,640	$	1,718	$	6,487	$	5,977	$	510

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 June 30, 2020 Compared to the Three Months Ended June 30, 2019:

Current year revenue increased due to 29% higher tons sold driven primarily by prior year planned and unplanned facility outages partially offset by a 7% decrease in price per ton sold driven by contract price adjustments based on actual mining costs.

Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019:

Current year revenue increased due to 7% higher tons sold driven primarily by prior year planned and unplanned facility outages partially offset by a 3% decrease in price per ton sold driven by contract price adjustments based on actual mining costs.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Tons of coal sold	972		754		1,868		1,751
Cubic yards of overburden moved	2,211		2,045		4,478		4,039

Revenue per ton	$	15.27	$	16.48	$	15.66	$	16.14

Corporate and Other


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)
Adjusted operating income (loss)	$	(29)	$	102	$	(131)	$	131	$	(405)	$	536

Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Variance		2020		2019		Variance
	(in thousands)										(in thousands)
Interest expense, net	$	(35,545)	$	(34,264)	$	(1,281)	$	(70,998)	$	(68,981)	$	(2,017)
Impairment of investment	—		—		$	—	(6,859)		—		$	(6,859)
Other income (expense), net	(1,863)		263		$	(2,126)	490		(526)		$	1,016
Income tax (expense)	(4,831)		(2,307)		$	(2,524)	(20,833)		(19,570)		$	(1,263)

Table of Contents

Three Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018
Tons of coal sold 969
1,078
2,720
3,119
Cubic yards of overburden moved 2,341
2,361
6,380
6,763

Revenue per ton $ 15.47
$ 15.54
$ 15.90
$ 15.92

~~Results of Operations for Mining for the~~ Three Months Ended ~~September~~June 30, ~~2019~~2020 Compared to the Three Months Ended ~~September~~June 30, ~~2018:~~2019.

Interest expense, net

Current year revenue decreased due to 10% fewer tons sold driven primarily by unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues.

~~Results of Operations for Mining~~The increase in Interest expense, net for the ~~Nine Months Ended September~~three months ended June 30, ~~2019 Compared~~2020, compared to the ~~Nine Months Ended September 30, 2018:~~same period in the prior year, was driven by higher debt balances partially offset by lower interest rates.

Other Income (Expense)

Current year revenue decreased due to 13% fewer tons sold driven primarily by planned and unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor and major maintenance expenses.

~~Table of Contents~~

~~Corporate and Other~~

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

~~________________~~


~~(a)~~	Due to the changes in our segment disclosures as discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Corporate and Other Adjusted operating income (loss) was revised for the three and nine months ended September 30, 2018, which resulted in a decrease of $(0.2) million and $(0.4) million, respectively.

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

The variance in ~~Adjusted operating~~Other income ~~(loss)~~(expense), net for the three months ended June 30, 2020, compared to the same period in the prior year, was primarily due to ~~prior year expenses related to the oil~~increased costs for our non-qualified benefit plans which were driven by market performance and ~~gas segment that were not reclassified to discontinued operations.~~increased non-service pension costs resulting from a change in accounting principle for our defined benefit pension plan effective January 1, 2020.

Income Tax (Expense)

Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax benefit (expense) for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018.

~~Impairment of Investment~~

For the three months ended ~~September~~June 30, ~~2019,~~2020, the effective tax rate was 16.4% compared to 11.5% for the same period in 2019. The higher effective tax rate is primarily due to a prior year discrete tax benefit related to repair costs and certain indirect costs.

Six Months Ended June 30, 2020 Compared to the Six Months Ended June 30, 2019.

Interest expense, net

The increase in Interest expense, net for the six months ended June 30, 2020, compared to the same period in the prior year was driven by higher debt balances partially offset by lower interest rates.

Impairment of Investment

For the six months ended June 30, 2020, we recorded a pre-tax non-cash write-down of ~~$20~~$6.9 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by ~~a deterioration~~continued adverse changes in ~~earnings performance of~~future natural gas prices and liquidity concerns at the privately held oil and gas ~~company~~company. The remaining book value of our investment is $1.5 million, and ~~an adverse change~~this is our only remaining investment in ~~future natural~~oil and gas ~~prices.~~exploration and production activities. See Note 2115 of the Notes to Condensed Consolidated Financial Statements for additional details.

Other Income (Expense)

The variance in Other income (expense), net for the six months ended June 30, 2020, compared to the same period in the prior year, was primarily due to reduced costs for our non-qualified benefit plans which are driven by market performance partially offset by increased non-service pension costs resulting from a change in accounting principle for our defined benefit pension plan effective January 1, 2020.

Income Tax ~~Benefit~~ (Expense)

~~Income tax benefit (expense) for~~For the ~~three~~six months ended ~~September~~June 30, ~~2019~~2020, the effective tax rate was ~~$(2.5) million~~14.6% compared to ~~$(7.5) million~~13.5% 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.~~2019. The higher effective tax rate is primarily due to a prior year ~~state tax benefit.~~

~~Consolidated Interest expense, Impairment of investment, Other income (expense) and Income~~discrete tax benefit ~~(expense) for the Nine Months Ended September 30, 2019 Compared~~related to repair costs and certain indirect costs and a current year discrete tax adjustment related to the ~~Nine Months Ended September 30, 2018.~~

~~Impairment~~impairment of ~~Investment~~

~~For the nine months ended September 30, 2019, we recorded a non-cash write-down of $20 million in~~ our investment in equity securities of a privately held oil and gas ~~company. The impairment was triggered by a deterioration in earnings performance of the privately held oil and gas~~ company ~~and an adverse change in future natural gas prices. See Note 21 of the Notes to Condensed Consolidated Financial Statements for additional details.~~

~~Table of Contents~~

~~Income Tax Benefit (Expense)~~

Income tax benefit (expense) for the nine months ended September 30, 2019 was $(22) million compared to $12 million reported for the same period in 2018. The increase in tax expense was primarily due to a prior year $49 million tax benefit resulting from legal entity restructuring partially offset by ~~a prior year $(7.5) million income~~increased 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 tax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $5.0 million ofbenefits from forecasted federal production ~~tax credits and related state investment~~ tax credits associated with new wind ~~assets, a $1.0 million tax benefit for deferred tax amortization related to tax reform.~~assets.

Table of Contents

Critical Accounting Policies Involving Significant Accounting Estimates

There have been no material changes in our critical accounting estimates from those reported in our ~~2018~~2019 Annual Report on Form 10-K filed with the ~~SEC.~~SEC except for Pension and Other Postretirement Benefits provided below. We continue to closely monitor the rapidly evolving and uncertain impact of COVID-19 on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities, and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our ~~2018~~2019 Annual Report on Form 10-K.

Pension and Other Postretirement Benefits

As described in Note 18 of the Notes to the Consolidated Financial Statements in our 2019 Annual Report on Form 10-K filed with the SEC, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A trust for the funded portion of the post-retirement healthcare plan has also been established.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

See Note 12 of the Notes to Condensed Consolidated Financial Statements for additional information.

Liquidity and Capital Resources

There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our ~~2018~~2019 Annual Report on Form 10-K filed with the SEC except as described ~~below.~~below and within the “COVID-19 Pandemic” discussion in the Ex ecutive Summary section above.

Collateral Requirements

Our utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At ~~September~~June 30, ~~2019,~~2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. For the six months ended June 30, 2020, we did not experience any requests to post additional collateral, including for concerns over a potential deterioration of our financial condition due to COVID-19.

~~Income Tax~~

~~The TCJA required revaluation~~

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

Cash Flow Activities

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


Cash provided by (used in):	2020		2019		Variance
Operating activities	$	309.0	$	289.8	$	19.2
Investing activities	$	(349.7)	$	(317.3)	$	(32.4)
Financing activities	$	62.8	$	13.6	$	49.2

Cash provided by (used in): 2019 2018 Variance
Operating activities $ 386,075
$ 378,722
$ 7,353
Investing activities $ (593,272 ) $ (281,771 ) $ (311,501 )
Financing activities $ 199,827
$ (101,949 ) $ 301,776

~~Table of Contents~~

Year-to-Date ~~2019~~2020 Compared to Year-to-Date ~~2018~~2019

Operating Activities

Net cash provided by operating activities was ~~$386~~$309 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, compared to net cash provided by operating activities of ~~$379~~$290 million for the same period in ~~2018~~2019, for an increase of $7$19 million. The variance was primarily attributable to:

•Cash earnings ~~(income from continuing operations~~(net income plus non-cash adjustments) were ~~$19~~$7.3 million higher for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same period in the prior ~~year;~~year primarily driven by higher operating income at the Gas Utilities segment;

•Net cash inflows from changes in operating assets and liabilities were ~~$28~~$26 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, compared to net cash inflows of ~~$42~~$14 million in the same period in the prior year. This ~~$14~~$12 million ~~decrease~~increase was primarily due to:


◦	Cash inflows increased by approximately $48 million primarily as a result of higher collections of accounts receivable for the nine months ended September 30, 2019 compared to the same period in the prior year;

◦Cash inflows decreased by $34 million primarily as a result of changes in accounts receivable driven by lower commodity prices and increased materials and supplies purchases;


◦	~~Cash outflows increased by approximately $3 million as a result of decreases in accounts payable and accrued liabilities driven by higher employee costs and other working capital requirements; and~~

◦Cash outflows decreased by $44 million as a result of changes in accounts payable and accrued liabilities driven by the impact of lower commodity prices, lower employee costs, lower outside services expenses and other working capital requirements;


◦	Cash inflows decreased by approximately $66 million as a result of changes in the timing of recovery from fuel cost adjustments as well as revenue reserved in the prior year due to the TCJA tax rate change that has subsequently been returned to customers.

◦Cash inflows increased by $12 million primarily as a result of changes in our regulatory assets and liabilities driven by timing of recovery from fuel costs adjustments and the TCJA tax rate change that was returned to customers in the prior year; and

◦Cash outflows increased by $13 million due to the timing of pension contributions made in the current year.

Investing Activities

Net cash used in investing activities was ~~$593~~$350 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, compared to net cash used in investing activities of ~~$282~~$317 million for the same period in ~~2018~~2019, for a variance of ~~$311~~$32 million. The variance was primarily attributable to:

•Capital expenditures of ~~approximately $593~~$348 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to ~~$278~~$318 million for the same period in the prior year. Higher current year expenditures ~~are~~were driven by higher programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the ~~35-mile Natural Bridge pipeline project at our Gas Utilities segment, the Busch Ranch II~~Corriedale wind project at our ~~Power Generation segment and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska at our~~ Electric Utilities segment.

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

Table of Contents

Financing Activities

Net cash provided by financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 was ~~$200~~$63 million, compared to ~~$102~~$14 million of net cash ~~used in~~provided by financing activities for the same period in ~~2018 for a variance~~2019, an increase of ~~$302 million. This variance is~~$49 million primarily due ~~to:~~to the following:

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

~~Current year issuance of~~•Cash dividends on common stock ~~for~~of $66 million were paid in the current year compared to $61 million paid in the prior year;

•Increase of $28 million in common stock issued due primarily to current year net proceeds of $99 million through ~~our ATM equity offering program;~~

~~Current~~an underwritten registered transaction partially offset by prior year net ~~short-term borrowings~~proceeds of ~~$109~~$69 million ~~driven by increased capital expenditures;~~through our ATM;

~~In the prior year, $99 million of net proceeds from the August 17, 2018 debt transaction was used to repay short-term debt;~~

•$15266 million of higher ~~current year dividend payments;~~repayments of short-term debt;

•Increase of $297 million in net proceeds due to issuances of long-term debt in excess of maturities; and

~~Payments~~•Cash outflows for other financing activities ~~decreased~~increased $4.5 million driven primarily by ~~$8.4 million, which was primarily driven by prior~~current year financing costs ~~associated with~~in the ~~July 30, 2018 and August~~June 17, ~~2018~~2020 debt ~~transactions.~~offering.

Dividends

Dividends paid on our common stock totaled ~~$92~~$66 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, or ~~$0.505~~$0.535 per share per quarter. On ~~October 31, 2019,~~July 27, 2020, our board of directors declared a quarterly dividend of $0.535 per share payable ~~December~~September 1, ~~2019,~~2020, equivalent to an annual dividend of $2.14 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.

Financing Transactions and Short-Term Liquidity

Revolving Credit Facility and CP Program

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


		Current		Revolver Borrowings at		CP Program Borrowings at		Letters of Credit^(a) at		Available Capacity at
Credit Facility	Expiration	Capacity		June 30, 2020		June 30, 2020		June 30, 2020		June 30, 2020
Revolving Credit Facility and CP Program	July 30, 2023	$	750	$	—	$	—	$	12	$	738

Current Short-term borrowings at Letters of Credit at Available Capacity at
Credit Facility Expiration Capacity September 30, 2019 September 30, 2019 September 30, 2019
Revolving Credit Facility and CP Program July 30, 2023 $ 750
$ 295
$ 18
$ 437
_______________

(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit

~~The weighted average interest rate on short-term borrowings at September 30, 2019 was 2.43%. Short-term~~Facility.

Revolving Credit Facility and CP Program borrowing activity for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 was (dollars in millions):


	For the Six Months Ended June 30, 2020
Maximum amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	220
Maximum amount outstanding - CP Program (based on daily outstanding balances)	$	366
Average amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	109
Average amount outstanding - CP Program (based on daily outstanding balances)	$	243
Weighted average interest rates - Revolving Credit Facility	1.75		%
Weighted average interest rates - CP Program	1.48		%

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 %

Table of Contents

Covenant Requirements

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of ~~September~~June 30, ~~2019.~~2020. See Note 87 of the Notes to Condensed Consolidated Financial Statements for more information.

Covenants within Wyoming Electric’s financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of ~~September~~June 30, ~~2019,~~2020, we were in compliance with these covenants.

Financing Activities

~~Financing~~See Notes 7 and 8 of the Notes to Condensed Consolidated Financial Statements for information concerning significant financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2019 consisted of the following:~~2020.

We issued a total of 1,328,332 shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.0 million in commissions. As of September 30, 2019, there were no shares that were sold, but not settled.

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continues to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. 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.

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

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, repay a portion of short-term debt.

Future Financing Plans

We will continue to assess debt and equity needs to support our capital expenditure plan.

Credit Ratings

After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.

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

2020:



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

__________


~~(a)~~	~~On February 28, 2019,~~ (a) On April 10, 2020, S&P affirmed our BBB+ rating and maintained a Stable outlook.


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


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

(b) On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.

56(c) On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

~~Table of Contents~~

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

2020:



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

__________


~~(a)~~	~~On April 30, 2019,~~ (a) On April 16, 2020, S&P affirmed A rating.


~~(b)~~	~~On October 15, 2019, Moody’s affirmed A1 rating.~~


~~(c)~~	~~On August 29, 2019, Fitch affirmed A rating.~~

(b) On December 20, 2019, Moody’s affirmed A1 rating.

Table of Contents

Capital Requirements

Capital Expenditures


	Actual		Planned											Actual		Planned
Capital Expenditures by Segment	Nine Months Ended September 30, 2019 ^(a)		2019 ^(b)		2020		2021		2022		2023		Capital Expenditures by Segment	Six Months Ended June 30, 2020 ^(a)		2020 ^(b)		2021		2022		2023		2024
(in millions)													(in millions)
Electric Utilities ^(c)	$	147	$	215	$	229	$	203	$	170	$	137
Gas Utilities ^(c)	367		490		361		297		274		303
Electric Utilities													Electric Utilities	$	117	$	246	$	203	$	170	$	137	$	152
Gas Utilities													Gas Utilities	209		391		309		285		316		293
Power Generation	79		84		7		9		11		6		Power Generation	6		7		9		11		6		6
Mining	6		8		8		12		9		9		Mining	6		8		12		9		9		9
Corporate and Other	15		23		18		22		11		12		Corporate and Other	10		17		22		11		12		10
	$	614	$	820	$	623	$	543	$	475	$	467		$	348	$	669	$	555	$	486	$	480	$	470

__________

(a) Expenditures for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 include the impact of accruals for property, plant and equipment.

(b) Includes actual capital expenditures for the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020.

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

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and statuses of large capital projects. To date, there have been limited impacts from COVID-19 on supply chains including the availability of supplies and materials and lead times. Capital projects are ongoing without material disruption to schedules. Our third party resources continue to ~~evaluate potential future acquisitions and other growth opportunities when they arise. As~~support our business plans without disruption. Contingency plans are ready to be executed if significant disruption to supply chain occurs; however, we currently do not anticipate a ~~result,~~significant impact from COVID-19 on our capital ~~expenditures may vary significantly from the estimates identified above.~~investment plan for 2020.

Contractual Obligations

There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our ~~2018~~2019 Annual Report on Form 10-K except for the items described in ~~Notes 8, 16, and 20~~Note 13 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Off-Balance Sheet Commitments

There have been no significant changes to off-balance sheet commitments from those previously disclosed in Item 7 of our ~~2018~~2019 Annual Report on Form 10-K filed with the SEC except for the items described in Note 87 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

New Accounting Pronouncements

Other than the pronouncements reported in our ~~2018~~2019 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.

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 &and 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, such as the COVID-19 pandemic, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our ~~2018~~2019 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our ~~2018~~2019 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.~~	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~~See Note 9 of the ~~nine~~Notes to Condensed Consolidated Financial Statements for updates to market risks during the six months ended ~~September~~June 30, ~~2019, there were no material changes to our quantitative and qualitative disclosures about market risk.~~2020.

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)~~1934, as amended (the “Exchange Act”)) as of ~~September~~June 30, ~~2019.~~2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at ~~September~~June 30, ~~2019.~~2020.

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~~SEC’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~~June 30, ~~2019,~~2020, there have been no changes in our internal ~~control~~controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. Although we have altered some work routines due to the COVID-19 pandemic, the changes in our work environment (i.e. remote work arrangements) have not materially impacted our internal controls over financial reporting and have not adversely affected the Company’s ability to maintain operations, including financial reporting systems, ICFR, and disclosure controls and procedures.

Table of Contents

PART II. OTHER INFORMATION

~~BLACK HILLS CORPORATION~~

~~Part II — Other Information~~


~~ITEM 1.~~	~~Legal Proceedings~~

ITEM 1.LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 19 in Item 8 of our ~~2018~~2019 Annual Report on Form 10-K and Note 1613 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1613 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 2019 Annual Report on Form 10-K filed with the SEC except as shown below:

Our business, results of operations, financial condition and cash flows could be adversely affected by the recent coronavirus (COVID-19) pandemic.

We have responded to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.

For the six months ended June 30, 2020, the COVID-19 pandemic had a limited financial impact on our business, operations, financial condition and cash flows. In particular, we experienced:

•Lower commercial and certain industrial and transport volumes partially offset by higher electric and natural gas residential usage;

•Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;

•Minimal cash flow impacts from delayed payments from residential, commercial and industrial customers;

•Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;

•Reduced availability and productivity of our employees;

•Minimal impacts to the availability of our third-party resources;

•Minimal decline in the funded status of our pension plan;

•Increased costs for personal protection equipment and cleaning supplies;

•Increased costs due to sequestration of mission-critical and essential employees;

•Minimal interest expense increase due to disruptions in the Commercial Paper markets; and

•Reduced training, travel and outside services expenses.

Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business, operations, financial condition and cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:

•Adverse impacts on our strategic business plans, growth strategy and capital investment plans;

•Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;

•Further reduction in the availability and productivity of our employees and third-party resources;

•Increased costs as a result of our emergency measures;

•Increased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment;

•Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;

•Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;

•Deterioration of the credit quality of our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;

•Impairment of goodwill or long-lived assets;

•Adverse impacts on our ability to develop, construct and operate facilities;

•Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;

•Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;

Table of Contents

•Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;

•Adverse impact on our liquidity position and cost of and ability to access funds from financial institutions and capital markets;

•Delays in our ability to change rates through regulatory proceedings; and

•Other risks that impact us, such as the risks described in the “Risk Factors” section of our 2019 Annual Report on Form 10-K and our ability to meet our financial obligations.

To date, we have experienced limited impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our business, results of operations, financial condition and cash flows.


~~ITEM 4.~~	~~Mine Safety Disclosures~~

ITEM 4. MINE SAFETY DISCLOSURES

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

ITEM 6. EXHIBITS


~~ITEM 6.~~Exhibit Number			~~Exhibits~~Description



~~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).
			Ninth Supplemental Indenture dated as of June 17, 2020 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on June 17, 2020).

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


			Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).




Exhibit 4.3*	Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014).
		First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014).
		Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).

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

Exhibit 10.1		~~First Amendment dated as of June 17, 2019 to Amended and Restated Credit~~Equity Distribution Sales Agreement dated ~~as of July 30, 2018,~~August 4, 2020 among Black Hills Corporation ~~as Borrower,~~and the ~~financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent~~several Agents named therein (filed as Exhibit ~~10.1~~1.1 to the Registrant’s Form ~~8–K~~8-K filed on ~~June 17, 2019)~~August 4, 2020).

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~~pursuance 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)

__________


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

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

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

Dated:		~~November 5, 2019~~August 4, 2020



☒	~~QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES~~
	~~EXCHANGE ACT OF 1934~~
	~~For the quarterly period ended~~	OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________. Commission File Number 001-31303 Black Hills Corporation Incorporated in South Dakota IRS Identification Number 46-0458824 7001 Mount Rushmore Road Rapid City, South Dakota 57702 Registrant’s telephone number (605) 721-1700 Former name, former address, and former fiscal year if changed since last report NONE ~~September 30, 2019~~
OR
☐	~~TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES~~
	~~EXCHANGE ACT OF 1934~~
	~~For the transition period from __________ to __________.~~

	~~Commission File Number~~	~~001-31303~~



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

~~7001 Mount Rushmore Road~~	~~Rapid City~~		~~South Dakota~~	~~57702~~

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


TABLE OF CONTENTS
						Page
~~Glossary of Terms and Abbreviations~~Item 2.			3

~~PART I. FINANCIAL INFORMATION~~

~~Item 1.~~	~~Financial Statements - unaudited~~	5
	~~Condensed Consolidated Statements of Income~~	5
	~~Condensed Consolidated Statements of Comprehensive Income~~	6
	~~Condensed Consolidated Balance Sheets~~	7
	~~Condensed Consolidated Statements of Cash Flows~~	9
	~~Condensed Consolidated Statements of Equity~~	10
	~~Notes to Condensed Consolidated Financial Statements~~	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			3736
		Executive Summary				36
		Results of Operations - Consolidated Summary and Overview				40
		Non-GAAP Financial Measure				41
		Electric Utilities Segment				42
		Gas Utilities Segment				46
		Regulatory Matters				49
		Power Generation Segment				50
		Mining Segment				52
		Corporate and Other				52
		Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)				52
		Critical Accounting Policies Involving Significant Accounting Estimates				54
		Liquidity and Capital Resources				55
		Cash Flow Activities				55
		Dividends				56
		Financing Transactions and Short-Term Liquidity				56
		Capital Requirements				58
		Contractual Obligations				58
		Off-Balance Sheet Commitments				58
		New Accounting Pronouncements				58
		Forward-Looking Information				59
Item 3.		Quantitative and Qualitative Disclosures ~~about~~About Market Risk				5859
Item 4.		Controls and Procedures				5960

PART II. OTHER INFORMATION
Item 1.		Legal Proceedings				60

Item 1.1A.	~~Legal Proceedings~~Risk Factors				5960

Item 4.		Mine Safety Disclosures				5961

Item 6.		Exhibits				5961

Signatures						6163



(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



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

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	16,751	$	(7,942	)	$	8,809
Services transferred over time	184,559		130,665		15,373		—		(19,243		)	311,354
Revenue from contracts with customers	$	184,559	$	130,665	$	15,373	$	16,751	$	(27,185	)	$	320,163



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



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		)
	$	—		$	—



	Accounts		Unbilled		Less Allowance for			Accounts
September 30, 2019	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,151	$	31,843	$	(500	)	$	70,494
Gas Utilities	46,265		24,091		(2,490		)	67,866
Power Generation	2,733		—		—			2,733
Mining	1,804		—		—			1,804
Corporate	6,261		—		(169		)	6,092
Total	$	96,214	$	55,934	$	(3,159	)	$	148,989



	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



	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



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



~~Yes~~	x	No o



~~Yes~~	x	No o



	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~~	%


~~(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.~~



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



	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.~~


	June 30, 2020		December 31, 2019
Investment in privately held oil and gas company	$	1,500	$	8,359
Cash surrender value of life insurance contracts	13,423		13,056
Other investments	515		514
Total investments	$	15,438	$	21,929


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


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


◦	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.



	(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



	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,
	2019		2018		2019		2018		2019	2018	2019	2018
Residential	$	58,919	$	58,122	$	162,257	$	163,979	384,735	372,623	1,075,394	1,084,531
Commercial	65,732		65,794		186,434		192,680		560,547	550,791	1,556,449	1,560,911
Industrial	33,937		31,939		98,074		93,959		462,809	429,133	1,335,260	1,248,438
Municipal	4,792		4,582		13,184		13,389		46,106	43,972	121,025	122,953
Subtotal Retail Revenue - Electric	163,380		160,437		459,949		464,007		1,454,197	1,396,519	4,088,128	4,016,833
Contract Wholesale	8,211		8,256		23,335		25,497		229,369	221,327	646,611	677,163
Off-system/Power Marketing Wholesale	6,452		9,059		16,592		18,142		160,357	206,791	436,298	514,686
Other	13,341		7,038		40,789		24,315		—	—	—	—
Total Revenue and Energy Sold	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	—		—		—		—		112,172	121,478	299,038	337,939
Total Revenue and Energy	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)	71,593		74,638		207,004		209,317
Gross Margin (non-GAAP) ^(a)	$	119,791	$	110,152	$	333,661	$	322,644



	(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




	Gas 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

Residential	$	383,466		$	383,972		$	201,168		$	192,072		44,356,725	42,642,021
Commercial	146,752			148,675			61,673			57,890			21,484,646	20,842,996
Industrial	18,764			20,805			5,830			5,341			5,141,399	5,235,417
Other ^(a)	(968		)	(6,789		)	(968		)	(6,789		)	—	—
Total Distribution	548,014			546,663			267,703			248,514			70,982,770	68,720,434

Transportation and Transmission	103,352			101,887			103,351			101,887			110,622,285	107,388,321

Total Regulated	651,366			648,550			371,054			350,401			181,605,055	176,108,755

Non-regulated Services	55,927			58,090			38,952			42,374

Total Gas Revenue & Gross Margin	$	707,293		$	706,640		$	410,006		$	392,775



	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

Arkansas	$	21,387	$	18,743	$	16,249	$	13,415	4,094,454	4,022,089
Colorado	22,632		22,362		15,667		15,210		3,806,360	2,893,029
Iowa	16,381		16,982		13,135		12,556		5,686,772	5,595,205
Kansas	19,013		18,497		12,309		11,129		7,602,758	6,164,821
Nebraska	35,715		40,553		28,046		31,264		13,999,302	13,831,306
Wyoming	15,616		14,539		12,314		11,976		5,208,567	5,592,715
Total Gas Revenue & Gross Margin (non-GAAP)	$	130,744	$	131,676	$	97,720	$	95,550	40,398,213	38,099,165


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