UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~10-Q~~March 31, 2020



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

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



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

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

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

Commission File Number 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road

Rapid City, South Dakota 57702

Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report

NONE

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



~~Yes~~	x	Yes ☒No ☐o

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).



~~Yes~~	x	Yes ☒No ☐ o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large Accelerated Filer	x	Accelerated Filer	☐

Non-accelerated Filer	☐	Smaller Reporting Company	☐

		Emerging Growth Company	☐

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)..Yes ☐ No ☒



~~Yes~~	☐	No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.



Class	Outstanding at ~~July 31, 2019~~April 30, 2020
Common stock, $1.00 par value	~~61,063,230~~62,749,727	shares



TABLE OF CONTENTS
		Page
Glossary of Terms and Abbreviations		34

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements - unaudited	57
	Condensed Consolidated Statements of Income	57
	Condensed Consolidated Statements of Comprehensive Income	68
	Condensed Consolidated Balance Sheets	79
	Condensed Consolidated Statements of Cash Flows	911
	Condensed Consolidated Statements of Equity	1012
	Notes to Condensed Consolidated Financial Statements	1113
	Note 1. Management’s Statement	1113
	Note 2. Revenue	1315
	Note 3. Business Segment Information	1516
	Note 4. ~~Accounts Receivable~~Selected Balance Sheet Information	1817
	Note 5. Regulatory ~~Accounting~~Matters	19
	Note 6. ~~Materials, Supplies and Fuel~~	20
	~~Note 7.~~ Earnings Per Share	20
	Note 8.7. Notes Payable, Current Maturities and Debt	21
	Note 8. Equity	22
	Note 9. ~~Equity~~Risk Management and Derivatives	2322
	Note 10. ~~Risk Management Activities~~Fair Value Measurements	2325
	Note 11. ~~Fair Value Measurements~~	26
	~~Note 12. Fair Value of Financial Instruments~~	29
	~~Note 13.~~ Other Comprehensive Income (Loss)	2927
	Note 12. Employee Benefit Plans	28
	Note 13. Commitments and Contingencies	30
	Note 14. ~~Supplemental Disclosure of Cash Flow Information~~Income Taxes	30
	Note 15. ~~Employee Benefit Plans~~Investments	31
	Note 16. ~~Commitments and Contingencies~~Subsequent Events	3231

Table of Contents



TABLE OF CONTENTS
	~~Note 17. Discontinued Operations~~	32
	~~Note 18. Income Taxes~~	33
	~~Note 19. Accrued Liabilities~~	33
	~~Note 20. Leases~~	34
	~~Note 21. Subsequent Event~~	36 Page
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Results of Operations	33
	Non-GAAP Financial Measure	36
	Electric Utilities Segment	37
	Gas Utilities Segment	40
	Regulatory Matters	42
	Power Generation Segment	42
	Mining Segment	43
	Corporate and Other	43
	Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)	43
	Critical Accounting Policies Involving Significant Accounting Estimates	43
	Liquidity and Capital Resources	43
	Cash Flow Activities	43
	Dividends	44
	Financing Transactions and Short-Term Liquidity	44
	Capital Requirements	45
	Contractual Obligations	45
	Off-Balance Sheet Commitments	45
	New Accounting Pronouncements	45
	Forward-Looking Information	45
Item 3.	Quantitative and Qualitative Disclosures ~~about~~About Market Risk	5745
Item 4.	Controls and Procedures	5846

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	5846
Item 1A.	Risk Factors	46
Item 4.	Mine Safety Disclosures	5847
Item 6.	Exhibits	5847

Signatures		6049

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
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	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
ATM	At-the-market equity offering program
Availability	The availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHC	Black Hills Corporation; the Company
Black Hills 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 is a~~ 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric ~~Generation. Colorado Electric and Black~~ ~~Hills Electric~~ Generation, each ~~have~~having a 50% ownership interest in the wind farm.
Busch Ranch II	~~Busch Ranch II wind project will be a~~ 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a ~~25-year~~ power purchase ~~agreement.~~agreement expiring in November 2044.
CAPP	Customer Appliance Protection Plan, which provides appliance repair services to residential natural gas customers through on-going monthly service agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.
CARES Act	Coronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which is a tax and spending package intended to provide additional economic relief and address the impact of the COVID-19 pandemic.
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as Black Hills ~~Energy and providing electric service)~~Energy). Also known as Wyoming Electric.
Choice Gas Program	~~The~~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 ~~natural gas~~commodity service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution and Wyoming Gas distribute the gas and Black Hills Energy Services, Wyoming Gas and Black Hills Gas Distribution are Choice Gas suppliers.
~~CIAC~~	~~Contribution In Aid of Construction~~delivery service.
City of Gillette	Gillette, Wyoming
~~Chief operating decision maker (CODM)~~	~~Chief Executive Officer~~
Colorado Electric	Black Hills Colorado Electric, LLC, ~~an indirect,~~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).

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~~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 ~~temperature~~temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth ~~of weather~~ and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
~~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.
COVID-19	The official name for the 2019 novel coronavirus disease, which was 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
CVA	Credit Valuation Adjustment
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act

~~Table of Contents~~



Dth	Dekatherm. A unit of energy equal to 10 therms or 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	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.
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	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatts
MWh	Megawatt-hours
Nebraska Gas	Black Hills Nebraska Gas, ~~Utility Company,~~ LLC, ~~a direct,~~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	Nebraska Public Service Commission
OCI	Other Comprehensive Income
PPA	Power Purchase Agreement
Pueblo Airport Generation	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 operates this facility. The plants commenced operation on January 1, 2012.
Renewable Ready	Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers. The Corriedale wind project will provide 52.5 MW of energy for Renewable Ready subscribers in Wyoming and western South Dakota.

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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~~RMNG	~~Remarketable junior subordinated notes, issued on November 23, 2015~~Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and ~~retired on August 17, 2018.~~wholesale services in western Colorado (doing business as Black Hills Energy).
SDPUC	South Dakota Public Utilities Commission
SEC	~~U. S.~~United States Securities and Exchange Commission
~~SourceGas~~Service Guard	~~SourceGas Holdings LLC~~Home appliance repair product offering for both natural gas and ~~its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners~~electric residential customers through on-going monthly service agreements. The consolidation of the existing Service Guard and ~~GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and~~CAPP plans into the revamped Service Guard Comfort Plan is ~~now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)~~currently underway across our service territories.
~~SourceGas Acquisition~~Service Guard Comfort Plan	~~The acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings~~New plan that will consolidate Service Guard and CAPP and provide similar services.
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~~
~~SSIR~~	~~System Safety and Integrity Rider~~
~~TCJA~~	~~Tax Cuts and Jobs Act enacted on December 22, 2017~~(doing business as Black Hills Energy).
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.
TCJA	Tax Cuts and Jobs Act
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 ~~Corp.,~~Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by ~~Pacificorp~~PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	~~Includes~~ Cheyenne ~~Light’s~~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).

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(in thousands, except per share amounts)												(in thousands, except per share amounts)

Revenue	$	333,888		$	355,704		$	931,698		$	931,093		$	537,050		$	597,810

Operating expenses:
Fuel, purchased power and cost of natural gas sold	89,826			104,661			338,605			352,300			187,879			249,742
Operations and maintenance	124,931			118,282			248,844			234,378			125,466			123,584
Depreciation, depletion and amortization	51,595			48,709			102,623			97,299			56,402			51,028
Taxes - property and production	13,142			13,976			26,661			27,276			14,118			13,325
Other operating expenses	393			525			833			2,015
Total operating expenses	279,887			286,153			717,566			713,268			383,865			437,679

Operating income	54,001			69,551			214,132			217,825			153,185			160,131

Other income (expense):
Interest charges -
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(36,058		)	(35,365		)	(72,032		)	(70,803		)	(35,781		)	(35,016		)
Allowance for funds used during construction - borrowed	1,397			511			2,355			644
Interest income	396			320			695			630			328			299
Allowance for funds used during construction - equity	127			242			175			310
Impairment of investment													(6,859		)	—
Other income (expense), net	137			(1,551		)	(700		)	(1,723		)	2,353			(789		)
Total other income (expense)	(34,001		)	(35,843		)	(69,507		)	(70,942		)	(39,959		)	(35,506		)

Income before income taxes	20,000			33,708			144,625			146,883			113,226			124,625
Income tax benefit (expense)	(2,307		)	(6,541		)	(19,570		)	19,261
Income from continuing operations	17,693			27,167			125,055			166,144
Net (loss) from discontinued operations	—			(2,427		)	—			(4,770		)
Income tax (expense)													(16,002		)	(17,263		)
Net income	17,693			24,740			125,055			161,374			97,224			107,362
Net income attributable to noncontrolling interest	(3,110		)	(2,823		)	(6,664		)	(6,453		)	(4,050		)	(3,554		)
Net income available for common stock	$	14,583		$	21,917		$	118,391		$	154,921		$	93,174		$	103,808

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

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

Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations	$	0.24		$	0.45		$	1.96		$	2.94
(Loss) from discontinued operations	—			(0.05		)	—			(0.09		)
Total earnings per share of common stock, Diluted	$	0.24		$	0.40		$	1.96		$	2.85
Earnings per share of common stock:
Earnings per share, Basic													$	1.51		$	1.73
Earnings per share, Diluted													$	1.51		$	1.73

Weighted average common shares outstanding:
Basic	60,467			53,355			60,195			53,337			61,778			59,920
Diluted	60,606			54,520			60,333			54,361			61,856			60,060

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(in thousands)												(in thousands)

Net income	$	17,693		$	24,740		$	125,055		$	161,374		$	97,224		$	107,362

Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $5, $9, $10 and $19, respectively)	(15		)	(35		)	(29		)	(70		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(52), $(135), $(105), and $(271), respectively)	169			487			336			973
Benefit plan liability adjustments - net gain (net of tax of $(17) and $0, respectively													55			—
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $7 and $5, respectively)													(23		)	(14		)
Reclassification adjustments of benefit plan liability - net gain (net of tax of $(95) and $(53), respectively)													502			167
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(172), $(152), $(335), and $(304), respectively)	541			561			1,091			1,122
Net unrealized gains (losses) on commodity derivatives (net of tax of $119, $(18), $65 and $51, respectively)	(399		)	30			(219		)	(198		)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $19, $(45), $147 and $(190), respectively)	(64		)	118			(490		)	594
Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(170) and $(163), respectively)													543			550
Net unrealized gains (losses) on commodity derivatives (net of tax of $54 and $(54), respectively)													(175		)	180
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(115) and $128, respectively)													371			(426		)
Other comprehensive income, net of tax	232			1,161			689			2,421			1,273			457

Comprehensive income	17,925			25,901			125,744			163,795			98,497			107,819
Less: comprehensive income attributable to noncontrolling interest	(3,110		)	(2,823		)	(6,664		)	(6,453		)	(4,050		)	(3,554		)
Comprehensive income available for common stock	$	14,815		$	23,078		$	119,080		$	157,342		$	94,447		$	104,265

See Note 1113 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, 2019 December 31, 2018
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 6,642
$ 20,776
Restricted cash 3,602
3,369
Accounts receivable, net 166,513
269,153
Materials, supplies and fuel 102,830
117,299
Derivative assets, current 405
1,500
Income tax receivable, net 13,547
12,978
Regulatory assets, current 48,925
48,776
Other current assets 27,209
29,982
Total current assets 369,673
503,833

Investments 41,271
41,013

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

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

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

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

~~Table of Contents~~

~~BLACK HILLS CORPORATION~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~(Continued)~~

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

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

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

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

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

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

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

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BLACK HILLS CORPORATION

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

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

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

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



(unaudited)	As of
	March 31, 2020			December 31, 2019
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	54,137		$	9,777
Restricted cash and equivalents	4,027			3,881
Accounts receivable, net	238,903			255,805
Materials, supplies and fuel	92,894			117,172
Derivative assets, current	1,780			342
Income tax receivable, net	22,319			16,446
Regulatory assets, current	49,415			43,282
Other current assets	26,198			26,479
Total current assets	489,673			473,184

Investments	15,250			21,929

Property, plant and equipment	6,808,261			6,784,679
Less: accumulated depreciation and depletion	(1,223,979		)	(1,281,493		)
Total property, plant and equipment, net	5,584,282			5,503,186

Other assets:
Goodwill	1,299,454			1,299,454
Intangible assets, net	13,083			13,266
Regulatory assets, non-current	222,814			228,062
Other assets, non-current	24,258			19,376
Total other assets, non-current	1,559,609			1,560,158

TOTAL ASSETS	$	7,648,814		$	7,558,457

~~See Note~~ 14 ~~for supplemental disclosure of cash flow information.~~

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)



(unaudited)	As of
	March 31, 2020			December 31, 2019
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	136,344		$	193,523
Accrued liabilities	203,445			226,767
Derivative liabilities, current	852			2,254
Regulatory liabilities, current	54,345			33,507
Notes payable	319,125			349,500
Current maturities of long-term debt	5,743			5,743
Total current liabilities	719,854			811,294

Long-term debt, net of current maturities	3,136,887			3,140,096

Deferred credits and other liabilities:
Deferred income tax liabilities, net	387,939			360,719
Regulatory liabilities, non-current	504,149			503,145
Benefit plan liabilities	152,693			154,472
Other deferred credits and other liabilities	122,869			124,662
Total deferred credits and other liabilities	1,167,650			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 62,772,978 and 61,480,658 shares, respectively	62,773			61,481
Additional paid-in capital	1,652,861			1,552,788
Retained earnings	838,841			778,776
Treasury stock, at cost – 24,656 and 3,956 shares, respectively	(1,925		)	(267		)
Accumulated other comprehensive income (loss)	(29,382		)	(30,655		)
Total stockholders’ equity	2,523,168			2,362,123
Noncontrolling interest	101,255			101,946
Total equity	2,624,423			2,464,069

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,648,814		$	7,558,457

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



(unaudited)	Three Months Ended March 31,
	2020			2019
Operating activities:	(in thousands)
Net income	$	97,224		$	107,362
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	56,402			51,028
Deferred financing cost amortization	2,237			2,007
Impairment of investment	6,859			—
Stock compensation	291			3,296
Deferred income taxes	21,876			19,602
Employee benefit plans	1,235			3,137
Other adjustments, net	892			4,428
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	19,222			29,387
Accounts receivable and other current assets	8,171			(15,857		)
Accounts payable and other current liabilities	(43,297		)	(41,689		)
Regulatory assets - current	20,679			13,031
Regulatory liabilities - current	1,316			(1,635		)
Other operating activities, net	(1,138		)	1,796
Net cash provided by operating activities	191,969			175,893

Investing activities:
Property, plant and equipment additions	(171,882		)	(144,126		)
Other investing activities	(1,202		)	(901		)
Net cash (used in) investing activities	(173,084		)	(145,027		)

Financing activities:
Dividends paid on common stock	(32,902		)	(30,332		)
Common stock issued	99,321			19,949
Net (payments) borrowings of short-term debt	(30,375		)	(20,970		)
Long-term debt - repayments	(4,291		)	(1,436		)
Distributions to noncontrolling interest	(4,741		)	(4,846		)
Other financing activities	(1,391		)	(1,657		)
Net cash provided by (used in) financing activities	25,621			(39,292		)

Net change in cash, restricted cash and cash equivalents	44,506			(8,426		)

Cash, restricted cash and cash equivalents at beginning of period	13,658			24,145
Cash, restricted cash and cash equivalents at end of period	$	58,164		$	15,719

Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)	$	(21,776	)	$	(30,672	)
Income taxes	—			8
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at March 31	53,011			56,571

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

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BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY


(unaudited)	Common Stock			Treasury Stock																				Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares		Value			Additional Paid in Capital			Retained Earnings			AOCI			Non controlling Interest			Total			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
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	—	—		—		—			—			103,808			—			3,554			107,362			—	—		—	—			—			93,174			—			4,050			97,224
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			457			—			457
Dividends on common stock ($0.505 per share)	—	—		—		—			—			(30,332		)	—			—			(30,332		)
Other comprehensive income, net of tax																								—	—		—	—			—			—			1,273			—			1,273
Dividends on common stock ($0.535 per share)																								—	—		—	—			—			(32,902		)	—			—			(32,902		)
Share-based compensation	48,956	49		(20,497	)	1,078			(589		)	—			—			—			538			69,378	69		20,700	(1,658		)	2,263			—			—			—			674
Issuance of common stock	280,497	280		—		—			19,719			—			—			—			19,999			1,222,942	1,223		—	—			98,777			—			—			—			100,000
Issuance costs	—	—		—		—			(289		)	—			—			—			(289		)	—	—		—	—			(967		)	—			—			—			(967		)
Implementation of ASU 2016-02 Leases	—	—		—		—			—			3,390			—			—			3,390
Implementation of ASU 2016-13 Financial Instruments -- Credit Losses																								—	—		—	—			—			(207		)	—			—			(207		)
Distributions to noncontrolling interest	—	—		—		—			—			—			—			(4,846		)	(4,846		)	—	—		—	—			—			—			—			(4,741		)	(4,741		)
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
March 31, 2020																								62,772,978	$	62,773	24,656	$	(1,925	)	$	1,652,861		$	838,841		$	(29,382	)	$	101,255		$	2,624,423

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



	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares		Value			Additional Paid in Capital			Retained Earnings			AOCI			Non controlling Interest			Total
December 31, 2018	60,048,567	$	60,049	44,253		$	(2,510	)	$	1,450,569		$	700,396		$	(26,916	)	$	105,835		$	2,287,423
Net income (loss) available for common stock	—	—		—		—			—			103,808			—			3,554			107,362
Other comprehensive income, 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

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BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s ~~2018~~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 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 for more information on discontinued operations.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the ~~June 30, 2019~~ ~~and~~March 31, 2020, December 31, ~~2018~~2019 and March 31, 2019 financial ~~information and are of a normal recurring nature.~~information. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and March 31, 2019, ~~and~~ ~~June 30, 2018~~, and our financial condition as of ~~June 30, 2019~~March 31, 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 Consolidated Statements of Income for the three months ended March 31, 2019. Amounts previously reported as Operations and maintenance, Taxes - property and production, and Other operating expenses of ($0.3) million, ($0.3) million, and ($0.4) million, respectively, have been reclassified to Fuel, purchased power and cost of natural gas sold to conform with current year presentation. The prior year reclassifications did not impact previously reported operating income or net income.

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 the electric and natural gas utilities as “critical” in providing essential services during this emergency. As a provider of critical 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 months ended March 31, 2020, there were no material adverse impacts on the Company’s results of operations.

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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 continue to 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 ASU 2018-19, ASU 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 is not expected to have ~~any~~an impact on our financial position, results of operations or cash flows.

~~Table of Contents~~

~~Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments,~~Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU ~~2018-19~~2018-15

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 on expected losses rather than~~a service contract with the requirements for capitalizing implementation costs incurred ~~losses. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We~~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 ~~currently assessing~~now capitalized as prepayments and amortized over the ~~impacts~~term of ~~adopting this standard.~~

~~Recently Adopted Accounting Standards~~

~~Leases, ASU 2016-02~~

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

arrangement. We adopted ~~the~~this standard ~~effective~~prospectively on 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.

2020. Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued rent receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings.

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

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

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(2) ~~REVENUE~~Revenue

~~Revenue Recognition~~

AsOur 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 six~~ months ended ~~June 30, 2019~~March 31, 2020 and ~~2018.~~2019. Sales tax and other similar taxes are excluded from revenues.

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

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

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

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



Three Months Ended March 31, 2020	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	148,640	$	298,247	$	—	$	14,403	$	(7,839	)	$	453,451
Transportation	—		44,108		—		—		(139		)	43,969
Wholesale	5,552		—		25,467		—		(23,612		)	7,407
Market - off-system sales	4,867		138		—		—		(2,639		)	2,366
Transmission/Other	14,857		12,572		—		—		(4,413		)	23,016
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642	)	$	530,209
Other revenues	223		5,708		499		802		(391		)	6,841
Total revenues	$	174,139	$	360,773	$	25,966	$	15,205	$	(39,033	)	$	537,050

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	14,403	$	(7,839	)	$	6,564
Services transferred over time	173,916		355,065		25,467		—		(30,803		)	523,645
Revenue from contracts with customers	$	173,916	$	355,065	$	25,467	$	14,403	$	(38,642	)	$	530,209

~~Table of Contents~~

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

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



Three Months Ended March 31, 2019	Electric Utilities		Gas Utilities			Power Generation		Mining		Inter-company Revenues			Total
Customer Types:
Retail	$	153,463	$	354,275		$	—	$	15,829	$	(8,128	)	$	515,439
Transportation	—		44,517			—		—		(432		)	44,085
Wholesale	8,343		—			24,147		—		(21,891		)	10,599
Market - off-system sales	6,692		217			—		—		(2,224		)	4,685
Transmission/Other	14,175		13,190			—		—		(4,203		)	23,162
Revenue from contracts with customers	$	182,673	$	412,199		$	24,147	$	15,829	$	(36,878	)	$	597,970
Other revenues	254		(1,119		)	1,098		600		(993		)	(160		)
Total Revenues	$	182,927	$	411,080		$	25,245	$	16,429	$	(37,871	)	$	597,810

Timing of Revenue Recognition:
Services transferred at a point in time	$	—	$	—		$	—	$	15,829	$	(8,128	)	$	7,701
Services transferred over time	182,673		412,199			24,147		—		(28,750		)	590,269
Revenue from contracts with customers	$	182,673	$	412,199		$	24,147	$	15,829	$	(36,878	)	$	597,970

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

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

~~(a)~~

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

1415

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Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4.4. We do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.

(3~~) BUSINESS SEGMENT INFORMATION~~(3) Business Segment Information

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

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

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

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

Three Months Ended June 30, 2019 External Operating Revenue Inter-company Operating Revenue Total Revenues
Contract Customers Other Revenues Contract Customers Other Revenues
Segment:
Electric Utilities $ 159,140
$ 1,977

$ 5,237
$ —

$ 166,354
Gas Utilities 163,303
1,443

723
—

165,469
Power Generation ^(a)
1,765
434

13,297
9,212

24,708
Mining 5,538
288

6,890
329

13,045
Inter-company eliminations ^(a)
—
—
(26,147 ) (9,541 ) (35,688 )
Total $ 329,746
$ 4,142
$ —
$ —
$ 333,888

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

~~Table of Contents~~


Six Months Ended June 30, 2019	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Three Months Ended March 31, 2020														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		$	167,503	$	223	$	6,413		$	—		$	174,139
Gas Utilities	574,803		324		1,422			—			576,549			354,287		5,708		778			—			360,773
Power Generation ^(a)	4,022		870		26,509			18,552			49,953			1,855		443		23,612			56			25,966
Mining	13,088		557		15,169			660			29,474			6,564		467		7,839			335			15,205
Inter-company eliminations ^(a)	—		—		(54,347		)	(19,212		)	(73,559		)	—		—		(38,642		)	(391		)	(39,033		)
Total	$	927,716	$	3,982	$	—		$	—		$	931,698		$	530,209	$	6,841	$	—		$	—		$	537,050



Six Months Ended June 30, 2018	External Operating Revenue				Inter-company Operating Revenue						Total Revenues
	Contract Customers		Other Revenues		Contract Customers			Other Revenues
Three Months Ended March 31, 2019														External Operating Revenue					Inter-company Operating Revenue						Total Revenues
														Contract Customers		Other Revenues			Contract Customers			Other Revenues
Segment:
Electric Utilities	$	333,743	$	1,987	$	11,441		$	—		$	347,171		$	176,663	$	254		$	6,010		$	—		$	182,927
Gas Utilities	572,141		2,096		727			—			574,964			411,500		(1,119		)	699			—			411,080
Power Generation ^(a)	2,850		718		25,521			17,593			46,682			2,257		436			21,890			662			25,245
Mining	17,082		476		15,820			649			34,027			7,550		269			8,279			331			16,429
Inter-company eliminations ^(a)	—		—		(53,509		)	(18,242		)	(71,751		)	—		—			(36,878		)	(993		)	(37,871		)
Total	$	925,816	$	5,277	$	—		$	—		$	931,093		$	597,970	$	(160	)	$	—		$	—		$	597,810



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

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	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Adjusted operating income:
Adjusted operating income ^(a):
Electric Utilities ^(a)	$	33,546		$	41,200		$	74,566		$	79,680		$	35,650		$	41,020
Gas Utilities	8,557			16,485			111,871			111,928			102,897			103,314
Power Generation ^(a)	10,156			8,877			22,123			20,652			11,349			11,967
Mining	1,640			3,825			5,977			8,096			3,129			4,337
Corporate and Other ^(a)	102			(836		)	(405		)	(2,531		)	160			(507		)
Operating income	54,001			69,551			214,132			217,825			153,185			160,131

Interest expense, net	(34,265		)	(34,534		)	(68,982		)	(69,529		)	(35,453		)	(34,717		)
Impairment of investment													(6,859		)	—
Other income (expense), net	264			(1,309		)	(525		)	(1,413		)	2,353			(789		)
Income tax benefit (expense) ^(b)	(2,307		)	(6,541		)	(19,570		)	19,261
Income from continuing operations	17,693			27,167			125,055			166,144
Net (loss) from discontinued operations	—			(2,427		)	—			(4,770		)
Income tax (expense)													(16,002		)	(17,263		)
Net income	17,693			24,740			125,055			161,374			97,224			107,362
Net income attributable to noncontrolling interest	(3,110		)	(2,823		)	(6,664		)	(6,453		)	(4,050		)	(3,554		)
Net income available for common stock	$	14,583		$	21,917		$	118,391		$	154,921		$	93,174		$	103,808

~~___________~~__________


(a)	~~Due to the changes in our segment disclosures,~~ Adjusted operating income ~~was revised~~recognizes intersegment revenues and costs for ~~the three and six months ended June 30, 2018, which resulted in~~Colorado Electric’s PPA with Black Hills Colorado IPP on an ~~increase (decrease)~~accrual basis rather than as ~~follows (in millions):~~

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


~~(b)~~	~~Income tax benefit (expense) for the six months ended June 30, 2018 included~~ a ~~$49 million tax benefit resulting fromlegal entity restructuring. See Note 18 for more information.~~ finance lease. This presentation of segment information does not impact consolidated financial results.

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


Total assets (net of inter-company eliminations) as of:	June 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Segment:
Electric Utilities ^(a)	$	2,777,803	$	2,707,695	$	2,931,902	$	2,900,983
Gas Utilities	3,645,840		3,623,475		4,043,539		4,032,339
Power Generation ^(a)	379,140		342,085		412,572		417,715
Mining	62,491		80,594		80,289		77,175
Corporate and Other	216,179		209,478		180,512		130,245
Total assets	$	7,081,453	$	6,963,327	$	7,648,814	$	7,558,457

~~___________~~


~~(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

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



	March 31, 2020			December 31, 2019
Accounts receivable, trade	$	162,138		$	144,747
Unbilled revenue	81,927			113,502
Less: Allowance for credit losses	(5,162		)	(2,444		)
Accounts receivable, net	$	238,903		$	255,805

Accounts Unbilled Less Allowance for Accounts
June 30, 2019 Receivable, Trade Revenue Doubtful Accounts Receivable, net
Electric Utilities $ 39,982
$ 31,573
$ (526 ) $ 71,029
Gas Utilities 67,686
23,753
(4,391 ) 87,048
Power Generation 2,867
—
—
2,867
Mining 2,505
—
—
2,505
Corporate 3,233
—
(169 ) 3,064
Total $ 116,273
$ 55,326
$ (5,086 ) $ 166,513

The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 9. The Company did not experience material credit losses or customer defaults during the three months ended March 31, 2020.

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

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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:



	March 31, 2020		December 31, 2019
Materials and supplies	$	88,346	$	82,809
Fuel - Electric Utilities	3,049		2,425
Natural gas in storage	1,499		31,938
Total materials, supplies and fuel	$	92,894	$	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:



	March 31, 2020		December 31, 2019
Accrued employee compensation, benefits and withholdings	$	45,070	$	62,837
Accrued property taxes	45,666		44,547
Customer deposits and prepayments	43,524		54,728
Accrued interest	43,776		31,868
Other (none of which is individually significant)	25,409		32,787
Total accrued liabilities	$	203,445	$	226,767

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(5) ~~REGULATORY ACCOUNTING~~Regulatory Matters

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


	June 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	34,257		$	29,661		$	35,687		$	34,088
Deferred gas cost adjustments ^(a)	2,342			3,362			—			1,540
Gas price derivatives ^(a)	3,945			6,201			1,302			3,328
Deferred taxes on AFUDC^(b)	7,716			7,841			7,739			7,790
Employee benefit plans ^(c)	109,899			110,524			117,150			115,900
Environmental^(a)	931			959			1,439			1,454
Loss on reacquired debt^(a)	20,140			21,001			24,299			24,777
Renewable energy standard adjustment ^(a)	1,994			1,722			340			1,622
Deferred taxes on flow through accounting^(c)	36,552			31,044			44,589			41,220
Decommissioning costs ^(b)	11,518			11,700			10,248			10,670
Gas supply contract termination ^(a)	11,413			14,310			7,007			8,485
Other regulatory assets^(a)	42,342			45,910			22,429			20,470
Total regulatory assets	283,049			284,235			272,229			271,344
Less current regulatory assets	(48,925		)	(48,776		)	(49,415		)	(43,282		)
Regulatory assets, non-current	$	234,124		$	235,459		$	222,814		$	228,062

Regulatory liabilities
Deferred energy and gas costs^(a)	$	16,808		$	6,991		$	40,002		$	17,278
Employee benefit plan costs and related deferred taxes^(c)	41,814			42,533			41,518			43,349
Cost of removal^(a)	158,477			150,123			170,954			166,727
Excess deferred income taxes ^(c)	307,871			310,562			283,690			285,438
TCJA revenue reserve	11,436			18,032			5,147			3,418
Other regulatory liabilities^(c)	18,150			12,553			17,183			20,442
Total regulatory liabilities	554,556			540,794			558,494			536,652
Less current regulatory liabilities	(39,642		)	(29,810		)	(54,345		)	(33,507		)
Regulatory liabilities, non-current	$	514,914		$	510,984		$	504,149		$	503,145

__________


(a)	~~We are allowed recovery~~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.

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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.

~~Regulatory Activity~~Black Hills Wyoming and Wyoming Electric

~~Renewable Ready Service Tariffs and Corriedale Wind Energy Project~~Wygen 1 FERC Filing

~~South Dakota~~Black Hills Wyoming has a PPA with Wyoming Electric expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On August 2, 2019, Black Hills Wyoming and Wyoming Electric ~~received approvals~~jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill Wyoming Electric’s capacity need at the ~~Renewable Ready Service Tariffs and related jointly-filed CPCN to construct~~expiration of the ~~$57 million, 40 MW Corriedale Wind Energy Project. The wind project~~current agreement on December 31, 2022. If approved, Black Hills Wyoming will ~~be jointly owned by the two electric utilities~~continue to deliver ~~renewable~~60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for ~~large commercial and industrial customers and governmental agencies. The project is expected~~an additional 20 years to December 31, 2042. On February 21, 2020, the FERC set this filing for hearing. However, the hearing has been placed in abeyance pending a FERC monitored settlement process. Settlement negotiations are ongoing among all parties. Any settlement would require FERC approval. To the extent the parties are unable to reach agreement, the next step in FERC’s process would be ~~in service in 2020.~~to set the matter for hearing. We will continue to evaluate our options to fulfill Wyoming Electric’s 60 MW capacity need.

~~Table of Contents~~

~~Kansas~~

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

~~Wyoming~~Colorado Gas

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

~~Blockchain Interruptible Service Tariff~~

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

~~Nebraska~~

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

~~Colorado~~Rate Review

On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its ~~two~~2 existing gas distribution ~~territories in Colorado.~~territories. The rate review ~~requests~~requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also ~~requesting~~requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and rider mechanism and also recommended a rate decrease. On April 14, 2020, the CPUC deliberated on the ALJ’s recommended decision and filed exceptions to that decision. The CPUC essentially accepted the ALJ’s recommended decisions, except for return on equity, which they lowered from 9.5% to 9.2%. A final order and new rates are anticipated to be effective in the second quarter of 2020.

((6) 6) ~~MATERIALS, SUPPLIES AND FUEL~~Earnings Per Share

~~The following~~A reconciliation of share amounts ~~by major classification are included in Materials, supplies and fuel~~used to compute earnings per share in the accompanying Condensed Consolidated ~~Balance Sheets~~Statements of Income was as follows (in thousands) ~~as of:~~:

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



	Three Months Ended March 31,
	2020		2019

Net income available for common stock	$	93,174	$	103,808

Weighted average shares - basic	61,778		59,920
Dilutive effect of:
Equity compensation	78		140
Weighted average shares - diluted	61,856		60,060

Earnings per share of common stock:
Earnings per share, Basic	$	1.51	$	1.73
Earnings per share, Diluted	$	1.51	$	1.73

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(7) ~~EARNINGS PER SHARE~~

~~A reconciliation of share amounts used to compute Earnings (loss)~~The following securities were excluded from the diluted earnings per share ~~in the accompanying Condensed Consolidated Statements~~computation because of ~~Income was as follows~~their anti-dilutive nature (in thousands):

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

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

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

~~__________~~


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

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


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended March 31,
	2019	2018	2019	2018	2020	2019

Equity compensation	—	15	—	17	12	6
Restricted stock					26	—
Anti-dilutive shares	—	15	—	17	38	6

~~Table of Contents~~

((7) 8) ~~NOTES PAYABLE, CURRENT MATURITIES AND DEBT~~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, 2019				December 31, 2018				March 31, 2020				December 31, 2019
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit ^(a)		Balance Outstanding		Letters of Credit ^(a)
Revolving Credit Facility	$	—	$	10,429	$	—	$	22,311	$	165,000	$	17,281	$	—	$	30,274
CP Program	102,500		—		185,620		—		154,125		—		349,500		—
Total	$	102,500	$	10,429	$	185,620	$	22,311	$	319,125	$	17,281	$	349,500	$	30,274

_______________

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

Facility.

~~Our~~For the three months ended March 31, 2020, we utilized a combination of our $750 million corporate Revolving Credit Facility extends through July 30, 2023 with two, one year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at June 30, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at June 30, 2019.

~~We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the~~ Revolving Credit Facility and ~~the~~ CP Program ~~either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not~~ to ~~exceed 397 days from the date of issuance~~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 ~~payments under the CP Program~~short-term borrowings (payments) during the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 were ~~$83~~$(30) million. ~~At June 30, 2019, the~~The weighted average interest rate on Revolving Credit Facility and CP Program borrowings at March 31, 2020 was ~~2.60%.~~1.92% and 1.74%, respectively.

Debt Covenants

Under our Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) ~~Consolidated Indebtedness,~~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 ~~June 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 March 31, 2020:



	As of March 31, 2020	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	58.2%	Less than	65%

~~Long-Term~~

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

2221

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~~(9) EQUITY~~(8) Equity

~~At-the-Market~~February 2020 Equity ~~Offering Program~~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 issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the SEC.

ATM Activity

Our ATM ~~equity offering program~~ allows us to sell shares of our common stock with an aggregate value of up to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the three months ended March 31, 2020 under the ATM. During the three months ended ~~June 30,~~March 31, 2019, we issued a total of ~~658,598~~0.3 million shares of common stock under the ATM ~~equity offering program~~ for proceeds of ~~$49~~$20 million, net of ~~$0.5~~$0.2 million in commissions. During the six months ended June 30, 2019, we issued a total of 939,095 shares of common stock under the ATM equity offering program for proceeds of $69 million, net of $0.7 million in commissions. As of June 30, 2019, there were no shares that were sold, but not settled.issuance costs.

(10~~) RISK MANAGEMENT ACTIVITIES~~(9) Risk Management and Derivatives

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 and wholesale electric power marketing activities, ~~and~~as well as 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; and

Interest rate risk associated with our variable debt.

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 guarantees, prepayments, letters of credit, and other security agreements.

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

Although we did not experience material credit losses or customer defaults for the three months ended March 31, 2020, we are monitoring 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 future financial impacts to the allowance for credit losses.

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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 1011.

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.

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.

~~Table of Contents~~

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 ~~July 2019~~April 2020 through May ~~2021; a~~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.

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:

June 30, 2019 December 31, 2018

Notional
(MMBtus)

Maximum
Term
(months)^(a)

Notional
(MMBtus)

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



		March 31, 2020		December 31, 2019
	Units	Notional Amounts	Maximum Term (months)^(a)	Notional Amounts	Maximum Term (months)^(a)
Natural gas futures purchased	MMBtus	920,000	9	1,450,000	12
Natural gas options purchased, net	MMBtus	—	0	3,240,000	3
Natural gas basis swaps purchased	MMBtus	790,000	9	1,290,000	12
Natural gas over-the-counter swaps, net ^(b)	MMBtus	4,620,000	26	4,600,000	24
Natural gas physical contracts, net ^(c)	MMBtus	1,104,725	12	13,548,235	12
Electric wholesale contracts ^(c)	MWh	195,825	9	—	0

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of ~~June 30, 2019, 2,130,000~~March 31, 2020, 800,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.


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

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

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At ~~June 30, 2019,~~March 31, 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~~

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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.

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



	Balance Sheet Location	March 31, 2020			December 31, 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	8		$	1
Noncurrent commodity derivatives	Other assets, non-current	—			3
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(284		)	(490		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(10		)	(29		)
Total derivatives designated as hedges		$	(286	)	$	(515	)

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	1,772		$	341
Noncurrent commodity derivatives	Other assets, non-current	156			2
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	(568		)	(1,764		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(28		)	(63		)
Total derivatives not designated as hedges		$	1,332		$	(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 six~~ months ended ~~June 30, 2019~~March 31, 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 March 31,						Three Months Ended March 31,
	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	257		(320		)	Fuel, purchased power and cost of natural gas sold	(486		)	554
Total	$	970	$	393			$	(1,199	)	$	(159	)

Based on March 31, 2020 prices, a $0.3 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.

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Derivatives Not Designated as 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 months ended March 31, 2020 and 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, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $ (713 )
Commodity derivatives Fuel, purchased power and cost of natural gas sold 83
Total $ (630 )



		Three Months Ended March 31,
		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	$	1,362	$	—
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold	766		25
		$	2,128	$	25

~~Table of Contents~~

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

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $ (713 )
Commodity derivatives Fuel, purchased power and cost of natural gas sold (163 )
Total $ (876 )

Six Months Ended June 30, 2019
(in thousands)
Derivatives in Cash Flow Hedging Relationships
Location of
Reclassifications from AOCI into Income

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $ (1,426 )
Commodity derivatives Fuel, purchased power and cost of natural gas sold 637
Total $ (789 )

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

Amount of
Gain/(Loss) Reclassified
from AOCI
into Income
Interest rate swaps Interest expense $ (1,426 )
Commodity derivatives Fuel, purchased power and cost of natural gas sold (784 )
Total $ (2,210 )

The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and six months ended June 30, 2019 and 2018.

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

~~Table of Contents~~

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

~~Derivatives Not Designated as Hedge Instruments~~

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

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

Commodity derivatives Fuel, purchased power and cost of natural gas sold $ (1,185 ) $ 771
$ (1,185 ) $ 771

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

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

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. ~~However, there~~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 ~~$3.9~~$1.3 million and ~~$6.2~~$3.3 million ~~for June 30, 2019~~as of March 31, 2020 and December 31, ~~2018,~~2019, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income.

(10) Fair Value Measurements

~~Table~~We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of ~~Contents~~

the following fair value categories:

(Level 111~~) FAIR VALUE MEASUREMENTS~~ — 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.

~~Derivative Financial Instruments~~

~~The accounting guidance~~Level 2 — Pricing inputs include quoted prices for ~~fair value measurements requires certain disclosures about~~identical or similar assets and liabilities ~~measured at~~in 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.

Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair ~~value. This guidance establishes~~value using its own assumptions about the assumptions a ~~hierarchical framework for disclosing~~market participant would use in pricing the ~~observability of the inputs utilized in measuring assets and liabilities at fair value.~~ asset or liability.

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~~

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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 ~~component~~ based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

~~Recurring Fair Value Measurements~~ For additional information, see Note 1 to the Consolidated Financial Statements included in our 2019 Annual Report on Form 10-K filed with the SEC.

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

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

~~Table of Contents~~


	As of December 31, 2018											As of March 31, 2020
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total		Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)											(in thousands)
Assets:
Commodity derivatives — Utilities	$	—	$	2,927	$	—	$	(1,408	)	$	1,519
Commodity derivatives — Gas Utilities												$	—	$	1,949	$	—	$	(13	)	$	1,936
Commodity derivatives — Electric Utilities												—		1,362		—		—			1,362
Total	$	—	$	2,927	$	—	$	(1,408	)	$	1,519	$	—	$	3,311	$	—	$	(13	)	$	3,298

Liabilities:
Commodity derivatives — Utilities	$	—	$	6,801	$	—	$	(5,794	)	$	1,007
Commodity derivatives — Gas Utilities												$	—	$	2,464	$	—	$	(1,573	)	$	891
Total	$	—	$	6,801	$	—	$	(5,794	)	$	1,007	$	—	$	2,464	$	—	$	(1,573	)	$	891



	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

~~Fair Value Measures by Balance Sheet Classification~~Pension and Postretirement Plan Assets

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

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

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

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

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our ~~2018~~2019 Annual Report on Form 10-K. The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our pension plan assets or defined benefit obligations. See Note 12 for additional information.

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.

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

Other fair value measures

~~Other~~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:

June 30, 2019 December 31, 2018

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



	March 31, 2020				December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities ^(a)	$	3,142,630	$	3,320,562	$	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 inas Level 2 in the fair value hierarchy.


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


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

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

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


	Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI												Location on the Condensed Consolidated Statements of Income	Amount Reclassified from AOCI
		Three Months Ended						Six Months Ended							Three Months Ended March 31,
		June 30, 2019			June 30, 2018			June 30, 2019			June 30, 2018				2020			2019
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(713	)	$	(1,426	)	$	(1,426	)	Interest expense	$	(713	)	$	(713	)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	83			(163		)	637			(784		)	Fuel, purchased power and cost of natural gas sold	(486		)	554
		(630		)	(876		)	(789		)	(2,210		)		(1,199		)	(159		)
Income tax	Income tax benefit (expense)	153			197			188			494			Income tax benefit (expense)	285			35
Total reclassification adjustments related to cash flow hedges, net of tax		$	(477	)	$	(679	)	$	(601	)	$	(1,716	)		$	(914	)	$	(124	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	20		$	44		$	39		$	89		Operations and maintenance	$	30		$	19

Actuarial gain (loss)	Operations and maintenance	(221		)	(622		)	(441		)	(1,244		)	Operations and maintenance	(597		)	(220		)
		(201		)	(578		)	(402		)	(1,155		)		(567		)	(201		)
Income tax	Income tax benefit (expense)	47			126			95			252			Income tax benefit (expense)	88			48
Total reclassification adjustments related to defined benefit plans, net of tax		$	(154	)	$	(452	)	$	(307	)	$	(903	)		$	(479	)	$	(153	)
Total reclassifications		$	(631	)	$	(1,131	)	$	(908	)	$	(2,619	)		$	(1,393	)	$	(277	)

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


													Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2019													$	(15,122	)	$	(456	)	$	(15,077	)	$	(30,655	)
Other comprehensive income (loss)
before reclassifications													—			(175		)	55			(120		)
Amounts reclassified from AOCI													543			371			479			1,393
As of March 31, 2020													$	(14,579	)	$	(260	)	$	(14,543	)	$	(29,382	)


	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total			Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2018	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)
Other comprehensive income (loss)
before reclassifications	—			(219		)	—			(219		)	—			180			—			180
Amounts reclassified from AOCI	1,091			(490		)	307			908			550			(426		)	153			277
As of June 30, 2019	$	(16,216	)	$	(381	)	$	(9,630	)	$	(26,227	)


	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
Balance as of December 31, 2017	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)
Other comprehensive income (loss)
before reclassifications	—			(198		)	—			(198		)
Amounts reclassified from AOCI	1,122			594			903			2,619
Reclassifications of certain tax effects from AOCI	15			—			3			18
As of June 30, 2018	$	(18,444	)	$	(122	)	$	(20,197	)	$	(38,763	)
As of March 31, 2019													$	(16,757	)	$	82		$	(9,784	)	$	(26,459	)

(14~~) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION~~(12) Employee Benefit Plans

Change in Accounting Principle - Pension Accounting Asset Method

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 continue to 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 three months ended March 31, 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 March 31, 2020, we estimate the unfunded status of our employee benefit plans to be approximately $46 million compared to $51 million at December 31, 2019. The Company has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our pension plan assets or defined benefit obligations.

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

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

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(15~~) EMPLOYEE BENEFIT PLANS~~

Defined Benefit Pension Plan

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Service cost	$	1,345		$	1,709		$	2,691		$	3,417		$	1,353		$	1,346
Interest cost	4,344			3,868			8,687			7,735			3,357			4,343
Expected return on plan assets	(6,100		)	(6,185		)	(12,200		)	(12,370		)	(5,648		)	(6,100		)
Prior service cost	7			14			13			29
Prior service cost (benefit)													—			6
Net loss (gain)	940			2,157			1,881			4,315			2,093			941
Net periodic benefit cost	$	536		$	1,563		$	1,072		$	3,126		$	1,155		$	536

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,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Service cost	$	454		$	572		$	908		$	1,145		$	514		$	454
Interest cost	563			521			1,123			1,042			412			560
Expected return on plan assets	(58		)	(56		)	(115		)	(113		)	(45		)	(57		)
Prior service cost (benefit)	(100		)	(99		)	(199		)	(198		)	(137		)	(99		)
Net loss (gain)	—			54			—			108			5			—
Net periodic benefit cost	$	859		$	992		$	1,717		$	1,984		$	749		$	858

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,				Three Months Ended March 31,
	2019		2018		2019		2018		2020			2019
Service cost	$	692	$	435	$	1,977	$	715	$	(1,370	)	$	1,285
Interest cost	324		292		648		585		275			324
Prior service cost	1		1		1		1
Net loss (gain)	134		250		268		500		426			134
Net periodic benefit cost	$	1,151	$	978	$	2,894	$	1,801	$	(669	)	$	1,743

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Contributions

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


	Contributions Made				Additional Contributions		Contributions		Contributions Made		Additional Contributions		Contributions
	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019		Anticipated for 2019		Anticipated for 2020		Three Months Ended March 31, 2020		Anticipated for 2020		Anticipated for 2021
Defined Benefit Pension Plan	$	—	$	—	$	12,700	$	12,700	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,108	$	2,217	$	2,217	$	4,271	$	1,335	$	4,006	$	5,364
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	366	$	732	$	732	$	1,562	$	355	$	1,065	$	1,614

(16~~) COMMITMENTS AND CONTINGENCIES~~(13) Commitments and Contingencies

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our ~~2018~~2019 Annual Report on Form 10-K except for those described below.

~~Platte River Power Authority PPAs~~Future Purchase Agreement - Black Hills Wyoming and Wyoming Electric

Black Hills Wyoming has a PPA with Wyoming Electric expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. On February 21, 2020, the FERC set this filing for hearing. However, the hearing has been placed in abeyance pending a FERC monitored settlement process. Settlement negotiations are ongoing among all parties. Any settlement would require FERC approval. To the extent the parties are unable to reach agreement, the next step in FERC’s process would be to set the matter for hearing. See Note 5 for additional information.

(14) Income Taxes

CARES Act

On ~~June 26, 2019, Colorado Electric entered into~~March 27, 2020, the President signed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which contained in part, an allowance for deferral of the employer portion of Social Security employment tax liabilities until 2021 and 2022, as well as a ~~PPA with Platte River Power Authority to purchase~~COVID-19 employee retention tax credit of up to ~~60 MW~~$5,000 per eligible employee.

Eligible employers are taxpayers experiencing either: (1) a full or partial suspension of ~~wind energy upon construction completion~~business operations stemming from a government COVID-19-related order or (2) a more than 50% drop in gross receipts compared to the corresponding calendar quarter in 2019. This 50% employee retention tax credit applies to up to $10,000 in qualified wages paid between March 13, 2020 through December 31, 2020, and is refundable to the extent it exceeds the employer portion of payroll tax liability.

Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee did not provide services. However, employees do not need to stop providing all services to the employer for the credit to potentially apply.

Additionally, the CARES Act accelerates the amount of alternative minimum tax (“AMT”) credits that can be refunded for the 2018 and 2019 annual tax returns.

Based on the timing of the CARES Act, for the three months ended March 31, 2020, the related tax benefits from the CARES Act were not material. We are currently reviewing the potential future benefits related to employee retention tax credits and the payroll tax deferral provision to assess the impact on our financial position, results of operations and cash flows.

Table of Contents

Income tax (expense) for the Three Months Ended March 31, 2020 Compared to the Three Months Ended March 31, 2019.

Income tax benefit (expense) for the three months ended March 31, 2020 was $(16) million compared to $(17) million reported for the same period in 2019. For the three months ended March 31, 2020 the effective tax rate was 14.1% compared to 13.9% for the same period in 2019. The higher effective tax rate is primarily due to a discrete tax adjustment related to the impairment of our investment in equity securities of a privately held oil and gas company partially offset by increased tax benefits from forecasted federal production tax credits associated with new wind ~~project, which is expected in mid-2020. This agreement will expire May 31, 2030.~~assets.

~~On June 26,~~

(15) Investments

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

During the third quarter of 2019, ~~Colorado Electric entered into~~we assessed our investment for impairment as a ~~PPA with Platte River Power Authority~~result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to ~~purchase 25 MW~~estimate the fair value of ~~unit contingent energy. This agreement is effective~~our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three months ended September 1,30, 2019, which was the difference between the carrying amount and ~~will expire June 30, 2024.~~the fair value of the investment at that time.

During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying amount and the fair value of the investment at March 31, 2020.

The following ~~is a schedule~~table presents the carrying value of ~~unconditional purchase obligations required under the 25 MW Platte River Power Authority PPA~~our investments (in thousands): as of:

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



	March 31, 2020		December 31, 2019
Investment in privately held oil and gas company	$	1,500	$	8,359
Cash surrender value of life insurance contracts	13,235		13,056
Other investments	515		514
Total investments	$	15,250	$	21,929

~~(17) DISCONTINUED OPERATIONS~~(16) Subsequent Events

~~Results of operations for discontinued operations were classified as Loss from discontinued operations, net of income taxes~~We evaluated all subsequent event activity and concluded that no subsequent events have occurred that would require recognition in the ~~accompanying Condensed Consolidated Statements of Income. Prior periods relating to our discontinued operations were also reclassified to reflect consistency within our~~ condensed consolidated financial ~~statements.~~statements or disclosures, with the exception of the Note 5 disclosure surrounding Colorado Gas’ jurisdictional consolidation and rate review.

~~Oil~~There are many uncertainties regarding the COVID-19 pandemic, and ~~Gas Segment~~

~~On November 1, 2017,~~ the ~~BHC Board~~Company is closely monitoring the impact of ~~Directors approved a complete divestiture~~the pandemic on all aspects of its business, including how it will impact its customers, employees, suppliers, vendors, and business partners. We are unable to predict the impact that COVID-19 will have on our ~~Oil~~financial position and ~~Gas segment. We completed~~operating results due to numerous uncertainties. The Company expects to continue to assess the ~~divestiture in 2018.~~

evolving impact of COVID-19 and intends to make adjustments to its responses accordingly.

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~~(18) INCOME TAXES~~

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

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

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

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

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

~~(19) ACCRUED LIABILITIES~~

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

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

~~Table of Contents~~

~~(20) LEASES~~

~~Lessee~~

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

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

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

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

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

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

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

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

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

~~Table of Contents~~



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

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

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

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


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


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

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

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

~~Lessor~~

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

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

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

~~Table of Contents~~

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

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


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

~~(21) SUBSEQUENT EVENTS~~

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


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

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

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately ~~212,000~~214,000 customers in Colorado, Montana, South Dakota and Wyoming. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our ~~own~~ distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services through our Tech Services product lines.

Gas Utilities: Our Gas Utilities ~~conduct~~segment conducts natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities ~~distribute~~segment distributes and ~~transport~~transports natural gas through our pipeline network to approximately ~~1,054,000~~1,066,000 natural gas customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-available basis.

~~Our Gas Utilities also provide non-regulated services through Black Hills Energy Services.~~ Black Hills Energy Services provides natural gas supply to approximately ~~47,000~~49,000 retail distribution customers under the Choice Gas Program in Nebraska and ~~Wyoming with unbundled natural gas commodity offerings~~Wyoming. Additionally, we provide services under the regulatory-approved Choice Gas Program. We also sell, install and service air conditioning, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard Comfort Plan and CAPP provide appliance repair services to approximately 62,000 and 28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services ~~serves gas transportation customers throughout our service territory by constructing~~ and ~~maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.~~also offer HomeServe products.

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

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

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

Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our ~~electric utilities~~Electric Utilities is June through August while the normal peak usage season for our ~~gas utilities~~Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 and ~~2018~~2019, and our financial condition as of ~~June 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 5745.

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

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Results of Operations

~~Executive~~COVID-19 Pandemic

One of the Company’s core values is safety. The COVID-19 pandemic has given us an opportunity to demonstrate our commitment to the health and safety of our employees, customers, business partners and the communities we serve. We have executed our business continuity plans across all of our jurisdictions with the goal of continuing to provide safe and reliable service during the COVID-19 pandemic.

For the three months ended March 31, 2020, we did not experience significant impacts to our financial results and operational activities due to COVID-19.

Decline in revenues and customer loads for the three months ended March 31, 2020, when compared to the same period in the prior year, were driven primarily by weather. We continue to closely monitor loads, particularly in states that have implemented more restrictive stay-at-home executive orders or recommendations. We have proactively communicated with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We did not experience a significant increase in bad debt expense for the three months ended March 31, 2020. We have informed both our customers and regulators that disconnections for non-payment will be temporarily suspended. We continue to monitor the impacts of COVID-19 on our cash flows and bad debt expense.

We continue to maintain adequate liquidity to operate our businesses and fund our capital investment program. In February 2020, the Company issued $100 million in equity to support its 2020 capital investment program. For the three months ended March 31, 2020, the Company utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. In recent weeks, the liquidity for A-2/P-2 rated issuers, which is the Company’s current Commercial Paper rating with S&P and Moody’s, respectively, within the Commercial Paper market has improved which provides additional liquidity options under the Revolving Credit Facility. The Company has no material debt maturities until late 2023, and as of March 31, 2020, had $468 million of liquidity which included cash and available capacity on its Revolving Credit Facility. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the first quarter 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts to supply chains including availability of supplies and materials and lead times. Capital projects are ongoing without material disruption to schedules. Our third party resources continue to support our business plans without disruption. Contingency plans are ongoing due to the impacts of COVID-19, including the potential for rescheduling projects. We currently do not anticipate a significant impact on our capital investment plan for 2020.

We continue to work closely with local health, public safety and government officials to minimize the spread of COVID-19 and minimize the impact to our employees and the service we provide to our customers. Some of the actions the Company has taken include implementing protocols for our field operations personnel to continue to safely and effectively interact with our customers, asking employees to work from home to the extent possible, quarantining employees if they had traveled to an at-risk area, limiting travel to only mission critical purposes and sequestering essential employees.

As we look forward, we anticipate that our 2020 operating results could potentially be impacted as a result of COVID-19, including impact related to the following:

Increased residential load and decreased commercial and industrial demand;

Increased allowance for credit losses and bad debt expense as a result of suspending disconnections and delayed or non-payment from customers;

Disruption in our supply chains impacting our ability to timely execute our capital investment and maintenance project plans;

Volatility in cost of sales due to changes in commodity prices;

Rate actions from our regulators;

Decreased training, travel and outside services related expenses;

Increased operation and maintenance costs if we experience a shortage of labor availability which would lead to deferral of capital projects and sequestration costs for employees deemed critical at our generating facilities; and

Increased tax benefits for employee retention tax credits and reduced cash tax payments for the payroll tax deferral provision and acceleration of alternative minimum tax (“AMT”) credit refunds from the CARES Act

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We provide recurring status updates and maintain ongoing dialogue with the regulatory commissions in our jurisdictions. We are working with regulators in each of our service territories to preserve our right for deferred regulatory treatment for certain COVID-19 related costs at a later date.

During these uncertain times, we remain highly focused on the safety and health of our employees, customers, business partners and communities. We continue to monitor load, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of resources to execute our plans and the capital markets to ensure we have the liquidity necessary to support our financial needs.

Consolidated Summary ~~Significant Events~~ and Overview


	Three Months Ended June 30,										Six Months Ended June 30,										Three Months Ended March 31,
	2019				2018						2019				2018						2020				2019
(in millions, except per share amounts)	Income		EPS		Income			EPS			Income		EPS		Income			EPS			Income		EPS		Income		EPS

Net income from continuing operations available for common stock	$	14.6	$	0.24	$	24.3		$	0.45		$	118.4	$	1.96	$	159.7		$	2.94
Net (loss) from discontinued operations	—		—		(2.4		)	(0.05		)	—		—		(4.8		)	(0.09		)
Net income available for common stock	$	14.6	$	0.24	$	21.9		$	0.40		$	118.4	$	1.96	$	154.9		$	2.85		$	93.2	$	1.51	$	103.8	$	1.73

Three Months Ended ~~June 30, 2019~~March 31, 2020 Compared to Three Months Ended ~~June 30, 2018.~~March 31, 2019.

The variance to the prior year included the following:

Electric Utilities’ adjusted operating income decreased ~~$7.7~~$5.4 million primarily due to ~~cooler spring~~lower heating demand from warmer winter weather, ~~compared to prior year~~lower power marketing margins and higher operating expenses ~~driven~~partially offset by ~~outside services~~increased mark-to-market on wholesale energy contracts and ~~employee costs;~~increased rider revenues;

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

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


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

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

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

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

~~The variance to the prior year included the following:~~

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

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

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

~~Mining’s adjusted operating income decreased $2.1~~$0.4 million primarily due to lower ~~tons sold driven by planned~~heating demand from warmer winter weather and ~~unplanned generating facility outages partially~~higher operating expenses mostly offset by ~~lower operating expenses;~~new rates, prior year amortization of excess deferred income taxes, customer growth and increased mark-to-market on non-utility natural gas commodity contracts;

~~Corporate~~A $6.9 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and ~~Other expenses decreased $2.1~~gas company; and

A $3.1 million increase in other income primarily due to ~~prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;~~


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

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

plan driven by market performance on plan assets.

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


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended March 31,
	2019			2018			Variance			2019			2018			Variance			2020			2019			Variance
Revenue
Revenue	$	369,576		$	390,879		$	(21,303	)	$	1,005,257		$	1,002,844		$	2,413		$	576,083		$	635,681		$	(59,598	)
Inter-company eliminations	(35,688		)	(35,175		)	(513		)	(73,559		)	(71,751		)	(1,808		)	(39,033		)	(37,871		)	(1,162		)
	$	333,888		$	355,704		$	(21,816	)	$	931,698		$	931,093		$	605		$	537,050		$	597,810		$	(60,760	)
Adjusted operating income ^(a)
Electric Utilities	$	33,546		$	41,200		$	(7,654	)	$	74,566		$	79,680		$	(5,114	)	$	35,650		$	41,020		$	(5,370	)
Gas Utilities	8,557			16,485			(7,928		)	111,871			111,928			(57		)	102,897			103,314			(417		)
Power Generation	10,156			8,877			1,279			22,123			20,652			1,471			11,349			11,967			(618		)
Mining	1,640			3,825			(2,185		)	5,977			8,096			(2,119		)	3,129			4,337			(1,208		)
Corporate and Other	102			(836		)	938			(405		)	(2,531		)	2,126			160			(507		)	667
Operating income	54,001			69,551			(15,550		)	214,132			217,825			(3,693		)	153,185			160,131			(6,946		)

Interest expense, net	(34,265		)	(34,534		)	269			(68,982		)	(69,529		)	547			(35,453		)	(34,717		)	(736		)
Impairment of investment																			(6,859		)	—			(6,859		)
Other income (expense), net	264			(1,309		)	1,573			(525		)	(1,413		)	888			2,353			(789		)	3,142
Income tax benefit (expense)	(2,307		)	(6,541		)	4,234			(19,570		)	19,261			(38,831		)
Income from continuing operations	17,693			27,167			(9,474		)	125,055			166,144			(41,089		)
Net (loss) from discontinued operations	—			(2,427		)	2,427			—			(4,770		)	4,770
Income tax (expense)																			(16,002		)	(17,263		)	1,261
Net income	17,693			24,740			(7,047		)	125,055			161,374			(36,319		)	97,224			107,362			(10,138		)
Net income attributable to noncontrolling interest	(3,110		)	(2,823		)	(287		)	(6,664		)	(6,453		)	(211		)	(4,050		)	(3,554		)	(496		)
Net income available for common stock	$	14,583		$	21,917		$	(7,334	)	$	118,391		$	154,921		$	(36,530	)	$	93,174		$	103,808		$	(10,634	)

__________

(a)

~~In 2019, we changed our measure~~Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation 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.information does not impact consolidated financial results.

~~Overview of~~ Business ~~Segments~~Segment Highlights and Corporate Activity

Electric Utilities Segment

On April 14, 2020, Colorado Electric submitted its 30-day report to the CPUC summarizing the first milestone in the Renewable Advantage Plan which is expected to provide cost savings to customers and ~~Wyoming~~double its renewable energy portfolio. The bidding process for new renewable energy projects concluded on February 15, 2020, attracting interest from developers in southern Colorado and across the U.S. In total, Colorado Electric ~~set new all-time~~received 54 bids from 25 bidders for renewable energy projects at varying sizes, prices, technology types and ~~summer peak loads:~~locations, with the majority of projects to be sited in Pueblo and Pueblo County. The winning bid(s) and pricing will be determined in June 2020 when Colorado Electric files its 120-day report to the CPUC.

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

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

~~South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57~~$79 million ~~40 MW~~ Corriedale ~~Wind Energy Project. The wind~~ project, ~~will be jointly owned by the two electric utilities to deliver renewable energy for large commercial and industrial customers and governmental agencies. The project~~which is expected to be placed in service by year-end 2020. As a result of COVID-19, we regularly communicate with our key suppliers to maintain visibility into any disruptions they are experiencing in ~~2020.~~the receipt of supplies and materials from their suppliers. At this time, we have not experienced significant disruption in our supply chain due to COVID-19 which would cause us to adjust the in-service date for this project. If significant disruptions occur and we were unable to complete the project by December 31, 2020, we could experience loss of production tax credits.

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Wyoming Electric will continue to receive 60 MW of energy from the Wygen I power plant starting January 1, 2023, and for 20 additional years. On February 21, 2020, the FERC set this filing for hearing. However, the hearing has been placed in abeyance pending a FERC monitored settlement process. Settlement negotiations are ongoing among all parties. Any settlement would require FERC approval. To the extent the parties are unable to reach agreement, the next step in FERC’s process would be to set the matter for hearing. We will continue to evaluate our options to fulfill our 60 MW capacity need.

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

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

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

Gas Utilities Segment

On February 1, 2019, Colorado Gas ~~Utilities experienced colder winter~~filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and ~~spring weather during~~services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ~~three~~ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and ~~six months ended June 30, 2019 compared~~rider mechanism and also recommended a rate decrease. On April 14, 2020, the CPUC deliberated on the ALJ’s recommended decision and filed exceptions to that decision. The CPUC essentially accepted the ~~same periods~~ALJ’s recommended decisions, except for return on equity, which they lowered from 9.5% to 9.2%. A final order and new rates are anticipated to be effective in ~~2018. Heating degree days for~~ the ~~three and six months ended June 30, 2019 were 5% and 10% higher than normal, compared to 1% lower and 1% higher than normal for the same periods in 2018.~~second quarter of 2020.

~~Regulatory activity:~~Wyoming Gas’s new single statewide rate structure was effective March 1, 2020. On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. New rates are expected to generate $13 million in new revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.

◦

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


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

◦

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

On ~~May 10, 2019, Wyoming~~January 1, 2020, Nebraska Gas ~~commenced construction~~completed the legal consolidation of its two natural gas utilities, having received approval from the NPSC on the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline will interconnect from a supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. The pipelineOctober 29, 2019. A rate review is expected to be ~~in service in late 2019.~~filed mid-year 2020 to consolidate the rates, tariffs and services of its two utilities.

Power Generation Segment

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and ~~continuing~~ for 20 additional years. ~~A decision from~~On February 21, 2020, the FERC ~~is expected later~~set this ~~year.~~

~~On March 11, 2019, Black Hills Electric Generation commenced construction on~~filing for hearing. However, the ~~$71 million, 60 MW Busch Ranch II Wind Farm. The wind generation project remains on schedule to be~~hearing has been placed in ~~service~~abeyance pending a FERC monitored settlement process. See additional information in the ~~fall of 2019.~~

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Electric Utilities Segment highlights above.

Corporate and Other

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

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

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

On April ~~30, 2019,~~16, 2020, S&P affirmed South Dakota Electric’s credit rating at A.

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

On February 27, 2020, we issued 1.2 million shares of common stock at a price of $81.77 per share for net proceeds of $99 million.

Operating Results

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

Non-GAAP Financial Measure

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

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

For the three months ended March 31, 2020, we did not experience significant impacts to gross margin for any business segment as a result of COVID-19. Prudently incurred fuel, purchased power, and natural gas costs to serve our customers are recovered through cost adjustment mechanisms at each of our regulated utilities.

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

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Electric Utilities


	Three Months Ended June 30,							Six Months Ended June 30,							Three Months Ended March 31,
	2019		2018		Variance			2019		2018		Variance			2020		2019		Variance
	(in thousands)														(in thousands)
Revenue	$	166,354	$	173,616	$	(7,262	)	$	349,281	$	347,171	$	2,110		$	174,139	$	182,927	$	(8,788	)

Total fuel and purchased power	62,128		65,942		(3,814		)	135,411		134,680		731			64,460		73,283		(8,823		)

Gross margin (non-GAAP)	104,226		107,674		(3,448		)	213,870		212,491		1,379			109,679		109,644		35

Operations and maintenance	48,734		45,101		3,633			95,878		90,194		5,684			50,499		47,144		3,355
Depreciation and amortization	21,947		21,373		574			43,427		42,617		810			23,530		21,480		2,050
Total operating expenses	70,681		66,474		4,207			139,305		132,811		6,494			74,029		68,624		5,405

Adjusted operating income ^(a)	$	33,545	$	41,200	$	(7,655	)	$	74,565	$	79,680	$	(5,115	)	$	35,650	$	41,020	$	(5,370	)

~~________________~~


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

Results of Operations for the Electric Utilities for the Three Months Ended ~~June 30, 2019~~March 31, 2020 Compared to the Three Months Ended ~~June 30, 2018:~~March 31, 2019:

Gross margin for the three months ended ~~June 30, 2019 decreased~~March 31, 2020 did not change as a result of the following:

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



	(in millions)
Increased mark-to-market on wholesale energy contracts	$	1.4
Rider recovery	1.0
Weather	(1.8		)
Off-system power marketing	(1.2		)
Other	0.6
Total change in Gross margin (non-GAAP)	$	—

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

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

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

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

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

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

Operating Statistics


													Electric Revenue				Quantities Sold
	Electric Revenue (in thousands)								Quantities sold (MWh)				(in thousands)				(MWh)
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2019		2018		2019	2018	2019	2018	2020		2019		2020	2019
Residential	$	45,700	$	50,116	$	103,338	$	105,857	301,481	328,638	690,659	711,908	$	54,505	$	57,638	373,150	389,178
Commercial	59,739		64,902		120,702		126,886		490,329	509,984	995,902	1,010,120	57,823		60,963		494,308	505,573
Industrial	31,697		31,220		64,137		62,020		445,837	418,596	872,451	819,305	32,169		32,440		460,632	426,614
Municipal	4,253		4,666		8,392		8,807		38,283	42,657	74,919	78,981	3,878		4,139		36,399	36,636
Subtotal Retail Revenue - Electric	141,389		150,904		296,569		303,570		1,275,930	1,299,875	2,633,931	2,620,314	148,375		155,180		1,364,489	1,358,001
Contract Wholesale	6,781		8,191		15,124		17,241		194,222	218,132	417,242	455,836
Contract Wholesale ^(a)													5,553		8,343		131,778	223,020
Off-system/Power Marketing Wholesale	3,448		4,939		10,140		9,083		135,091	178,854	275,941	307,895	4,867		6,692		165,785	140,850
Other	14,736		9,582		27,448		17,277		—	—	—	—	15,344		12,712		—	—
Total Revenue and Energy Sold	166,354		173,616		349,281		347,171		1,605,243	1,696,861	3,327,114	3,384,045	174,139		182,927		1,662,052	1,721,871
Other Uses, Losses or Generation, net	—		—		—		—		89,866	125,606	186,866	216,461
Other Uses, Losses or Generation, net ^(b)													—		—		90,871	97,000
Total Revenue and Energy	166,354		173,616		349,281		347,171		1,695,109	1,822,467	3,513,980	3,600,506	174,139		182,927		1,752,923	1,818,871
Less cost of fuel and purchased power ^(a)	62,128		65,942		135,411		134,680
Gross Margin (non-GAAP) ^(a)	$	104,226	$	107,674	$	213,870	$	212,491
Less cost of fuel and purchased power													64,460		73,283
Gross Margin (non-GAAP)													$	109,679	$	109,644




Three Months Ended March 31,	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(b)
	2020		2019		2020		2019		2020	2019
Colorado Electric	$	58,558	$	59,847	$	32,270	$	31,444	550,771	491,682
South Dakota Electric ^(a)	71,611		79,041		55,624		56,308		685,224	845,001
Wyoming Electric	43,970		44,039		21,785		21,892		516,928	482,188
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	174,139	$	182,927	$	109,679	$	109,644	1,752,923	1,818,871

________________

(a)

~~Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, cost of fuel~~Revenue and purchased power ~~was revised~~ for the three ~~and six~~ months ended ~~June 30, 2018, which resulted in an increase of $1.7 million~~March 31, 2020, as well as associated quantities, for certain wholesale contracts have been presented on a net basis. Amounts for the three months ended March 31, 2019 were presented on a gross basis and, ~~$3.3 million, respectively. There~~due to their immaterial nature, were ~~corresponding decreases to~~not revised. This presentation change has no impact on Gross ~~margin for each period.~~margin.


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



	Three Months Ended March 31,
Quantities Generated and Purchased (MWh)	2020	2019

Coal-fired	547,829	585,295
Natural Gas and Oil	167,744	124,657
Wind	73,550	55,419
Total Generated	789,123	765,371
Purchased ^(a)	963,800	1,053,500
Total Generated and Purchased	1,752,923	1,818,871

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


											Three Months Ended March 31,
	Electric Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Quantities Sold (MWh) ^(a)
Six Months Ended June 30,	2019		2018		2019		2018		2019	2018
Quantities Generated and Purchased (MWh)											2020	2019
Generated:
Colorado Electric ^(b)	$	115,259	$	120,885	$	62,495	$	67,547	977,028	1,029,528	94,051	100,530
South Dakota Electric	148,287		144,491		107,173		101,298		1,602,641	1,666,120	472,966	457,369
Wyoming Electric	85,735		81,795		44,202		43,646		934,311	904,858	222,106	207,472
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	349,281	$	347,171	$	213,870	$	212,491	3,513,980	3,600,506
Total Generated											789,123	765,371
Purchased:
Colorado Electric											456,720	391,152
South Dakota Electric ^(a)											212,258	387,632
Wyoming Electric											294,822	274,716
Total Purchased											963,800	1,053,500

Total Generated and Purchased											1,752,923	1,818,871

________________

(a)

~~Total MWh~~Purchased power quantities for the three months ended March 31, 2020, for certain wholesale contracts have been presented on a net basis. Amounts for the three months ended March 31, 2019 ~~includes Other Uses, Losses or Generation, net, which are approximately 5%, 5%,~~were presented on a gross basis and, ~~6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, respectively.~~due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.



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

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

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


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended March 31,
Quantities Generated and Purchased (MWh)	2019	2018	2019	2018
Generated:
					2020				2019
Heating Degree Days					Actual	Variance from Normal		Actual Variance to Prior Year	Actual	Variance from Normal

Colorado Electric	91,886	132,927	192,416	224,975	2,456	(7	)%	(4)%	2,549	(4	)%
South Dakota Electric	315,925	411,839	773,294	824,033	3,111	(3	)%	(21)%	3,916	22	%
Wyoming Electric	207,009	197,772	414,481	404,434	2,999	(1	)%	(6)%	3,198	—	%
Total Generated	614,820	742,538	1,380,191	1,453,442
Purchased:
Colorado Electric	393,460	409,601	784,612	804,553
South Dakota Electric	441,715	426,104	829,347	842,087
Wyoming Electric	245,114	244,224	519,830	500,424
Total Purchased	1,080,289	1,079,929	2,133,789	2,147,064

Total Generated and Purchased	1,695,109	1,822,467	3,513,980	3,600,506
Combined^(a)					2,789	(4	)%	(11)%	3,147	7	%

~~Table of Contents~~

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

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

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

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

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

~~__________~~____________________


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


Electric Utilities Power Plant Availability	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		Three Months Ended March 31,
Contracted Power Plant Fleet Availability ^(a)									2020		2019
Coal-fired plants ^(a)	79.2	%	91.2	%	87.7	%	93.1	%	90.8	%	96.2	%
Natural gas-fired plants and Other plants ^(b)	89.3	%	98.1	%	90.0	%	97.2	%	83.5	%	90.7	%
Wind	94.5	%	96.7	%	95.6	%	96.9	%	99.0	%	96.8	%
Total availability	86.4	%	95.8	%	89.7	%	95.9	%
Total Availability									87.1	%	92.9	%

Wind capacity factor	34.8	%	41.7	%	38.7	%	46.1	%
Wind Capacity Factor									45.6	%	42.6	%

~~__________~~____________________


(a)	~~2019 included planned outages at Neil Simpson II~~Availability and ~~Wygen III and unplanned outages at Wyodak Plant.~~Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.


(b)	~~2019~~2020 included ~~planned outages~~an unplanned outage at ~~Neil Simpson CT and Lange CT.~~Pueblo Airport Generation.

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Gas Utilities


	Three Months Ended June 30,							Six Months Ended June 30,							Three Months Ended March 31,
	2019		2018		Variance			2019		2018		Variance			2020		2019		Variance
	(in thousands)														(in thousands)
Revenue:
Natural gas - regulated	$	149,942	$	161,212	$	(11,270	)	$	533,817	$	531,480	$	2,337		$	335,897	$	383,875	$	(47,978	)
Other - non-regulated services	15,527		16,408		(881		)	42,732		43,484		(752		)	24,876		27,205		(2,329		)
Total revenue	165,469		177,620		(12,151		)	576,549		574,964		1,585			360,773		411,080		(50,307		)

Cost of sales:
Natural gas - regulated	51,108		62,453		(11,345		)	252,158		267,537		(15,379		)	153,999		201,050		(47,051		)
Other - non-regulated services	5,876		5,601		275			12,105		10,202		1,903			1,363		6,229		(4,866		)
Total cost of sales	56,984		68,054		(11,070		)	264,263		277,739		(13,476		)	155,362		207,279		(51,917		)

Gross margin (non-GAAP)	108,485		109,566		(1,081		)	312,286		297,225		15,061			205,411		203,801		1,610

Operations and maintenance	77,130		71,667		5,463			155,068		142,573		12,495			77,293		77,938		(645		)
Depreciation and amortization	22,797		21,414		1,383			45,346		42,724		2,622			25,221		22,549		2,672
Total operating expenses	99,927		93,081		6,846			200,414		185,297		15,117			102,514		100,487		2,027

Adjusted operating income	$	8,558	$	16,485	$	(7,927	)	$	111,872	$	111,928	$	(56	)	$	102,897	$	103,314	$	(417	)

Results of Operations for the Gas Utilities for the Three Months Ended ~~June 30, 2019~~March 31, 2020 Compared to the Three Months Ended ~~June 30, 2018:~~March 31, 2019:

Gross margin for the three months ended ~~June 30, 2019 decreased~~March 31, 2020 increased as a result of:

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

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

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



	(in millions)
New rates	$	5.1
Prior year amortization of excess deferred income taxes	3.2
Customer growth - distribution	1.5
Increased mark-to-market on non-utility natural gas commodity contracts	0.9
Non-utility - Gas supply services	0.8
Weather	(10.4		)
Decreased transportation and transmission	(0.7		)
Other	1.2
Total increase in Gross margin (non-GAAP)	$	1.6

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

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

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

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

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

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

Operating Statistics

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

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

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

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

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

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

~~Table of Contents~~




	Gas Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)						Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019			2020	2019

Residential	$	207,231		$	241,129		$	103,121		$	105,057		28,230,795	32,838,018
Commercial	80,236			96,139			33,519			35,158			12,834,803	14,990,848
Industrial	5,200			6,014			2,043			2,017			1,061,052	1,182,527
Other	(1,242		)	(4,354		)	(1,242		)	(4,354		)	—	—
Total Distribution	291,425			338,928			137,441			137,878			42,126,650	49,011,393

Transportation and Transmission	44,472			44,947			44,457			44,947			45,055,507	46,316,160

Total Regulated	335,897			383,875			181,898			182,825			87,182,157	95,327,553

Non-regulated Services	24,876			27,205			23,513			20,976

Total Gas Revenue & Gross Margin (non-GAAP)	$	360,773		$	411,080		$	205,411		$	203,801

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

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

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

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

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

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



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

Revenue (in thousands)
Gross Margin (non-GAAP)(in thousands)

Gas Utilities Quantities Sold & Transported (Dth)

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

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

Revenue (in thousands)
Gross Margin (non-GAAP)(in thousands)

Gas Utilities Quantities Sold & Transported (Dth)

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

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




	Revenue (in thousands)				Gross Margin (non-GAAP) (in thousands)				Gas Utilities Quantities Sold & Transported (Dth)
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
	2020		2019		2020		2019		2020	2019

Arkansas Gas	$	74,845	$	79,391	$	48,855	$	44,282	10,962,948	12,424,196
Colorado Gas	72,606		76,471		38,006		37,600		13,096,405	13,176,925
Iowa Gas	54,824		65,641		21,328		23,050		14,280,273	15,663,687
Kansas Gas	33,494		41,217		18,603		18,119		9,914,858	10,443,270
Nebraska Gas	83,666		108,797		51,666		56,073		26,509,036	28,999,018
Wyoming Gas	41,338		39,563		26,953		24,677		12,418,637	14,620,457
Total Gas Revenue & Gross Margin (non-GAAP)	$	360,773	$	411,080	$	205,411	$	203,801	87,182,157	95,327,553

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.

4741

Table of Contents

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

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




	Three Months Ended March 31,
	2020			2019
Heating Degree Days:	Actual	Variance from Normal	Actual Variance to Prior Year	Actual	Variance from Normal
Arkansas Gas ^(a)	1,659	(21)%	(21)%	2,101	—%
Colorado Gas	2,829	(3)%	(7)%	3,030	3%
Iowa Gas	3,181	(6)%	(17)%	3,830	14%
Kansas Gas ^(a)	2,304	(7)%	(17)%	2,779	13%
Nebraska Gas	2,835	(7)%	(19)%	3,483	15%
Wyoming Gas	3,217	1%	(8)%	3,513	10%
Combined Gas ^(b)	2,918	(6)%	(15)%	3,449	11%

__________


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


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

Regulatory Matters

For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 5 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our ~~2018~~2019 Annual Report on Form 10-K filed with the SEC.

~~Table of Contents~~

Power Generation

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

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

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

~~________________~~


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



	Three Months Ended March 31,
	2020		2019		Variance
	(in thousands)
Revenue	$	25,966	$	25,245	$	721

Fuel expense	2,285		2,626		(341		)
Operations and maintenance	6,997		6,062		935
Depreciation and amortization	5,335		4,590		745
Total operating expense	14,617		13,278		1,339

Adjusted operating income	$	11,349	$	11,967	$	(618	)

Results of Operations for Power Generation for the Three ~~and Six~~ Months Ended ~~June 30, 2019~~March 31, 2020 Compared to the Three ~~and Six~~ Months Ended ~~June 30, 2018:~~ March 31, 2019:

Revenue increased in the current year driven by an increase in MWh sold due to ~~increased~~new wind ~~MWh sold~~assets and ~~higher PPA prices.~~additional Black Hills Colorado IPP fired-engine hours. Operating expenses increased in the current year primarily due to higher ~~depreciation~~maintenance expense and ~~property taxes~~depreciation from new wind assets.

The following table summarizes MWh for our Power Generation segment:


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended March 31,
	2019	2018	2019	2018	2020	2019
Quantities Sold, Generated and Purchased (MWh) ^(a)
Sold
Black Hills Colorado IPP ^(b)	210,316	208,888	416,289	441,263
Black Hills Wyoming ^(c)	149,713	144,460	313,762	310,061
Black Hills Electric Generation ^(d)	47,796	—	81,549	—
Black Hills Colorado IPP					265,225	205,973
Black Hills Wyoming ^(b)					156,352	164,049
Black Hills Electric Generation					97,279	33,753
Total Sold	407,825	353,348	811,600	751,324	518,856	403,775

Generated
Black Hills Colorado IPP ^(b)	210,316	208,888	416,289	441,263
Black Hills Wyoming ^(c)	132,189	128,819	264,782	262,848
Black Hills Electric Generation ^(d)	47,796	—	81,549	—
Black Hills Colorado IPP					265,225	205,973
Black Hills Wyoming ^(b)					126,485	132,593
Black Hills Electric Generation					97,279	33,753
Total Generated	390,301	337,707	762,620	704,111	488,989	372,319

Purchased
Black Hills Wyoming ^(c)(b)	13,761	17,122	39,340	49,039	29,856	25,579
Total Purchased	13,761	17,122	39,340	49,039	29,856	25,579

____________


(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.



	Three Months Ended March 31,
Contracted Power Plant Fleet Availability ^(a)	2020		2019

Coal-fired plant ^(b)	89.3	%	94.8	%
Natural gas-fired plants	99.5	%	95.6	%
Wind	99.3	%	90.4	%
Total Availability	97.8	%	94.1	%

Wind Capacity Factor	30.4	%	28.2	%

____________________


~~(d)~~(a)	~~Increase from prior year is driven by Black Hills Electric Generation’s acquisition~~Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of ~~new wind assets.~~our generating fleet.


(b)	2020 included a planned outage at Wygen I.

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

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

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

~~____________~~


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


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

Mining


	Three Months Ended June 30,							Six Months Ended June 30,							Three Months Ended March 31,
	2019		2018		Variance			2019		2018		Variance			2020		2019		Variance
	(in thousands)														(in thousands)
Revenue	$	13,045	$	16,899	$	(3,854	)	$	29,474	$	34,027	$	(4,553	)	$	15,205	$	16,429	$	(1,224	)

Operations and maintenance	9,175		11,124		(1,949		)	19,088		22,046		(2,958		)	9,826		9,913		(87		)
Depreciation, depletion and amortization	2,230		1,950		280			4,409		3,885		524			2,250		2,179		71
Total operating expenses	11,405		13,074		(1,669		)	23,497		25,931		(2,434		)	12,076		12,092		(16		)

Adjusted operating income	$	1,640	$	3,825	$	(2,185	)	$	5,977	$	8,096	$	(2,119	)	$	3,129	$	4,337	$	(1,208	)

Results of Operations for Mining for the Three Months Ended March 31, 2020 Compared to the Three Months Ended March 31, 2019:

Current year revenue decreased due to 10% fewer tons sold driven primarily by decreased demand at the Wyodak Plant and timing of planned spring outages at our coal-fired generation facilities partially offset by an increase 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,				Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
Tons of coal sold	754		963		1,751		2,041		896		997
Cubic yards of overburden moved	2,045		2,380		4,039		4,402		2,267		1,994

Revenue per ton	$	16.48	$	16.97	$	16.14	$	16.12	$	16.08	$	15.87

~~Results~~

Corporate and Other



	Three Months Ended March 31,
	2020		2019			Variance
	(in thousands)
Adjusted operating income (loss)	$	160	$	(507	)	$	667

Interest Expense, Impairment of ~~Operations for Mining~~Investment, Other Income (Expense) and Income Tax (Expense)



	Three Months Ended March 31,
	2020			2019			Variance
	(in thousands)
Interest expense, net	$	(35,453	)	$	(34,717	)	$	(736	)
Impairment of investment	(6,859		)	—			$	(6,859	)
Other income (expense), net	2,353			(789		)	$	3,142
Income tax (expense)	(16,002		)	(17,263		)	$	1,261

Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax (expense) for the Three Months Ended ~~June 30, 2019~~March 31, 2020 Compared to the Three Months Ended ~~June 30, 2018:~~March 31, 2019.

Impairment of Investment

For the three months ended March 31, 2020, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See Note 15 of the Notes to Condensed Consolidated Financial Statements for additional details.

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

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

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

~~Table of Contents~~

~~Corporate and Other~~

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

~~________________~~


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

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

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

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

~~Income Tax Benefit (Expense)~~

~~Income tax benefit (expense)~~ for the three months ended ~~June 30, 2019 was $(2.3) million~~March 31, 2020, compared to ~~$(6.5) million~~the same period in the prior year was primarily due to reduced costs for our non-qualified benefit plan which are driven by market performance on plan assets.

Income Tax (Expense)

For the three months ended March 31, 2020, the effective tax rate was 14.1% compared to 13.9% for the same period in ~~2018.~~2019. The decrease is driven by a lower 2019 forecasted annual effective tax rate primarily due to an increase of federal production tax credits and state investment credits associated with new wind assets; and a current year $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.

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

~~Income Tax Benefit (Expense)~~

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

~~For the six months ended June 30, 2019 the effective tax rate was 13.5% compared to 19.0% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2018. The lower~~higher effective tax rate is primarily due to ~~$3.5 million~~a discrete tax adjustment related to the impairment of our investment in equity securities of a privately held oil and gas company partially offset by increased tax benefits from forecasted federal production tax ~~credits and related state investment~~ credits associated with new wind ~~assets, a $1.7 million tax benefit for deferred tax amortization related to tax reform and a $1.6 million flow-through discrete tax benefit related to repair costs and certain indirect costs.~~assets.

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.

~~Table of Contents~~

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 Results of Operations 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 ~~June 30, 2019,~~March 31, 2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. For the three months ended March 31, 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 of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. We have reached agreements with regulators in six states and are working with regulators in our seventh state, as well as FERC regarding returning benefits to customers. Our working capital requirements increased as a result of complying with the TCJA and providing the benefits of the TCJA to customers. These agreements will negatively impact our cash flows by approximately $40 million to $45 million per year for each of the next several years.

Cash Flow Activities

The following table summarizes our cash flows for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 (in thousands):


Cash provided by (used in):	2019			2018			Variance			2020			2019			Variance
Operating activities	$	289,779		$	310,701		$	(20,922	)	$	191,969		$	175,893		$	16,076
Investing activities	$	(317,297	)	$	(163,526	)	$	(153,771	)	$	(173,084	)	$	(145,027	)	$	(28,057	)
Financing activities	$	13,617		$	(153,701	)	$	167,318		$	25,621		$	(39,292	)	$	64,913

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~~Year-to-Date 2019~~Three Months Ended March 31, 2020 Compared to ~~Year-to-Date 2018~~Three Months Ended March 31, 2019

Operating Activities

Net cash provided by operating activities was ~~$290~~$192 million for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, compared to net cash provided by operating activities of ~~$311~~$176 million for the same period in ~~2018~~2019 for ~~a decrease~~an increase of ~~$21~~$16 million. The variance was primarily attributable to:

Cash earnings ~~(income from continuing operations~~(net income plus non-cash adjustments) were ~~$13~~$4 million ~~higher~~lower for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 compared to the same period in the prior ~~year;~~year primarily driven by lower operating income at the Electric Utilities and Mining segments;

Net cash inflows from changes in operating assets and liabilities were ~~$14~~$5.0 million for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, compared to net cash ~~inflows~~outflows of ~~$47~~$15 million in the same period in the prior year. This ~~$33~~$20 million ~~decrease~~increase was primarily due to:


◦	Cash inflows increased by ~~approximately $46~~$14 million primarily as a result of decreases in natural gas in storage and higher collections of accounts receivable partially offset by ~~higher~~increased materials ~~inventory to support capital projects for the six months ended June 30, 2019 compared to the same period in the prior year;~~and supplies purchases;


◦	Cash outflows increased by ~~approximately $11~~$1.6 million as a result of decreases in accounts payable and accrued liabilities primarily driven by higher employee costs ~~higher gas purchases~~ and other working capital ~~requirements; and~~requirements partially offset by lower interest paid;


◦	Cash inflows ~~decreased~~increased by ~~approximately $66~~$11 million primarily as a result of changes in our current regulatory assets ~~and liabilities~~ driven by ~~differences in~~the timing of recovery from fuel cost ~~adjustments as well as revenue reserved in the prior year~~adjustments; and


◦	Net cash outflows increased by $2.9 million from other operating activities primarily due to ~~the TCJA tax rate change that has subsequently been returned to customers.~~higher employee benefits costs and outside services.

Investing Activities

Net cash used in investing activities was ~~$317~~$173 million for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, compared to net cash used in investing activities of ~~$164~~$145 million for the same period in ~~2018~~2019 for a variance of ~~$154~~$28 million. The variance was primarily attributable to:

Capital expenditures of ~~approximately $318~~$172 million for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 compared to ~~$157~~$144 million for the same period in the prior year. Higher current year expenditures are ~~primarily~~ driven by higher programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the ~~Busch Ranch II~~Corriedale wind project at our ~~Power Generation segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska at our~~ Electric Utilities ~~segment and the 35-mile Natural Bridge pipeline project at our Gas Utilities segment; and~~

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

Financing Activities

Net cash provided by financing activities for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 was ~~$14~~$26 million, compared to ~~$154~~$39 million of net cash used in financing activities for the same period in ~~2018 for a variance~~2019, an increase of ~~$167 million. This variance is primarily~~$65 million due ~~to:~~to the following:

~~We amended our Corporate term loan due July 30, 2020, which increased total commitments to $400~~Increase of $79 million ~~from $300 million;~~

~~Current year issuance of~~in common stock ~~for~~issued driven by current year net proceeds of ~~approximately $69~~$99 million through an underwritten registered transaction as compared to prior year net proceeds of $20 million issued through our ~~ATM equity offering program;~~ATM;

$1012 million of higher repayments of short-term and long-term debt; and

$2.6 million of higher current year dividend ~~payments; and~~

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

~~Table of Contents~~

Dividends

Dividends paid on our common stock totaled ~~$61~~$33 million for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, or ~~$0.505~~$0.535 per share per quarter. On ~~July 31, 2019,~~April 27, 2020, our board of directors declared a quarterly dividend of ~~$0.505~~$0.535 per share payable ~~September~~June 1, ~~2019,~~2020, equivalent to an annual dividend of ~~$2.02~~$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 at		Available Capacity at			Current		Revolver Borrowings at		CP Program Borrowings at		Letters of Credit at		Available Capacity at
Credit Facility	Expiration	Capacity		June 30, 2019				June 30, 2019				Expiration	Capacity		March 31, 2020		March 31, 2020		March 31, 2020
Revolving Credit Facility	July 30, 2023	$	750	$	—	$	103	$	10	$	637
Revolving Credit Facility and CP Program												July 30, 2023	$	750	$	165	$	154	$	17	$	414

The weighted average interest ~~rate~~rates on CP Program ~~borrowings at June 30, 2019 was 2.60%.~~and Revolving Credit Facility borrowings at March 31, 2020 were 1.74% and 1.92%, respectively. CP Program ~~financing~~and Revolving Credit Facility borrowing activity for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 was (dollars in millions):

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



	For the Three Months Ended March 31, 2020
Maximum amount outstanding - CP Program (based on daily outstanding balances)	$	366
Maximum amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	165
Average amount outstanding - CP Program (based on daily outstanding balances)	$	288
Average amount outstanding - Revolving Credit Facility (based on daily outstanding balances)	$	150
Weighted average interest rates - CP Program	1.84		%
Weighted average interest rates - Revolving Credit Facility	1.92		%

Covenant Requirements

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of ~~June 30, 2019.~~March 31, 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 ~~June 30, 2019,~~March 31, 2020, we were in compliance with these covenants.

Financing Activities

Financing activities for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 consisted of the following:

On ~~June 17, 2019,~~February 27, 2020, we ~~amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400~~issued 1.2 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 used to pay down short-term debt. See Note 8 of the Notes to Condensed Consolidated Financial Statements for more information.

~~We issued a total of 939,095~~ shares of common stock ~~under the ATM equity offering program~~to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of ~~$69~~$99 million, net of ~~$0.7~~$1.0 million ~~in commissions. As~~ of ~~June 30, 2019, there were no shares that were sold, but not settled.~~issuance costs.

Short-term borrowings from our Revolving Credit Facility and CP Program.

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Future Financing Plans

~~Evaluate refinancing options for~~We anticipate the following financing activities in 2020:

Renew our ~~$200 million senior notes due July 15, 2020.~~shelf registration and ATM;

Refinance a portion of short-term borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and

Continue to assess debt and equity needs to support our capital expenditure plan.

Credit Ratings

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

The following table represents the credit ratings and outlook and risk profile of BHC at ~~June 30, 2019:~~March 31, 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,~~April 10, 2020, S&P affirmed our BBB+ rating and maintained a Stable outlook.


(b)	On December ~~12, 2018,~~20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.


(c)	On ~~October 11, 2018,~~August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

The following table represents the credit ratings of South Dakota Electric at ~~June 30, 2019:~~March 31, 2020:



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

__________


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


(b)	On December ~~12, 2018,~~20, 2019, Moody’s affirmed A1 rating.


(c)	On ~~July 23,~~August 29, 2019, Fitch affirmed A rating.

~~Table of Contents~~

Capital Requirements

Capital Expenditures


	Actual		Planned										Actual		Planned
Capital Expenditures by Segment	Six Months Ended June 30, 2019 ^(a)		2019^(b)		2020		2021		2022		2023		Three Months Ended March 31, 2020 ^(a)		2020 ^(b)		2021		2022		2023		2024
(in millions)
Electric Utilities ^(c)	$	87	$	205	$	221	$	203	$	170	$	137	$	49	$	246	$	203	$	170	$	137	$	152
Gas Utilities ^(c)	185		464		323		289		277		274		113		391		309		285		316		293
Power Generation	41		84		9		8		10		4		5		7		9		11		6		6
Mining	5		8		7		11		10		7		1		8		12		9		9		9
Corporate and Other	14		16		22		8		5		7		5		17		22		11		12		10
	$	332	$	777	$	582	$	519	$	472	$	429	$	173	$	669	$	555	$	486	$	480	$	470

__________

(a) Expenditures for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 include the impact of accruals for property, plant and equipment.

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

~~(c) Planned capital expenditures increased for 2019 through 2023 primarily due to increased programmatic integrity spending.~~March 31, 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts to supply chains including availability of supplies and materials and lead times and capital projects are ongoing without material disruption to schedules. Our third party resources continue to ~~evaluate~~support our business plans without disruption. Contingency plans are ongoing due to the impacts of COVID-19, including the potential ~~future acquisitions and other growth opportunities when they arise. As~~for rescheduling projects. We currently do not anticipate a ~~result,~~significant impact 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 & 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.	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 ~~six~~Notes to Condensed Consolidated Financial Statements for updates to market risks during the three months ended ~~June 30, 2019, there were no material changes to our quantitative and qualitative disclosures about market risk.~~March 31, 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 ~~June 30, 2019.~~March 31, 2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at ~~June 30, 2019.~~March 31, 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 ~~June 30, 2019,~~March 31, 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.

5745

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~~BLACK HILLS CORPORATION~~

~~Part II — Other Information~~

PART II. OTHER INFORMATION


ITEM 1.	~~Legal Proceedings~~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 1316 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1316 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 are responding to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread. We provide an essential service to our customers which means it is critical we keep our employees who operate our businesses healthy and minimize unnecessary exposure to the virus. We continue to execute our business continuity plan and have implemented a comprehensive set of actions for the health and safety of our customers, employees, business partners and the communities we serve. We have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities and we have implemented work from home policies where appropriate. We have implemented sequestration plans for employees critical to maintaining reliable service.

We have informed both our customers and regulators that disconnections for non-payment will be temporarily suspended. We have instituted measures to ensure our supply chain remains open to us. We continue to implement strong physical and cyber-security measures to ensure our systems remain functional to both serve our operational needs with a remote workforce and to provide uninterrupted service to our customers.

For the three months ended March 31, 2020, the impacts of COVID-19 had a minimal financial impact on our business, operations and financial condition. In particular, we experienced minimal financial impacts to the following due to COVID-19:

Volatility in electricity and natural gas usage from our residential, commercial and industrial customers resulting in a minimal decrease in total demand;

Delayed payments from an isolated population of our commercial and industrial customers within hard-hit industries;

Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plans as planned;

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 due to sequestration of mission critical and essential employees; and

Reduced training, travel and outside services related expenses.

Should the COVID-19 pandemic continue for a prolonged period, or impact the areas we serve more significantly than it has today, our business, operations and financial condition could be impacted in more significant ways. The continued spread of COVID-19 and efforts to contain the virus could have the following impacts, in addition to exacerbating the impacts described above:

Adversely impact our strategic business plans, growth strategy and capital investment plans;

Adversely impact electricity and natural gas demand from our customers, particularly from businesses, commercial and industrial customers;

Reduce the availability and productivity of our employees and third-party resources;

Cause us to experience an increase in costs as a result of our emergency measures;


•	Result in 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;

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

Table of Contents

Cause delays and disruptions in the supply chain resulting in disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and potential damages in our power purchase agreements;

Cause a 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;

Cause impairment of goodwill or long-lived assets;

Adversely impact our ability to develop, construct and operate facilities;

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

Cause a deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;

Cause a delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;

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

Cause delays in our ability to change rates through regulatory proceedings; and

Cause other risks to 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 not experienced significant 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~~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~~EXHIBITS



Exhibit Number	Description

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

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

Exhibit 4.1*	Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
	First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
	Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009).
	Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).
	Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on November 18, 2013).
	Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016).
	Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016).
	Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on August 17, 2018).
	Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on October 4, 2019).

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

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



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




Exhibit 4.4*	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~~18.1	First Amendment dated as of June 17, 2019 to Amended and Restated Credit Agreement dated as of July 30, 2018, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8–K filed on June 17, 2019).Preferability letter from Deloitte & Touche LLP regarding change in pension accounting asset method.

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

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

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

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

Exhibit 95	Mine Safety and Health Administration Safety Data.

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

104	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

__________


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

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SIGNATURES

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

BLACK HILLS CORPORATION



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

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

Dated:	~~August 6, 2019~~May 5, 2020

6049



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

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



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



	Accounts		Unbilled		Less Allowance for			Accounts
June 30, 2019	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	39,982	$	31,573	$	(526	)	$	71,029
Gas Utilities	67,686		23,753		(4,391		)	87,048
Power Generation	2,867		—		—			2,867
Mining	2,505		—		—			2,505
Corporate	3,233		—		(169		)	3,064
Total	$	116,273	$	55,326	$	(5,086	)	$	166,513



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



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



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



	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)	$	1,085
2020	2,010
2021	1,843
2022	1,793
2023	1,799
Thereafter	55,481
Total lease receivables	$	64,011



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



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




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

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



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



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



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

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

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

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

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

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




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

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

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

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

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

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



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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common stock of $1.00 par value

New York Stock Exchange