Black Hills Service Company, LLC

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K



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

	For the fiscal year ended	December 31, 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, including area code		(605)	721-1700

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)		Name of each exchange on which registered
Common stock of $1.00 par value	BKH		New York Stock Exchange



Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
	Yes	☒	No	☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
	Yes	☐	No	☒

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	☒	No	☐

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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
	Yes	☒	No	☐

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



Large accelerated filer	☒	Accelerated filer	☐

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	☒

The aggregate market value of the voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s
most recently completed second fiscal quarter, June 30, 2019, was			$4,727,278,183



Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Class	Outstanding at January 31, 2020
Common stock, $1.00 par value	61,475,403	shares

Documents Incorporated by Reference

Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2020 Annual Meeting of Stockholders to be held on April 28, 2020, are incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS



		Page
GLOSSARY OF TERMS AND ABBREVIATIONS		3
WEBSITE ACCESS TO REPORTS		8
FORWARD-LOOKING INFORMATION		8
Part I
ITEMS 1. and 2.	BUSINESS AND PROPERTIES	9
	History and Organization	9
	Electric Utilities	9
	Gas Utilities	17
	Utility Regulation Characteristics	22
	Power Generation	23
	Mining	25
	Environmental Matters	27
	Other Properties	28
	Employees	29
ITEM 1A.	RISK FACTORS	29
ITEM 1B.	UNRESOLVED STAFF COMMENTS	37
ITEM 3.	LEGAL PROCEEDINGS	37
ITEM 4.	MINE SAFETY DISCLOSURES	37
INFORMATION ABOUT OUR EXECUTIVE OFFICERS		38
Part II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	39
ITEM 6.	SELECTED FINANCIAL DATA	40
ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	42
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	72
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	143
ITEM 9A.	CONTROLS AND PROCEDURES	143
ITEM 9B.	OTHER INFORMATION	143
Part III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	144
ITEM 11.	EXECUTIVE COMPENSATION	144
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	144
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	144
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	144
Part IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	145
ITEM 16.	FORM 10-K SUMMARY	148
SIGNATURES		149

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:



AC	Alternating Current
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
APSC	Arkansas Public Service Commission
Arkansas Gas	Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as 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.
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation; the Company
BHSC	Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
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 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
BLM	United States Bureau of Land Management
Btu	British thermal unit
Busch Ranch I	29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm.
Busch Ranch II	60 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a power purchase 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.
CFTC	United States Commodity Futures Trading Commission
Cheyenne Prairie	132 MW natural-gas fired generating facility jointly owned by South Dakota Electric and Wyoming Electric in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
Choice Gas Program	Regulator approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing the unbundling of the commodity service from the distribution delivery service.
City of Gillette	Gillette, Wyoming
City of Cheyenne	Cheyenne, Wyoming

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Colorado Electric	Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas	Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Common Use System (CUS)	The Common Use System is a joint transmission system we participate in with Basin Electric and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming.
Consolidated Indebtedness to Capitalization Ratio	Any Indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated 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 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.
Corriedale	Wind project near Cheyenne, Wyoming, that will be a 52.5 MW wind farm jointly owned by South Dakota Electric and Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program.
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
CP Program	Commercial Paper Program
CPUC	Colorado Public Utilities Commission
CT	Combustion turbine
CTII	The 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette.
Cushion Gas	The portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability.
CVA	Credit Valuation Adjustment
DC	Direct current
Dividend payout ratio	Annual dividends paid on common stock divided by net income from continuing operations available for common stock
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DSM	Demand Side Management
DRSPP	Dividend Reinvestment and Stock Purchase Plan
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu).
EBITDA	Earnings before interest, taxes, depreciation and amortization, a non-GAAP measurement
ECA	Energy Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
Economy Energy	Purchased energy that costs less than that produced with the utilities’ owned generation.
EIA	Environmental Improvement Adjustment -- annual adjustment mechanism that allows us to recover from customers eligible investments in, and expense related to, new environmental measures.
EPA	United States Environmental Protection Agency
Equity Unit	Each Equity Unit has 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 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.
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board

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FDIC	Federal Deposit Insurance Corporation
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings Inc.
GAAP	Accounting principles generally accepted in the United States of America
GCA	Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.
GHG	Greenhouse gases
Global Settlement	Settlement with a utilities commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Happy Jack	Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
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	We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
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
ITC	Investment tax credit
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).
kV	Kilovolt
LIBOR	London Interbank Offered Rate
Mcf	Thousand cubic feet
Mcfd	Thousand cubic feet per day
MDU	Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
MISO	Midcontinent Independent System Operator, Inc.
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MSHA	Mine Safety and Health Administration
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
N/A	Not Applicable
NAV	Net Asset Value
Nebraska Gas	Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
NERC	North American Electric Reliability Corporation
NO_x	Nitrogen oxide
NOL	Net operating loss
NPSC	Nebraska Public Service Commission
NYSE	New York Stock Exchange
OPEB	Other Post-Employment Benefits
OSHA	Occupational Safety & Health Administration
OSM	United States Department of the Interior’s Office of Surface Mining

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PacifiCorp	PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway.
PCA	Power Cost Adjustment -- annual adjustment mechanism that allows us to pass a portion of prudently-incurred delivered power costs, including fuel, purchased capacity and energy, and transmission costs, through to customers.
PCCA	Power Capacity Cost Adjustment -- annual adjustment that allows us to pass the prudently-incurred purchased capacity costs, incremental to costs included in base rates, through to customers.
Peak View	60 MW wind generating project owned by Colorado Electric, placed in service on November 7, 2016 and adjacent to Busch Ranch I.
PPA	Power Purchase Agreement
PRPA	Platte River Power Authority
PSA	Power Sales Agreement
PSCo	Public Service Company of Colorado
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.
PTC	Production tax credit
PUHCA 2005	Public Utility Holding Company Act of 2005
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.
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.
RMNG	Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy).
RSNs	Remarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.
SCADA	Supervisory control and data acquisition
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Service Guard	Home appliance repair product offering for both natural gas and electric residential 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.
Service Guard Comfort Plan	New plan that will consolidate Service Guard and CAPP and provide similar services.
Silver Sage	Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO₂	Sulfur dioxide
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
SPP	Southwest Power Pool, Inc. which oversees the bulk electric grid and wholesale power market in the central United States
SourceGas Transaction	On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing.
South Dakota Electric	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SSIR	System Safety and Integrity Rider
System Peak Demand	Represents the highest point of retail customer usage for a single hour.
TCA	Transmission Cost Adjustment -- annual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the next rate review.
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017

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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.
TFA	Transmission Facility Adjustment -- annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers.
VEBA	Voluntary Employee Benefit Association
VIE	Variable Interest Entity
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
Wind Capacity Factor	Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
Working Capacity	Total gas storage capacity minus cushion gas
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)
Wyoming Electric	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas	Black Hills Wyoming Gas, LLC, an indirect, 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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Website Access to Reports

The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information contained on our website is not part of this document.

Forward-Looking Information

This Form 10-K 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 7 - 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 on which the statement is made and 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 is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, 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 in this Form 10-K, including statements contained within Item 1A - Risk Factors.

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PART I


ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

History and Organization

Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941. It was formed through the purchase and combination of several existing electric utilities and related assets, some of which had served customers in the Black Hills region since 1883. In 1956, with the purchase of the WRDC mine, we began producing and selling energy through non-regulated businesses.

We operate our business in the United States, reporting our operating results through our regulated Electric Utilities, regulated Gas Utilities, Power Generation and Mining segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 214,000 electric utility customers in Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 939 MW of generation and 8,892 miles of electric transmission and distribution lines.

Our Gas Utilities segment serves approximately 1,066,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate approximately 4,775 miles of intrastate gas transmission pipelines and 41,210 miles of gas distribution mains and service lines, seven natural gas storage sites, nearly 49,000 horsepower of compression and over 500 miles of gathering lines.

Our Power Generation segment produces electric power from its wind, natural gas and coal-fired generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts. Our Mining segment produces coal at our mine near Gillette, Wyoming, and sells and delivers it primarily under long-term contracts to adjacent mine-mouth electric generation facilities owned by our Electric Utilities and Power Generation businesses.

Electric Utilities Segment

We conduct electric utility operations through our Colorado, South Dakota and Wyoming subsidiaries. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our 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.

Capacity and Demand. System peak demand for the Electric Utilities’ retail customers for each of the last three years are listed below:



	System Peak Demand (in MW)
	2019		2018		2017
	Summer	Winter	Summer	Winter	Summer	Winter
Colorado Electric ^(a)	422	297	413	313	398	299
South Dakota Electric	335	320	355	314	370	310
Wyoming Electric ^(b)	265	247	254	238	249	230

________________________


(a)	The Colorado Electric July 2019 summer peak load of 422 surpassed previous summer peak record load of 413 set in June 2018. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011.


(b)	The Wyoming Electric July 2019 summer peak load of 265 surpassed previous summer peak record load of 254 set in July 2018. The December 2019 winter peak load of 247 surpassed the previous winter peak record load of 238 set in December 2018.

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Regulated Power Plants. As of December 31, 2019, our Electric Utilities’ ownership interests in electric generating plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	In Service Date
Colorado Electric:
Busch Ranch I^(a)	Wind	Pueblo, Colorado	50%	14.5	2012
Peak View ^(b)	Wind	Pueblo, Colorado	100%	60.0	2016
Pueblo Airport Generation	Gas	Pueblo, Colorado	100%	180.0	2011
Pueblo Airport Generation CT	Gas	Pueblo, Colorado	100%	40.0	2016
AIP Diesel	Oil	Pueblo, Colorado	100%	10.0	2001
Diesel #1 and #3-5	Oil	Pueblo, Colorado	100%	8.0	1964
Diesel #1-5	Oil	Rocky Ford, Colorado	100%	10.0	1964
South Dakota Electric:
Cheyenne Prairie ^(c)	Gas	Cheyenne, Wyoming	58%	55.0	2014
Wygen III^(d)	Coal	Gillette, Wyoming	52%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyoming	100%	90.0	1995
Wyodak Plant ^(e)	Coal	Gillette, Wyoming	20%	72.4	1978
Neil Simpson CT	Gas	Gillette, Wyoming	100%	40.0	2000
Lange CT	Gas	Rapid City, South Dakota	100%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, South Dakota	100%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, South Dakota	100%	80.0	1977-1979
Wyoming Electric:
Cheyenne Prairie ^(c)	Gas	Cheyenne, Wyoming	42%	40.0	2014
Cheyenne Prairie CT ^(c)	Gas	Cheyenne, Wyoming	100%	37.0	2014
Wygen II	Coal	Gillette, Wyoming	100%	95.0	2008
Total MW Capacity				939.1

________________________


(a)	Busch Ranch I is operated by Colorado Electric. In 2013, the facility was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act. Black Hills Electric Generation owns the remaining 50% interest in the wind farm. Colorado Electric has a PPA with Black Hills Electric Generation for its share of power from the wind farm.


(b)	The Peak View facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins. Peak View was placed in service in November 2016.


(c)	Cheyenne Prairie serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW).


(d)	Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our adjacent WRDC mine supplies all of the fuel for the plant.


(e)	Wyodak Plant, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by South Dakota Electric. This baseload plant is operated by PacifiCorp and our WRDC mine supplies all of the fuel for the plant.

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The Electric Utilities’ annual weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh for the years ended December 31 was as follows:



Fuel Source (dollars per MWh)	2019		2018		2017
Coal	$	11.46	$	11.10	$	10.95

Natural Gas	$	25.92	$	33.42	$	34.05

Diesel Oil ^(a)	$	209.86	$	329.27	$	210.11

Total Weighted Average Fuel Cost	$	13.86	$	13.53	$	12.80

Purchased Power - Coal, Gas and Oil	$	43.73	$	45.62	$	45.63

Purchased Power - Renewable Sources	$	48.61	$	54.31	$	53.08

______________


(a)	Included in the Price per MWh for Diesel Oil are unit start-up costs. The diesel-fueled generating units are generally used as supplemental peaking units and the cost per MWh is reflective of how often the units are started and how long the units are run.

Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended December 31 was as follows:



Power Supply	2019		2018		2017
Coal	30	%	32	%	32	%
Gas, Oil and Wind	12		10		8
Total Generated	42		42		40
Purchased ^(a)	58		58		60
Total	100	%	100	%	100	%

______________


(a)	Wind represents approximately 6%, 6% and 6% of our purchased power in 2019, 2018, and 2017, respectively.

Power Purchase and Power Sales Agreements. We have executed various PPAs to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Our Electric Utilities also have various long-term PSAs. Key contracts are disclosed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly own an electric transmission system, referred to as the Common Use System, with Basin Electric and Powder River Energy Corporation.

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At December 31, 2019, our Electric Utilities owned the electric transmission and distribution lines shown below:



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
Colorado Electric	Colorado	598	3,120
South Dakota Electric	South Dakota, Wyoming	1,219	2,557
South Dakota Electric - Jointly Owned ^(a)	South Dakota, Wyoming	43	—
Wyoming Electric	Wyoming	49	1,306
		1,909	6,983

__________________________

(a)

South Dakota Electric owns 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western and eastern United States, respectively. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids. See Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

Material contracts are disclosed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. Additional contracts disclosed below are also key to allowing us to serve our customer load:

Colorado Electric is party to a joint dispatch agreement with PSCo and PRPA. This FERC-approved agreement, effective in 2017, is structured to allow PSCo, as administrator, to receive load and generation bid information for all three parties and, on an intra-hour basis, serve the combined utility load utilizing the combined bid generating resources on a least-cost basis. In other words, if one party has excess generation at a lower cost than another party’s generation, the administrator will increase dispatch of the lower-cost generation and decrease dispatch of the higher-cost generation. This results in lower energy costs to customers through more efficient dispatch of low-cost generating resources. Under the agreement, Colorado Electric retains the ability to participate or not participate in the joint dispatch at its discretion.

South Dakota Electric has firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming, to serve our power sales contract with MDU through December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

Wyoming Electric has a firm network transmission agreement with Western Area Power Administration’s Loveland Area Project that allows us to serve our existing load in Cheyenne, Wyoming.

Operating Agreements. Our Electric Utilities have the following material operating agreements:


•	Shared Services Agreements -


◦	South Dakota Electric, Wyoming Electric, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity is charged for the use of assets located at the Gillette, Wyoming energy complex by the affiliate entity.


◦	Black Hills Colorado IPP and Colorado Electric are also parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric assets.


◦	South Dakota Electric and BHSC are parties to a shared facilities agreement, whereby BHSC is charged for the use of the Horizon Point facility that is owned by South Dakota Electric and BHSC provides certain operations and maintenance services at the facility.


◦	South Dakota Electric and Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.


•	Jointly Owned Facilities agreements are discussed in Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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Seasonal Variations of Business. Our Electric Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, demand is often greater in the summer and winter months for cooling and heating, respectively.

Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas. Various legislative or regulatory restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date, these initiatives have not had a material impact on our utilities. In Colorado, our electric utility is subject to rules which may require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-affiliated independent power producers for the right to provide electric energy and capacity for Colorado Electric when resource plans require additional resources.

Rates and Regulation. Our Electric Utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate and the FERC for certain assets. These commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities. The following table provides regulatory information for each of our Electric Utilities:



Subsidiary	Jurisdic-tion	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Authorized Capital Structure Debt/Equity	Authorized Rate Base (in millions)	Effective Date	Additional Tariffed Mechanisms	Percentage of Power Marketing Profit Shared with Customers

Colorado Electric	CO	9.37%	7.43%	47.6%/52.4%	$539.6	1/2017	ECA, TCA, PCCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment	90%
	CO	9.37%	6.02%	67.3%/32.7%	$57.9	1/2017	Clean Air Clean Jobs Act Adjustment Rider	N/A
South Dakota Electric	WY	9.9%	8.13%	46.7%/53.3%	$46.8	10/2014	ECA	65%
	SD	Global Settlement	7.76%	Global Settlement	$543.9	10/2014	ECA, Energy Efficiency Cost Recovery/DSM, TFA, EIA	70%
	FERC	10.8%	8.76%	43%/57%	$138.4 ^(a)	2/2009	FERC Transmission Tariff	N/A
Wyoming Electric	WY	9.9%	7.98%	46%/54%	$376.8	10/2014	PCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment	N/A
	FERC	10.6%	8.51%	46%/54%	$31.5	5/2014	FERC Transmission Tariff	N/A

__________


(a)	Includes $121.3 million in 2019 rate base for the Common Use System formula rate that is updated annually and $17.1 million in rate base for the DC transmission tie that is based on the approved stated rate from 2005.

The regulatory provisions for recovering the costs to supply electricity vary by state. In all states, subject to thresholds noted below, we have cost adjustment mechanisms for our Electric Utilities that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers. These mechanisms allow the utility operating in that state to collect, or refund the difference between the cost of commodities and certain services embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate review. In addition, some states allow for recovery of new capital investment placed in service between base rate reviews through approved rider tariffs. These tariffs allow the utility a return on the investment.

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A summary of mechanisms we have in place are shown in the table below:



Electric Utility Jurisdiction	Cost Recovery Mechanisms
Electric Utility Jurisdiction	Environmental Cost	Energy Efficiency	Transmission Expense	Fuel Cost	Transmission Capital	Purchased Power
Colorado Electric		þ	þ	þ	þ	þ
South Dakota Electric (SD)	þ	þ	þ	þ	þ	þ
South Dakota Electric (WY)		þ	þ	þ		þ
South Dakota Electric (FERC)					þ
Wyoming Electric		þ	þ	þ		þ

See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current electric rate activity.

The significant mechanisms we have in place include the following by utility:

Colorado Electric has:

•

A quarterly ECA rider that allows us to recover forecasted increases or decreases in purchased energy and fuel costs, including the recovery for amounts payable to others for the transmission of the utility's electricity over transmission facilities owned by others, and the sharing of off-system sales margins, less certain operating costs (customer receives 90%). The ECA provides for not only direct recovery, but also for the issuance of credits for decreases in purchased energy, fuel costs and eligible energy resources.


•	An annual TCA rider that includes nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism.


•	A Clean Air Clean Jobs Act Adjustment rider rate that collects the authorized revenue requirement for the 40 MW combustion turbine placed in service on December 31, 2016 with rates effective January 1, 2017.


•	A Renewable Energy Standard Adjustment rider that is specifically designed for meeting the requirements of Colorado’s renewable energy standard and most recently includes cost recovery for Peak View.

South Dakota Electric has:

•

An approved annual EIA tariff which recovers costs associated with generation plant environmental improvements. South Dakota Electric also has a TFA tariff which recovers the costs associated with transmission facility improvements. The EIA and TFA were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to extend the 6-year moratorium period by an additional 3 years whereby rate increases for these recovery mechanisms will not go into effect prior to July 1, 2026. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

•

An annual cost adjustment clause which provides for the over or under recovery of fuel, transmission and purchased power cost incurred to serve South Dakota customers. Additionally, this ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 100% of off-system power marketing operating income from the first $1.0 million of power marketing margin from short-term sales and a credit equal to 70% of power marketing margins from short-term sales in excess of the first $1.0 million. South Dakota Electric retains the remaining 30%. For the period of July 1, 2017 through March 31, 2023, the 100% credit of power marketing margin increased from $1.0 million to $2.0 million. The ECA methodology allows us to directly assign renewable resources and firm purchases to the customer load. In Wyoming, a similar fuel and purchased power cost adjustment is also in place.


•	An approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff.

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Wyoming Electric has:


•	An annual cost adjustment mechanism that allows us to pass the prudently-incurred power costs above costs included in base rates through to electric customers. The annual cost adjustment allows for recovery of 85% of coal and coal-related cost per kWh variances from base and recovery of 95% of purchased power, transmission, and natural gas cost per kWh variances from base.

Tariff Filings. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for tariff filings and additional information regarding current rate activity.

Operating Statistics. The following tables summarize information for our Electric Utilities:



	For the year ended December 31,
Degree Days	2019		2018		2017
	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	5,453	(3)%	5,119	4%	4,693	(16)%
South Dakota Electric	8,284	16%	7,749	8%	6,870	(4)%
Wyoming Electric	7,406	1%	7,036	(7)%	6,623	(12)%

Combined ^(a)	6,813	5%	6,405	3%	5,826	(11)%

Cooling Degree Days:
Colorado Electric	1,226	37%	1,420	58%	1,027	14%
South Dakota Electric	404	(36)%	488	(23)%	709	11%
Wyoming Electric	462	33%	430	24%	429	23%

Combined ^(a)	791	14%	902	29%	798	14%

________________


(a)	The combined degree days are calculated based on a weighted average of total customers by state.



	Electric Revenue (in thousands)						Quantities Sold (MWh)
	For the year ended December 31,						For the year ended December 31,
	2019		2018		2017		2019	2018	2017
Residential	$	216,108	$	218,558	$	210,172	1,440,551	1,450,585	1,390,952
Commercial	246,704		250,894		258,754		2,055,253	2,034,917	2,038,495
Industrial	131,831		124,668		122,958		1,787,412	1,682,074	1,598,755
Municipal	17,206		17,871		18,144		157,298	160,913	160,882
Subtotal Retail Revenue - Electric	611,849		611,991		610,028		5,440,514	5,328,489	5,189,084
Contract Wholesale ^(a)	19,078		33,688		30,435		368,360	900,854	722,659
Off-system/Power Marketing Wholesale	25,622		24,800		21,111		701,633	673,994	661,263
Other	56,203		40,972		43,076		—	—	—
Total Revenue and Energy Sold	712,752		711,451		704,650		6,510,507	6,903,337	6,573,006
Other Uses, Losses or Generation, net ^(b)	—		—		—		393,573	470,250	468,179
Total Revenue and Energy	712,752		711,451		704,650		6,904,080	7,373,587	7,041,185
Less cost of fuel and purchased power ^(c)	268,297		283,840		274,363
Gross Margin (non-GAAP) ^(c) ^(d)	$	444,455	$	427,611	$	430,287

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	Electric Revenue (in thousands)						Gross Margin (non-GAAP) ^(d) (in thousands)						Quantities Sold (MWh)
	For the year ended December 31,						For the year ended December 31,						For the year ended December 31,
	2019		2018		2017		2019		2018		2017		2019	2018	2017
Colorado Electric ^(c)	$	247,332	$	251,218	$	251,090	$	137,323	$	138,901	$	140,121	2,180,985	2,151,918	2,091,676
South Dakota Electric ^(a)	291,219		298,080		288,433		218,104		205,194		200,795		2,798,887	3,360,396	3,187,392
Wyoming Electric	174,201		162,153		165,127		89,028		83,516		89,371		1,924,208	1,861,273	1,762,117
Total Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	712,752	$	711,451	$	704,650	$	444,455	$	427,611	$	430,287	6,904,080	7,373,587	7,041,185

________________


(a)	2019 revenue and purchased power, as well as associated quantities, for a certain wholesale contract have been presented on a net basis. Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This 2019 presentation change has no impact on Gross margin.


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

(c)

Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, cost of fuel and purchased power was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in an increase of $6.7 million and $6.0 million, respectively. There were corresponding decreases to Gross margin for both years. These changes had no impact on consolidated financial results.


(d)	For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.



	For the year ended December 31,
Quantities Generated and Purchased (MWh)	2019	2018	2017

Coal-fired	2,226,028	2,368,506	2,230,617
Natural Gas and Oil	600,002	446,373	307,815
Wind	238,999	253,180	239,472
Total Generated	3,065,029	3,068,059	2,777,904
Purchased ^(a)	3,839,051	4,305,528	4,263,281
Total Generated and Purchased	6,904,080	7,373,587	7,041,185



	For the year ended December 31,
Quantities Generated and Purchased (MWh)	2019	2018	2017
Generated:
Colorado Electric	443,770	481,446	397,965
South Dakota Electric	1,768,456	1,734,222	1,581,915
Wyoming Electric	852,803	852,391	798,024
Total Generated	3,065,029	3,068,059	2,777,904
Purchased:
Colorado Electric	1,737,215	1,670,472	1,693,711
South Dakota Electric ^(a)	1,030,431	1,626,174	1,605,477
Wyoming Electric	1,071,405	1,008,882	964,093
Total Purchased	3,839,051	4,305,528	4,263,281

Total Generated and Purchased	6,904,080	7,373,587	7,041,185

________________


(a)	2019 purchased power quantities for a wholesale contract have been presented on a net basis. Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This 2019 presentation change has no impact on Gross margin.

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	As of December 31,
Customers at End of Year	2019	2018	2017
Residential	183,232	181,459	179,911
Commercial	29,921	29,299	29,354
Industrial	83	84	86
Other	1,024	1,030	914
Total Electric Customers at End of Year	214,260	211,872	210,265



	As of December 31,
Customers at End of Year	2019	2018	2017
Colorado Electric	97,890	96,645	95,951
South Dakota Electric	73,052	72,533	72,184
Wyoming Electric	43,318	42,694	42,130
Total Electric Customers at End of Year	214,260	211,872	210,265

Gas Utilities Segment

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

We also provide non-regulated services to our regulated customers. Black Hills Energy Services provides natural gas supply to approximately 49,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide services under the Service Guard Comfort Plan and Tech Services and also offer HomeServe products.

We procure natural gas for our distribution customers from a diverse mix of producers, processors and marketers and generally use hedging, physical fixed-price purchases and market-based price purchases to achieve dollar-cost averaging within our natural gas portfolio. The majority of our procured natural gas is transported in interstate pipelines under firm transportation service agreements.

In addition to company-owned storage assets in Arkansas, Colorado and Wyoming, we also contract with many of the third-party transportation providers noted above for natural gas storage service to provide gas supply during the winter heating season and to meet peak day customer demand for natural gas.

The following table summarizes certain information regarding our regulated underground gas storage facilities as of December 31, 2019:



State	Working Capacity (Mcf)	Cushion Gas (Mcf)	Total Capacity (Mcf)	Maximum Daily Withdrawal Capability (Mcfd)
State	Working Capacity (Mcf)	Cushion Gas (Mcf)	Total Capacity (Mcf)	Maximum Daily Withdrawal Capability (Mcfd)
Arkansas	8,442,700	13,149,040	21,591,740	196,000
Colorado	2,360,895	6,165,315	8,526,210	30,000
Wyoming	5,733,900	17,145,600	22,879,500	36,000
Total	16,537,495	36,459,955	52,997,450	262,000

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The following tables summarize certain operating information for our Gas Utilities.



System Infrastructure (in line miles) as of	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
December 31, 2019	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
Arkansas	942	4,880	1,161
Colorado	693	6,814	2,554
Iowa	165	2,813	2,138
Kansas	330	2,910	1,355
Nebraska	1,311	8,664	3,230
Wyoming	1,334	3,472	1,219
Total	4,775	29,553	11,657



	For the year ended December 31,
Degree Days	2019		2018		2017
	Actual	Variance From Normal	Actual	Variance From Normal	Actual	Variance From Normal
Heating Degree Days:
Arkansas ^(a)	3,897	(4)%	4,169	3%	3,295	(19)%
Colorado	6,672	1%	6,136	(7)%	5,728	(14)%
Iowa	7,200	6%	7,192	6%	6,149	(9)%
Kansas ^(a)	5,190	6%	5,242	7%	4,452	(9)%
Nebraska	6,578	7%	6,563	6%	5,554	(10)%
Wyoming	8,010	7%	7,425	(1)%	7,123	(5)%
Combined^(b)	6,840	5%	6,628	2%	5,862	(10)%

________________


(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 Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as market price. In particular, demand is often greater in the winter months for heating. Natural gas is used primarily for residential and commercial heating, so the demand for this product depends heavily upon weather throughout our service territories and as a result, a significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters. Demand for natural gas can also be impacted by summer weather patterns that are cooler than normal and/or provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation.

Competition. We generally have limited competition for the retail distribution of natural gas in our service areas. Various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives are aimed at increasing competition. To date, these initiatives have not had a material impact on our utilities. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial customers, in instances where independent marketers displace us as the seller of natural gas, we still collect a distribution charge for transporting the gas through our distribution network.

Rates and Regulation. Our Gas Utilities are subject to the jurisdiction of the public utility commissions in the states where they operate. These commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities.

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Our Gas Utilities are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure that they recover all the costs prudently incurred in purchasing gas for their customers. In addition to natural gas cost recovery mechanisms, we have other recovery mechanisms, which vary by utility, but allow us to recover certain costs or earn a return on capital investments, such as energy efficiency plan costs and system safety and integrity investments. The following table provides regulatory information for each of our natural gas utilities:



Subsidiary	Jurisdic-tion	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Authorized Capital Structure Debt/Equity	Authorized Rate Base (in millions)	Effective Date	Additional Tariffed Mechanisms
Gas Utilities:
Arkansas Gas	AR	9.61%	6.82% ^(a)	50.9%/49.1%	$451.5 ^(b)	10/2018	GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, Energy Efficiency, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas	CO	9.6%	8.41%	50%/50%	$57.5	12/2012	GCA, Energy Efficiency Cost Recovery/DSM
Colorado Gas Dist.	CO	10.0%	8.02%	49.52%/ 50.48%	$127.1	12/2010	GCA, Energy Efficiency Cost Recovery/DSM
RMNG	CO	9.9%	6.71%	53.37%/ 46.63%	$118.7	6/2018	System Safety Integrity Rider, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas	IA	Global Settlement	Global Settlement	Global Settlement	$109.2	2/2011	GCA, Energy Efficiency Cost Recovery, Capital Infrastructure Automatic Adjustment Mechanism, Farm Tap Tracker Adjustment, Gas Supply Optimization revenue sharing
Kansas Gas	KS	Global Settlement	Global Settlement	Global Settlement	$127.9	1/2015	GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Pension Levelized Adjustment
Nebraska Gas	NE	10.1%	9.11%	48%/52%	$161.0	9/2010	GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge, Farm Tap Recovery Mechanism
Nebraska Gas Dist.	NE	9.6%	7.67%	48.84%/ 51.16%	$87.6/ $69.8 ^(c)	6/2012	Choice Gas Program, System Safety and Integrity Rider, Bad Debt expense recovered through Choice Supplier Fee
Wyoming Gas	WY	9.4%	6.98	49.77%/50.23%	$354.4	3/2020	GCA, Energy Efficiency Cost Recovery, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program

__________


(a)	Arkansas Gas return on rate base is adjusted to remove current liabilities from rate review capital structure for comparison with other subsidiaries.


(b)	Arkansas Gas rate base is adjusted to include current liabilities for comparison with other subsidiaries.


(c)	Total Nebraska Gas Distribution rate base of $87.6 million includes amounts allocated to serve non-jurisdictional customers. Jurisdictional Nebraska rate base totals $69.8 million and is used for calculation of jurisdictional base rates.

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All of our Gas Utilities, except where the Choice Gas Program is the only option, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer between rate reviews. Some of the mechanisms we have in place include the following:



Gas Utility Jurisdiction	Cost Recovery Mechanisms
Gas Utility Jurisdiction	Energy Efficiency	Integrity Additions	Bad Debt	Weather Normal	Pension Recovery	Gas Cost	Billing Determinant Adjustment
Arkansas Gas	þ	þ		þ		þ	þ
Colorado Gas	þ					þ
Colorado Gas Distribution	þ					þ
RMNG	N/A	þ	N/A	N/A	N/A	N/A	N/A
Iowa Gas	þ	þ				þ
Kansas Gas		þ	þ	þ	þ	þ
Nebraska Gas		þ	þ			þ
Nebraska Gas Distribution		þ	þ
Wyoming Gas ^(a)	þ	þ				þ

__________


(a)	The Wyoming Gas integrity rider is effective March 1, 2020.

See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current rate activity.

Operating Statistics



	Revenue (in thousands)								Gross Margin (non-GAAP) ^(a)(in thousands)								Quantities Sold and Transported (Dth)
	For the year ended December 31,								For the year ended December 31,								For the year ended December 31,
	2019			2018			2017		2019			2018			2017		2019	2018	2017

Residential	$	551,701		$	567,785		$	499,852	$	285,802		$	276,858		$	255,626	66,956,080	65,352,164	54,645,598
Commercial	212,229			214,718			197,054		88,264			82,529			78,249		32,241,441	30,753,361	27,315,871
Industrial	24,832			26,466			24,454		8,053			7,056			6,226		6,548,023	6,309,211	5,855,053
Other	(1,361		)	(7,899		)	8,647		(1,361		)	(7,899		)	8,647		—	—	—
Total Distribution	787,401			801,070			730,007		380,758			358,544			348,748		105,745,544	102,414,736	87,816,522

Transportation and Transmission	144,710			141,854			135,824		144,710			141,850			135,824		153,101,264	148,299,003	141,600,080

Total Regulated	932,111			942,924			865,831		525,468			500,394			484,572		258,846,808	250,713,739	229,416,602

Non-regulated Services	77,919			82,383			81,799		58,664			62,760			53,455		—	—	—

Total Revenue, Gross Margin (non-GAAP) and Quantities Sold	$	1,010,030		$	1,025,307		$	947,630	$	584,132		$	563,154		$	538,027	258,846,808	250,713,739	229,416,602

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	Revenue (in thousands)						Gross Margin (non-GAAP) ^(a)(in thousands)						Quantities Sold & Transported (Dth)
	For the year ended December 31,						For the year ended December 31,						For the year ended December 31,
	2019		2018		2017		2019		2018		2017		2019	2018	2017

Arkansas	$	185,201	$	176,660	$	153,691	$	115,899	$	100,917	$	94,007	30,496,243	30,931,390	26,491,537
Colorado	199,369		188,002		180,852		106,776		99,851		100,718		33,908,529	29,857,063	28,436,744
Iowa	151,619		161,843		143,446		70,290		68,384		66,619		41,795,729	40,668,682	37,013,645
Kansas	105,906		112,306		105,576		58,020		55,226		53,841		32,650,854	31,387,672	28,251,947
Nebraska	255,622		278,969		252,631		155,901		164,513		154,259		81,481,192	81,658,938	73,890,509
Wyoming	112,313		107,527		111,434		77,246		74,263		68,583		38,514,261	36,209,994	35,332,220
Total Revenue, Gross Margin (non-GAAP) and Quantities Sold	$	1,010,030	$	1,025,307	$	947,630	$	584,132	$	563,154	$	538,027	258,846,808	250,713,739	229,416,602

________________


(a)	For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.



	As of December 31,
Customers at End of Year	2019	2018	2017

Residential	831,351	821,624	806,744
Commercial	82,912	82,498	86,461
Industrial	2,208	2,221	2,214
Transportation/Other	149,971	147,550	146,839
Total Customers at End of Year	1,066,442	1,053,893	1,042,258



	As of December 31,
Customers at End of Year	2019	2018	2017

Arkansas	174,447	171,978	169,303
Colorado	191,950	186,759	181,876
Iowa	159,641	158,485	157,444
Kansas	115,846	114,840	114,082
Nebraska	293,576	291,723	290,264
Wyoming	130,982	130,108	129,289
Total Customers at End of Year	1,066,442	1,053,893	1,042,258

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Utility Regulation Characteristics

State Regulations

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. As of December 31, 2019, we were subject to the following renewable energy portfolio standards or objectives:

•

Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% maximum annual retail rate impact for compliance with the electric resource standards. The electric resource standards require our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 20% of retail sales from 2015 to 2019; and (ii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) is limited to 2%. The standard encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We have been and currently remain in compliance with these standards.

On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric under a 25-year PPA, which expires in November 2044. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard.

•

Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, South Dakota Electric filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. In March 2013, the Montana Legislature adopted legislation that had the effect of excluding South Dakota Electric from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers South Dakota Electric has in Montana and the relatively high cost of meeting the renewable requirements.


•	South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015.


•	Wyoming. Wyoming currently has no renewable energy portfolio standard.

Absent a specific renewable energy mandate in the territories we serve, our current strategy is to proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. Mandatory portfolio standards have increased, and will likely continue to increase, the power supply costs of our Electric Utilities’ operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Federal Regulation

Energy Policy Act. BHC is a holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and a holding company regulated by FERC under the Federal Power Act and PUHCA 2005.

Federal Power Act. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must maintain tariffs and rate schedules on file with FERC that govern the rates, and terms and conditions for the provision of FERC-jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their affiliates. Our public Electric Utilities’ subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.

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Our Electric Utilities and Power Generation entities are authorized by FERC to make wholesale sales of electric capacity and energy at market-based rates under tariffs on file with FERC. As a condition of their market-based rate authority, each files Electric Quarterly Reports with FERC. Our Electric Utilities own and operate FERC-jurisdictional interstate transmission facilities and provide open access transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to their compliance with FERC’s regulations.

The Federal Power Act authorizes FERC to certify and oversee a national electric reliability organization with authority to promulgate and enforce mandatory reliability standards applicable to all users, owners and operators of the bulk-power system. FERC has certified NERC as the electric reliability organization. NERC has promulgated mandatory reliability standards and NERC, in conjunction with regional reliability organizations that operate under FERC’s and NERC’s authority and oversight, enforces those mandatory reliability standards.

PUHCA 2005. PUHCA 2005 gives FERC authority with respect to the books and records of a utility holding company. As a utility holding company with a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.

Power Generation Segment

Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops, constructs and operates our non-regulated power plants. As of December 31, 2019, we held varying interests in independent power plants with a total net ownership of approximately 423 MW.

We produce electric power from our generating plants and sell the electric capacity and energy, primarily to affiliates under a combination of mid- to long-term contracts, which mitigates the impact of a potential downturn in future power prices. We currently sell a majority of our non-regulated generating capacity under contracts having terms greater than one year.

As of December 31, 2019, the power plant ownership interests held by our Power Generation segment include:



Power Plants	Fuel Type	Location	Ownership Interest	Owned Capacity (MW)	In Service Date
Wygen I ^(a)	Coal	Gillette, Wyoming	76.5%	68.9	2003
Pueblo Airport Generation	Gas	Pueblo, Colorado	50.1%	200.0	2012
Busch Ranch I ^(b)	Wind	Pueblo, Colorado	50.0%	14.5	2012
Busch Ranch II ^{(c) (e)}	Wind	Pueblo, Colorado	100.0%	60.0	2019
Top of Iowa ^{(d) (e)}	Wind	Joice, Iowa	100.0%	80.0	2019
				423.4

_________________________


(a)	The Wygen I generation facility is a mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5% of the plant and MEAN owns the remaining 23.5%.


(b)	On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in Busch Ranch I. This facility originally qualified under the Section 1603 program grant in lieu of ITCs.


(c)	On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II.


(d)	On February 5, 2019, Black Hills Electric Generation purchased 80 MW of wind generating assets in Iowa. A third-party operates the facility and we sell the wind energy generated in the MISO market.


(e)	This facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service.

Power Sales Agreements. Our Power Generation facilities have various long-term power sales agreements. See Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

Third Party Noncontrolling Interest in Subsidiary. In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third party buyer. See Note 12 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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The following table summarizes MWh for our Power Generation segment:



	For the year ended December 31,
Quantities Sold, Generated and Purchased (MWh) ^(a)	2019	2018	2017
Sold
Black Hills Colorado IPP	935,997	1,000,577	943,618
Black Hills Wyoming^(b)	629,788	582,938	645,810
Black Hills Electric Generation ^(c)	167,296	5,873	—
Total Sold	1,733,081	1,589,388	1,589,428

Generated
Black Hills Colorado IPP	935,997	1,000,577	943,618
Black Hills Wyoming ^(b)	557,119	501,945	577,124
Black Hills Electric Generation ^(c)	167,296	5,873	—
Total Generated	1,660,412	1,508,395	1,520,742

Purchased
Black Hills Wyoming ^(b)	74,199	83,213	69,377
Total Purchased	74,199	83,213	69,377

____________________


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

(b)

Under the 20-year economy energy PPA (discussed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K) with the City of Gillette, 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.


(c)	Black Hills Electric Generation amounts in this table are related to wind facilities held by our Power Generation segment. Change from 2018 to 2019 is driven by acquisition, and placing in service, of new wind assets.

Operating Agreements. Our Power Generation segment has the following material operating agreements:


•	Black Hills Wyoming’s economy energy PPA and other ancillary agreements are discussed in Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


•	Operating and Maintenance Services Agreement

◦

In conjunction with the sale of a noncontrolling interest in 2016, an operating and maintenance services agreement was entered into between Black Hills Electric Generation and Black Hills Colorado IPP. This agreement sets forth the obligations and responsibilities of Black Hills Electric Generation as the operator of the generating facility owned by Black Hills Colorado IPP. This agreement became effective on the date of the noncontrolling interest purchase and remains effective as long as the operator or one of its affiliates is responsible for managing the generating facilities in accordance with the noncontrolling interest agreement, or until termination by owner or operator.

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•	Shared Services Agreements


◦	South Dakota Electric, Wyoming Electric and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity is charged for the use of assets by the affiliate entity.


◦	Black Hills Colorado IPP and Colorado Electric are parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric’s assets.


◦	Black Hills Colorado IPP, Wyoming Electric and South Dakota Electric are parties to a Spare Turbine Use Agreement, whereby Black Hills Colorado IPP charges South Dakota Electric and Wyoming Electric a monthly fee for the availability of a spare turbine to support the operation of Cheyenne Prairie.


◦	Black Hills Colorado IPP and Black Hills Wyoming receive certain staffing and management services from BHSC.


•	Jointly owned facilities agreements are discussed in Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess.

With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity and foster competition within the wholesale electricity markets. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for independent power producers in some regions.

The Energy Policy Act of 1992. The passage of the Energy Policy Act of 1992 encouraged independent power production by providing certain exemptions from regulation for EWGs. EWGs are exclusively in the business of owning or operating, or both owning and operating, eligible power facilities and selling electric energy at wholesale. EWGs are subject to FERC regulation, including rate regulation. We own five EWGs: Wygen I, Pueblo Airport Generation, Busch Ranch I, Busch Ranch II and Top of Iowa. Our EWGs were granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates.

Mining Segment

Our Mining segment operates through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC mine, which we acquired in 1956 from Homestake Mining Company, is located in the Powder River Basin in eastern Wyoming. We produced approximately 3.7 million tons of coal in 2019.

During our surface mining operations, we strip and store the topsoil. We then remove the overburden (earth and rock covering the coal) with heavy equipment. Removal of the overburden typically requires drilling and blasting. Once the coal is exposed, we drill, fracture and systematically remove it, using front-end loaders and conveyors to transport the coal to the mine-mouth generating facilities. We reclaim disturbed areas as part of our normal mining activities by back-filling the pit with overburden removed during the mining process. Once we have replaced the overburden and topsoil, we reestablish vegetation and plant life in accordance with our approved post-mining topography plan.

In a basin characterized by thick coal seams, our overburden ratio, a comparison of the cubic yards of dirt removed to a ton of coal uncovered, has in recent years trended upwards. The overburden ratio at December 31, 2019 was 2.30 which increased from the prior year as we continued mining in areas with higher overburden. We expect our stripping ratio to be approximately 2.18 by the end of 2020 as we mine in areas with comparable overburden.

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Mining rights to the reserves are based on three federal leases and one state lease. The federal leases expire between March 31, 2021 and September 30, 2025 and the state lease expires on August 1, 2023. The duration of the leases varies; however, the lease terms generally are extended to the exhaustion of economically recoverable reserves, as long as active mining continues. We pay federal and state royalties of 12.5% of the selling price of all coal. As of December 31, 2019, we estimated our recoverable reserves to be approximately 185 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable reserve life is equal to approximately 50 years at the current production levels. Our recoverable reserve estimates are periodically updated to reflect past production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable reserves include reserves that can be economically and legally extracted at the time of their determination.

Substantially all of the mine’s production is currently sold under contracts to:


•	South Dakota Electric for use at the 90 MW Neil Simpson II plant to which we sell approximately 500,000 tons each year. This contract is for the life of the plant;


•	Wyoming Electric for use at the 95 MW Wygen II plant to which we sell approximately 550,000 tons each year. This contract is for the life of the plant;

•

The 362 MW Wyodak Plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 375,000 tons per year for its 20% share of the power plant, subject to adjustments for planned outages. This contract expires December 31, 2022 and negotiations are underway to extend the contract;


•	The 110 MW Wygen III power plant owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons each year. This contract expires June 1, 2060;


•	The 90 MW Wygen I power plant owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons each year. This contract expires June 30, 2038; and


•	Certain regional industrial customers served by truck to which we sell a total of approximately 150,000 tons each year. These contracts have terms of one to five years.

Our Mining segment sells coal to South Dakota Electric and Wyoming Electric for all of their requirements under cost-based agreements that regulate earnings from these affiliate sales to a specified return on our mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above Moody’s A-Rated Utility Bond Index applied to our Mining investment base. South Dakota Electric made a commitment to the SDPUC, the WPSC and the City of Gillette that coal for South Dakota Electric’s operating plants would be furnished and priced as provided by that agreement for the life of the Neil Simpson II plant and through June 1, 2060, for Wygen III. The agreement with Wyoming Electric provides coal for the life of the Wygen II plant.

The price of unprocessed coal sold to PacifiCorp for the Wyodak Plant is determined by the supply agreement described above. The agreement included a price adjustment in 2019. The price adjustment essentially allowed us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment was based on market price plus considerations for the avoided costs of rail transportation and an unloading facility, which PacifiCorp would have to incur if it purchased from another mine. In addition, the agreement also provided for the monthly escalation of price based on an escalation factor.

In October 2019, negotiations were completed for the price re-opener in the contract with Wyodak Plant. The new price was

reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton. The current contract price is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of an unloading facility (approximately 30% of current price); and 3) a rolling 12-month average of the Coal Daily spot market price of 8,400 Btu Powder River Basin coal (approximately 50% of current price).

WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement using a base price that includes price escalators and quality adjustments through June 30, 2038 and includes actual cost per ton plus a margin equal to the yield for Moody’s A-Rated Utility Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. The agreement stipulates that WRDC will supply coal to the 90 MW Wygen I plant through June 30, 2038.

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Competition. Our strategy is to sell the majority of our production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically, any off-site sales have been to consumers within close proximity to the WRDC mine. Rail transport market opportunities for WRDC are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC mine is served by only one railroad, resulting in less competitive transportation rates. Management continues to explore the limited market opportunities for our product through truck transport.

Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental considerations and availability affect the overall demand for coal as a fuel.

Environmental Matters. We are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. See Environmental Matters section for further information.

Mine Reclamation. Reclamation is required during production and after mining has been completed. Under applicable law, we must submit applications to, and receive approval from, the WDEQ for any mining and reclamation plans that provide for orderly mining, reclamation and restoration of the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC mine is permitted to operate under a five-year mining permit issued by the State of Wyoming. In 2016, that five-year permit was re-issued. Based on extensive reclamation studies, we have accrued approximately $14 million for reclamation costs as of December 31, 2019. See additional information in Note 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Environmental Matters

Methane Rules (Greenhouse Gas Emissions). The EPA and the State of Colorado have implemented strict regulatory requirements on hydrocarbon and methane emissions associated with natural gas gathering and transmission systems. The BLM repealed similar hydrocarbon and methane emissions reductions it previously established under the Methane Rule (Venting and Flaring rule). Presently, we have four facilities in our Colorado natural gas transmission operations affected by the hydrocarbon and methane reduction rules.

Our operations are currently in compliance with both EPA and State of Colorado rules. Future modifications to our gathering and transmissions systems are anticipated to trigger EPA methane rules. We plan to develop a corporate-wide methane control strategy to address GHG emissions as we anticipate this will be a requirement in future rule-making efforts.

Water Issues. Our facilities are subject to a variety of state and federal regulations governing existing and potential water/ wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through EPA’s surface water discharge and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013, and published the final rule on November 3, 2015. In 2017, the EPA postponed the implementation of the rule and set a timeline in 2018 to revise the rule. To date, the rule is being reviewed by the Office of Management and Budget. This rule will have an impact on the Wyodak Plant. Until the EPA issues the rule for publication, we cannot quantify what the potential impact may be on the Wyodak Plant. The terms of this new regulation may impact the next permit renewal, which will be in 2020.

Short-term Emission Limits. The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for SO2, NOx and opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.

We proactively manage this requirement through maintenance efforts and installing additional pollution control systems to control SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut the power plant down if a predicted emission limit is to be exceeded. Similar efforts have been taken and similar results achieved with our natural gas fired combustion turbine sites as well.

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Regional Haze (Impacts to the Wyodak Plant). The EPA Regional Haze rule was promulgated to improve visibility in our National Parks and Wilderness Areas. The State of Wyoming proposed controls in its Regional Haze State Implementation Plan (SIP) which allowed PacifiCorp to install low-NO_x burners in the Wyodak Plant, of which South Dakota Electric owns 20%. The EPA did not agree with the State of Wyoming’s determination and overruled it in a Federal Implementation Plan (FIP). The State of Wyoming and other interested parties are challenging the EPA’s determination. If the challenge is unsuccessful, additional capital investment would be necessary to bring the Wyodak Plant into compliance. South Dakota Electric’s 20% share of this capital investment for the facility would be approximately $27 million if PacifiCorp is required to install a Selective Catalytic Reactor for NO_x control. The case is currently held in abeyance at the 10th circuit court as the parties work on a settlement. Basin Electric, who is part of the legal action, settled with the EPA. In lieu of going to court, PacifiCorp entered into mediation with the EPA and conservation groups. PacifiCorp submitted a “Request for Reconsideration” on October 24, 2019 to the EPA and provided a copy to the court. The purpose of the submittal is to revisit the emission impacts and cost of additional investment.

Mining. Operations at the WRDC mine must regularly address issues related to the proximity of the mine disturbance boundary to the City of Gillette and to residential and industrial properties. Homeowner complaints and challenges to the permits may occur as mining operations move closer to residential areas. Specific concerns could include damage to wells, fugitive dust emissions, vibration and an emissions cloud from blasting.

Former Manufactured Gas Plants (FMGP). Federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. We are currently in discussions with the EPA, state regulators, and/or other third-parties to determine the ultimate resolution to these sites. As of December 31, 2019, our Gas Utilities have two active FMGP sites, which are located in Council Bluffs, Iowa, and McCook, Nebraska. For the Council Bluffs site, the delay in clean-up is due to identifying the Potential Responsible Parties (PRPs or Successors to the Operators) to pay for the clean-up. We are the landowner and not the Successors to the Operator, whom would be responsible for paying for the majority of clean-up. We have been working with the EPA to identify the PRPs. The EPA has sent out information requests to the PRPs seeking transaction documents to determine the Successors to the Operators of the site who created the contamination. For the McCook, Nebraska site, we have been contacted by a third-party who intends to manage and pay for the clean-up at this site. The third-party is conducting site assessments and working with the State of Nebraska on a clean-up plan.

Affordable Clean Energy Rule. The EPA was directed to repeal, revise, and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy rule. This rule focuses on heat-rate improvements on coal-fired boiler units. In July 2019, the rule was finalized and applies only to our coal-fired plants. These plants have implemented or plan to implement a majority of the efficiency requirements listed in the rule.

OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR which is currently effective and establishes requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because ash is used for backfill reclamation in areas previously mined. The current administration has not pursued further modification of the CCR.

Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Other Properties

In addition to the facilities previously disclosed in Items 1 and 2, we own or lease several facilities throughout our service territories. Our owned facilities are as follows:


•	In Rapid City, South Dakota, we have a 220,000 square foot corporate headquarters building, Horizon Point, which was completed in 2017.


•	In Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 1,030,000 square feet utilized by our Gas Utilities.


•	In Colorado, South Dakota, and Wyoming we own various office, service center, storage, shop and warehouse space totaling approximately 305,000 square feet utilized by our Electric Utilities and Mining segments.

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In addition to our owned properties, we lease 92,527 square feet of properties within our service areas.

Substantially all of the tangible utility properties of South Dakota Electric and Wyoming Electric are subject to liens securing first mortgage bonds issued by South Dakota Electric and Wyoming Electric, respectively.

Employees

At December 31, 2019, we had 2,944 employees. Approximately 25% of our employees are represented by a union. We have not experienced any labor stoppages in recent years. At December 31, 2019, approximately 22% of our total employees and 25% of our Electric and Gas Utilities employees were eligible for regular (age 65 with at least 5 years of service) or early (ages 55 to 64 with at least 5 years of service) retirement.

The following table sets forth the number of employees included in continuing operations:



	Number of Employees
	At December 31, 2019
Corporate and Shared Services	1,273
Electric Utilities and Gas Utilities	1,609
Power Generation and Mining	62
Total	2,944

At December 31, 2019, certain employees of our Electric Utilities and Gas Utilities were covered by the following collective bargaining agreements:



Utility	Number of Employees	Union Affiliation	Expiration Date of Collective Bargaining Agreement
Colorado Electric	102	IBEW Local 667	April 15, 2023
South Dakota Electric	135	IBEW Local 1250	March 31, 2024
Wyoming Electric	23	IBEW Local 111	June 30, 2024
Iowa Gas	113	IBEW Local 204	July 31, 2020
Kansas Gas	18	Communications Workers of America, AFL-CIO Local 6407	December 31, 2024
Nebraska Gas	99	IBEW Local 244	March 13, 2022
Nebraska Gas ^(a)	146	CWA Local 7476	October 30, 2019
Wyoming Gas ^(a)	101	CWA Local 7476	October 30, 2019
Total	737

__________


(a)	In the 2016 negotiations with the CWA Local 7476, the union agreed to disclaim their interest in Colorado Gas employees and to split the remaining bargaining unit into two distinct bargaining units, Nebraska Gas and Wyoming Gas. There are ongoing negotiations with both bargaining units at this time.


ITEM 1A.	RISK FACTORS

OPERATING RISKS

The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.

Our continued success is dependent on execution of our strategic business plans and growth strategy.

Our results of operations depend, in significant part, on our ability to execute our strategic business plans and growth strategy. Technology advancements, disruptive forces and innovations in the marketplace and changing business or regulatory conditions may negatively impact our current plans and strategies. An inability to successfully and timely adapt to changing conditions and execute our strategic plans and growth strategy could materially affect our financial operating results including earnings, cash flow and liquidity.

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We may be subject to unfavorable federal and state regulatory outcomes.

Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and eight state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our various regulatory authorities will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in full recovery of our costs and the allowed return on invested capital. In addition, rate decisions could be influenced by many factors, including general economic conditions and the political environment.

Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and the state utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect financial operating results including earnings, cash flow and liquidity.

We may be subject to future laws, regulations, or actions associated with fossil-fuel generation and GHG emissions.

We own and operate regulated and unregulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase and deliver natural gas to our customers. These business activities are subject to evolving public concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.

Increased rules and regulations associated with fossil fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution, generation and storage facilities or coal mine. Further, these rules could create the need to purchase or build clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity.

Our financial performance depends on the successful management of our facilities operations, including ongoing operation, construction, expansion, and refurbishment.

Operation, construction, expansion and refurbishment of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities, and a coal mine involve risks that could result in fires, explosions, property damage and personal injury, including death. These risks include:


•	Inherent dangers. Electricity and natural gas are dangerous for employees and the general public; contact with power lines, natural gas pipelines, electrical or natural gas service facilities and equipment can result in fires and explosions, causing significant property damage and personal injuries, including death;

•

Weather, natural conditions and disasters. Severe weather events could negatively impact operations, including our ability to provide energy safely and reliably and our ability to complete construction, expansion or refurbishment of facilities as planned. Extreme natural conditions and other disasters such as wind, lightning, flooding and winter storms, can cause wildfires, electric transmission or distribution pole failures, natural gas pipeline interruptions, outages, property damage and personal injury;


•	Operating hazards. Operating hazards such as leaks, mechanical problems and accidents, including fires or explosions could impact employee and public safety, reliability and customer confidence;

•

Labor and labor relations. The cost of recruiting and retaining skilled technical labor or the unavailability of such resources could have a negative impact on our operations. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2019, approximately 25% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk; approximately 25% of our employees are represented by a total of eight collective bargaining agreements.

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•	Equipment and processes. Breakdown or failure of equipment or processes, the unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology.

•

Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically, or with cyber means, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;

•

Natural gas supply for generation and distribution. Our utilities purchase natural gas from a number of suppliers for our generating facilities and for distribution to our customers. Our results of operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limit our utilities’ ability to operate their facilities;


•	Replacement power. The cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities could negatively impact our results of operations;


•	Governmental permits. The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate and our results of operations;


•	Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and contractual agreements, including those that restrict the timing of generation plant scheduled outages, could negatively impact our results of operations;


•	Increased costs. Increased capital and operating costs to comply with increasingly stringent environmental and pipeline safety laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;


•	Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses.


•	Disruption in the functioning of our information technology and network infrastructure which is vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions.

The ongoing operation of our business involves the risks described above, in addition to risks associated with threats to our overall business model, such as electrification initiatives. Any of these risks could cause us to experience negative financial results and damage to our reputation and public confidence. These risks could cause us to incur significant costs or be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce revenues or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance and obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.

Our energy production, transmission and distribution activities, and our storage facilities for our natural gas involve numerous risks that may result in accidents and other catastrophic events.

Inherent in our businesses are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. Many of our transmission and distribution assets are located near populated residential areas, commercial business centers and industrial sites.

These hazards could result in injury or loss of human life, cause environmental pollution, significantly damage property or natural resources or impair our ability to operate our facilities. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully covered by our insurance and could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.

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Customer growth and usage in our service territories may fluctuate with current economic conditions, emerging technologies or responses to price increases.

Our financial operating results are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, economic conditions impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our financial operating results including earnings, cash flow and liquidity.

Cyberattacks, terrorism, or other malicious acts could disrupt our operations, or lead to a loss or misuse of confidential and proprietary information.

To effectively operate our business, we rely upon a sophisticated electronic control system, SCADA, information technology systems and network infrastructure to collect and retain sensitive information including personal information about our customers and employees. Cyberattacks, terrorism or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or gas operations. Attacks targeting other key information technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective. Despite our implementation of security measures and safeguards, all of our information technology systems may be vulnerable to disability, failures or unauthorized access

Risks associated with deployment of capital may impact our ability to execute our business plans and growth strategy.

We have significant capital investment programs planned for the next five years. The successful execution of our capital investment strategy depends on, or could be affected by, a variety of factors that include, but are not limited to: extreme weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, governmental approvals and permitting and regulatory cost recovery.

Weather conditions may cause fluctuation in customer usage as well as service disruptions.

Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation. Unusually mild summers and winters, therefore, could have an adverse effect on our results of operations, financial position or cash flows.

Our businesses are located in areas that could be subject to severe weather events such as snow and ice storms, tornadoes, strong winds, significant thunderstorms, flooding and drought. These events could result in lost operating revenues due to outages, property damage, including inoperable generation facilities and downed transmission and distribution lines, and storm restoration activities. We may not be able to recover the costs incurred following these weather events resulting in a negative impact on our financial operating results including earnings, cash flow and liquidity.

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We may be subject to increased risks of regulatory penalties.

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many agencies employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, SEC and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business, which could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.

Certain Federal laws provide special protection to certain designated animal species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation, wind and pipeline projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

Municipal governments may seek to limit or deny our franchise privileges.

Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. We regularly engage in negotiations on renewals of franchise agreements with our municipal governments. We have from time to time faced challenges or ballot initiatives on franchise renewals. To date, we have been successful in resolving or defending each of these challenges. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation. We also cannot quantify the impact that such action would have on the remainder of our business operations.

FINANCING RISKS

A sub-investment grade credit rating could impact our ability to access capital markets.

Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and complete new financings on reasonable terms, if at all. A credit rating downgrade, particularly to sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities, potentially significantly increasing our cost of capital and other associated operating costs.

Derivatives regulations could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.

Dodd-Frank contains significant derivatives regulations, including a requirement that certain transactions be cleared resulting in a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users such as utilities and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.

We use derivative instruments for our hedging activities for our Gas and Electric Utilities’ operations. We may also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral for certain swap transactions we enter into. In addition, our exchange-traded futures contracts are subject to futures margin posting requirements, which could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.

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Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to mark-to-market accounting treatment.

We use various financial contracts and derivatives, including futures, forwards, options and swaps to manage commodity price and financial market risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities being hedged. Fluctuating commodity prices could have a negative effect on our liquidity, financial condition, and results of operations.

Our use of derivative financial instruments could result in material financial losses.

From time to time, we have sought to limit a portion of the potential adverse effects resulting from changes in commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.

Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans.

Assumptions related to interest rates, expected return on investments, mortality and other key actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. An adverse change to key assumptions associated with our defined benefit retirement plans may require significant unplanned contributions to the plans which could adversely affect our financial operating results including earnings, cash flow and liquidity.

We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments are dependent upon cash distributions to the holding company from the subsidiaries.

As a holding company, our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital, equity or debt service funds.

There is no assurance as to the amount, if any, of future dividends because they depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.

We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, pay dividends and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.

In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in the context of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.

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National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

A future recession, if one occurs, may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting insurance businesses, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject, including but not limited to environmental hazards, fire-related liability from natural events or inadequate facility maintenance, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation of gas in pipelines.

Costs associated with our healthcare plans and other benefits could increase significantly.

The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes. Our electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery. The increasing cost, or inadequate recovery of, rising employee benefit costs may adversely affect our financial operating results including earnings, cash flow, or liquidity.

An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the effectiveness of these controls. During their assessment of these controls, management or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.

A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. If we are unable to assert that our internal controls over financial reporting are effective, market perception of our business, operating results and stock price could be adversely affected.

ENVIRONMENTAL RISKS

Developments in federal and state laws concerning GHG regulations and air emissions relating to climate could materially increase our generation costs and render some of our generating units uneconomical to operate and maintain.

To the extent climate change occurs, our businesses could be adversely impacted. Warmer temperatures during the heating season in our utility service territories, or cooler temperatures during the cooling season in our electric service territories could adversely affect financial results through lower natural gas volumes delivered, lower MWh sold and associated lower revenues.

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We own and operate regulated and non-regulated fossil-fuel generating plants in Colorado, South Dakota and Wyoming. Developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the section “Environmental Matters”.

There is uncertainty surrounding current climate regulation due to legal challenges, new federal climate legislation anticipated in the future, or state climate legislation and regulation. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial position or cash flows.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or reduction of load of coal-fired power generation facilities and potential increased load of our combined cycle natural gas-fired generation units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain; this could cause those generating units to be de-commissioned, potentially resulting in impairment costs. We will attempt to recover any remaining asset value; however, any unrecovered costs could have a material impact on our results of operations and financial condition.

The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, or failure to comply, could increase significantly.

Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.

The business segments may not be successful in recovering capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on the business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization.

Future regulations may require further reductions in emissions of mercury, hazardous pollutants, SO₂, NO_x, volatile organic compounds, particulate matter and GHG, which are released into the air when coal is burned. These requirements could require the installation of costly emission control technology or the implementation of other measures.

Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. The EPA was directed to repeal, revise and replace the CPP rule. At this time, it is not known what effect this will have on coal as a domestic energy source, and could have a significant impact on our mining operations.

Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our financial operating results including earnings, cash flow and liquidity could be adversely impacted.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 19, “Commitments and Contingencies”, of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

ITEM 4. MINE SAFETY DISCLOSURES

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

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

David R. Emery, age 57, has been Executive Chairman since January 1, 2019, Chairman and Chief Executive Officer from 2016 through 2018, and Chairman, President and Chief Executive Officer from 2005 through 2015. Prior to that, he held various positions with the Company, including President and Chief Executive Officer and member of the Board of Directors from 2004 to 2005, President and Chief Operating Officer — Retail Business Segment from 2003 to 2004 and Vice President — Fuel Resources from 1997 to 2003. Mr. Emery has 30 years of experience with the Company.

Linden R. Evans, age 57, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer — Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 18 years of experience with the Company.

Scott A. Buchholz, age 58, has been our Senior Vice President — Chief Information Officer since the closing of the Aquila Transaction in 2008. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 39 years of experience with the Company, including 28 years with Aquila.

Brian G. Iverson, age 57, has been Senior Vice President, General Counsel and Chief Compliance Officer since August 26, 2019. He served as Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary from February 1, 2019 to August 26, 2019, Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 16 years of experience with the Company.

Richard W. Kinzley, age 54, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 20 years of experience with the Company.

Jennifer C. Landis, age 45, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 18 years of experience with the Company.

Karen Beachy, age 48, has been Senior Vice President - Growth and Strategy since August 26, 2019. She served as Vice President - Growth and Strategy from 2018 to August 2019, Vice President - Supply Chain from 2016 to 2018, and Director of Supply Chain from 2014 to 2016. Ms. Beachy has 5 years of experience with the Company.

Stuart Wevik, age 58, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 34 years of experience with the Company.

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PART II


ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of December 31, 2019, we had 3,586 common shareholders of record and 32,285 beneficial owners, representing all 50 states, the District of Columbia and 6 foreign countries.

We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 29, 2020 meeting, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. This equivalent rate, if declared and paid in 2020, will represent 50 consecutive years of annual dividend increases.

For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.

UNREGISTERED SECURITIES ISSUED

There were no unregistered securities sold during 2019.

ISSUER PURCHASES OF EQUITY SECURITIES



There were no equity securities acquired for the twelve months ended December 31, 2019.

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ITEM 6.	SELECTED FINANCIAL DATA

(Minor differences may result due to rounding)



Years Ended December 31,	2019				2018				2017				2016 ^(a)				2015
(dollars in thousands, except per share amounts)

Total Assets	$	7,558,457			$	6,963,327			$	6,658,902			$	6,541,773			$	4,626,643

Property, Plant and Equipment
Property, plant and equipment	$	6,784,679			$	6,000,015			$	5,567,518			$	5,315,296			$	3,849,309
Accumulated depreciation and depletion	(1,281,493		)		(1,145,136		)		(1,026,088		)		(929,119		)		(794,695		)
Total property, plant and equipment, net	$	5,503,186			$	4,854,879			$	4,541,430			$	4,386,177			$	3,054,614

Capital Expenditures
Continuing Operations	$	849,755			$	502,424			$	337,689			$	460,450			$	289,896
Discontinued Operations ^(b)	—				2,402				23,222				6,669				168,925
Total Capital Expenditures	$	849,755			$	504,826			$	360,911			$	467,119			$	458,821

Capitalization (excluding noncontrolling interests)
Current maturities of long-term debt	$	5,743			$	5,743			$	5,743			$	5,743			$	—
Notes payable	349,500				185,620				211,300				96,600				76,800
Long-term debt, net of current maturities	3,140,096				2,950,835				3,109,400				3,211,189				1,853,682
Total stockholders’ equity	2,362,123				2,181,588				1,708,974				1,614,639				1,465,867
Total capitalization	$	5,857,462			$	5,323,786			$	5,035,417			$	4,928,171			$	3,396,349

Total Operating Revenues	$	1,734,900			$	1,754,268			$	1,680,266			$	1,538,916			$	1,261,322

Net Income Available for Common Stock
Income from continuing operations available for common stock	199,310			(c) (g)	265,329			(c)(f)	194,133			(c) (d)	137,132			(c) (d)	141,548			(d)
Income (loss) from discontinued operations, net of tax ^(b)	—				(6,887		)		(17,099		)		(64,162		)		(173,659		)
Net income (loss) available for common stock	$	199,310			$	258,442			$	177,034			$	72,970			$	(32,111	)

Common Stock Data^(e) (in thousands)
Shares outstanding, average basic	60,662				54,420				53,221				51,922				45,288
Shares outstanding, average diluted	60,798				55,486				55,120				53,271				45,288
Shares outstanding, end of year	61,477				60,004				53,541				53,382				51,192

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SELECTED FINANCIAL DATA continued



Years Ended December 31,	2019			2018			2017			2016			2015
(dollars in thousands, except per share amounts)

Earnings (Loss) Per Share of Common Stock (in dollars)
Basic earnings (loss) per average share -
Continuing operations	$	3.52		$	5.14		$	3.92		$	2.83		$	3.12
Discontinued operations ^(b)	—			(0.13		)	(0.32		)	(1.23		)	(3.83		)
Non-controlling interest ^(c)	(0.23		)	(0.26		)	(0.27		)	(0.19		)	—
Total	$	3.29		$	4.75		$	3.33		$	1.41		$	(0.71	)
Diluted earnings (loss) per average share -
Continuing operations	$	3.51		$	5.04		$	3.78		$	2.75		$	3.12
Discontinued operations ^(b)	—			(0.12		)	(0.31		)	(1.20		)	(3.83		)
Non-controlling interest ^(c)	(0.23		)	(0.26		)	(0.26		)	(0.18		)	—
Total	$	3.28		$	4.66		$	3.21		$	1.37		$	(0.71	)

Cash Dividends Paid on Common Stock	$	124,647		$	106,591		$	96,744		$	87,570		$	72,604

Dividends Declared per Share	$	2.05		$	1.93		$	1.81		$	1.68		$	1.62

Book Value Per Share, End of Year	$	38.42		$	36.36		$	31.92		$	30.25		$	28.63

____________________________________

(a)

Effective February 12, 2016, we completed the SourceGas Transaction. Total cash consideration paid, net of debt assumed and working capital adjustment received, was $1.124 billion, funded with a combination of the issuance of 6.3 million shares of our common stock on November 23, 2015, 5.98 million equity units issued on November 23, 2015, $546 million of net proceeds from the issuance of senior unsecured notes on January 13, 2016, cash on hand and draws under our revolving credit facility.

(b)

On November 1, 2017, we made the decision to divest our Oil and Gas assets which was completed in 2018. Oil and Gas results are shown in discontinued operations. 2017 includes a non-cash after-tax fair value impairment on held-for-sale assets of $13 million. 2016 includes non-cash after-tax impairment charges to crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax impairment charges to crude oil and natural gas properties of $158 million.


(c)	On April 14, 2016, Black Hills Electric Generation sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2019, 2018, 2017 and 2016 was reduced by $14 million, $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest.


(d)	2017, 2016 and 2015 include incremental SourceGas Transaction costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively.


(e)	In 2019, we issued 1.33 million shares at an average share price of $75.28 under our ATM equity offering program. On November 1, 2018, we issued 6.3 million shares of common stock upon conversion of our Equity Units. In 2016, we issued 1.97 million shares at an average share price of $60.95 under our ATM equity offering program.


(f)	The increase in 2018 included a $73 million tax benefit resulting from legal entity restructuring. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.


(g)	2019 includes a non-cash after-tax impairment of $15 million in our investment in equity securities of a privately held oil and gas company. See Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

For additional information on our business segments see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures about Market Risk and Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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ITEMS 7 & and 7A. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK



Items 7 and 7A Index
Executive Summary	42
Prospective Information	46
Results of Operations - Consolidated Summary and Overview of Business Segments	47
Non-GAAP Measure	50
Electric Utilities	51
Gas Utilities	52
Power Generation	54
Mining	55
Corporate	56
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)	56
Liquidity and Capital Resources	57
Debt, Equity and Liquidity	59
Cash Flow Activities	62
Capital Expenditures	64
Credit Ratings	64
Contractual Obligations and Off-Balance Sheet Items	66
Critical Accounting Estimates	67
Market Risk Disclosures	70
New Accounting Pronouncements	71

Executive Summary

We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of improving life with energy and a vision to be the energy partner of choice. The Company provides electricity and natural gas through its Electric and Gas Utilities to 1.3 million customers in 824 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company’s Electric Utilities are supported by our Power Generation and Mining segments. The Power Generation segment produces electric power from its five generating facilities and sells most of the electric capacity and energy to our Electric Utilities under long-term contracts. Our Mining segment produces coal at our only location near Gillette, Wyoming, and sells nearly all production to fuel the on-site, mine-mouth power generation facilities.

The Company has provided energy and served customers for 136 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. Our strategic focus has not changed in over a century - serving customers with affordable, reliable and safe energy. Our strategy today continues that emphasis on serving customers, but with a renewed focus on better engaging with the people and communities we serve. Customer expectations are rapidly changing with the advancement of technology and customers are demanding simpler, faster and more convenient solutions to their energy needs. We are Ready to serve as we have done for the past 136 years.

Our strategy consists of five primary areas that focus on improving the way we serve customers with safe, reliable and affordable energy while improving the lives of the customers and communities we serve. The strategy is to 1) become the safest energy company in the utility industry; 2) transform the customer experience; 3) grow our electric and natural gas customer load; 4) pursue operating efficiencies; and 5) modernize utility infrastructure. This strategic focus will present the company with significant investment needs as we modernize our infrastructure systems and meet customer growth. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective interactions.

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Key Elements of our Business Strategy

Modernize, replace and operate utility infrastructure to meet our customers’ energy needs while providing safe, reliable and affordable energy. Our utilities own and operate large electric and natural gas infrastructure systems that span nearly 1,600 miles. Our Electric Utilities own and operate 939 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities own and operate 46,000 miles of natural gas transmission and distribution pipelines. A key strategic focus is to modernize this utility infrastructure to meet customers’ and communities’ varied energy needs and to ensure the continued delivery of safe, reliable and affordable energy. In addition, we need to invest in the accessibility, capacity and integrity of our systems to meet customer growth.

We rigorously comply with all applicable federal, state and local regulations and strive to consistently meet industry best practice standards. A key component of our modernization effort is the development of programs by our Electric and Gas utilities to systematically and proactively replace aging infrastructure on a system-wide basis. To meet our electric customers’ continued expectations of high levels of reliability, our Electric Utilities utilize a distribution integrity program to ensure the timely repair and replacement of aging infrastructure. Our Gas Utilities utilize a programmatic approach to system-wide pipeline system replacement, particularly in high consequence areas. Under the programmatic approach, obsolete, at-risk and vintage materials are replaced in a proactive and systematic time frame. We have removed all cast- and wrought-iron from our natural gas transmission and distribution systems and continue to replace aging infrastructure through programs that prioritize safety and reliability for our customers. Many of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments which reflect the cost incurred in repairing and replacing the gas delivery systems.

We estimate our five-year capital investment to be approximately $2.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure and to support customer and community growth needs. Our actual 2019 and forecasted capital expenditures and depreciation for next five years from 2020 through 2024 are as follows (in millions):

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	Actual		Planned		Planned		Planned		Planned		Planned
Capital Expenditures By Segment	2019		2020		2021		2022		2023		2024
(in millions)
Electric Utilities	$	223	$	246	$	203	$	170	$	137	$	152
Gas Utilities	512		391		309		285		316		293
Power Generation	85		7		9		11		6		6
Mining	9		8		12		9		9		9
Corporate and Other	21		17		22		11		12		10
Total	$	850	$	669	$	555	$	486	$	480	$	470

Efficiently plan, construct and operate rate base power generation facilities to serve our Electric Utilities. We believe that we best serve customers and communities with a vertically integrated business model for our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to cost-effectively supply electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.

Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs, efficiency in converting fuel into energy, low per unit operating and maintenance costs and high levels of power plant availability. For our coal-fired power plants, we leverage our mine-mouth location advantage to eliminate coal transportation costs that often represent the largest component of the delivered cost of coal for many other utilities. Additionally, we operate our plants with high levels of availability as compared to industry benchmarks.

We continue to believe that ownership of power generation facilities by our Electric Utilities best serves customers. Rate-based generation assets offer several advantages for customers and shareholders, including:


•	When generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run; especially when compared to power otherwise purchased from the open market through wholesale contracts that are periodically re-priced to reflect current and varying market conditions;


•	Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;


•	The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of capital; and


•	Investors are provided a long-term, reasonable, stable return on their investment.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. Some of our customers, particularly our larger customers, are demanding more renewable and cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from voters, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest, we have created and received approvals for new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmental agency customer requests for renewable energy resources in South Dakota and Wyoming. To meet the renewable energy commitments under the new tariffs, we also received approval from the Wyoming Public Service Commission to build the Corriedale wind project, a 52.5 MW wind farm to be constructed near Cheyenne, Wyoming. The $79 million project is expected to be in service by year-end 2020. Supporting our renewable energy efforts in Colorado, in November 2019, we successfully commissioned Busch Ranch II, a 60 MW wind farm near Pueblo, Colorado, to provide renewable energy to our Colorado Electric utility.

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To date, many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting GHG emissions reduction targets. Federal legislation for both renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely drive the need for significant investment in our Electric Utilities and Gas Utilities segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility we are responsible for providing safe, reliable and affordable sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with standards and regulations that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.

Build and maintain strong relationships with wholesale power customers of our utilities and our power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be an important provider of electricity to wholesale utility customers, who will continue to need products such as capacity and energy to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns for shareholders over the long-term than we would by selling energy into more volatile energy spot markets. In addition, relationships that we have established with wholesale power customers have developed into other opportunities. MEAN, MDU and the City of Gillette, Wyoming were wholesale power customers that are now joint minority owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues.

Vertically integrate businesses that are supportive of our Electric and Gas utility businesses. While our primary focus is on growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to our utilities. We currently own and operate power generation and mining assets that are vertically integrated into and supportive of our Electric Utilities. These operations are located at our utility-generating complexes and are physically integrated into our Electric Utility operations.

The Power Generation segment currently owns five power facilities, four of which are contracted with our affiliate Electric Utilities under long-term power purchase agreements. Our Power Generation segment has an experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed 20 coal-fired, gas-fired and renewable generation projects since 1995 with aggregate project costs in excess of $2.1 billion. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the company’s generation assets. In certain states, our Electric Utilities are required to competitively bid for generation resources needed to serve customers. Generally, our Power Generation segment submits bids in response to those competitive solicitations. Our Power Generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs.

Our surface coal mine is located immediately adjacent to our Gillette energy complex in northeastern Wyoming, where all five of our coal-fired power plants are located. We operate and own majority interests in four of our five power plants. We own 20% of the fifth power plant which is operated by a majority owner. The mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our power plants when compared to other coal-fired and gas-fired power plants. Nearly all of the mine’s production is sold to the five on-site, mine-mouth generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck.

Expand utility operations through selective acquisitions of electric and gas utilities. The electric and natural gas utility industries have consolidated significantly over the past two decades and continue to consolidate. We have successfully acquired and integrated numerous utility systems since 2005, including two large, transformational acquisitions - the Aquila Transaction in 2008 and SourceGas Transaction in 2016. Through these acquisitions, we developed a scalable platform that simplifies the rapid integration of acquired utilities, providing significant benefits to both customers and shareholders. The company targets small to large utilities, including municipal and private utility systems, located primarily in geographies that are near to or contiguous with our existing utility service territories and can provide long-term value for both customers and shareholders. In the near-term, we do not expect to pursue large utility acquisitions, particularly given the high valuation multiples realized in recent utility transactions. As pipeline regulations continue to increase, we believe there will be more opportunities to purchase these smaller and more rural utility systems.

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Grow our dividend. We are extremely proud of our track record of annual dividend increases for shareholders. In January 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend of $2.14 per share. This current annual equivalent rate of $2.14 per share, if declared and paid in 2020, will represent 50 consecutive years of annual dividend increases. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating.

Prospective Information

We expect to generate long-term growth through the expansion of integrated utilities and supporting operations. Sustained growth requires continued capital deployment. Our integrated energy portfolio, focused predominately on regulated utilities, provides growth opportunities, yet avoids concentrating business risk. We expect much of our growth in the next few years will come from the need for capital deployment at our utilities and continued focus on improving efficiencies and controlling costs. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plan. Prospective information for our operating segments should be read in conjunction with our business strategy discussed above, and our 2019 company highlights discussed below.

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Our discussion and analysis for the year ended December 31, 2019 compared to 2018, as well as discussion and analysis of the results of operations for the year ended December 31, 2018 compared to 2017 given segment reporting changes adopted by the Company in 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2018 compared to 2017, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 19, 2019.

Segment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.

Results of Operations

Consolidated Summary and Overview



	For the Years Ended December 31,
	2019				2018						2017
(in millions, except per diluted share amounts)	Income		EPS		Income			EPS			Income			EPS

Net income from continuing operations available for common stock	$	199.3	$	3.28	$	265.3		$	4.78		$	194.1		$	3.52
Net (loss) from discontinued operations	—		—		(6.9		)	(0.12		)	(17.1		)	(0.31		)
Net income available for common stock	$	199.3	$	3.28	$	258.4		$	4.66		$	177.0		$	3.21

2019 Compared to 2018

The variance to the prior year included the following:


•	Electric Utilities’ adjusted operating income increased $4.4 million due to reduced purchased power capacity costs, increased rider revenues and the prior year Wyoming Electric PCA settlement partially offset by higher operating expenses driven by outside services and employee costs;


•	Gas Utilities’ adjusted operating income increased $4.7 million primarily due to new customer rates and rider revenues, customer growth and increased transport and transmission driven by increased volumes from new and existing customers partially offset by higher operating expenses driven by outside services and employee costs;


•	Power Generation’s adjusted operating income increased $2.2 million primarily due to higher revenue from increased wind MWh sold and higher PPA pricing partially offset by higher depreciation and property taxes from new wind assets;


•	Mining’s adjusted operating income decreased $3.7 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 $1.4 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;


•	A $20 million pre-tax non-cash impairment in 2019 of our investment in equity securities of a privately held oil and gas company;


•	We expensed $5.4 million of development costs related to projects we no longer intend to construct; and


•	Increased tax expense of $53 million primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially offset by a prior year $4.0 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes and current year $5.9 million federal PTCs and related state ITCs associated with new wind assets.

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2018 Compared to 2017

The variance when comparing 2018 to 2017 included the following:


•	Electric Utilities’ adjusted operating income decreased $21.9 million due to TCJA benefits delivered to customers, the Wyoming Electric PCA settlement and higher operating expenses partially offset by increased rider revenues and favorable weather;


•	Gas Utilities’ adjusted operating income increased $0.1 million primarily due to colder winter weather, new customer rates, customer growth and increased transport and transmission offset by TCJA benefits delivered to customers and higher operating expenses;


•	Power Generation’s adjusted operating income decreased $4.1 million primarily due to a decrease in MWh sold and higher operating expenses;


•	Mining’s adjusted operating income increased $2.8 million primarily due to increase in price per ton sold and lower operating expenses;


•	Corporate and Other expenses decreased $3.3 million primarily due to prior year acquisition costs; and


•	Increased tax benefit of $97 million primarily due to a $73 million tax benefit resulting from legal entity restructuring and a reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.

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



	For the Years Ended December 31,
	2019			Variance			2018			Variance			2017
	(in thousands)
Revenue
Revenue	$	1,885,669		$	(11,573	)	$	1,897,242		$	83,721		$	1,813,521
Intercompany eliminations	(150,769		)	(7,795		)	(142,974		)	(9,719		)	(133,255		)
	$	1,734,900		$	(19,368	)	$	1,754,268		$	74,002		$	1,680,266

Adjusted operating income ^(a)
Electric Utilities	$	160,297		$	4,428		$	155,869		$	(21,868	)	$	177,737
Gas Utilities	189,971			4,732			185,239			134			185,105
Power Generation	44,779			2,165			42,614			(4,076		)	46,690
Mining	12,627			(3,713		)	16,340			2,840			13,500
Corporate and Other	(1,632		)	1,393			(3,025		)	3,271			(6,296		)
	406,042			9,005			397,037			(19,699		)	416,736

Interest expense, net	(137,659		)	2,316			(139,975		)	(2,873		)	(137,102		)
Impairment of investment	(19,741		)	(19,741		)	—			—			—
Other income (expense), net	(5,740		)	(4,560		)	(1,180		)	(3,288		)	2,108
Income tax benefit (expense)	(29,580		)	(53,247		)	23,667			97,034			(73,367		)
Income from continuing operations	213,322			(66,227		)	279,549			71,174			208,375
(Loss) from discontinued operations, net of tax	—			6,887			(6,887		)	10,212			(17,099		)
Net income	213,322			(59,340		)	272,662			81,386			191,276
Net income attributable to noncontrolling interest	(14,012		)	208			(14,220		)	22			(14,242		)
Net income available for common stock	$	199,310		$	(59,132	)	$	258,442		$	81,408		$	177,034

_____________


(a)	In 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

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2019 Overview of Business Segments and Corporate Activity

Electric Utilities

•

On December 13, 2019, Colorado Electric issued a request for proposals for its Renewable Advantage program, to potentially add up to 200 MW of renewable energy to its southern Colorado system. A competitive solicitation process for the addition of cost-effective, utility-scale renewable energy projects includes wind, solar and battery storage to supplement existing natural gas and wind generation power supplies Bidders have until February 15, 2020, to submit proposals, which will be reviewed by an independent evaluator overseen by the CPUC. Based on the outcome of the bidding process, projects would be placed in service no later than 2023.

•

In July 2019, South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready program and related jointly-filed CPCN to construct Corriedale. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric received approval from the SDPUC to increase the offering under the program by 12.5 MW. The two electric utilities also received a determination from the WPSC to increase the project to 52.5 MW. The $79 million project is expected to be in service by year-end 2020.


•	On September 17, 2019, South Dakota Electric completed construction on the final 94-mile segment of a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.


•	Colorado Electric set a new all-time and summer peak load:


•	On July 19, 2019, Colorado Electric set a new all-time and summer peak load of 422 MW, exceeding the previous peak of 413 MW set in June 2018.


•	Wyoming Electric set a new all-time and summer peak load, and also set a new winter peak load:


•	On July 19, 2019, Wyoming Electric set a new all-time and summer peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.


•	On December 16, 2019, Wyoming Electric set a new winter peak load of 247 MW, exceeding the previous peak of 238 MW set in December 2018.


•	Cooling degree days for the year ended December 31, 2019 were 14% higher than the normal compared to 29% higher than normal in 2018.


•	Heating degree days for the year ended December 31, 2019 were 5% higher than normal compared to 3% higher than normal in 2018.

Gas Utilities


•	Gas Utilities continued to consolidate utility jurisdictions within the States of Colorado, Nebraska, and Wyoming:

◦

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. A new, single statewide rate structure will be effective March 1, 2020. 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 February 1, 2019, Colorado Gas submitted a rate review with the CPUC to consolidate rates, tariffs and 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 ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and recommending a rate decrease. Colorado Gas has filed exceptions to the ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 and completed in early 2019.

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◦	On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two natural gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services.

•

On December 1, 2019, Wyoming Gas placed in service 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 interconnects from a supply point near Douglas, Wyoming, to facilities near Casper, Wyoming. The associated investment was included in the Wyoming Gas rate review completed in December 2019.


•	Heating degree days at the Gas Utilities for the year ended December 31, 2019 were 5% higher than normal compared to 2% higher than normal in 2018.

Power Generation


•	On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II. Through a competitive bidding process, Black Hills Electric Generation was selected to deliver renewable energy under a 25-year PPA to Colorado Electric.

•

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. 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 for 20 additional years. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.

Mining


•	In October 2019, negotiations were completed for the price reopener in the contract with the Wyodak power plant. Effective July 1, 2019, the new price was reset at $17.94 per ton with customary escalators, compared to the prior contract price of $18.25 per ton. The contract expires on December 31, 2022 and negotiations are underway to extend the contract.

Corporate and Other


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


•	During the year ended December 31, 2019, we issued a total of 1.3 million shares of common stock for net proceeds of $99 million under our ATM equity offering program.


•	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 and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

Operating Results

A discussion of operating results from our business segments follows.

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

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

Electric Utilities

Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands):



	2019		Variance			2018		Variance			2017

Revenue	$	712,752	$	1,301		$	711,451	$	6,801		$	704,650

Total fuel and purchased power	268,297		(15,543		)	283,840		9,477			274,363

Gross margin (non-GAAP)	444,455		16,844			427,611		(2,676		)	430,287

Operations and maintenance	195,581		9,406			186,175		13,868			172,307
Depreciation and amortization	88,577		3,010			85,567		5,324			80,243
Total operating expenses	284,158		12,416			271,742		19,192			252,550

Adjusted operating income ^(a)	$	160,297	$	4,428		$	155,869	$	(21,868	)	$	177,737

____________________


(a)	Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Electric Utilities Adjusted operating income was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in an increase of $6.4 million and $7.1 million, respectively.

2019 Compared to 2018

Gross margin increased over the prior year as a result of:



	(in millions)
Reduction in purchased power capacity costs	$	6.5
Prior year Wyoming Electric PCA Stipulation settlement	3.7
Rider recovery	3.1
Increased commercial and industrial demand	1.9
Weather	0.2
Other	1.4
Total increase in Gross margin (non-GAAP)	$	16.8

Operations and maintenance expense increased primarily due to $4.7 million of higher employee costs and $2.9 million of higher outside services expenses. Various other expenses comprise the remainder of the increase compared to the prior year.

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

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2018 Compared to 2017

Gross margin decreased over the prior year as a result of:



	(in millions)
TCJA revenue reserve	$	(22.3	)
Wyoming Electric PCA Stipulation settlement	(2.6		)
Other	(1.4		)
Horizon Point shared facility revenue ^(a)	9.8
Rider recovery	5.1
Weather	3.6
Power Marketing, transmission and Tech Services	3.5
Residential customer growth	1.6
Total increase (decrease) in Gross margin (non-GAAP)	$	(2.7	)

____________________


(a)	Horizon Point shared facility revenue was offset by facility expenses at our operating segments and had no impact on consolidated results.

Operations and maintenance expense increased primarily due to $4.5 million of higher facility costs, $4.1 million of higher outside services expenses, $3.6 million of higher employee costs, and $1.0 million of higher property taxes due to a higher asset base.

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



	For the year ended December 31,
Contracted power plant fleet availability ^(a)	2019	2018	2017

Coal-fired plants^(b)	92.1%	93.9%	88.9%
Natural gas fired plants and Other plants ^(c)	87.9%	96.4%	96.1%
Wind	95.6%	96.9%	93.3%
Total availability	89.9%	95.6%	93.6%

Wind capacity factor	38.7%	39.2%	36.7%

____________________


(a)	Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.


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


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

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Gas Utilities

Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):



	2019		Variance			2018		Variance			2017
Revenue:
Natural gas - regulated	$	932,111	$	(10,813	)	$	942,924	$	77,093		$	865,831
Other - non-regulated services	77,919		(4,464		)	82,383		584			81,799
Total revenue	1,010,030		(15,277		)	1,025,307		77,677			947,630

Cost of natural gas sold:
Natural gas - regulated	406,643		(35,887		)	442,530		61,271			381,259
Other - non-regulated services	19,255		(368		)	19,623		(8,721		)	28,344
Total cost of sales	425,898		(36,255		)	462,153		52,550			409,603

Gross margin (non-GAAP)	584,132		20,978			563,154		25,127			538,027

Operations and maintenance	301,844		10,363			291,481		22,291			269,190
Depreciation and amortization	92,317		5,883			86,434		2,702			83,732
Total operating expenses	394,161		16,246			377,915		24,993			352,922

Adjusted operating income	$	189,971	$	4,732		$	185,239	$	134		$	185,105

2019 Compared to 2018

Gross margin increased over the prior year as a result of:



	(in millions)
New rates	$	16.2
Customer growth - distribution	5.2
Increased transport and transmission	2.6
Weather	(2.2		)
Decreased mark-to-market on non-utility natural gas commodity contracts	(3.3		)
Other	2.5
Total increase in Gross margin (non-GAAP)	$	21.0

Operations and maintenance expense increased primarily due to $5.5 million of higher outside services expenses, $1.2 million higher employee costs and $2.0 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures. Various other expenses comprise the remainder of the increase compared to the prior year.

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

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2018 Compared to 2017

Gross margin increased over the prior year as a result of:



	(in millions)
Weather ^(a)	$	13.8
New rates	10.7
Customer growth - distribution	5.2
Increased mark-to-market on non-utility natural gas commodity contracts	4.0
Increased transport and transmission	3.6
Natural gas volumes sold	3.2
Non-utility - Choice Gas, Tech Services and appliance repair	2.7
Other	2.4
TCJA revenue reserve	(20.5		)
Total increase (decrease) in Gross margin (non-GAAP)	$	25.1

___________________


(a)	Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than normal compared to 10% lower than normal in 2017.

Operations and maintenance expense increased primarily due to $11.8 million of higher employee costs, $4.7 million of higher facility costs, $4.0 million of higher outside services expenses and $2.1 million of higher bad debt expense driven by an increase in revenues.

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

Power Generation

Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):



	2019		Variance		2018		Variance			2017

Revenue	$	101,258	$	8,807	$	92,451	$	(2,169	)	$	94,620

Total fuel	9,059		467		8,592		(748		)	9,340
Operations and maintenance	28,429		3,294		25,135		2,093			23,042
Depreciation and amortization	18,991		2,881		16,110		562			15,548
Total operating expenses	56,479		6,642		49,837		1,907			47,930

Adjusted operating income ^(a)	$	44,779	$	2,165	$	42,614	$	(4,076	)	$	46,690

____________________


(a)	Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Power Generation Adjusted operating income was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(5.7) million and $(6.5) million, respectively.

2019 Compared to 2018

Revenue increased in the current year due to increased wind MWh sold and higher PPA prices. Operating expenses increased in the current year primarily due to higher depreciation and property taxes from new wind assets.

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2018 Compared to 2017

Revenue decreased in 2018 due to a decrease in MWh sold, primarily from a planned outage at Wygen I. Operating expenses increased due to higher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation.



	For the year ended December 31,
Contracted power plant fleet availability ^(a)	2019	2018	2017

Coal-fired plant ^(b)	94.5%	85.8%	96.9%
Natural gas-fired plants	98.6%	99.4%	99.2%
Wind ^(c)	90.6%	N/A	N/A
Total availability	95.0%	95.9%	98.6%

Wind capacity factor ^(c)	23.5%	N/A	N/A

___________


(a)	Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.


(b)	Wygen I experienced a planned outage in 2018


(c)	Change from 2018 to 2019 is driven by Black Hills Electric Generation’s acquisition of new wind assets.

Mining

Mining operating results for the years ended December 31 were as follows (in thousands):



	2019		Variance			2018		Variance			2017

Revenue	$	61,629	$	(6,404	)	$	68,033	$	1,412		$	66,621

Operations and maintenance	40,032		(3,696		)	43,728		(1,154		)	44,882
Depreciation, depletion and amortization	8,970		1,005			7,965		(274		)	8,239
Total operating expenses	49,002		(2,691		)	51,693		(1,428		)	53,121

Adjusted operating income	$	12,627	$	(3,713	)	$	16,340	$	2,840		$	13,500

The following table provides certain operating statistics for the Mining segment (in thousands):



	2019		2018		2017
Tons of coal sold	3,716		4,085		4,183
Cubic yards of overburden moved	8,534		8,970		9,018
Coal reserves at year-end (in tons)	185,448		189,164		194,909

Revenue per ton	$	15.94	$	16.11	$	15.93

2019 Compared to 2018

Current year revenue decreased primarily due to 9% fewer tons sold driven primarily by planned and unplanned generation facility outages at the Wyodak Plant. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor, and major maintenance expenses.

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2018 Compared to 2017

Revenue increased primarily due to a 1% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income, net. Operating expenses decreased primarily due to lower major maintenance expenses.

Corporate and Other

Corporate and Other operating results for the years ended December 31 were as follows (in thousands):



(in thousands)	2019			Variance		2018			Variance		2017

Adjusted operating (loss) ^(a)	$	(1,632	)	$	1,393	$	(3,025	)	$	3,271	$	(6,296	)

____________


(a)	Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Corporate and Other Adjusted operating (loss) was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(0.7) million and $(0.6) million, respectively.

2019 Compared to 2018

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

2018 Compared to 2017

The variance in Adjusted operating (loss) was primarily due to prior year acquisition costs.

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



(in thousands)	2019			Variance			2018			Variance			2017

Interest expense, net	$	(137,659	)	$	2,316		$	(139,975	)	$	(2,873	)	$	(137,102	)
Impairment of investment	(19,741		)	(19,741		)	—			—			—
Other income (expense), net	(5,740		)	(4,560		)	(1,180		)	(3,288		)	2,108
Income tax benefit (expense)	(29,580		)	(53,247		)	23,667			97,034			(73,367		)

2019 Compared to 2018

Impairment of Investment

For the year ended December 31, 2019, we recorded a pre-tax non-cash write-down of $20 million in our investment in equity

securities of a privately held oil and gas company. The impairment was triggered by a deterioration in earnings performance of

the privately held oil and gas company and an adverse change in future natural gas prices. See Note 1 of the Notes to

Consolidated Financial Statements for additional details.

Other Income (Expense)

For the year ended December 31, 2019, we expensed $5.4 million of development costs related to projects we no longer intend to construct.

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Income Tax Benefit (Expense)

The increase in tax expense was primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially offset by:


•	A prior year $(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes;


•	Current year $3.8 million of federal PTCs and $2.1 million of related state ITCs associated with new wind assets;


•	A current year $1.9 million tax benefit from increased repair activity in flow-through regulatory jurisdictions;


•	A current year $1.4 million tax benefit for incremental excess deferred tax amortization related to tax reform; and


•	A current year $3.4 million tax benefit from a federal tax loss carry-back claim including interest. We identified certain qualified expenses that extend beyond the typical two-year carry-back period.

2018 Compared to 2017

Other Income (Expense)

The variance in Other income (expense), net was primarily due to the presentation change of non-service pension costs to Other income (expense) in 2018, previously reported in Operations and maintenance.

Income Tax Benefit (Expense)

The variance in Income tax benefit (expense) was primarily due to a $73 million tax benefit in 2018 resulting from legal entity restructuring and the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by a $(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

Liquidity and Capital Resources

OVERVIEW

Our company requires significant cash to support and grow our businesses. Our predominant source of cash is from our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.

We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the construction season.

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

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The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):



Financial Position Summary	2019			2018
Cash and cash equivalents	$	9,777		$	20,776
Restricted cash and equivalents	$	3,881		$	3,369
Notes payable	$	349,500		$	185,620
Short-term debt, including current maturities of long-term debt	$	5,743		$	5,743
Long-term debt ^(a)	$	3,140,096		$	2,950,835
Stockholders’ equity	$	2,362,123		$	2,181,588

Ratios
Long-term debt ratio	57		%	57		%
Total debt ratio	60		%	59		%

______________


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

Significant Factors Affecting Liquidity

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including weather seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow. However, the potential for unforeseen events affecting cash needs will continue to exist.

Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At December 31, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.

Weather Seasonality, Commodity Pricing and Associated Hedging Strategies

We manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest rate movements and commodity price movements.

Utility Factors

Our cash flows, and in turn liquidity needs in many of our regulated jurisdictions, can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and physical fixed price purchases.

Interest Rates

Some of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We do not have any interest rate swap agreements at December 31, 2019; 90% of our interest rate exposure has been mitigated through fixed interest rates.

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Federal and State Regulations

We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

CASH GENERATION AND CASH REQUIREMENTS

Cash Generation

Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring in 2023, our CP Program, our ATM equity offering program and our ability to access the public and private capital markets through debt and equity securities offerings when necessary.

Cash Collateral

Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral with the counterparty to meet these obligations. The cash collateral we were required to post at December 31, 2019 was not material.

DEBT, EQUITY AND LIQUIDITY

Debt

Revolving Credit Facility and CP Program

We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

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



		Current		Short-term borrowings at		Letters of Credit at		Available Capacity at
Credit Facility	Expiration	Capacity		December 31, 2019		December 31, 2019		December 31, 2019
Revolving Credit Facility and CP Program	July 30, 2023	$	750	$	350	$	30	$	370

The weighted average interest rate on short-term borrowings at December 31, 2019 was 2.03%. Short-term borrowing activity for the twelve months ended December 31, 2019 was:



	(dollars in millions)
Maximum amount outstanding - short-term borrowing (based on daily outstanding balances)	$	357
Average amount outstanding - short-term borrowing (based on daily outstanding balances)	$	187
Weighted average interest rates - short-term borrowing	2.47		%

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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. We were in compliance with these covenants as of December 31, 2019. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

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

Cross-Default Provisions

Our $7 million Corporate term loan contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to make timely payments of debt obligations or triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and the threshold principal amount is $50 million.

The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.

Utility Money Pool

As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates (2.210% at December 31, 2019). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.

At December 31, 2019, money pool balances included (in thousands):



Subsidiary	Borrowings From Money Pool Outstanding
BHSC	$	148,041
South Dakota Electric	57,585
Wyoming Electric	37,993
Total Money Pool borrowings from Parent	$	243,619

Equity

Shelf Registration

We have an effective automatic shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2020. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2019, we had approximately 61 million shares of common stock outstanding and no shares of preferred stock outstanding.

ATM

In 2019, we issued a total of 1,328,332 shares of common stock under the ATM for proceeds of $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled.

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Common Stock Dividends

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.

On January 29, 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:



	2019	2018	2017
Dividend Payout Ratio	63%	40%	50%
Dividends Per Share	$2.05	$1.93	$1.81

Our three-year compound annualized dividend growth rate was 6.9% and all dividends were paid out of available operating cash flows.

Dividend Restrictions

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

As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. See additional information in Note 6 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. See additional information in Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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 December 31, 2019, we were in compliance with these covenants.

Financing Activities

Financing activities in 2019 consisted of the following:


•	We issued a total of 1.3 million shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.2 million in issuance costs.

•

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

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•

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


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

Future Financing Plans

We anticipate the following financing activities in 2020:


•	Renew our shelf registration and ATM;


•	Continued equity issuance under the ATM or assess other equity issuance options;


•	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.

CASH FLOW ACTIVITIES

The following table summarizes our cash flows (in thousands):



	2019			2018			2017
Cash provided by (used in)
Operating activities	$	505,513		$	488,811		$	428,261
Investing activities	$	(816,210	)	$	(465,849	)	$	(317,118	)
Financing activities	$	300,210		$	(17,057	)	$	(108,695	)

2019 Compared to 2018

Operating Activities:

Net cash provided by operating activities was $17 million higher than in 2018. The variance to the prior year was primarily attributable to:


•	Cash earnings (income from continuing operations plus non-cash adjustments) were $37 million higher than prior year driven primarily by higher margins at our Electric and Gas Utilities;


•	Net outflows from operating assets and liabilities were $25 million higher than prior year, primarily attributable to:


•	Cash outflows increased by approximately $40 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of higher outside services, employee costs and other working capital requirements;


•	Cash inflows increased by approximately $59 million compared to the prior year primarily as a result of lower accounts receivable driven by lower pass-through revenues reflecting lower commodity prices; and


•	Cash inflows decreased by approximately $44 million primarily as a result of changes in our current regulatory liabilities due to the TCJA tax rate change that has subsequently been returned to customers and from changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity prices; and


•	Cash outflows decreased approximately $5.5 million due to the absence of operating activities of discontinued operations in 2019.

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Investing Activities:

Net cash used in investing activities was $816 million in 2019, compared to net cash used in investing activities of $466 million in 2018 for a variance of $350 million. This variance was primarily due to:

•

Capital expenditures of approximately $818 million in 2019 compared to $458 million in 2018. The $361 million increase from the prior year was due to higher capital expenditures driven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities segments, the Corriedale Wind Energy Project at our Electric Utilities 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, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, and construction of Busch Ranch II at our Power Generation segment; and


•	Net cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of our oil and gas segment.

Financing Activities:

Net cash provided by financing activities was $300 million in 2019 as compared to net cash used by financing activities of $17 million in 2018, an increase of $317 million due to the following:


•	Increase of $539 million due to issuances of long and short-term debt in excess of required maturities that were used to fund our capital program


•	Decrease of $199 million in common stock issued primarily due to prior year gross proceeds of approximately $299 million from the Equity Unit conversion partially offset by current year net proceeds of $99 million through our ATM equity offering program;


•	Cash dividends on common stock of $125 million were paid in 2019 compared to $107 million paid in 2018; and


•	Cash outflows for other financing activities increased by approximately $5.5 million driven primarily by current year financing costs incurred in the October 3, 2019 debt transaction.

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CAPITAL EXPENDITURES

Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See Key Elements of our Business Strategy above in Item 7 - Executive Summary and Business Strategy for forecasted capital expenditure requirements.

A significant portion of our capital expenditures relates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and can be recovered from our utility customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.

Historical Capital Requirements

Our primary capital requirements for the three years ended December 31 were as follows (in thousands):



	2019		2018		2017
Property additions: ^(a)
Electric Utilities ^(b)	$	222,911	$	152,524	$	138,060
Gas Utilities ^(c)	512,366		288,438		184,389
Power Generation ^(d)	85,346		30,945		1,864
Mining	8,430		18,794		6,708
Corporate and Other	20,702		11,723		6,668
Capital expenditures before discontinued operations	849,755		502,424		337,689
Discontinued operations	—		2,402		23,222
Total capital expenditures	849,755		504,826		360,911
Common stock dividends	124,647		106,591		96,744
Maturities/redemptions of long-term debt	905,743		854,743		105,743
Total capital requirements	$	1,880,145	$	1,466,160	$	563,398

____________________________


(a)	Includes accruals for property, plant and equipment as disclosed in Note 17 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


(b)	Current year capital expenditures at our Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Corriedale wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska.


(c)	Current year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the 35-mile Natural Bridge pipeline project.


(d)	Current year capital expenditures at our Power Generation segment increased due to construction of Busch Ranch II.

CREDIT RATINGS AND COUNTERPARTIES

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. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. 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 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.

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The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2019:



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

__________


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


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


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

Certain of our fees and our interest rates under various bank credit agreements are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgraded our senior unsecured debt, we will be required to pay higher fees and interest rates under these bank credit agreements.

The following table represents the credit ratings of South Dakota Electric at December 31, 2019:



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

__________


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


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


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

We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.

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CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS

Contractual Obligations

In addition to our capital expenditure programs, we have contractual obligations and other commitments that will need to be funded in the future. The following information summarizes our cash obligations and commercial commitments at December 31, 2019. Actual future obligations may differ materially from these estimated amounts (in thousands):



	Payments Due by Period
Contractual Obligations	2020		2021		2022		2023		2024		Thereafter		Total
Long-term debt^(a)	$	5,743	$	8,435	$	—	$	525,000	$	2,855	$	2,635,000	$	3,177,033
Interest payments ^(a)	131,859		131,842		131,756		131,756		109,390		1,273,648		1,910,251
Unconditional purchase obligations^(b)	181,773		159,827		134,018		105,583		54,098		126,147		761,446
Lease obligations^(c)	1,144		991		869		844		724		2,009		6,581
AROs ^(d)	330		231		144		33		9,362		54,105		64,205
Employee benefit plans^(e)	18,921		19,678		19,736		19,944		19,896		35,580		133,755
CP Program	349,500		—		—		—		—		—		349,500
Total contractual cash obligations^(f)	$	689,270	$	321,004	$	286,523	$	783,160	$	196,325	$	4,126,489	$	6,402,771

__________


(a)	Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2019.

(b)

Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas transportation and storage agreements. The energy charges under the PPAs are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2019 and price assumptions using existing prices at December 31, 2019. Our transmission obligations are based on filed tariffs as of December 31, 2019.


(c)	Includes leases associated with several office and operating facilities, communication tower sites, equipment and materials storage.


(d)	Represents estimated payments for AROs associated with long-lived assets primarily related to retirement and reclamation of natural gas pipelines, mining sites, wind farms and an evaporation pond. See Notes 1 and 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.


(e)	Represents estimated employer contributions to the Defined Benefit Pension Plan, the Non-Pension Defined Benefit Postretirement Healthcare Plan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2029 as discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(f)

Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including commodity related contracts that have a negative fair value at December 31, 2019. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table; (3) our $4.2 million liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions as discussed in Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. In addition, a portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure, are carried out for 60 days. As of December 31, 2019, we are committed to purchase 3.7 million MMBtu, 3.7 million MMBtu, and 1.8 million MMBtu in each of the years from 2020 to 2022, respectively.

Off-Balance Sheet Commitments

We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit.

Guarantees

We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 20 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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Letters of Credit

Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. For more information on these letters of credit, see Note 7 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Critical Accounting Policies Involving Significant Accounting Estimates

We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments, or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.

The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Regulation

Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.

Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.

As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million, respectively, and total regulatory liabilities of $537 million and $541 million, respectively. See Note 13 of the Notes to the Consolidated Financial Statements for further information.

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Goodwill

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process.

Accounting standards for testing goodwill for impairment require a two-step process be performed to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. The first step of this test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss.

Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2019. Although 1% to 2% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews, as well as other improved efficiency and cost reduction initiatives. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.

The estimates and assumptions used in the impairment assessments are based on available market information and we believe they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. For the years ended December 31, 2019, 2018, and 2017, there were no impairment losses recorded. At December 31, 2019, the fair value substantially exceeded the carrying value at all reporting units.

As described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have prospectively adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, on January 1, 2020.

Pension and Other Postretirement Benefits

As described in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, 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.

The 2020 pension benefit cost for our non-contributory funded pension plan is expected to be $10.2 million compared to $2.1 million in 2019. The increase in pension benefit cost is driven primarily by a decrease in the discount rate and lower expected return on assets.

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The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:



		December 31,
Assumptions	Percentage Change	2019 Increase/(Decrease) PBO/APBO ^(a)	2020 Increase/(Decrease) Expense - Pretax

Pension
Discount rate ^(b)	+/- 0.5	(28,998)/31,912	(3,965)/4,311
Expected return on assets	+/- 0.5	N/A	(2,036)/2,036

OPEB
Discount rate ^(b)	+/- 0.5	(2,836)/3,095	90/116
Expected return on assets	+/- 0.5	N/A	(39)/39

__________________________


(a)	Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans.


(b)	Impact on service cost, interest cost and amortization of gains or losses.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.

As of December 31, 2019, we have a regulatory liability associated with TCJA related items of $285 million, completing our accounting for the revaluation of deferred taxes pursuant to the TCJA. A significant portion of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets.

As of December 31, 2019, the Company has amortized $6.5 million of regulatory liability associated with TCJA related items. The portion that was eligible for amortization under the average rate assumption method in 2019, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.

See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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Market Risk Disclosures

Our market risk disclosures are detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, with additional information provided in the following paragraphs.

Our exposure to the market risks detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K is also affected by other factors including the size, duration and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates and the liquidity of the related interest rate and commodity markets.

The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at least quarterly and as necessary, appropriate or desirable, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.

Electric and Gas Utilities

We produce, purchase and distribute power in four states, and purchase and distribute natural gas in six states. Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to “true-up” billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota and Wyoming, we have ECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that adjust natural gas rates when our natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic prudence reviews by the state utility commissions. See additional information in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Wholesale Power

A potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. These potential short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.

Financing Activities

Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and anticipated debt refinancings. At December 31, 2019, we had no interest rate swaps in place. As discussed in Item 7 - Liquidity and Capital Resources, 90% of our variable interest rate exposure has been mitigated through issuing fixed rate debt.

Further details of past swap agreements are set forth in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Credit Risk

Our credit risk disclosures are detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, with additional information provided below.

We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. In addition, our Executive Risk Committee, which includes senior executives, meets on a regular basis to review our credit activities and to monitor compliance with the adopted policies.

New Accounting Pronouncements

See Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2019 or pending adoption.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Management’s Report on Internal Controls Over Financial Reporting	73
Reports of Independent Registered Public Accounting Firm	74

Consolidated Statements of Income	77
Consolidated Statements of Comprehensive Income	78
Consolidated Balance Sheets	79
Consolidated Statements of Cash Flows	81
Consolidated Statements of Equity	82
Notes to the Consolidated Financial Statements	83
Note 1. Business Description and Significant Accounting Policies	83
Note 2. Revenue	92
Note 3. Property, Plant and Equipment	94
Note 4. Jointly Owned Facilities	96
Note 5. Business Segments	97
Note 6. Long-term Debt	102
Note 7. Notes Payable	104
Note 8. Asset Retirement Obligations	105
Note 9. Risk Management Activities	106
Note 10. Fair Value Measurements	109
Note 11. Fair Value of Financial Instruments	112
Note 12. Equity	112
Note 13. Regulatory Matters	116
Note 14. Leases	120
Note 15. Income Taxes	123
Note 16. Other Comprehensive Income	126
Note 17. Supplemental Cash Flow Information	128
Note 18. Employee Benefit Plans	128
Note 19. Commitments and Contingencies	135
Note 20. Guarantees	139
Note 21. Discontinued Operations	140
Note 22. Quarterly Historical Data (unaudited)	141

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Management’s Report on Internal Control over Financial Reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 2019.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of December 31, 2019. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.

Black Hills Corporation

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Black Hills Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, cash flows, and equity, for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control--Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting--Impact of Rate Regulation on the Financial Statements--Refer to Note 1 and Note 13 to the financial statements

Critical Audit Matter Description

The Company is subject to cost-of-service regulation and earnings oversight by federal and state utility commissions (collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense).

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Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to have been prudently incurred or that the rate regulation process in which rates are determined will always result in rates that produce a full recovery of costs and the return on invested capital.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers. Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

•

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.


•	We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•

We read relevant regulatory orders issued by the Commissions, procedural memorandums, filings made by the Company, and other publicly available information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions.


•	We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 14, 2020

We have served as the Company’s auditor since 2002.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Black Hills Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule of the Company as of and for the year ended December 31, 2019, and our report dated February 14, 2020 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 14, 2020

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME



Year ended	December 31, 2019			December 31, 2018			December 31, 2017
	(in thousands, except per share amounts)

Revenue	$	1,734,900		$	1,754,268		$	1,680,266

Operating expenses:
Fuel, purchased power and cost of natural gas sold	570,829			625,610			563,288
Operations and maintenance	495,994			481,706			454,605
Depreciation, depletion and amortization	209,120			196,328			188,246
Taxes - property and production	52,915			51,746			51,578
Other operating expenses	—			1,841			5,813
Total operating expenses	1,328,858			1,357,231			1,263,530

Operating income	406,042			397,037			416,736

Other income (expense):
Interest charges -
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(145,847		)	(143,720		)	(140,533		)
Allowance for funds used during construction - borrowed	6,556			2,104			2,415
Interest income	1,632			1,641			1,016
Allowance for funds used during construction - equity	472			619			2,321
Impairment of investment	(19,741		)	—			—
Other income (expense), net	(6,212		)	(1,799		)	(213		)
Total other income (expense)	(163,140		)	(141,155		)	(134,994		)
Income before income taxes	242,902			255,882			281,742
Income tax benefit (expense)	(29,580		)	23,667			(73,367		)
Income from continuing operations	213,322			279,549			208,375
Net (loss) from discontinued operations	—			(6,887		)	(17,099		)
Net income	213,322			272,662			191,276
Net income attributable to noncontrolling interest	(14,012		)	(14,220		)	(14,242		)
Net income available for common stock	$	199,310		$	258,442		$	177,034

Amounts attributable to common shareholders:
Net income from continuing operations	$	199,310		$	265,329		$	194,133
Net (loss) from discontinued operations	—			(6,887		)	(17,099		)
Net income available for common stock	$	199,310		$	258,442		$	177,034

Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations	$	3.29		$	4.88		$	3.65
(Loss) from discontinued operations	—			(0.13		)	(0.32		)
Total earnings per share of common stock, Basic	$	3.29		$	4.75		$	3.33

Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations	$	3.28		$	4.78		$	3.52
(Loss) from discontinued operations	—			(0.12		)	(0.31		)
Total earnings per share of common stock, Diluted	$	3.28		$	4.66		$	3.21

Weighted average common shares outstanding:
Basic	60,662			54,420			53,221
Diluted	60,798			55,486			55,120

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

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



Year ended	December 31, 2019			December 31, 2018			December 31, 2017
	(in thousands)
Net income	$	213,322		$	272,662		$	191,276

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $1,886, $(660) and $1,030, respectively)	(6,253		)	2,155			(1,890		)
Benefit plan liability adjustments - prior service costs (net of tax of $2, $0 and $0, respectively)	(8		)	—			—
Reclassification adjustment of benefit plan liability - net loss (net of tax of $434, $(586) and $(585), respectively)	1,179			1,901			1,072
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $19, $43 and $69, respectively)	(58		)	(135		)	(128		)
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(666), $(599) and$(1,029) , respectively)	2,185			2,252			1,912
Net unrealized gains (losses) on commodity derivatives (net of tax of $126, $(228) and $(135), respectively)	(422		)	755			231
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $55, $(31) and $154, respectively)	(362		)	99			(516		)
Other comprehensive income (loss), net of tax	(3,739		)	7,027			681

Comprehensive income	209,583			279,689			191,957
Less: comprehensive income attributable to non-controlling interest	(14,012		)	(14,220		)	(14,242		)
Comprehensive income available for common stock	$	195,571		$	265,469		$	177,715

See Note 16 for additional disclosures related to Comprehensive Income.

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

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS



	As of
	December 31, 2019			December 31, 2018
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	9,777		$	20,776
Restricted cash and equivalents	3,881			3,369
Accounts receivable, net	255,805			269,153
Materials, supplies and fuel	117,172			117,299
Derivative assets, current	342			1,500
Income tax receivable, net	16,446			12,978
Regulatory assets, current	43,282			48,776
Other current assets	26,479			29,982
Total current assets	473,184			503,833

Investments	21,929			41,013

Property, plant and equipment	6,784,679			6,000,015
Less accumulated depreciation and depletion	(1,281,493		)	(1,145,136		)
Total property, plant and equipment, net	5,503,186			4,854,879

Other assets:
Goodwill	1,299,454			1,299,454
Intangible assets, net	13,266			14,337
Regulatory assets, non-current	228,062			235,459
Other assets, non-current	19,376			14,352
Total other assets, non-current	1,560,158			1,563,602
TOTAL ASSETS	$	7,558,457		$	6,963,327

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

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Continued)



	As of
	December 31, 2019			December 31, 2018
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	193,523		$	210,609
Accrued liabilities	226,767			215,501
Derivative liabilities, current	2,254			947
Regulatory liabilities, current	33,507			29,810
Notes payable	349,500			185,620
Current maturities of long-term debt	5,743			5,743
Total current liabilities	811,294			648,230

Long-term debt, net of current maturities	3,140,096			2,950,835

Deferred credits and other liabilities:
Deferred income tax liabilities, net	360,719			311,331
Regulatory liabilities, non-current	503,145			510,984
Benefit plan liabilities	154,472			145,147
Other deferred credits and other liabilities	124,662			109,377
Total deferred credits and other liabilities	1,142,998			1,076,839

Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)

Equity:
Stockholders’ equity -
Common stock $1 par value; 100,000,000 shares authorized; issued: 61,480,658 and 60,048,567, respectively	61,481			60,049
Additional paid-in capital	1,552,788			1,450,569
Retained earnings	778,776			700,396
Treasury stock at cost - 3,956 and 44,253, respectively	(267		)	(2,510		)
Accumulated other comprehensive income (loss)	(30,655		)	(26,916		)
Total stockholders’ equity	2,362,123			2,181,588
Noncontrolling interest	101,946			105,835
Total equity	2,464,069			2,287,423

TOTAL LIABILITIES AND TOTAL EQUITY	$	7,558,457		$	6,963,327

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

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



Year ended	December 31, 2019			December 31, 2018			December 31, 2017
	(in thousands)
Operating activities:
Net income	$	213,322		$	272,662		$	191,276
Loss from discontinued operations, net of tax	—			6,887			17,099
Income from continuing operations	213,322			279,549			208,375
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	209,120			196,328			188,246
Deferred financing cost amortization	7,838			7,845			8,261
Impairment of investment	19,741			—			—
Stock compensation	12,095			12,390			7,626
Deferred income taxes	38,020			(24,239		)	80,992
Employee benefit plans	12,406			14,068			10,141
Other adjustments, net	16,485			5,836			(4,773		)
Change in certain operating assets and liabilities:
Materials, supplies and fuel	2,052			(2,919		)	(10,089		)
Accounts receivable and other current assets	7,578			(45,966		)	4,534
Accounts payable and other current liabilities	(34,906		)	5,305			(28,222		)
Regulatory assets - current	23,619			33,608			(15,407		)
Regulatory liabilities - current	(15,158		)	18,533			(4,536		)
Contributions to defined benefit pension plans	(12,700		)	(12,700		)	(27,700		)
Other operating activities, net	6,001			6,689			(8,418		)
Net cash provided by operating activities of continuing operations	505,513			494,327			409,030
Net cash provided by (used in) operating activities of discontinued operations	—			(5,516		)	19,231
Net cash provided by operating activities	505,513			488,811			428,261

Investing activities:
Property, plant and equipment additions	(818,376		)	(457,524		)	(326,010		)
Purchase of investment	—			(24,429		)	—
Other investing activities	2,166			(4,281		)	1,011
Net cash (used in) investing activities of continuing operations	(816,210		)	(486,234		)	(324,999		)
Net cash provided by investing activities of discontinued operations	—			20,385			7,881
Net cash (used in) investing activities	(816,210		)	(465,849		)	(317,118		)

Financing activities:
Dividends paid on common stock	(124,647		)	(106,591		)	(96,744		)
Common stock issued	101,358			300,834			4,408
Net (payments) borrowings of short-term debt	163,880			(25,680		)	114,700
Long-term debt - issuance	1,100,000			700,000			—
Long-term debt - repayments	(905,743		)	(854,743		)	(105,743		)
Distributions to noncontrolling interests	(17,901		)	(19,617		)	(18,397		)
Other financing activities	(16,737		)	(11,260		)	(6,919		)
Net cash provided by (used in) financing activities	300,210			(17,057		)	(108,695		)

Net change in cash, restricted cash and cash equivalents	(10,487		)	5,905			2,448

Cash, restricted cash and cash equivalents beginning of year	24,145			18,240			15,792
Cash, restricted cash and cash equivalents end of year	$	13,658		$	24,145		$	18,240

See Note 17 for supplemental disclosure of cash flow information.

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

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY



	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares		Value			Additional Paid in Capital			Retained Earnings			AOCI			Non controlling Interest			Total
Balance at December 31, 2016	53,397,467	$	53,397	15,258		$	(791	)	$	1,138,982		$	457,934		$	(34,883	)	$	115,495		$	1,730,134
Net income (loss) available for common stock	—	—		—		—			—			177,034			—			14,242			191,276
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			681			—			681
Reclassification of certain tax effects from AOCI	—	—		—		—			—			7,000			(7,000		)	—			—
Dividends on common stock	—	—		—		—			—			(96,744		)	—			—			(96,744		)
Share-based compensation	134,266	134		23,806		(1,515		)	8,948			—			—			—			7,567
Tax effect of share-based compensation	—	—		—		—			533			3,184			—			—			3,717
Issuance costs	—	—		—		—			(189		)	—			—			—			(189		)
Dividend reinvestment and stock purchase plan	48,253	49		—		—			3,107			—			—			—			3,156
Distributions to noncontrolling interest	—	—		—		—			(1,096		)	209			—			(18,505		)	(19,392		)
Balance at December 31, 2017	53,579,986	$	53,580	39,064		$	(2,306	)	$	1,150,285		$	548,617		$	(41,202	)	$	111,232		$	1,820,206
Net income (loss) available for common stock	—	—		—		—			—			258,442			—			14,220			272,662
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			7,027			—			7,027
Reclassification of certain tax effects from AOCI	—	—		—		—			—			—			740			—			740
Reclassification to regulatory asset	—	—		—		—			—			—			6,519			—			6,519
Dividends on common stock	—	—		—		—			—			(106,591		)	—			—			(106,591		)
Share-based compensation	92,830	93		5,189		(204		)	7,301			—			—			—			7,190
Issuance of common stock	6,371,690	6,372		—		—			292,628			—			—			—			299,000
Issuance costs	—	—		—		—			(15		)	—			—			—			(15		)
Dividend reinvestment and stock purchase plan	4,061	4		—		—			216			—			—			—			220
Other stock transactions	—	—		—		—			154			(72		)	—			—			82
Redemption of and distributions to noncontrolling interest	—	—		—		—			—			—			—			(19,617		)	(19,617		)
Balance at 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	—	—		—		—			—			199,310			—			14,012			213,322
Other comprehensive income (loss), net of tax	—	—		—		—			—			—			(3,739		)	—			(3,739		)
Dividends on common stock	—	—		—		—			—			(124,647		)	—			—			(124,647		)
Share-based compensation	103,759	104		(40,297	)	2,243			4,729			—			—			—			7,076
Issuance of common stock	1,328,332	1,328		—		—			98,672			—			—			—			100,000
Issuance costs	—	—		—		—			(1,182		)	—			—			—			(1,182		)
Other	—	—		—		—			—			327			—			—			327
Implementation of ASU 2016-02 Leases	—	—		—		—			—			3,390			—			—			3,390
Distributions to noncontrolling interest	—	—		—		—			—			—			—			(17,901		)	(17,901		)
Balance at December 31, 2019	61,480,658	$	61,481	3,956		$	(267	)	$	1,552,788		$	778,776		$	(30,655	)	$	101,946		$	2,464,069

__________________

Dividends per share paid were $2.05, $1.93 and $1.81 for the years ended December 31, 2019, 2018 and 2017, respectively.

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

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BLACK HILLS CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2019, 2018 and 2017


(1)	BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Segment Reporting

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.

Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming.

Most of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5.

On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued operations in 2018 or 2017. 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 consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5.

Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information.

Variable Interest Entities

We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

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A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.

Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12.

Cash and Cash Equivalents and Restricted Cash

We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal.

We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.

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Following is a summary of accounts receivable as of December 31 (in thousands):



2019	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	41,428	$	33,886	$	(592	)	$	74,722
Gas Utilities	97,607		79,616		(1,683		)	175,540
Power Generation	2,164		—		—			2,164
Mining	2,277		—		—			2,277
Corporate	1,271		—		(169		)	1,102
Total	$	144,747	$	113,502	$	(2,444	)	$	255,805



2018	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			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

Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):



	Balance at Beginning of Year		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions			Balance at End of Year
2019	$	3,209	$	5,795	$	3,942	$	(10,502	)	$	2,444
2018	$	3,081	$	6,859	$	4,092	$	(10,823	)	$	3,209
2017	$	2,392	$	4,926	$	8,262	$	(12,499	)	$	3,081

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):



	2019		2018
Materials and supplies	$	82,809	$	75,081
Fuel - Electric Utilities	2,425		2,850
Natural gas in storage	31,938		39,368
Total materials, supplies and fuel	$	117,172	$	117,299

Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our Natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.

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Investments

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

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

The following table presents the carrying value of our investments (in thousands) as of December 31:



	2019		2018
Investment in privately held oil and gas company	$	8,359	$	28,100
Cash surrender value of life insurance contracts	13,056		12,812
Other investments	514		101
Total investments	$	21,929	$	41,013

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “Cushion gas” as property, plant and equipment.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.

Goodwill and Intangible Assets

Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information.

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Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies.

We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill amounts have not changed since 2016. As of December 31, 2019, 2018 and 2017, Goodwill balances were as follows (in thousands):



	Electric Utilities		Gas Utilities		Power Generation		Total
Goodwill	$	248,479	$	1,042,210	$	8,765	$	1,299,454

Our intangible assets represent easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):



	2019			2018			2017
Intangible assets, net, beginning balance	$	14,337		$	7,559		$	8,392
Additions ^(a)	—			7,602			—
Amortization expense ^(b)	(1,071		)	(824		)	(833		)
Intangible assets, net, ending balance	$	13,266		$	14,337		$	7,559

_________________


(a)	The 2018 addition is related to the Busch Ranch 1 contract intangible asset. See Note 4 for further information.


(b)	Amortization expense for existing intangible assets is expected to be $1.1 million for each year of the next five years.

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):



	2019		2018
Accrued employee compensation, benefits and withholdings	$	62,837	$	63,742
Accrued property taxes	44,547		42,510
Customer deposits and prepayments	54,728		43,574
Accrued interest	31,868		31,759
CIAC current portion	1,952		1,485
Other (none of which is individually significant)	30,835		32,431
Total accrued liabilities	$	226,767	$	215,501

Asset Retirement Obligations

Accounting standards for AROs associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability.

We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. Additional information is included in Note 8.

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Fair Value Measurements

Financial Instruments

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

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

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities 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 using its own assumptions about the assumptions a market participant would use in pricing the 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.

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

Valuation Methodologies for Derivatives

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

Additional information on fair value measurements is included in Notes 10, 11 and 18.

Derivatives and Hedging Activities

All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utilities’ operations, we enter into contracts to buy and sell energy to meet the requirements of our customers.

In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980.

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We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings.

Deferred Financing Costs

Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities.

Regulatory Accounting

Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:


•	Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.


•	Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred

Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.

As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million respectively, and total regulatory liabilities of $537 million and $541 million respectively. See Note 13 for further information.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.

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It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income.

We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.

Earnings per Share of Common Stock

Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans.

A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands):



	2019		2018		2017

Net income available for common stock	$	199,310	$	258,442	$	177,034

Weighted average shares - basic	60,662		54,420		53,221
Dilutive effect of:
Equity Units	—		898		1,783
Equity compensation	136		168		116
Weighted average shares - diluted	60,798		55,486		55,120

Net income available for common stock, per share - Diluted	$	3.28	$	4.66	$	3.21

The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands):

Noncontrolling Interests

We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on Noncontrolling Interests.

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Share-Based Compensation

We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures.

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.

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

In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

Simplifying the Test for Goodwill Impairment, ASU 2017-04

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance is not expected to have any impact on our financial position, results of operations or cash flows.

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

In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, 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. It is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted.

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 doubtful accounts, primarily associated with the inclusion of expected losses on unbilled revenue. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.

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Recently Adopted Accounting Standards

Leases, ASU 2016-02

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

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

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

See Note 14 for additional details on leases.

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

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement 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. We have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.

(2) REVENUE

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

•

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

•

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

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•

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

•

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

The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the years ended December 31, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.



Year ended December 31, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	605,756	$	817,840	$	—	$	59,233	$	(32,053	)	$	1,450,776
Transportation	—		143,390		—		—		(1,042		)	142,348
Wholesale	20,884		—		99,157		—		(91,577		)	28,464
Market - off-system sales	23,817		691		—		—		(7,736		)	16,772
Transmission/Other	57,104		47,725		—		—		(16,797		)	88,032
Revenue from contracts with customers	707,561		1,009,646		99,157		59,233		(149,205		)	1,726,392
Other revenues	5,191		384		2,101		2,396		(1,564		)	8,508
Total revenues	$	712,752	$	1,010,030	$	101,258	$	61,629	$	(150,769	)	$	1,734,900

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	59,233	$	(32,053	)	$	27,180
Services transferred over time	707,561		1,009,646		99,157		—		(117,152		)	1,699,212
Revenue from contracts with customers	$	707,561	$	1,009,646	$	99,157	$	59,233	$	(149,205	)	$	1,726,392

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Year ended December 31, 2018	Electric Utilities		Gas Utilities		Power Generation ^(a)		Mining		Inter-company Revenues ^(a)			Total
Customer types:	(in thousands)
Retail	$	594,329	$	833,379	$	—	$	65,803	$	(32,194	)	$	1,461,317
Transportation	—		140,705		—		—		(1,348		)	139,357
Wholesale	33,687		—		90,791		—		(84,957		)	39,521
Market - off-system sales	24,799		866		—		—		(8,102		)	17,563
Transmission/Other	56,209		49,402		—		—		(14,827		)	90,784
Revenue from contracts with customers	709,024		1,024,352		90,791		65,803		(141,428		)	1,748,542
Other revenues	2,427		955		1,660		2,230		(1,546		)	5,726
Total revenues	$	711,451	$	1,025,307	$	92,451	$	68,033	$	(142,974	)	$	1,754,268

Timing of revenue recognition:
Services transferred at a point in time	$	—	$	—	$	—	$	65,803	$	(32,194	)	$	33,609
Services transferred over time	709,024		1,024,352		90,791		—		(109,234		)	1,714,933
Revenue from contracts with customers	$	709,024	$	1,024,352	$	90,791	$	65,803	$	(141,428	)	$	1,748,542

(a)

Due to the changes in our segment disclosures discussed in Note 5, Power Generation Wholesale revenue was revised for the year ended December 31, 2018, which resulted in an increase of $38 million. The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million. There was no impact to our consolidated Total Revenues.

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

Revenue Not in Scope of ASC 606

Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. Effective January 1, 2019, we changed how we account for the PPA between Black Hills Colorado IPP and Colorado Electric at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information.

Significant Judgments and Estimates

Unbilled Revenue

To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.

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 1. We do not typically incur costs that would be capitalized to obtain or fulfill a contract.

(3) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):



	2019				2018				Lives (in years)
Electric Utilities	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Property, Plant and Equipment ^(b)			Weighted Average Useful Life (in years)	Minimum	Maximum

Electric plant:
Production	$	1,348,049		41	$	1,318,643		41	32	46
Electric transmission	483,640			51	437,082			51	43	54
Electric distribution	861,042			47	793,725			48	46	50
Plant acquisition adjustment ^(a)	4,870			32	4,870			32	32	32
General	259,266			28	233,531			28	26	33
Total electric plant in service	2,956,867				2,787,851
Construction work in progress	102,268				60,480
Total electric plant	3,059,135				2,848,331
Less accumulated depreciation and amortization	(670,861		)		(615,365		)
Electric plant net of accumulated depreciation and amortization	$	2,388,274			$	2,232,966

_____________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with 11 years remaining.

(b)

Due to the changes in our segment disclosures discussed in Note 5, Total electric plant in service, Accumulated depreciation and amortization, and Electric plant net of accumulated depreciation and amortization were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million, $91 million and ($170) million, respectively. There was no impact on our consolidated Plant, property and equipment.

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	2019				2018				Lives (in years)
Gas Utilities	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	13,000		35	$	13,580		35	24	71
Gas transmission	516,172			50	423,873			48	22	67
Gas distribution	1,857,233			43	1,595,644			42	30	56
Cushion gas - depreciable ^(a)	3,539			28	3,539			28	28	28
Cushion gas - not depreciable ^(a)	44,443			N/A	46,369			N/A	N/A	N/A
Storage	46,977			31	29,335			30	27	49
General	437,054			20	355,920			19	10	24
Total gas plant in service	2,918,418				2,468,260
Construction work in progress	63,080				38,271
Total gas plant	2,981,498				2,506,531
Less accumulated depreciation and amortization	(336,721		)		(279,580		)
Gas plant net of accumulated depreciation and amortization	$	2,644,777			$	2,226,951

_____________


(a)	Depreciation of Cushion gas is determined by the respective regulatory jurisdiction in which the Cushion gas resides.



2019												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	532,397	$	2,121	$	534,518	$	(154,362	)	$	380,156	31	2	40
Mining	$	179,198	$	1,275	$	180,473	$	(118,585	)	$	61,888	13	2	59



2018												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation ^(a)	$	435,438	$	11,796	$	447,234	$	(137,832	)	$	309,402	31	2	40
Mining	$	175,650	$	—	$	175,650	$	(111,689	)	$	63,961	13	2	59

_____________


(a)	Due to the changes in our segment disclosures discussed in Note 5, Property, plant and equipment, Accumulated depreciation and amortization, and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of $261 million, ($73) million and $188 million, respectively. There was no impact on our consolidated Plant, property and equipment.

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2019												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	5,721	$	23,334	$	29,055	$	(964	)	$	28,091	10	3	30



2018												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation and Amortization			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate ^(a)	$	5,721	$	16,548	$	22,269	$	(670	)	$	21,599	8	3	30

___________


(a)	Due to the changes in our segment disclosures discussed in Note 5, Corporate Accumulated depreciation and amortization and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($18) million and ($18) million respectively. There was no impact on our consolidated Plant, property and equipment.

(4) JOINTLY OWNED FACILITIES

Our consolidated financial statements include our share of several jointly-owned utility and non-regulated facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.

•

South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

•

South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC and SPP regions. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie.

•

South Dakota Electric owns 52% of the Wygen III generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies fuel to Wygen III for the life of the plant.


•	Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations.

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At December 31, 2019, our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Less Accumulated Depreciation			Plant Net of Accumulated Depreciation
Wyodak Plant	$	116,074	$	729	$	(64,413	)	$	52,390
Transmission Tie	$	19,862	$	4,161	$	(6,612	)	$	17,411
Wygen I	$	120,824	$	289	$	(48,703	)	$	72,410
Wygen III	$	146,161	$	400	$	(25,518	)	$	121,043

Jointly Owned Facility - Related Party

Colorado Electric owns 50% of Busch Ranch I while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. On December 11, 2018, Black Hills Electric Generation purchased its 50% ownership interest in Busch Ranch I for $16 million. Colorado Electric retains responsibility for operations of the wind farm. We recorded this purchase as an asset acquisition at fair value with $8.7 million of the purchase price recorded as wind generation assets, and $7.6 million recorded as an intangible asset, reflective of the fair value of the PPA. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.

(5) BUSINESS SEGMENT INFORMATION

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

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

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

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Segment information was as follows (in thousands):



Total Assets (net of intercompany eliminations) as of December 31,	2019		2018
Electric Utilities ^(a)	$	2,900,983	$	2,707,695
Gas Utilities	4,032,339		3,623,475
Power Generation^(a)	417,715		342,085
Mining	77,175		80,594
Corporate and Other	130,245		209,478
Total assets	$	7,558,457	$	6,963,327

__________________


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



Capital Expenditures ^(a) for the years ended December 31,	2019		2018
Capital expenditures
Electric Utilities	$	222,911	$	152,524
Gas Utilities	512,366		288,438
Power Generation	85,346		30,945
Mining	8,430		18,794
Corporate and Other	20,702		11,723
Total capital expenditures of continuing operations	849,755		502,424
Total capital expenditures of discontinued operations	—		2,402
Total capital expenditures	$	849,755	$	504,826

_________________


(a)	Includes accruals for property, plant and equipment as disclosed in Note 17.



Property, Plant and Equipment as of December 31,	2019		2018
Electric Utilities ^(a)	$	3,059,135	$	2,848,331
Gas Utilities	2,981,498		2,506,531
Power Generation ^(a)	534,518		447,234
Mining	180,473		175,650
Corporate and Other	29,055		22,269
Total property, plant and equipment	$	6,784,679	$	6,000,015

_______________


(a)	Due to the changes in our segment disclosures, Electric Utilities and Power Generation Property, Plant and Equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million and $261 million, respectively. There was no impact on our consolidated Property, Plant and Equipment.

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	Consolidating Income Statement
Year ended December 31, 2019	Electric Utilities		Gas Utilities		Power Generation		Mining		Corporate		Inter-Company Eliminations			Total

Revenue -
Contracts with customers	$	684,445	$	1,007,187	$	7,580	$	27,180	$	—	$	—		$	1,726,392
Other revenues	5,191		384		1,859		1,074		—		—			8,508
	689,636		1,007,571		9,439		28,254		—		—			1,734,900
Inter-company operating revenue -
Contracts with customers	23,116		2,459		91,577		32,053		230		(149,435		)	—
Other revenues	—		—		242		1,322		343,975		(345,539		)	—
	23,116		2,459		91,819		33,375		344,205		(494,974		)	—
Total revenue	712,752		1,010,030		101,258		61,629		344,205		(494,974		)	1,734,900

Fuel, purchased power and cost of natural gas sold	268,297		425,898		9,059		—		268		(132,693		)	570,829
Operations and maintenance	195,581		301,844		28,429		40,032		286,799		(303,776		)	548,909
Depreciation, depletion and amortization	88,577		92,317		18,991		8,970		22,065		(21,800		)	209,120
Adjusted operating income (loss)	$	160,297	$	189,971	$	44,779	$	12,627	$	35,073	$	(36,705	)	$	406,042

Interest expense, net														(137,659		)
Impairment of investment ^(a)														(19,741		)
Other income (expense), net														(5,740		)
Income tax benefit (expense)														(29,580		)
Income from continuing operations														213,322
(Loss) from discontinued operations, net of tax														—
Net income														213,322
Net income attributable to noncontrolling interest														(14,012		)
Net income available for common stock														$	199,310

________________


(a)	In 2019 we recorded an impairment of our investment in equity securities of a privately held oil and gas company. See Note 1 for additional information.

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	Consolidating Income Statement
Year ended December 31, 2018	Electric Utilities ^(b)		Gas Utilities		Power Generation ^(b)		Mining		Corporate		Inter-Company Eliminations ^(b)			Total

Revenue -
Contracts with customers	$	686,272	$	1,022,828	$	5,833	$	33,609	$	—	$	—		$	1,748,542
Other revenues	2,427		955		1,413		931		—		$	—		5,726
	688,699		1,023,783		7,246		34,540		—		—			1,754,268
Inter-company operating revenue -
Contracts with customers	22,752		1,524		84,959		32,194		148		(141,577		)	—
Other revenues	—		—		246		1,299		379,775		(381,320		)	—
	22,752		1,524		85,205		33,493		379,923		(522,897		)	—
Total revenue	711,451		1,025,307		92,451		68,033		379,923		(522,897		)	1,754,268

Fuel, purchased power and cost of natural gas sold	283,840		462,153		8,592		—		44		(129,019		)	625,610
Operations and maintenance	186,175		291,481		25,135		43,728		324,916		(336,142		)	535,293
Depreciation, depletion and amortization	85,567		86,434		16,110		7,965		21,161		(20,909		)	196,328
Adjusted operating income (loss)	155,869		185,239		42,614		16,340		33,802		(36,827		)	397,037

Interest expense, net														(139,975		)
Other income (expense), net														(1,180		)
Income tax benefit (expense)^(a)														23,667
Income from continuing operations														279,549
(Loss) from discontinued operations, net of tax														(6,887		)
Net income														272,662
Net income attributable to noncontrolling interest														(14,220		)
Net income available for common stock														$	258,442

________________


(a)	Income tax benefit (expense) includes a tax benefit of $73 million resulting from legal entity restructuring. See Note 15.


(b)	Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2018, which resulted in an increase (decrease) as follows (in millions):



Year ended December 31, 2018	Electric Utilities			Power Generation			Inter-Company Eliminations			Total
Inter-company operating revenue - Contracts with customers	$	—		$	3.5		$	(3.5	)	$	—
Fuel, purchased power and cost of natural gas sold	6.7			—			(6.7		)	—
Depreciation, depletion and amortization	(13.1		)	9.2			3.9			—
Adjusted operating income (loss)	$	6.4		$	(5.7	)	$	(0.7	)	$	—

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	Consolidating Income Statement
Year ended December 31, 2017	Electric Utilities ^(b)		Gas Utilities		Power Generation ^(b)		Mining		Corporate		Inter-Company Eliminations ^(b)			Total

Revenue	$	689,945	$	947,595	$	7,263	$	35,463	$	—	$	—		$	1,680,266
Inter-company revenue	14,705		35		87,357		31,158		344,685		(477,940		)	—
Total revenue	704,650		947,630		94,620		66,621		344,685		(477,940		)	1,680,266

Fuel, purchased power and cost of natural gas sold	274,363		409,603		9,340		—		151		(130,169		)	563,288
Operations and maintenance	172,307		269,190		23,042		44,882		296,067		(293,492		)	511,996
Depreciation, depletion and amortization	80,243		83,732		15,548		8,239		21,031		(20,547		)	188,246
Adjusted operating income (loss)	177,737		185,105		46,690		13,500		27,436		(33,732		)	416,736

Interest expense, net														(137,102		)
Other income (expense), net														2,108
Income tax benefit (expense)														(73,367		)
Income from continuing operations														208,375
(Loss) from discontinued operations, net of tax^(a)														(17,099		)
Net income														191,276
Net income attributable to noncontrolling interest														(14,242		)
Net income available for common stock														$	177,034

________________


(a)	Discontinued operations includes oil and gas property impairments. See Note 21.


(b)	Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2017, which resulted in an increase (decrease) as follows (in millions):



Year ended December 31, 2017	Electric Utilities			Power Generation			Inter-Company Eliminations			Total
Inter-company revenue	$	—		$	3.1		$	(3.1	)	$	—
Fuel, purchased power and cost of natural gas sold	6.0			—			(6.0		)	—
Depreciation, depletion and amortization	(13.1		)	9.6			3.5			—
Adjusted operating income (loss)	$	7.1		$	(6.5	)	$	(0.6	)	$	—

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(6) LONG-TERM DEBT

Long-term debt outstanding was as follows (dollars in thousands):



		Interest Rate at	Balance Outstanding
	Due Date	December 31, 2019	December 31, 2019			December 31, 2018
Corporate
Senior unsecured notes due 2023	November 30, 2023	4.25%	$	525,000		$	525,000
Senior unsecured notes due 2020	July 15, 2020	N/A	—			200,000
Senior unsecured notes due 2026	January 15, 2026	3.95%	300,000			300,000
Senior unsecured notes due 2027	January 15, 2027	3.15%	400,000			400,000
Senior unsecured notes due 2033	May 1, 2033	4.35%	400,000			400,000
Senior unsecured notes, due 2046	September 15, 2046	4.20%	300,000			300,000
Senior unsecured notes, due 2029	October 15, 2029	3.05%	400,000			—
Senior unsecured notes, due 2049	October 15, 2049	3.88%	300,000			—
Corporate term loan due 2021 ^(a)	June 17, 2021	N/A	—			300,000
Corporate term loan due 2021	June 7, 2021	2.32%	7,178			12,921
Total Corporate debt			2,632,178			2,437,921
Less unamortized debt discount			(6,462		)	(5,122		)
Total Corporate debt, net			2,625,716			2,432,799

South Dakota Electric
Series 94A Debt, variable rate ^(b)	June 1, 2024	1.84%	2,855			2,855
First Mortgage Bonds due 2032	August 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13%	180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43%	85,000			85,000
Total South Dakota Electric debt			342,855			342,855
Less unamortized debt discount			(82		)	(86		)
Total South Dakota Electric debt, net			342,773			342,769

Wyoming Electric
Industrial development revenue bonds due 2021^(a)	September 1, 2021	1.68%	7,000			7,000
Industrial development revenue bonds due 2027^(a)	March 1, 2027	1.68%	10,000			10,000
First Mortgage Bonds due 2037	November 20, 2037	6.67%	110,000			110,000
First Mortgage Bonds due 2044	October 20, 2044	4.53%	75,000			75,000
Total Wyoming Electric debt			202,000			202,000
Less unamortized debt discount			—			—
Total Wyoming Electric debt, net			202,000			202,000

Total long-term debt			3,170,489			2,977,568
Less current maturities			5,743			5,743
Less unamortized deferred financing costs ^(b)			24,650			20,990
Long-term debt, net of current maturities and deferred financing costs			$	3,140,096		$	2,950,835

_______________


(a)	Variable interest rate.


(b)	Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2019 and December 31, 2018, respectively.

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Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2020	$	5,743
2021	$	8,435
2022	$	—
2023	$	525,000
2024	$	2,855
Thereafter	$	2,635,000

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2019.

Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.

Debt Transactions

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured noted. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following:

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

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

• Repay a portion of short-term debt.

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

On December 12, 2018, we paid off the $250 million, 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to pay off this debt.

On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due May 1, 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt.

The issuance of the $400 million senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see Note 12). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate).

On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, had a maturity date of July 30, 2020 and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. This term loan was later amended on June 17, 2019 and then repaid using proceeds from the October 3, 2019 public debt offering.

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Amortization Expense

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):



Deferred Financing Costs Remaining at		Amortization Expense for the years ended December 31,
December 31, 2019		2019		2018		2017
$	24,650	$	3,242	$	2,829	$	3,349

Dividend Restrictions

Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. As of December 31, 2019, we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2019:


•	Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2019, the restricted net assets at our Electric and Gas Utilities were approximately $156 million.


•	Wyoming Electric and South Dakota Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements.

(7) NOTES PAYABLE

We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):



	December 31, 2019				December 31, 2018
	Balance Outstanding		Letters of Credit ^(a)		Balance Outstanding		Letters of Credit ^(a)
Revolving Credit Facility	$	—	$	30,274	$	—	$	22,311
CP Program	349,500		—		185,620		—
Total	$	349,500	$	30,274	$	185,620	$	22,311

_______________


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

Revolving Credit Facility and CP Program

On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. 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 December 31, 2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2019.

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

Our net short-term borrowings (payments) during 2019 were $164 million. As of December 31, 2019, the weighted average interest rate on short-term borrowings was 2.03%.

Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See Note 6 above for additional details.

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 is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. 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. As of December 31, 2019, we were in compliance with these covenants.

(8) ASSET RETIREMENT OBLIGATIONS

We have identified legal retirement obligations related to reclamation of mining sites in the Mining segment and removal of fuel tanks, transformers containing polychlorinated biphenyls, and an evaporation pond at our Electric Utilities, wind turbines at our Electric Utilities and Power Generation segments, retirement of gas pipelines at our Gas Utilities and removal of asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these AROs. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment.

The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):



	December 31, 2018		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates ^{(a) (b)}			December 31, 2019
Electric Utilities ^(c)	$	6,258	$	—	$	—		$	385	$	2,686		$	9,329
Gas Utilities	34,627		—		—			1,458		—			36,085
Power Generation ^(c)	300		3,445		—			158		836			4,739
Mining	15,615		—		(380		)	740		(1,923		)	14,052
Total	$	56,800	$	3,445	$	(380	)	$	2,741	$	1,599		$	64,205

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	December 31, 2017		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates ^(b)		December 31, 2018
Electric Utilities	$	6,287	$	—	$	—		$	269	$	2	$	6,558
Gas Utilities	33,238		152		—			1,237		—		34,627
Mining	12,499		—		(4		)	649		2,471		15,615
Total	$	52,024	$	152	$	(4	)	$	2,155	$	2,473	$	56,800

_____________________


(a)	The increase in Electric Utilities Revisions to Prior Estimates was primarily driven by an increase to the estimated cost to decommission certain regulated wind farm assets.


(b)	The changes in the Mining Revision to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process.


(c)	We reclassified $0.3 million of ARO as of December 31, 2018 related to Busch Ranch I from Electric Utilities to the Power Generation segment as a result of Black Hills Electric Generation’s purchase of its 50% ownership interest in Busch Ranch I. Additional liabilities were incurred in 2019 from new wind assets.

We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time.

(9) RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal 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 Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1.

Market Risk

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


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


•	Interest rate risk associated with our variable debt as described in Notes 6 and 7.

Credit Risk

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

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

Our credit exposure at December 31, 2019 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10.

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Utilities

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

For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying 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 Consolidated Statements of Income.

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from January 2020 through December 2021. A portion of 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 Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our hedging position is evaluated at least quarterly.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of:



	December 31, 2019		December 31, 2018
	Notional (MMBtus)	Maximum Term (months) ^(a)	Notional (MMBtus)	Maximum Term (months) ^(a)
Natural gas futures purchased	1,450,000	12	4,000,000	24
Natural gas options purchased, net	3,240,000	3	4,320,000	13
Natural gas basis swaps purchased	1,290,000	12	3,960,000	24
Natural gas over-the-counter swaps, net ^(b)	4,600,000	24	3,660,000	24
Natural gas physical commitments, net ^(c)	13,548,235	12	18,325,852	30

__________


(a)	Term reflects the maximum forward period hedged.


(b)	As of December 31, 2019, 1,415,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.


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

Based on December 31, 2019 prices, a $0.5 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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Cash Flow Hedges

The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2019, 2018 and 2017 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.



	December 31, 2019
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income

Interest rate swaps	Interest expense	$	(2,851	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	417
Total impact from cash flow hedges		$	(2,434	)



	December 31, 2018
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income

Interest rate swaps	Interest expense	$	(2,851	)
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(130		)
Total impact from cash flow hedges		$	(2,981	)



	December 31, 2017
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income

Interest rate swaps	Interest expense	$	(2,941	)
Commodity derivatives	Net (loss) from discontinued operations	913
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(243		)
Total impact from cash flow hedges		$	(2,271	)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2019, 2018 and 2017 (in thousands).



	December 31, 2019			December 31, 2018		December 31, 2017

Increase (decrease) in fair value:
Forward commodity contracts	$	(548	)	$	983	$	366
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	2,851			2,851		2,941
Forward commodity contracts	(417		)	130		(670		)
Total other comprehensive income (loss) from hedging	$	1,886		$	3,964	$	2,637

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Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.



		December 31, 2019			December 31, 2018		December 31, 2017
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income		Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives	Fuel, purchased power and cost of natural gas sold	$	(1,100	)	$	1,101	$	(2,207	)
		$	(1,100	)	$	1,101	$	(2,207	)

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

(10) FAIR VALUE MEASUREMENTS

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 1.

Recurring Fair Value Measurements

Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

A discussion of fair value of financial instruments is included in Note 11. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands):



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

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

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

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

Fair Value Measures by Balance Sheet Classification

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

The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):



		December 31,
	Balance Sheet Location	2019			2018
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets - current	$	1		$	415
Noncurrent commodity derivatives	Other assets, non-current	3			18
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities - current	(490		)	(114		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(29		)	(4		)
Total derivatives designated as hedges		$	(515	)	$	315

Not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets - current	$	341		$	1,085
Noncurrent commodity derivatives	Other assets, non-current	2			1
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities - current	(1,764		)	(833		)
Noncurrent commodity derivatives	Other deferred credits and other liabilities	(63		)	(56		)
Total derivatives not designated as hedges		$	(1,484	)	$	197

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Derivatives Offsetting

It is our policy to offset, in our Consolidated Balance Sheets, contracts which provide for legally enforceable netting of our accounts receivable and payable and derivative activities.

As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at December 31, 2019 and 2018, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure.

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2019 was as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Commodity derivative assets subject to a master netting agreement or similar arrangement	$	1,085	$	(1,085	)	$	—
Commodity derivative assets not subject to a master netting agreement or similar arrangement	348		—			348
Total derivative assets	$	1,433	$	(1,085	)	$	348



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Commodity derivative liabilities subject to a master netting agreement or similar arrangement	$	2,908	$	(2,908	)	$	—
Commodity derivative liabilities not subject to a master netting agreement or similar arrangement	2,345		—			2,345
Total derivative liabilities	$	5,253	$	(2,908	)	$	2,345

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2018 were as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Commodity derivative assets subject to a master netting agreement or similar arrangement	$	1,408	$	(1,408	)	$	—
Commodity derivative assets not subject to a master netting agreement or similar arrangement	1,519		—			1,519
Total derivative assets	$	2,927	$	(1,408	)	$	1,519



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Commodity derivative liabilities subject to a master netting agreement or similar arrangement	$	5,794	$	(5,794	)	$	—
Commodity derivative liabilities not subject to a master netting agreement or similar arrangement	1,007		—			1,007
Total derivative liabilities	$	6,801	$	(5,794	)	$	1,007

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(11) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10, were as follows at December 31 (in thousands):



	2019				2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	9,777	$	9,777	$	20,776	$	20,776
Restricted cash and equivalents ^(a)	$	3,881	$	3,881	$	3,369	$	3,369
Notes payable ^(b)	$	349,500	$	349,500	$	185,620	$	185,620
Long-term debt, including current maturities ^(c)	$	3,145,839	$	3,479,367	$	2,956,578	$	3,039,108

_______________


(a)	Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy.


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


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

Cash and Cash Equivalents

Included in cash and cash equivalents is cash, money market mutual funds, and term deposits. As part of our cash management process, excess operating cash is invested in money market mutual funds with our bank. Money market mutual funds are not deposits and are not insured by the U.S. Government, the FDIC, or any other government agency and involve investment risk including possible loss of principal. We believe, however, that the market risk arising from holding these financial instruments is minimal.

Restricted Cash and Equivalents

Restricted cash and cash equivalents represent restricted cash and uninsured term deposits.

Notes Payable and Long-Term Debt

For additional information on our notes payable and long-term debt, see Note 6 and Note 7.

(12) EQUITY

At-the-Market Equity Offering Program

Our ATM equity offering program allows us to sell shares of our common stock with an aggregate value of up to $300 million.

The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are

offered pursuant to our shelf registration statement filed with the SEC. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2018 and 2017.

Equity Units

On November 23, 2015, we issued 5.98 million Equity Units for total gross proceeds of $299 million. Each Equity Unit had a stated amount of $50.00 and consisted of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028.

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On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued on November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of BHC common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of BHC common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units. See Note 6 for additional information.

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

Equity Compensation Plans`

Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 672,049 shares available to grant at December 31, 2019.

Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2019, total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 2 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follows for the years ended December 31 (in thousands):



	2019		2018		2017
Stock-based compensation expense	$	12,095	$	12,390	$	7,626

Stock Options

The Company has not issued any stock options since 2014 and has 14,000 stock options outstanding at December 31, 2019. The amount of stock options granted during the last three years, and related exercise activity are not material to the Company’s consolidated financial statements.

Restricted Stock

The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.

The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.

A summary of the status of the restricted stock and restricted stock units at December 31, 2019, was as follows:



	Restricted Stock		Weighted-Average Grant Date Fair Value
	(in thousands)
Balance at beginning of period	236		$	57.50
Granted	92		73.66
Vested	(120	)	56.33
Forfeited	(16	)	62.02
Balance at end of period	192		$	65.66

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The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, were as follows:



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2019	$	73.66	$	8,438
2018	$	57.31	$	6,776
2017	$	60.63	$	7,909

As of December 31, 2019, there was $9.0 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 years.

Performance Share Plan

Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.

The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.9 million at December 31, 2019 would be reclassified as a liability.

Outstanding performance periods at December 31 were as follows (shares in thousands):



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
January 1, 2017	January 1, 2017 - December 31, 2019	46	0%	200%
January 1, 2018	January 1, 2018 - December 31, 2020	50	0%	200%
January 1, 2019	January 1, 2019 - December 31, 2021	37	0%	200%

A summary of the status of the Performance Share Plan at December 31 was as follows:



	Equity Portion				Liability Portion
			Weighted-Average Grant Date Fair Value^(a)				Weighted-Average Fair Value at
	Shares		Weighted-Average Grant Date Fair Value^(a)		Shares		December 31, 2019
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	77		$	57.66	77
Granted	20		68.72		20
Forfeited	(4	)	64.60		(4	)
Vested	(26	)	47.76		(26	)
Performance Shares balance at end of period	67		$	64.32	67		$	89.63

_____________________


(a)	The grant date fair values for the performance shares granted in 2019, 2018 and 2017 were determined by Monte Carlo simulation using a blended volatility of 21%, 21% and 23%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

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The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:



	Weighted Average Grant Date Fair Value
December 31, 2019	$	68.72
December 31, 2018	$	61.82
December 31, 2017	$	63.52

Performance plan payouts have been as follows (in thousands):



Performance Period	Year Paid	Stock Issued	Cash Paid		Total Intrinsic Value
January 1, 2016 to December 31, 2018	2019	44	$	2,860	$	5,720
January 1, 2015 to December 31, 2017		—	—		—
January 1, 2014 to December 31, 2016		—	—		—

On January 28, 2020, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2017 through December 31, 2019 performance period was at the 36.3 percentile of its peer group and confirmed a payout equal to 58.86% of target shares, valued at $2.2 million. The payout was fully accrued at December 31, 2019.

As of December 31, 2019, there was $3.4 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.6 years.

Shareholder Dividend Reinvestment and Stock Purchase Plan

We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2019, there were 214,967 shares of unissued stock available for future offering under the plan.

Preferred Stock

Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding.

Noncontrolling Interest in Subsidiary

Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In April 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric.

The accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.

Net income available for common stock for the years ended December 31, 2019, 2018 and 2017 was reduced by $14 million, $14 million, and $14 million, respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holders is based on ownership interests with the exception of certain agreed upon adjustments.

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Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31 (in thousands):



	2019		2018
Assets
Current assets	$	13,350	$	13,620
Property, plant and equipment of variable interest entities, net	$	193,046	$	199,839

Liabilities
Current liabilities	$	6,013	$	5,174

(13) REGULATORY MATTERS

We had the following regulatory assets and liabilities as of December 31 (in thousands):



	2019			2018
Regulatory assets
Deferred energy and fuel cost adjustments ^(a)	$	34,088		$	29,661
Deferred gas cost adjustments^(a)	1,540			3,362
Gas price derivatives ^(a)	3,328			6,201
Deferred taxes on AFUDC^(b)	7,790			7,841
Employee benefit plans ^(c)	115,900			110,524
Environmental^(a)	1,454			959
Loss on reacquired debt ^(a)	24,777			21,001
Renewable energy standard adjustment ^(a)	1,622			1,722
Deferred taxes on flow through accounting^(c)	41,220			31,044
Decommissioning costs ^(a)	10,670			11,700
Gas supply contract termination ^(a)	8,485			14,310
Other regulatory assets^(a)	20,470			45,910
Total regulatory assets	271,344			284,235
Less current regulatory assets	(43,282		)	(48,776		)
Regulatory assets, non-current	$	228,062		$	235,459

Regulatory liabilities
Deferred energy and gas costs^(a)	$	17,278		$	6,991
Employee benefit plan costs and related deferred taxes ^(c)	43,349			42,533
Cost of removal^(a)	166,727			150,123
Excess deferred income taxes ^(c)	285,438			310,562
TCJA revenue reserve	3,418			18,032
Other regulatory liabilities^(c)	20,442			12,553
Total regulatory liabilities	536,652			540,794
Less current regulatory liabilities	(33,507		)	(29,810		)
Regulatory liabilities, non-current	$	503,145		$	510,984

__________


(a)	Recovery of costs, but we are not allowed a rate of return.


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


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

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Regulatory assets represent items we expect to recover from customers through probable future rates.

Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. The recovery period for these costs is less than a year.

Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions. The recovery period for these costs is less than a year.

Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2019 are hedged over a maximum forward term of two years.

Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI.

Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.

Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills.

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.

Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing.

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Gas Supply Contract Termination - Agreements under the previous ownership required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Colorado, Nebraska, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the CPUC, NPSC and WPSC on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs.

Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.

Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense.

Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA.

TCJA Revenue Reserve - Revenue to be returned to customers as a result of the TCJA. See Note 15 for additional information.

Regulatory Matters

Electric Utilities Regulatory Activity

South Dakota Electric

Settlement

On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement agreement to extend the 6-year moratorium period by an additional 3 years to June 30, 2026. Also, as part of the settlement, we withdrew our application for deferred accounting treatment and expensed $5.4 million of development costs related to projects we no longer intend to construct. This settlement amends a previous agreement approved by the SDPUC on June 16, 2017, whereby South Dakota Electric would not increase base rates, absent an extraordinary event, for a 6 year moratorium period effective July 1, 2017. The moratorium period also includes suspension of both the TFA and EIA.

FERC Formula Rate

The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2019 the annual revenue requirement increased by $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019 combined. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.

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South Dakota Electric and Wyoming Electric

Renewable Ready

Black Hills Wyoming and Wyoming Electric

Wygen 1 FERC Filing

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. 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 an additional 20 years to December 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.

Wyoming Electric

Blockchain Tariff

On April 30, 2019, 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.

PCA Settlement

On October 31, 2018, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric was to provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulated the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers.

Gas Utilities Regulatory Activity

Arkansas Gas

Rate Review

On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates were to generate approximately $12 million of new annual revenue. The APSC’s approval also allowed Arkansas Gas to include $11 million of revenue that was being collected through certain rider mechanisms in the new base rates. The new revenue increase was based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.

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Colorado Gas

Jurisdictional Consolidation and 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 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 ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and recommending a rate decrease. Colorado Gas has filed exceptions to the ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 and completed in early 2019.

Nebraska Gas

Jurisdictional Consolidation and Rate Review

On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services.

SSIR

On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NPSC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered.

On October 2, 2017, Nebraska Gas Distribution filed with the NPSC requesting recovery of $6.8 million, which includes $0.3 million of increased annual revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2018, and went into effect on February 1, 2018.

Wyoming Gas

Jurisdictional Consolidation and Rate Review

(14) 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 1 year to 36 years, including options to extend that are reasonably certain to be exercised.

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The components of lease expense for the year ended December 31 were as follows (in thousands) :



	Income Statement Location	2019
Operating lease cost	Operations and maintenance	$	1,456
Finance lease cost:
Amortization of right-of-use asset	Depreciation, depletion and amortization	100
Interest on lease liabilities	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	19
Total lease cost		$	1,575

Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands):



	Balance Sheet Location	2019
Assets:
Operating lease assets	Other assets, non-current	$	4,629
Finance lease assets	Other assets, non-current	465
Total lease assets		$	5,094

Liabilities:
Current:
Operating leases	Accrued liabilities	$	1,179
Finance lease	Accrued liabilities	109

Noncurrent:
Operating leases	Other deferred credits and other liabilities	3,821
Finance lease	Other deferred credits and other liabilities	364
Total lease liabilities		$	5,473

Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands):



	2019
Cash paid included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1,263
Operating cash flows from finance lease	$	19
Financing cash flows from finance lease	$	93
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	2,801
Finance lease	$	67

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Weighted average remaining terms and discount rates related to leases as of December 31 were as follows:



	2019
Weighted average remaining lease term (years):
Operating leases	8 years
Finance lease	4 years

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

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



	Operating Leases		Finance Lease		Total
2020	1,018		126		1,144
2021	865		126		991
2022	743		126		869
2023	718		126		844
2024	714		10		724
Thereafter	2,009		—		2,009
Total lease payments^(a)	$	6,067	$	514	$	6,581
Less imputed interest	1,067		41		1,108
Present value of lease liabilities	$	5,000	$	473	$	5,473

_______________


(a)	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 for the year ended December 31 were as follows (in thousands):



	Income Statement Location	2019
Operating lease income	Revenue	$	2,306

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As of December 31, 2019, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands):



	Operating Leases
2020	2,227
2021	1,857
2022	1,793
2023	1,799
2024	1,743
Thereafter	53,739
Total lease receivables	$	63,158

(15) INCOME TAXES

TCJA

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the federal and state utility commissions, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the year ended December 31, 2018 we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2019, the Company has amortized $6.5 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2019, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.

Tax benefit related to legal entity restructuring

As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018 and December 31, 2018. As a result of these transactions, additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $73 million were recorded to income tax benefit (expense) on the Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.

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Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):



	2019			2018			2017
Current:
Federal	$	(8,578	)	$	325		$	(6,193	)
State	138			247			(1,432		)
	(8,440		)	572			(7,625		)
Deferred:
Federal	34,551			(25,022		)	76,522
State	3,469			783			4,470
	38,020			(24,239		)	80,992

	$	29,580		$	(23,667	)	$	73,367

Included in discontinued operations is a tax benefit of $2.6 million and $8.4 million for 2018 and 2017, respectively.

The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):



	2019			2018
Deferred tax assets:
Regulatory liabilities	$	89,754		$	92,966
State tax credits	23,261			20,466
Federal net operating loss	120,624			139,371
State net operating loss	13,537			16,647
Partnership	14,030			16,032
Credit Carryovers	27,139			23,124
Other deferred tax assets^(a)	33,395			39,349
Less: Valuation allowance	(12,063		)	(11,809		)
Total deferred tax assets	309,677			336,146

Deferred tax liabilities:
Accelerated depreciation, amortization and other property-related differences	(533,292		)	(529,338		)
Regulatory assets	(23,586		)	(32,324		)
Goodwill ^(b)	(15,875		)	(602		)
State deferred tax liability	(72,911		)	(64,095		)
Other deferred tax liabilities	(24,732		)	(21,118		)
Total deferred tax liabilities	(670,396		)	(647,477		)

Net deferred tax liability	$	(360,719	)	$	(311,331	)

_______________


(a)	Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability.


(b)	Legal entity restructuring - see above.

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The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:



	2019		2018		2017
Federal statutory rate	21.0	%	21.0	%	35.0	%
State income tax (net of federal tax effect)	1.5		2.3		0.9
Non-controlling interest ^(a)	(1.2	)	(1.3	)	(1.8	)
Tax credits	(3.9	)	(2.0	)	(1.7	)
Flow-through adjustments^(b)	(2.4	)	(1.6	)	(1.1	)
Jurisdictional consolidation project ^(d)	—		(28.5	)	—
Other tax differences	(1.6	)	(0.1	)	(2.6	)
TCJA corporate rate reduction ^(c)	—		1.6		(2.7	)
Amortization of excess deferred income tax expense ^(e)	(1.2	)	(0.7	)	—
	12.2	%	(9.3	)%	26.0	%

_________________________


(a)	The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded.

(b)

Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.

(c)

On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. During the year ended December 31, 2018, we recorded $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded $7.6 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017.


(d)	Legal entity restructuring - see above.


(e)	Primarily TCJA - see above.

At December 31, 2019, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands):



	Amounts		Expiration Dates
Federal Net Operating Loss Carryforward	$	575,457	2022	to	2037

State Net Operating Loss Carryforward ^(a)	$	224,716	2020	to	2040

_________________________


(a)	The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.

As of December 31, 2019, we had a $0.5 million valuation allowance against the state NOL carryforwards. Our 2019 analysis of the ability to utilize such NOLs resulted in no increase in the valuation allowance. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.

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The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):



	Changes in Uncertain Tax Positions
Beginning balance at January 1, 2017	$	3,592
Additions for prior year tax positions	358
Reductions for prior year tax positions	(5,713		)
Additions for current year tax positions	5,026
Settlements	—
Ending balance at December 31, 2017	3,263
Additions for prior year tax positions	251
Reductions for prior year tax positions	(417		)
Additions for current year tax positions	486
Settlements	—
Ending balance at December 31, 2018	3,583
Additions for prior year tax positions	446
Reductions for prior year tax positions	(862		)
Additions for current year tax positions	998
Settlements	—
Ending balance at December 31, 2019	$	4,165

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.3 million.

We recognized no interest expense associated with income taxes for the years ended December 31, 2019, December 31, 2018 and December 31, 2017. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2019 and December 31, 2018.

The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which filed a separate consolidated tax return from BHC and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. BHC is no longer subject to examination for tax years prior to 2016.

As of December 31, 2019, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2020.

State tax credits have been generated and are available to offset future state income taxes. At December 31, 2019, we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Year
ITC	$	23,060	2023	to	2041
Research and development	$	201	No expiration

As of December 31, 2019, we had a $9 million valuation allowance against the state tax credit carryforwards. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.

(16) OTHER COMPREHENSIVE INCOME

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.

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



	Location on the Consolidated Statements of Income	Amount Reclassified from AOCI
	Location on the Consolidated Statements of Income	December 31, 2019			December 31, 2018
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(2,851	)	$	(2,851	)
Commodity contracts	Fuel, purchased power and cost of natural gas sold	417			(130		)
		(2,434		)	(2,981		)
Income tax	Income tax benefit (expense)	611			630
Total reclassification adjustments related to cash flow hedges, net of tax		$	(1,823	)	$	(2,351	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	77		$	178

Actuarial gain (loss)	Operations and maintenance	(745		)	(2,487		)
		(668		)	(2,309		)
Income tax	Income tax benefit (expense)	(453		)	543
Total reclassification adjustments related to defined benefit plans, net of tax		$	(1,121	)	$	(1,766	)

Total reclassifications		$	(2,944	)	$	(4,117	)

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



	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2018	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)
Other comprehensive income (loss)
before reclassifications	—			(422		)	(6,261		)	(6,683		)
Amounts reclassified from AOCI	2,185			(362		)	1,121			2,944
As of December 31, 2019	$	(15,122	)	$	(456	)	$	(15,077	)	$	(30,655	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2017	$	(19,581	)	$	(518	)	$	(21,103	)	$	(41,202	)
Other comprehensive income (loss)
before reclassifications	—			755			2,155			2,910
Amounts reclassified from AOCI	2,252			99			1,766			4,117
Reclassification to regulatory asset	—			—			6,519			6,519
Reclassification of certain tax effects from AOCI	22			(8		)	726			740
As of December 31, 2018	$	(17,307	)	$	328		$	(9,937	)	$	(26,916	)

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(17) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Years ended December 31,	2019			2018			2017
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Accrued property, plant and equipment purchases at December 31	$	91,491		$	69,017		$	28,191
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	5,044		$	2,625		$	3,198

Cash (paid) refunded during the period for continuing operations-
Interest (net of amounts capitalized)	$	(131,774	)	$	(137,965	)	$	(132,428	)
Income taxes (paid) refunded	$	4,682		$	(14,730	)	$	1,775

(18) EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.

The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company.

Defined Benefit Pension Plan

We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria.

The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments.

The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2019, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 29% to 37% return-seeking assets and 63% to 71% liability-hedging assets.

Our Pension Plan is funded in compliance with the federal government’s funding requirements.

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Plan Assets

The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows:



	2019	2018
Equity	20%	17%
Real estate	3	4
Fixed income	71	71
Cash	1	3
Hedge funds	5	5
Total	100%	100%

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are funded on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plan

BHC sponsors a retiree healthcare plan (Healthcare Plan) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plan for participating business units are pre-funded via VEBA trusts. Pre-65 retirees as well as a grandfathered group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange.

Plan Assets

We fund the Healthcare Plan on a cash basis as benefits are paid. The Black Hills Corporation Retiree Medical Plan provides for partial pre-funding via VEBA trusts. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Iowa and Kansas. We do not pre-fund the Healthcare Plan for those employees outside Arkansas, Iowa and Kansas.

Plan Contributions

Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands):



	2019		2018
Defined Contribution Plan
Company retirement contributions	$	9,714	$	8,766
Company matching contributions	$	14,558	$	13,559



	2019		2018
Defined Benefit Plans
Defined Benefit Pension Plan	$	12,700	$	12,700
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	7,033	$	5,298
Supplemental Non-Qualified Defined Benefit Plans	$	2,344	$	2,073

While we do not have required contributions, we expect to make approximately $13 million in contributions to our Pension Plan in 2020.

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Fair Value Measurements

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):



Pension Plan	December 31, 2019
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV ^(a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	60	$	—	$	60	$	—	$	60
Common Collective Trust - Cash and Cash Equivalents	—		7,054		—		7,054		—		7,054
Common Collective Trust - Equity	—		87,106		—		87,106		—		87,106
Common Collective Trust - Fixed Income	—		306,275		—		306,275		—		306,275
Common Collective Trust - Real Estate	—		—		—		—		14,239		14,239
Hedge Funds	—		—		—		—		19,550		19,550
Total investments measured at fair value	$	—	$	400,495	$	—	$	400,495	$	33,789	$	434,284



Pension Plan	December 31, 2018
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV ^(a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	1,867	$	—	$	1,867	$	—	$	1,867
Common Collective Trust - Cash and Cash Equivalents	—		9,923		—		9,923		—		9,923
Common Collective Trust - Equity	—		67,457		—		67,457		—		67,457
Common Collective Trust - Fixed Income	—		279,148		—		279,148		—		279,148
Common Collective Trust - Real Estate	—		67		—		67		13,551		13,618
Hedge Funds	—		—		—		—		18,783		18,783
Total investments measured at fair value	$	—	$	358,462	$	—	$	358,462	$	32,334	$	390,796

_____________

(a)

Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.



Non-pension Defined Benefit Postretirement Healthcare Plan	December 31, 2019
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		Total Investments
Cash and Cash Equivalents	$	8,305	$	—	$	—	$	8,305	$	8,305
Total investments measured at fair value	$	8,305	$	—	$	—	$	8,305	$	8,305

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Non-pension Defined Benefit Postretirement Healthcare Plan	December 31, 2018
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		Total Investments
Cash and Cash Equivalents	$	4,873	$	—	$	—	$	4,873	$	4,873
Equity Securities	1,005		—		—		1,005		1,005
Intermediate-term Bond	—		2,284		—		2,284		2,284
Total investments measured at fair value	$	5,878	$	2,284	$	—	$	8,162	$	8,162

Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:

AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.

Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.

Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. Some of the funds without participant withdrawal limitations are categorized as Level 2.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance:

Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy.

Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. 20% of the shares may be redeemed at the end of each month with a 10-day notice and full redemptions are available at the end of each quarter with 30-day notice and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.

Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

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Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (ETFs) for diversification into the other sectors of the economy. ETFs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Intermediate-term Bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2.

Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI:

Benefit Obligations



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31 (in thousands),	2019			2018			2019			2018			2019			2018
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	445,381		$	474,725		$	43,010		$	45,112		$	60,817		$	69,339
Service cost	5,383			6,834			4,995			1,764			1,815			2,291
Interest cost	17,374			15,470			1,295			1,170			2,247			2,085
Actuarial (gain) loss	56,384			(31,340		)	7,132			(2,963		)	5,976			(9,045		)
Benefits paid	(39,146		)	(20,308		)	(2,344		)	(2,073		)	(7,033		)	(5,298		)
Plan participants’ contributions	—			—			—			—			1,455			1,445
Projected benefit obligation at end of year	$	485,376		$	445,381		$	54,088		$	43,010		$	65,277		$	60,817

Employee Benefit Plan Assets



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan ^(a)
As of December 31 (in thousands),	2019			2018			2019			2018			2019			2018
Change in fair value of plan assets:
Beginning fair value of plan assets	$	390,796		$	416,343		$	—		$	—		$	8,162		$	8,621
Investment income (loss)	69,934			(17,939		)	—			—			260			(149		)
Employer contributions	12,700			12,700			2,344			2,073			5,461			3,543
Retiree contributions	—			—			—			—			1,455			1,445
Benefits paid	(39,146		)	(20,308		)	(2,344		)	(2,073		)	(7,033		)	(5,298		)
Ending fair value of plan assets	$	434,284		$	390,796		$	—		$	—		$	8,305		$	8,162

____________________


(a)	Assets of VEBA trusts.

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The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2019		2018		2019		2018		2019		2018
Regulatory assets	$	88,471	$	82,919	$	—	$	—	$	11,670	$	6,655
Current liabilities	$	—	$	—	$	1,420	$	1,463	$	4,802	$	3,885
Non-current assets	$	—	$	—	$	—	$	—	$	—	$	249
Non-current liabilities	$	51,093	$	54,585	$	51,243	$	41,547	$	52,136	$	49,015
Regulatory liabilities	$	3,524	$	4,620	$	—	$	—	$	4,088	$	5,207

Accumulated Benefit Obligation



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31 (in thousands)	2019		2018		2019		2018		2019		2018
Accumulated Benefit Obligation	$	470,615	$	428,851	$	49,241	$	40,530	$	65,277	$	60,817

Components of Net Periodic Expense

Net periodic expense consisted of the following for the year ended December 31 (in thousands):



	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2019			2018			2017			2019		2018		2017		2019			2018			2017
Service cost	$	5,383		$	6,834		$	7,034		$	4,995	$	1,764	$	1,546	$	1,815		$	2,291		$	2,300
Interest cost	17,374			15,470			15,520			1,295		1,170		1,276		2,247			2,085			2,141
Expected return on assets	(24,401		)	(24,741		)	(24,517		)	—		—		—		(230		)	(315		)	(315		)
Net amortization of prior service cost	26			58			58			2		2		2		(398		)	(398		)	(411		)
Recognized net actuarial loss (gain)	3,763			8,632			4,007			535		1,000		1,001		—			216			499
Net periodic expense	$	2,145		$	6,253		$	2,102		$	6,827	$	3,936	$	3,825	$	3,434		$	3,879		$	4,214

For the years ended December 31, 2019 and 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other expense on the Consolidated Statements of Income. For the year ended December 31, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because non-service costs were not considered material for the year ended December 31, 2017, they were not reclassified on the Consolidated Statements of Income.

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AOCI

For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):



	Defined Benefit Pension Plan					Supplemental Non-qualified Defined Benefit Plans					Non-pension Defined Benefit Postretirement Healthcare Plan
	2019		2018			2019		2018			2019			2018
Net (gain) loss	$	5,322	$	11,967		$	9,893	$	4,668		$	90		$	860
Prior service cost (gain)	—		1			2		3			(230		)	(317		)
Reclassification of certain tax effects from AOCI	—		(594		)	—		(87		)	—			(45		)
Reclassification to regulatory asset	—		(5,600		)	—		—			—			(919		)
Total AOCI	$	5,322	$	5,774		$	9,895	$	4,584		$	(140	)	$	(421	)

Assumptions



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine benefit obligations:	2019		2018		2017		2019		2018		2017		2019		2018		2017

Discount rate	3.27	%	4.40	%	3.71	%	3.14	%	4.34	%	3.56	%	3.15	%	4.28	%	3.60	%
Rate of increase in compensation levels	3.49	%	3.52	%	3.43	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2019		2018		2017		2019		2018		2017		2019		2018		2017

Discount rate ^(a)	4.40	%	3.71	%	4.27	%	4.34	%	3.67	%	4.02	%	4.28	%	3.60	%	4.05	%
Expected long-term rate of return on assets ^(b)	6.00	%	6.25	%	6.75	%	N/A		N/A		N/A		3.00	%	3.93	%	3.88	%
Rate of increase in compensation levels	3.52	%	3.43	%	3.47	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A

_____________________________


(a)	The estimated discount rate for the Defined Benefit Pension Plan is 3.27% for the calculation of the 2020 net periodic pension costs.


(b)	The expected rate of return on plan assets is 5.25% for the calculation of the 2020 net periodic pension cost.

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The healthcare benefit obligation was determined at December 31 as follows:



	2019	2018
Trend Rate - Medical
Pre-65 for next year - All Plans	6.40%	6.70%
Pre-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Trend Year	2027	2027

Post-65 for next year - All Plans	4.92%	4.94%
Post-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Trend Year	2028	2026

The following benefit payments to employees, which reflect future service, are expected to be paid (in thousands):



	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
2020	$	24,586	$	1,420	$	5,919
2021	$	25,774	$	1,786	$	5,974
2022	$	26,728	$	2,167	$	5,790
2023	$	27,795	$	2,223	$	5,521
2024	$	28,547	$	2,412	$	5,329
2025-2029	$	145,426	$	14,689	$	23,030

(19) COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:


•	Colorado Electric’s PPA with PRPA to purchase up to 60 MW of wind energy upon construction of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030.


•	Colorado Electric’s PPA with PRPA to purchase 25 MW of unit contingent energy. This agreement will expire June 30, 2024.


•	South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.


•	South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp expiring December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.


•	South Dakota Electric’s PPA with PRPA to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.


•	Wyoming Electric’s PPA with Happy Jack, expiring September 3, 2028, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric.


•	Wyoming Electric’s PPA with Silver Sage, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energy from Silver Sage to South Dakota Electric.

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•

Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.

Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):



	2019		2018		2017
Colorado Electric PPA with PRPA - Unit Contingent Energy	$	1,802	$	—	$	—
Colorado Electric PPA Busch Ranch I^(a)	$	—	$	—	$	1,966
South Dakota Electric PPA with PacifiCorp	$	7,477	$	13,681	$	13,218
South Dakota Electric Transmission services agreement with PacifiCorp	$	1,741	$	1,742	$	1,671
South Dakota Electric PPA with PRPA	$	688	$	223	$	—
Wyoming Electric PPA with Happy Jack	$	3,936	$	3,884	$	3,846
Wyoming Electric PPA with Silver Sage	$	5,366	$	5,376	$	4,934

________________


(a)	On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm.

Power Purchase Agreements - Related Party

On November 26, 2019, Black Hills Electric Generation completed and placed in service Busch Ranch II. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric under a new PPA, which expires in November 2044.

On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in Busch Ranch I. Black Hills Electric Generation provides its 14.5 MW share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. Effective January 1, 2019, we changed how we account for this PPA at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information.

Other Gas Supply Agreements

Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044.

Purchase Commitments

We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract.

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Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2019, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):



	NNG-Ventura	NWPL-Wyoming
2020	3,660,000	1,520,000
2021	3,650,000	1,510,000
2022	1,810,000	1,510,000
2023	0	1,510,000
2024	0	910,000
Thereafter	0	0

Purchases under these contracts totaled $6.7 million, $27 million and $65 million for 2019, 2018 and 2017, respectively.

The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and natural gas transportation and storage agreements (in thousands):



	Power purchase and transmission services agreements		Natural gas transportation and storage agreements
2020	$	25,476	$	156,297
2021	$	11,678	$	148,149
2022	$	11,678	$	122,340
2023	$	11,678	$	93,905
2024	$	2,738	$	51,360
Thereafter	$	—	$	126,147

Future Purchase Agreement - Related Party

Wyoming Electric has a PPA with Black Hills Wyoming 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. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. 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 an additional 20 years to December 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.

Power Sales Agreements

Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:


•	During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.


•	South Dakota Electric has an agreement to provide MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.

•

During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement which is renewed annually on September 3, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

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•

South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires May 31, 2028. The contract terms are from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:



Contract Years	Total Contract Capacity		Contingent Capacity Amounts on Wygen III		Contingent Capacity Amounts on Neil Simpson II
2019-2020	15	MW	10	MW	5	MW
2020-2022	15	MW	7	MW	8	MW
2022-2023	15	MW	8	MW	7	MW
2023-2028	10	MW	5	MW	5	MW


•	South Dakota Electric has an agreement that expires December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.

Reimbursement Agreement

We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.

Reclamation Liability

For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under our land leases for our wind generation facilities, we are required to reclaim all land where we have placed wind turbines. The reclamation liabilities are recorded at the present value of the estimated future cost to reclaim the land.

Under its mining permit, WRDC is required to reclaim all land where it has mined reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

See Note 8 for additional information.

Manufactured Gas Processing

In 2008, we acquired whole and partial liabilities for former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.1 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.5 million regulatory asset for manufactured gas processing sites; see Note 13 for additional information.

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As of December 31, 2019, our estimated liabilities for Iowa’s manufactured gas processing site currently range from approximately $2.6 million to $10 million for which we had $2.6 million accrued for remediation of the site as of December 31, 2019 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

For additional information, see Environmental Matters in Item 1 of this Annual Report on Form 10-K.

Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.

In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

(20) GUARANTEES

We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee.

We had the following guarantees in place as of (in thousands):



	Maximum Exposure at
Nature of Guarantee	December 31, 2019		Expiration
Indemnification for subsidiary reclamation/surety bonds ^(a)	$	55,527	Ongoing
Contract performance guarantee ^(b)	46,831		May 2020
	$	102,358

_______________________


(a)	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.


(b)	BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of Busch Ranch II. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations.

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(21) DISCONTINUED OPERATIONS

Results of operations for discontinued operations were classified as Net (loss) from discontinued operations in the accompanying Consolidated Statements of Income. Prior periods relating to our discontinued operations were reclassified to reflect consistency within our consolidated financial statements.

Oil and Gas Segment

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

In 2017, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale were reasonable based on the information that was known when the estimates were made. At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required a pre-tax write down of $20 million. There were no adjustments made to the fair value of our held for sale liabilities.

For the year ended December 31, 2018, we recorded $3.3 million of expenses comprised of royalty payments and reclamation costs related to final closing on the sale of oil and gas assets.

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



	For the Years Ended
	December 31, 2018			December 31, 2017

Revenue	$	5,897		$	25,382

Operations and maintenance	11,014			22,872
Loss on sale of assets	3,259			—
Depreciation, depletion and amortization	1,300			7,521
Impairment of long-lived assets	—			20,385
Total operating expenses	15,573			50,778

Operating (loss)	(9,676		)	(25,396		)

Interest income (expense), net	(19		)	181
Other income (expense), net	190			(297		)
Income tax benefit	2,618			8,413

Net (loss) from discontinued operations	$	(6,887	)	$	(17,099	)

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(22) QUARTERLY HISTORICAL DATA (Unaudited)

The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2019 and 2018.



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2019
Revenue	$	597,810		$	333,888		$	325,548		$	477,654
Operating income	$	160,131		$	54,001		$	70,551		$	121,359
Income from continuing operations	$	107,362		$	17,693		$	15,395		$	72,872
(Loss) from discontinued operations	$	—		$	—		$	—		$	—
Net income attributable to noncontrolling interest	$	(3,554	)	$	(3,110	)	$	(3,655	)	$	(3,693	)
Net income available for common stock	$	103,808		$	14,583		$	11,740		$	69,179

Amounts attributable to common shareholders:
Net income from continuing operations	$	103,808		$	14,583		$	11,740		$	69,179
Net (loss) from discontinued operations	—			—			—			—
Net income available for common stock	$	103,808		$	14,583		$	11,740		$	69,179

Income per share for continuing operations - Basic	$	1.73		$	0.24		$	0.19		$	1.13
(Loss) per share for discontinued operations - Basic	—			—			—			—
Earnings per share - Basic	$	1.73		$	0.24		$	0.19		$	1.13

Income per share for continuing operations - Diluted	$	1.73		$	0.24		$	0.19		$	1.13
(Loss) per share for discontinued operations - Diluted	—			—			—			—
Earnings per share - Diluted	$	1.73		$	0.24		$	0.19		$	1.13

Included within the Income (loss) from continuing operations in the third quarter of 2019 is $15 million non-cash after-tax impairment of our investment in equity securities of a privately held oil and gas company.

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	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2018
Revenue	$	575,389		$	355,704		$	321,979		$	501,196
Operating income	$	148,274		$	69,551		$	65,085		$	114,127
Income from continuing operations	$	138,977		$	27,167		$	21,801		$	91,604
(Loss) from discontinued operations	$	(2,343	)	$	(2,427	)	$	(857	)	$	(1,260	)
Net income attributable to noncontrolling interest	$	(3,630	)	$	(2,823	)	$	(3,994	)	$	(3,773	)
Net income available for common stock	$	133,004		$	21,917		$	16,950		$	86,571

Amounts attributable to common shareholders:
Net income from continuing operations	$	135,347		$	24,344		$	17,807		$	87,831
Net (loss) from discontinued operations	(2,343		)	(2,427		)	(857		)	(1,260		)
Net income available for common stock	$	133,004		$	21,917		$	16,950		$	86,571

Income per share for continuing operations - Basic	$	2.54		$	0.46		$	0.33		$	1.52
(Loss) per share for discontinued operations - Basic	(0.05		)	(0.05		)	(0.02		)	(0.02		)
Earnings per share - Basic	$	2.49		$	0.41		$	0.32		$	1.50

Income per share for continuing operations - Diluted	$	2.50		$	0.45		$	0.32		$	1.51
(Loss) per share for discontinued operations - Diluted	(0.04		)	(0.05		)	(0.02		)	(0.02		)
Earnings per share - Diluted	$	2.46		$	0.40		$	0.31		$	1.49

Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million, respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.	CONTROLS AND PROCEDURES

Disclosure 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 (Exchange Act)) as of December 31, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

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

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2019, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting is presented on Page 73 of this Annual Report on Form 10-K.


ITEM 9B.	OTHER INFORMATION

None.

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PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 2020 Annual Meeting of Shareholders, which is incorporated herein by reference. Information about our Executive Officers is reported in Part 1 of this Annual Report on Form 10-K.


ITEM 11.	EXECUTIVE COMPENSATION

Information required under this item is set forth in the Proxy Statement for our 2020 Annual Meeting of Shareholders, which is incorporated herein by reference.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 2020 Annual Meeting of Shareholders, which is incorporated herein by reference.

EQUITY COMPENSATION PLAN INFORMATION

The following table includes information as of December 31, 2019 with respect to our equity compensation plans. These plans include the 2005 Omnibus Incentive Plan and 2015 Omnibus Incentive Plan.



Equity Compensation Plan Information
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights				Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)				(c)
Equity compensation plans approved by security holders	160,179	⁽¹⁾		$	39.99	⁽¹⁾	672,049	⁽²⁾
Equity compensation plans not approved by security holders	—			$	—		—
Total	160,179			$	39.99		672,049

_________________________

(1)

Includes 146,179 full value awards outstanding as of December 31, 2019, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares, STIP or common stock units. In addition, 192,120 shares of unvested restricted stock were outstanding as of December 31, 2019, which are not included in the above table because they have already been issued.


(2)	Shares available for issuance are from the 2015 Omnibus Incentive Plan. The 2015 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 2020 Annual Meeting of Shareholders, which is incorporated herein by reference.


ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

Information regarding principal accounting fees and services is set forth in the Proxy Statement for our 2020 Annual Meeting to Shareholders, which is incorporated herein by reference.

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PART IV


ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)	1.	Consolidated Financial Statements

		Financial statements required under this item are included in Item 8 of Part II

	2.	Schedules

		Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2019, 2018 and 2017

	3.	Exhibits

		All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto.

SCHEDULE II

Consolidated valuation and qualifying accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


3.	Exhibits



Exhibit Number	Description

2.1*	Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer, dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on July 14, 2015).

2.2*	First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015).

2.3*	Option Agreement, by and among, Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 8-K filed on July 14, 2015).

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

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).

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).

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	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).

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).

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).

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).

4.5	Description of Securities

10.1*†	Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001).
	First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002).
	Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008).

10.2*†	2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant’s Form 10-K for 2008).

10.3*†	Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008).
	First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011).

10.4*†	Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010).

10.5*†	First Amendment to the Black Hills Corporation Nonqualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2018).

10.6*†	Black Hills Corporation Post-2018 Nonqualified Deferred Compensation Plan (filed as Exhibit 10.6 to the Registrant’s Form 10-K for 2018).

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10.7*†	Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005).
	First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008).
	Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).

10.8*†	Black Hills Corporation 2015 Omnibus Incentive Plan (filed as Appendix B to the Registrant’s Proxy Statement filed March 19, 2015).

10.9*†	Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.7 to the Registrant’s Form 10-K for 2013).
	Form of Stock Option Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.8 to Registrant’s Form 10-K for 2015).

10.10*†	Form of Restricted Stock Award Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2015).

10.11*†	Form of Restricted Stock Unit Award Agreement for 2015 Omnibus Plan effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2015).

10.12†	Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
	Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2017.

10.13*†	Form of Short-term Incentive effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.7 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).

10.14*†	Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).

10.15†	Change in Control Agreement dated November 15, 2019 between Black Hills Corporation and Linden R. Evans.

10.16†	Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers.

10.17*†	Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant’s Form 10-K for 2008).
	First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2010).
	Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012).
	Third Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2015 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2014).
	Fourth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2017 (filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2016).
	Fifth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2018 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2017).

10.18*†	Sixth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2019 (filed as Exhibit 10.18 to the Registrant’s Form 10-K for 2018).

10.19*†	Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.8 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).

10.20	Equity Distribution Sales Agreement dated August 4, 2017 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on August 4, 2017).
	First Amendment to the Equity Distribution Sales Agreement.

10.21*	Third Amended and Restated Credit Agreement dated as of July 30, 2018 (relating to $750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 31, 2018).

147

Table of Contents




10.22*	Amended and Restated Credit Agreement dated as of July 30, 2018 (relating to $300 million, two-year term loan), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 31, 2018).
	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).

10.23*	Coal Leases between WRDC and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10‑K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10‑K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10‑K for 1989).

10.24*	Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).

21	List of Subsidiaries of Black Hills Corporation.

23.1	Consent of Independent Registered Public Accounting Firm.

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.

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.

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.

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.

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.


†	Indicates a board of director or management compensatory plan.


ITEM 16.	FORM 10-K SUMMARY

None.

148

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

		By:	/S/ LINDEN R. EVANS
		Linden R. Evans, President and Chief Executive Officer
Dated:	February 14, 2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



/S/ LINDEN R. EVANS	Director and	February 14, 2020
Linden R. Evans, President	Principal Executive Officer
and Chief Executive Officer

/S/ RICHARD W. KINZLEY	Principal Financial and	February 14, 2020
Richard W. Kinzley, Senior Vice President	Accounting Officer
and Chief Financial Officer

/S/ DAVID R. EMERY	Director and	February 14, 2020
David R. Emery, Executive Chairman	Executive Chairman

/S/ TONY A. JENSEN	Director	February 14, 2020
Tony A. Jensen

/S/ MICHAEL H. MADISON	Director	February 14, 2020
Michael H. Madison

/S/ KATHLEEN S. MCALLISTER	Director	February 14, 2020
Kathleen S. McAllister

/S/ STEVEN R. MILLS	Director	February 14, 2020
Steven R. Mills

/S/ ROBERT P. OTTO	Director	February 14, 2020
Robert P. Otto

/S/ REBECCA B. ROBERTS	Director	February 14, 2020
Rebecca B. Roberts

/S/ MARK A. SCHOBER	Director	February 14, 2020
Mark A. Schober

/S/ TERESA A. TAYLOR	Director	February 14, 2020
Teresa A. Taylor

/S/ JOHN B. VERING	Director	February 14, 2020
John B. Vering

/S/ THOMAS J. ZELLER	Director	February 14, 2020
Thomas J. Zeller

149

Exhibit

DESCRIPTION OF SECURITIES

This summary of general terms and provisions of the capital stock of Black Hills Corporation (the “Company,” “we” and “our”) does not purport to be complete and is subject to and qualified by reference to our Restated Articles of Incorporation (the “Articles”) and our Amended and Restated Bylaws (the “Bylaws,” and together with the Articles, our “Governing Documents”), each of which is included as an exhibit to the Company’s most recent annual report on Form 10-K filed with the Securities and Exchange Commission. For additional information, please refer to our Governing Documents and to the applicable provisions of the South Dakota Business Corporation Act. Our common stock is our only class of securities that is registered under Section 12(b) of the Securities Exchange Act of 1934, as amended.

General

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $1.00 per share, and 25,000,000 shares of preferred stock, without par value.

Common Stock

The holders of our common stock are entitled to one vote for each share held of record on all matters submitted to a vote of shareholders. Holders may use cumulative voting for the election of directors. Subject to preferences that may be applicable to any outstanding series of preferred stock, holders of our common stock are entitled to receive equally dividends as they may be declared by our board of directors out of funds legally available for the payment of dividends. Our revolving credit facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. In the event of our liquidation or dissolution, holders of our common stock are entitled to share equally in all assets remaining after payment of liabilities and the liquidation preference of any outstanding series of preferred stock.

Holders of our common stock have no preemptive rights and have no rights to convert their common stock into any other securities.

Preferred Stock

Our board of directors has the authority, without further action by our shareholders, to issue shares of undesignated preferred stock from time to time in one or more series and to fix the related number of shares and the designations, voting powers, preferences, optional and other special rights, and restrictions or qualifications of that preferred stock. The rights, preferences, privileges and restrictions or qualifications of different series of preferred stock may differ from common stock and other series of preferred stock with respect to dividend rates, amounts payable on liquidation, voting rights, conversion rights, redemption provisions, sinking fund provisions and other matters. The issuance of additional series of preferred stock could:


•	decrease the amount of earnings and assets available for distribution to holders of common stock and other series of preferred stock;


•	adversely affect the rights and powers, including voting rights, of holders of common stock and other series of preferred stock; or


•	have the effect of delaying, deferring or preventing a change in control.

Special Meetings of Shareholders

Our Bylaws provide that special meetings of the shareholders may be called by a majority of our board of directors and shall be called by our board of directors upon the written demand of the holders of at least 10% of the votes entitled to be cast on any issue proposed to be considered at the special meeting.

Notice Requirements for Shareholder Proposals and Director Nominees

Shareholders wishing to nominate a director or to propose other action at an annual meeting must generally give advance written notice of such nomination or proposal that complies with Article I, Section 9, of our Bylaws to the Secretary of the Company not less than 90 nor more than 120 days prior to the anniversary date of the immediately preceding year’s annual meeting.

Anti-Takeover Effects of South Dakota Law and Provisions of Our Governing Documents

South Dakota law and our Governing Documents contain certain provisions that may be characterized as anti-takeover provisions. These provisions may make it more difficult to acquire control of us or remove our management.

Control Share Acquisitions

We have elected in our Articles not to be subject to the control share acquisition provisions of the South Dakota Domestic Public Corporation Takeover Act, which would otherwise apply to us. These provisions provide generally that the shares of a publicly held South Dakota corporation acquired by a person that exceed the thresholds of voting power described below will have the same voting rights as other shares of the same class or series only if approved by:


•	the affirmative vote of the majority of all outstanding shares entitled to vote, including all shares held by the acquiring person; and


•	the affirmative vote of the majority of all outstanding shares entitled to vote, excluding all interested shares.

Each time an acquiring person reaches a threshold, the acquiring person must deliver an information statement to the corporation and a vote must be held as described above before the acquiring person will have any voting rights with respect to shares in excess of such threshold. The thresholds which require shareholder approval before voting powers are obtained with respect to shares acquired in excess of such thresholds are 20%, 33¹/3% and 50%, respectively.

Shares acquired in the absence of such approval are denied voting rights and are redeemable at their then-current market value by the corporation within 10 days after the acquiring person has failed to give a timely information statement to the corporation or the date the shareholders voted not to grant voting rights to the acquiring person’s shares.

Business Combinations

We are subject to the provisions of Section 47-33-17 of the South Dakota Domestic Public Corporation Takeover Act. In general, Section 47-33-17 prohibits a publicly held South Dakota corporation from engaging in a “business combination” with an “interested shareholder,” unless the business combination or the transaction in which the person became an interested shareholder is approved in a prescribed manner. A business combination with the interested shareholder must be approved by (i) the board of directors of the corporation prior to the date that the person became an interested shareholder of the corporation (referred to as the person’s “share acquisition date”), (ii) the affirmative vote of all of the holders of all of the outstanding voting shares, or, under some circumstances, by the affirmative vote of the holders of a majority of the outstanding voting shares not including those shares beneficially owned by the interested shareholder or any of its affiliates or associates, (iii) the affirmative vote of the holders of a majority of the outstanding voting shares not including those shares beneficially owned by the interested shareholder or any of its affiliates or associates at a meeting no earlier than four years after the interested shareholder’s share acquisition date, or (iv) the affirmative vote of the holders of a majority of the outstanding voting shares at a meeting no earlier than four years after the interested shareholder’s share acquisition date if the business combination satisfies the conditions of Section 47-33-18 of the Act. Generally, an “interested shareholder” is a person who, together with affiliates and associates, beneficially owns, directly or indirectly, 10% or more of the corporation's voting stock. A “business combination” includes a merger, a transfer of 10% or more of the corporation's assets, the issuance or transfer of stock equal to 5% or more of the aggregate market value of all of the corporation's outstanding shares, the adoption of a plan of liquidation or dissolution, or other transaction resulting in a financial benefit to the interested shareholder.

Multiple Constituencies

The South Dakota Domestic Public Corporation Takeover Act further provides that our board, in determining whether to approve a merger or other change of control, may take into account both the long-term as well as short-term interests of us and our shareholders, the effect on our employees, customers, creditors and suppliers, the effect upon the community in which we operate and the effect on the economy of the state and nation. This provision may permit our board to vote against some proposals that, in the absence of this provision, it would otherwise have a fiduciary duty to approve.

Fair Price Provision

Our Articles require the affirmative vote of the holders of 80% or more of the outstanding shares of our voting stock to approve any “business transaction” with any “related person” or any “business transaction” in which a “related person” has an interest. However, if a majority of the continuing members of our board who are not affiliated with the related party approve the business transaction, or if the cash or fair market value of any consideration received by our shareholders pursuant to a business transaction meets certain enumerated requirements, then the 80% voting requirement will not be applicable. Generally, our Articles define a “business transaction” to include, among other things, a merger, asset or stock sale. Our Articles generally define a “related person” as any person, entity or group that, together with its affiliates and associates, beneficially owns 10% or more of our outstanding voting stock. Any amendment to our Articles to amend or repeal this provision similarly requires the affirmative vote of the holders of 80% or more of the outstanding shares of our voting stock.

Board Composition

Our Articles and Bylaws provide for a staggered board of directors divided into three classes, with the term of office of one class expiring each year. Our Articles and Bylaws also provide that our directors may be removed only for cause and by the affirmative vote of the majority of the remaining members of the board of directors. The likely effect of our staggered board of directors and the limitation on the removal of directors is an increase in the time required for the shareholders to change the composition of our board of directors.

Authorized but Unissued Shares

The authorized but unissued shares of our common stock and preferred stock are available for future issuance without shareholder approval. These additional shares may be used for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued and unreserved common stock and preferred stock could also render more difficult or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise. Our board has the authority, without further shareholder approval, to issue one or more series of preferred stock that could, depending on the terms of the series, either impede or facilitate the completion of a merger, tender offer or other takeover attempt.

Shareholder Action by Written Consent Must Be Unanimous

South Dakota law provides that any action that may be taken at a meeting of shareholders may be taken without a meeting if a written consent, setting forth the action taken, is signed by all of the shareholders entitled to vote with respect to the action taken. This provision prevents holders of less than all of our common stock from unilaterally using the written consent procedure to take shareholder action.

Exhibit

Black Hills Corporation

2015 Omnibus Incentive Plan

Performance Share Award Agreement

(for Awards granted on or after January 1, 2017)

Performance Period January 1, 2020 - December 31, 2022

AWARD AGREEMENT WITH EEI INDEX AS PEER INDEX

Contents



Article 1. Performance Period	1

Article 2. Value of Performance Shares	1

Article 3. Performance Shares and Achievement of Performance Measure	2

Article 4. Termination Provisions	2

Article 5. Change in Control	3

Article 6. Forfeiture and Repayment	4

Article 7. Dividends	6

Article 8. Form and Timing of Payment of Performance Shares	6

Article 9. Nontransferability	7

Article 10.Administration	7

Article 11.Miscellaneous	7

Black Hills Corporation

2015 Omnibus Incentive Plan

Performance Share Award Agreement

Performance Period January 1, 2020 - December 31, 2022

You have been selected to be a participant in the Black Hills Corporation 2015 Omnibus

Incentive Plan (the “Plan”), as specified below:

Participant: ____________

Target Performance Share Award: _______ shares

Performance Period: January 1, 2020 to December 31, 2022

Performance Measure: Total Shareholder Return (“TSR”).

Peer Index: EEI Index

The peer group for TSR performance purposes consists of all companies comprising the EEI Index. Throughout the performance period, companies may be added or dropped from the index due to mergers or other activities. At the end of the performance period, new companies that are added to the index are included in the rankings as if they had been in the ranking from the beginning, provided there is sufficient trading history to include them in the final calculation. When a company is dropped from the index, everything related to the company is excluded as if it were never in the index. Companies included in the EEI Index at the beginning of the Performance Period excluding Black Hills Corporation, are listed in Appendix A.

THIS AGREEMENT (the “Agreement”) effective January 1, 2020, represents the grant of Performance Shares by Black Hills Corporation, a South Dakota corporation (the “Company”), to the Participant named above, pursuant to the provisions of the Plan.

The Plan provides a complete description of the terms and conditions governing the Performance Shares. If there is any inconsistency between the terms of this Agreement and the terms of the Plan, the Plan’s terms shall completely supersede and replace the conflicting terms of this Agreement.

All capitalized terms shall have the meanings ascribed to them in the Plan, unless specifically set forth otherwise herein.

The parties hereto agree as follows:

Article 1. Performance Period

The Performance Period commences on January 1, 2020 and ends on December 31, 2022.

Article 2. Value of Performance Shares

Each Performance Share shall represent and have a value equal to one share of common stock of the Company.

Article 3. Performance Shares and Achievement of Performance Measure

The number of Performance Shares to be earned under this Agreement shall be based upon the achievement of pre-established TSR performance goals as set by the Compensation Committee of the Board of Directors (the “Committee”) for the Performance Period, based on the following chart:



TSR Performance Relative to Companies in Peer Index	Payout (% of Target)

90^th Percentile or Above	200%
50^th Percentile	100%
25^th Percentile	25%
Below 25^th Percentile and TSR is equal to or greater than 35%	25%
Below the 25^th Percentile and TSR is below 35%	0%

In addition, if TSR is negative during the Performance Period, the payout will not exceed 100% of target.

Interpolation shall be used to determine the percentile rank in the event the Company’s Percentile Rank does not fall directly on one of the ranks listed in the above chart.

For this purpose, Total Shareholder Return (rounded to nearest basis point) shall be determined as follows:



Total Shareholder Return	=	Change in Stock Price + Dividends Paid Beginning Stock Price

Beginning Stock Price shall mean the average closing price (rounded to nearest cent $xx.xx) on the applicable stock exchange of one share of stock for the twenty (20) trading days immediately prior to the first day of the Performance Period; Ending Stock Price shall mean the average closing price (rounded to nearest cent $xx.xx) on the applicable stock exchange of one share of stock for the last twenty (20) trading days of the Performance Period; Change in Stock Price shall mean the difference between the Beginning Stock Price and the Ending Stock Price; and Dividends Paid shall mean the total of all dividends (unrounded) on one (1) share of stock with Dividend Payable Dates during the Performance Period. Following the Total Shareholder Return determination, the Company’s Percentile Rank shall be determined as follows:

Percentile Rank shall be determined by listing from highest Total Shareholder Return to lowest Total Shareholder Return each company in the Peer Index (excluding the Company). The top company would have a one hundred percentile (100%) rank and the bottom company would have a zero percentile (0.0%) rank. Each company in between would be one hundred divided by n minus one (100/(n-1)) (rounded to nearest basis point - x.xx%) above the company below it, where “n” is the total number of companies in the Peer Index. The Company percentile rank would then be interpolated based on the Company TSR.

Article 4. Termination Provisions

Except as provided below in this Article 4 and in Article 5, a Participant shall be eligible for payment of awarded Performance Shares, as determined in Article 3, only if the Participant’s employment with the Company continues through the end of the Performance Period.

If participant Retires, suffers a Disability, or dies during the Performance Period, the Participant (or the Participant’s estate) shall be entitled to that proportion of the number of Performance Shares as such Participant is entitled to under Article 3 for such Performance Period that the number of full months of participation during the Performance Period bears to the total number of months in the Performance Period. The form and timing of the payment of such Performance Shares shall be as set forth in Article 8.

“Retirement” or “Retires” means a Separation from service by a Participant on or after (i) attaining the age of 55 with at least 5 years of service, or (ii) attaining the age of 65.

“Separation from service” (as defined in Treasury Regulation Section 1.409A-1(h)) during the Performance Period other than (i) due to Retirement, Disability, or death, or (ii) following a Change in Control shall require forfeiture of this entire award, with no payment to the Participant.

Article 5. Change in Control

Notwithstanding anything herein to the contrary, in the event of a Change in Control, the Participant shall be entitled to that proportion of the number of Performance Shares as such Participant is entitled to under Article 3 for such Performance Period that the number of full months of participation during the Performance Period (as of the effective date of the Change in Control) bears to the total number of months in the Performance Period. When there is a Change in Control, the TSR shall be calculated as set forth in Article 3, except that the Ending Stock Price shall mean the average closing price on the applicable stock exchange of one share of stock for the twenty (20) trading days immediately prior to the Change in Control. Performance Shares shall be paid out to the Participant in cash within thirty (30) days of the effective date of the Change in Control.

"Change in Control" of the Company shall be deemed to have occurred (as of a particular day, as specified by the Board) upon the occurrence of any of the following events:

(a)

The acquisition in a transaction or series of transactions by any Person of Beneficial Ownership of thirty percent (30%) or more of the combined voting power of the then outstanding shares of common stock of the Company; provided, however, that for purposes of this Agreement, the following acquisitions will not constitute a Change in Control: (A) any acquisition by the Company; (B) any acquisition of common stock of the Company by an underwriter holding securities of the Company in connection with a public offering thereof; and (C) any acquisition by any Person pursuant to a transaction which complies with subsections (c) (i), (ii) and (iii);

(b)

Individuals who, as of December 31, 2018 are members of the Board (the "Incumbent Board"), cease for any reason to constitute at least a majority of the members of the Board; provided, however, that if the election, or nomination for election by the Company's common shareholders, of any new director was approved by a vote of at least two-thirds of the Incumbent Board, such new director shall, for purposes of this Plan, be considered as a member of the Incumbent Board; provided further, however, that no individual shall be considered a member of the Incumbent Board if such individual initially assumed office as a result of either an actual or threatened "Election Contest" (as described in Rule 14a‑11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board (a "Proxy Contest") including by reason of any agreement intended to avoid or settle any Election Contest or Proxy Contest;

(c)

Consummation, following shareholder approval, of a reorganization, merger, or consolidation of the Company, or a sale or other disposition of all or substantially all of the assets of the Company (each a “Business Combination”), unless, in each case, immediately following such Business Combination, all of the following have occurred: (i) all or substantially all of the individuals and entities who were beneficial owners of shares of the common stock of the Company immediately prior to such Business Combination beneficially own, directly or indirectly, more than fifty percent (50%) of the combined voting power of the then outstanding shares of the entity resulting from the Business Combination or any direct or indirect parent corporation thereof (including, without limitation, an entity which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one (1) or more subsidiaries) (the “Successor Entity”); (ii) no Person (excluding any Successor Entity or any employee benefit plan or related trust, of the Company or such Successor Entity) owns, directly or indirectly, thirty percent (30%) or more of the combined voting power of the then outstanding shares of common stock of the Successor Entity, except to the extent that such

ownership existed prior to such Business Combination; and (iii) at least a majority of the members of the Board of Directors of the entity resulting from such Business Combination or any direct or indirect parent corporation thereof were members of the Incumbent Board at the time of the execution of the initial agreement or action of the Board providing for such Business Combination; or


(d)	Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company, except pursuant to a Business Combination that complies with subsections (c) (i), (ii), and (iii) above.

(e)

A Change in Control shall not be deemed to occur solely because any Person (the "Subject Person") acquired Beneficial Ownership of more than the permitted amount of the then outstanding common stock as a result of the acquisition of common stock by the Company which, by reducing the number of shares of common stock then outstanding, increases the proportional number of shares Beneficially Owned by the Subject Persons, provided that if a Change in Control would occur (but for the operation of this sentence) as a result of the acquisition of common stock by the Company, and after such stock acquisition by the Company, the Subject Person becomes the Beneficial Owner of any additional common stock which increases the percentage of the then outstanding common stock Beneficially Owned by the Subject Person, then a Change in Control shall occur.


(f)	A Change in Control shall not be deemed to occur unless and until all regulatory approvals required in order to effectuate a Change in Control of the Company have been obtained and the transaction constituting the Change in Control has been consummated.

Notwithstanding the above provisions of this definition, to the extent that any payment under the Agreement due to a Change in Control is subject to Code Section 409A for deferred compensation, then the term “Change in Control” shall be construed in a manner that is consistent with Code Section 409A(a)(2)(A)(v), but only to the extent inconsistent with the above provisions as determined by the Board.

Article 6. Forfeiture and Repayment.


(a)	In the event the Participant incurs a separation from service for a reason other than those described in Article 4 herein during the Performance Period this entire award will be forfeited, unless the separation from service follows a Change in Control.


(b)	Without limiting the generality of Article 6(a), the Company reserves the right to cancel all Performance Shares awarded hereunder, whether or not vested, and require the Participant to repay all income or gains previously realized in respect of such Performance Shares, in the event of the occurrence of any of the following events:


(i)	termination of Participant’s employment for Cause;


(ii)	within one year following any termination of Participant’s employment, the Board determines that the Participant engaged in conduct before the Participant’s termination date that would have constituted the basis for a termination of employment for Cause;


(iii)	at any time during the Participant’s employment or the twelve month period immediately following any termination of employment, Participant:


(x)	publicly disparages the Company, any of its affiliates or any of its or their officers, directors or senior executive employees or otherwise makes any public statement that is materially detrimental to the interests or reputation of the Company, any of its affiliates or such individuals; or


(y)	violates in any material respect any policy or any code of ethics or standard of behavior or conduct generally applicable to Participant, including the Code of Conduct; or


(iv)	Participant engages in any fraudulent, illegal or other misconduct involving the Company or any of its affiliates, including but not limited to any breach of fiduciary duty, breach of a duty of loyalty, or interference with contract or business expectancy.


(c)	If the Board determines that the Participant’s conduct, activities or circumstances constitute events described in Article 6(b), in addition to any other remedies the Company has available to it, the Company may in its sole discretion:


(i)	cancel any Performance Shares awarded hereby, whether or not issued; and/or


(ii)	require the Participant to repay an amount equal to all income or gain realized in respect of all such Performance Shares. The amount of repayment shall include, without limitation, amounts received in connection with the delivery or sale of Shares of such Performance Shares or cash paid in respect of any Performance Shares.

There shall be no forfeiture or repayment under Article 6(b) following a Change-in-Control.

(d)

The Board, in its discretion, shall determine whether a Participant’s conduct, activities or circumstances constitute events described in Article 6(b) and whether and to what extent the Performance Shares awarded hereby shall be forfeited by Participant and/or a Participant shall be required to repay an amount pursuant to Article 6(c). The Board shall have the authority to suspend the payment, delivery or settlement of all or any portion of such Participant’s outstanding Performance Shares pending an investigation of a bona fide dispute regarding Participant’s eligibility to receive a payment under the terms of this Agreement as determined by the Board in good faith.


(e)	For purposes of applying this provision:


(i)	“Cause” means any of the following:


(u)	a Participant’s violation of his or her material duties to the Company or any of its affiliates, which continues after written notice from the Company or any affiliate to cure such violation;


(v)	Participant’s willful failure to follow the lawful written directives of the Board in any material respect;

(w)

Participant’s willful misconduct in connection with the performance of any of his or her duties, including but not limited to falsifying or attempting to falsify documents, books or records of the Company or any of its affiliates, making or delivering a false representation, statement or certification of compliance to the Company, misappropriating or attempting to misappropriate funds or other property of the Company or any of its

affiliates, or securing or attempting to secure any personal profit in connection with any transaction entered into on behalf of the Company or any of its affiliates;


(x)	Participant’s breach of any material provisions of this Agreement or any other non-competition, non-interference, non-disclosure, confidentiality or other similar agreement executed by Participant with the Company or any of its affiliates;


(y)	conviction (or plea of nolo contendere) of the Participant of any felony, or a misdemeanor involving false statement, in connection with conduct involving the Company or any of its subsidiaries or affiliates; or


(z)	intentional engagement in any activity which would constitute or cause a breach of duty of loyalty, or any fiduciary duty to the Company or any of its subsidiaries or affiliates.


(ii)	“Code of Conduct” means any code of ethics or code of conduct now or hereafter adopted by the Company or any of its affiliates, including to the extent applicable the Company’s Employee Conduct and Disclosure Policy, as amended or supplemented from time to time, and the Company’s or subsidiary Risk Management Policies and Procedures, as amended, supplemented or replaced from time to time.


(f)	Participant agrees that the provisions of this Article 6 are entered into in consideration of, and as a material inducement to, the agreements by the Company herein as well as an inducement for the Company to enter into this Agreement, and that, but for Participant’s agreement to the provisions of this Article 6, the Company would not have entered into this Agreement.

Article 7. Dividends

During the Performance Period, all dividends and other distributions paid with respect to the shares of common stock shall accrue for the benefit of the Participant to be paid out to the Participant pursuant to Article 8.

Article 8. Form and Timing of Payment of Performance Shares

Payment of the Performance Shares, including accrued dividends, shall be made fifty percent (50%) in cash and fifty percent (50%) in shares of Company stock.

Payment of Performance Shares shall be made within sixty (60) calendar days following the close of the Performance Period, subject to the following:


(a)	The Participant shall have no right with respect to any Award or a portion there of, until such award shall be paid to such Participant.


(b)	If the Committee determines, in its sole discretion, that a Participant at any time has willfully engaged in any activity that the Committee determines was or is harmful to the Company, any unpaid pending Award will be forfeited by such Participant.


(c)	All appropriate taxes will be withheld from the cash portion of the award.

Article 9. Nontransferability

Performance Shares may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. Further, except as otherwise provided in a Participant’s Award Agreement, a Participant’s rights under the Plan shall be exercisable during the Participant’s lifetime only by the Participant or the Participant’s legal representative. The terms hereof shall be binding on the executors, administrators, heirs and successors of the Participant.

Article 10. Administration

This Agreement and the rights of the Participant hereunder are subject to all the terms and conditions of the Plan, as the same may be amended from time to time by the Board of Directors, as well as to such rules and regulations as the Committee may adopt for administration of the Plan. It is expressly understood that the Committee is authorized to administer, construe, and make all determinations necessary or appropriate to the administration of the Plan and this Agreement, in its sole discretion, all of which shall be binding upon the Participant.

Any inconsistency between the Agreement and the Plan shall be resolved in favor of the Plan.

Article 11. Miscellaneous

(a)

The selection of any employee for participation in the Plan shall not give such Participant any right to be retained in the employ of the Company. The right and power of the Company to dismiss or discharge any Participant at-will, is specifically reserved. Such Participant or any person claiming under or through the Participant shall not have any right or interest in the Plan or any Award thereunder, unless and until all terms, conditions, and provisions of the Plan that affect such Participant have been complied with as specified herein.


(b)	With the approval of the Board, the Committee may terminate, amend, or modify the Plan; provided, however, that no such termination, amendment, or modification of the Plan may in any way adversely affect the Participant’s rights under this Agreement without the Participant’s written consent, except as required by law.


(c)	Participant shall not have voting rights with respect to the Performance Shares. Participant shall obtain voting rights upon the settlement of Performance Shares and distribution into shares of common stock of the Company.

(d)

The Participant may defer such Participant’s receipt of the payment of cash and the delivery of shares of common stock, that would otherwise be due to such Participant by virtue of the satisfaction of the performance goals with respect to the Performance Shares, pursuant to the rules of the Black Hills Corporation Nonqualified Deferred Compensation Plan, if allowed, and the procedures set forth by the Compensation Committee. If the Participant elects to defer the receipt of the award, the Participant will be required to pay any necessary taxes from their own funds. They will not be allowed to have their deferred award reduced for tax withholding.


(e)	This Agreement shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.


(f)	To the extent not preempted by federal law, this Agreement shall be governed by, and construed in accordance with, the laws of the State of South Dakota.


(g)	Any awards received by Participant are subject to the provisions of the Stock Ownership Guidelines approved by the Board of Directors.


(h)	Waiver and Modification. The provisions of this Agreement may not be waived or modified unless such waiver or modification is in writing and signed by the Company.


(i)	Compliance with Exchange Act. If the Participant is subject to Section 16 of the Exchange Act, Performance Shares granted pursuant to the Award are intended to comply with all applicable conditions of Rule 16b-3 or its successors under the Exchange Act.

The following parties have caused this Agreement to be executed effective as of January 1, 2020.

Black Hills Corporation

By: ______________________

___________________________

Participant

Appendix A

Companies Included in EEI Index

as of January 1, 2020, Excluding Black Hills Corporation

Companies included in the EEI Index at the beginning of the Performance Period excluding Black Hills Corporation, are as follows:



ALLETE, Inc.	ALE	IdaCorp, Inc.	IDA
Alliant Energy Corporation	LNT	MDU Resources Group, Inc.	MDU
Ameren Corporation	AEE	MGE Energy, Inc.	MGEE
American Electric Power Company, Inc.	AEP	NextEra Energy, Inc.	NEE
Avangrid, Inc.	AGR	NiSource Inc.	NI
Avista Corporation	AVA	NorthWestern Corporation	NWE
CenterPoint Energy, Inc.	CNP	OGE Energy Corp.	OGE
CMS Energy Corporation	CMS	Otter Tail Corporation	OTTR
Consolidated Edison, Inc.	ED	PG&E Corporation	PCG
Dominion Energy, Inc.	D	Pinnacle West Capital Corporation	PNW
DTE Energy Company	DTE	PNM Resources, Inc.	PNM
Duke Energy Corporation	DUK	Portland General Electric Company	POR
Edison International	EIX	PPL Corporation	PPL
El Paso Electric Company	EE	Public Service Enterprise Group Inc.	PEG
Entergy Corporation	ETR	Sempra Energy	SRE
Evergy, Inc.	EVRG	The Southern Company	SO
Eversource Energy	ES	Unitil Corporation	UTL
Exelon Corporation	EXC	WEC Energy Group, Inc.	WEC
FirstEnergy Corp.	FE	Xcel Energy Inc.	XEL
Hawaiian Electric Industries, Inc.	HE

Exhibit

CHANGE IN CONTROL AGREEMENT

This Change in Control Agreement (“Agreement”) dated as of November 15, 2019, is entered into by and between Black Hills Corporation (“Company”) and Linden R. Evans (“Employee”).


1.	RECITALS.

The Board of Directors of the Company (“Board”) has determined that it is in the best interests of the Company and its shareholders to encourage the Employee’s full attention and dedication to the Company currently and in the event of any threatened or pending Change in Control (as defined below). Therefore, in order to accomplish these objectives, the Board has caused the Company to enter into this Agreement.


2.	DEFINITIONS.

“AFFILIATE” shall have the meaning ascribed to such term in rule 12b-2 of the General Rules and Regulations of the Exchange Act.

“ANNUAL COMPENSATION” shall mean, with respect to any calendar year, all of the following compensation paid or payable, as applicable, to or on behalf of the Employee by the Company during a calendar year including: (a) base salary, targeted annual incentive bonus, targeted long-term incentive grants and awards; and (b) Company Matching Contributions and Company Retirement Contributions or other benefits payable under the Retirement Savings Plan and Supplemental Matching Contributions, Supplemental Retirement Contributions and Supplemental Target Contributions under the Nonqualified Deferred Compensation Plan (as such terms are defined in the applicable plans).

“BENEFICIAL OWNER” or “BENEFICIAL OWNERSHIP” shall have the meaning ascribed to such term in Rule 13d-3 of the General Rules and Regulations under the Exchange Act.

“CAUSE” means those events or conditions described in subsections 9(a).

“CHANGE IN CONTROL” shall mean any of the following events:

(a)The acquisition in a transaction or series of transactions by any Person of Beneficial Ownership of thirty percent (30%) or more of the combined voting power of the then outstanding shares of common stock of the Company; provided, however, that for purposes of this Agreement, the following acquisitions will not constitute a Change in Control: (A) any acquisition by the Company; (B) any acquisition of common stock of the Company by an underwriter holding securities of the Company in connection with a public offering thereof; and (C) any acquisition by any Person pursuant to a transaction which complies with subsections (c)(i), (ii) and (iii);

(b)Individuals who, as of December 31, 2018 are members of the Board (the “Incumbent Board”), cease for any reason to constitute at least a majority of the members of the Board; provided, however, that if the election, or nomination for election by the Company’s common shareholders, of any new director was approved by a vote of at least two-thirds of the Incumbent Board, such new director shall, for purposes of this Agreement, be considered as a member of the Incumbent Board; provided further, however, that no individual shall be considered a member of the Incumbent Board if such individual initially assumed office as a result of either

an actual or threatened “Election Contest” (as described in Rule 14a-11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board (a “Proxy Contest”) including by reason of any agreement intended to avoid or settle any Election Contest or Proxy Contest;

(c)Consummation, following shareholder approval, of a reorganization, merger, or consolidation of the Company, or a sale or other disposition of all or substantially all of the assets of the Company (each a “Business Combination”), unless, in each case, immediately following such Business Combination, all of the following have occurred: (i) all or substantially all of the individuals and entities who were beneficial owners of shares of the common stock of the Company immediately prior to such Business Combination beneficially own, directly or indirectly, more than fifty percent (50%) of the combined voting power of the then outstanding shares of the entity resulting from the Business Combination or any direct or indirect parent corporation thereof (including, without limitation, an entity which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one (1) or more subsidiaries) (the “Successor Entity”) (ii) no Person (excluding any Successor Entity or any employee benefit plan or related trust, of the Company or such Successor Entity) owns, directly or indirectly, thirty percent (30%) or more of the combined voting power of the then outstanding shares of common stock of the Successor Entity, except to the extent that such ownership existed prior to such Business Combination; and (iii) at least a majority of the members of the Board of Directors of the entity resulting from such Business Combination or any direct or indirect parent corporation thereof were members of the Incumbent Board at the time of the execution of the initial agreement or action of the Board providing for such Business Combination; or

(d)Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company, except pursuant to a Business Combination that complies with subsections (c)(i), (ii), and (iii) above.

(e)A Change in Control shall not be deemed to occur solely because any Person (the “Subject Person”) acquired Beneficial Ownership of more than the permitted amount of the then outstanding Common Stock as a result of the acquisition of Common Stock by the Company which, by reducing the number of shares of Common stock then outstanding, increases the proportional number of shares Beneficially Owned by the Subject Persons, provided that if a Change in Control would occur (but for the operation of this sentence) as a result of the acquisition of Common Stock by the Company, and after such stock acquisition by the Company, the Subject Person becomes the Beneficial Owner of any additional Common Stock which increases the percentage of the then outstanding Common Stock Beneficially Owned by the Subject Person, then a Change in Control shall occur.

(f)A Change in Control shall not be deemed to occur unless and until all regulatory approvals required in order to effectuate a Change in Control of the Company have been obtained and the transaction constituting the Change in Control has been consummated.

“CODE” means the Internal Revenue Code of 1986, as amended from time to time, and applicable regulations and guidance thereunder.

“DISABILITY” means a physical or mental infirmity that can be expected to result in death or to last for a continuous period of not less than 12 months, because of which Employee is receiving benefits under the Company sponsored group long-term disability plan in which the Employee participates.

“DISABILITY DATE” means the date subsequent to a Change in Control on which the Employee is determined to have a Disability.

“EFFECTIVE DATE” means the first date on which a Change in Control occurs. The Effective Date does not occur and no benefits shall be paid under this Agreement if for any reason the Employee is not an employee of the Company on the day immediately prior to the Effective Date.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“EXCHANGE ACT” means the Securities Exchange Act of 1934, as amended from time to time, or any successor act thereto.

“GOOD REASON” means those events or conditions described in subsections 9(c) below.

“NONQUALIFIED DEFERRED COMPENSATION PLAN” means the Company’s

Nonqualified Deferred Compensation Plan as amended and restated effective January 1, 2011, and as amended or replaced from time to time thereafter prior to the Effective Date.

“NOTICE OF TERMINATION” means a notice which indicates the specific termination provision in this Agreement, if any, relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee’s employment under the provisions so indicated. Any purported termination by the Company or Employee shall be communicated by written notice of termination to the other.

“OMNIBUS INCENTIVE COMPENSATION PLANS” means the incentive compensation plans known as the “Black Hills Corporation 2015 Omnibus Incentive Compensation Plan” as effective April 28, 2015, and the “Black Hills Corporation 2005 Omnibus Incentive Compensation Plan” as effective May 25, 2005, and as the plans are amended or replaced from time to time thereafter prior to the Effective Date.

“2005 PENSION EQUALIZATION PLAN” means the Company’s 2005 Pension Equalization Plan as in effect on January 1, 2008 and as amended or replaced from time to time thereafter prior to the Effective Date.

“PENSION PLAN” means the Company’s tax qualified defined benefit pension plan as amended and restated effective October 1, 2000, and as amended from time to time thereafter prior to the Effective Date.

“PERSON” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d).

“PROTECTION PERIOD” means the time period beginning on the Effective Date and ending on the third anniversary of the Effective Date.

“RELATED COMPANY” means any business organization or legal entity that directly or indirectly, controls, is controlled by or is under common control with the Company. For purposes of this definition, the term “control” (including the terms “controlling”, “controlled by”, and “under common control with”) includes the possession, direct or indirect, of the power to vote 50 percent or more of the voting equity securities, membership interest, or other voting interest, or to direct or cause the direction of the management and policies of such business organization or other legal entity, whether through the ownership of voting equity securities, membership interest, by contract, or otherwise.

“RESTORATION PLAN” means the Company’s Restoration Plan as in effect on January 1,

2008 and as amended or replaced from time to time thereafter prior to the Effective Date.

“RETIREE HEALTHCARE PLAN” means the Company’s Retiree Healthcare Plan as amended and restated effective January 1, 2015, and as further amended from time to time thereafter prior to the Effective Date.

“RETIREMENT SAVINGS PLAN” means the Black Hills Corporation Retirement Savings Plan (401K) as amended and restated effective January 1, 2016, and as further amended from time to time thereafter prior to the Effective Date.

“SEVERANCE COMPENSATION” means the Employee’s base salary and annual incentive target on the day immediately prior to the Effective Date.

“SUBSIDIARY” means any corporation, partnership, limited liability company, joint venture, or other entity in which the Company has a majority voting interest.

“SUCCESSOR EMPLOYER” means any Successor Entity (as defined in the definition of “Change in Control” herein) or any other successor in interest or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) of the business and/or assets of the Company.

“TERMINATION DATE” means the date, subsequent to the Effective Date, of the Employee’s separation from service (as defined for purposes of Code Section 409A) with the Company and all Related Companies.

“WELFARE BENEFITS” means the Black Hills Corporation Medical and Dental Plan, the Black Hills Corporation Flexible Benefit Plan, and the Black Hills Corporation Employee Life and Long-Term Disability Plan, and the Short-Term Disability Plan, as the plans and the terms and conditions thereof exist on the day immediately prior to the Effective Date. Following the Employee’s Termination Date, the term Welfare Benefits shall not include a “flexible spending arrangement” (within the meaning of Proposed Regulation Section 1.125-5(a) or subsequent authoritative guidance).


3.	TERM OF AGREEMENT.

The Term of this Agreement shall commence on the date of execution and shall continue in effect until November 15, 2022. If no Change in Control shall have occurred during the Term, this Agreement shall expire. If a Change in Control occurs during the Term, this Agreement shall remain in effect for full performance according to its terms. Upon expiration of the Term prior to a Change in Control, the Company, by action of its Board of Directors, may elect to renew or not renew this Agreement, or may offer to renew the Agreement subject to modifications of any term or condition, at its discretion. The Board of Directors may, in its discretion, terminate this Agreement prior to the expiration of the Term, in the event that Employee, for any reason, ceases to be employed with the Company in a position as an executive officer within the meaning of the Exchange Act.


4.	EMPLOYMENT.

Subject to the provisions of this Agreement, during the Protection Period the Company or Successor Employer agrees to continue to employ the Employee and the Employee agrees to remain in the employ of the Company or Successor Employer. During the Protection Period, the Employee shall be employed in a position substantially similar to Employee’s position prior to the Change in Control or in such other capacity as may be mutually agreed to in writing by the parties. Employee shall perform the duties, undertake the responsibilities and exercise the authority customarily performed, undertaken and exercised by persons situated in a similar capacity.

During the Protection Period, excluding periods of vacation, sick leave or another approved leave of absence, Employee agrees to devote full attention and time to the business and affairs of the Company or Successor Employer to the extent necessary to discharge the responsibilities assigned to Employee hereunder. It is expressly understood and agreed that to the extent that any civic, charitable or industry-related activities have been conducted by Employee prior to the Effective Date, the continued conduct of such activities (or the conduct of activities similar in nature and scope thereto) subsequent to the Effective Date shall not thereafter be deemed to interfere with the performance of Employee’s responsibilities to the Company or Successor Employer. In addition, if Employee serves on a public Board of Directors prior to the Effective Date, the Employee shall retain the right to continue to serve on that particular Board.


5.	COMPENSATION.

During the Protection Period, the Company or Successor Employer agrees to pay or cause to be paid to Employee Annual Compensation at a rate at least equal to the highest rate of the Employee’s Annual Compensation as in effect at any time within one year preceding the Effective Date, and as may be increased from time to time. Such Annual Compensation shall be payable in accordance with the Company’s customary practices applicable to its officers and employees.


6.	EMPLOYEE WELFARE AND PENSION BENEFITS.

During the Protection Period, the Company or the Successor Employer shall provide to the Employee the Welfare Benefits (including Retiree Healthcare Plan credits for purposes of this Section 6) and the Pension Plan, including supplemental medical insurance, travel accident insurance, short-term disability, long-term disability or life insurance benefits, or other substantially similar employee welfare and pension benefits, but in no event on a basis less favorable in the aggregate in terms of benefit levels and coverage than the Welfare Benefits and the Pension Plan. In the event Employee is not a participant in a Welfare Benefits plan or the Pension Plan prior to the Effective Date, then Company shall have no obligation to provide that Welfare Benefits plan or the Pension Plan or other substantially similar employee welfare and pension benefits as provided in this Section 6. For purposes of this Section 6, if the Employee is not entitled to any future benefit accruals in the Pension Plan as of the Effective Date the Employee shall not be treated as a participant in the Pension Plan for purposes of accruing benefits under the Pension Plan.


7.	2005 PENSION EQUALIZATION PLAN; RESTORATION PLAN.

If Employee was a participant in the 2005 Pension Equalization Plan prior to the Effective Date, then during the Protection Period, the Company or Successor Employer shall continue to provide Employee with coverage and participation under the 2005 Pension Equalization Plan or a substantially similar supplemental retirement plan.

If Employee was a participant in the Restoration Plan prior to the Effective Date, then during the Protection Period, the Company or Successor Employer shall continue to provide Employee with coverage and participation under the Restoration Plan or a substantially similar supplemental retirement plan. For purposes of this Section 7, if the Employee is not entitled to any future benefit accruals in the Restoration Plan as of the Effective Date the Employee shall not be treated as a participant in the Restoration Plan for purposes of accruing benefits under the Restoration Plan.

In no event shall coverage during the Protection Period be on a basis less favorable in terms of benefit levels and coverage than the 2005 Pension Equalization Plan and the Restoration Plan.


8.	OTHER BENEFITS.

(a)Executive and Fringe Benefits and Paid-Time-Off. During the Protection Period, Employee shall be entitled to all executive and fringe benefits and paid-time-off generally made available by the

Company or Successor Employer, as applicable, to its executives or other employees. Unless otherwise provided herein, the executive and fringe benefits and paid-time-off provided to Employee shall be on the same basis and terms as other similarly situated employees of the Company, but in no event shall be less favorable in the aggregate than the most favorable executive and fringe benefits or paid-time-off to Employee at any time within one year period preceding the Effective Date, or if more favorable, at any time thereafter.

(b)

Expenses. Employee shall be entitled to receive prompt reimbursement of all expenses reasonably incurred by Employee in connection with the performance of Employee’s duties hereunder or for promoting, pursuing or otherwise furthering the business or interests of the Company or Successor Employer. All reimbursements under this Section 8(b) will be paid as promptly as administratively practicable, but in no event later than by December 31st of the year next following the calendar year in which the expense was incurred.

(c)Indemnity. If, at the time of a Change in Control, the Employee was covered by an Indemnity Agreement and/or Directors’ and Officers’ Insurance (D & O) coverage, then the Indemnity Agreement and D & O coverage shall continue in full force and effect throughout the Protection Period, and beyond the Protection Period, with respect to claims arising out of acts or omissions of the Employee prior to a Change in Control. If, following a Change in Control, Company or the Successor Employer adopts substitute Indemnity Agreements, and/or D & O coverage, for employees having substantially the same authority, duties, and responsibilities as Employee, then Employee shall be entitled to receive the benefit of such protection with respect to claims arising from acts or omissions of Employee following a Change in Control. Payment for expenses to be reimbursed under this Section 8(c) shall be made in accordance with the time specified under the Indemnity Agreement or D & O coverage, but in no event later than by December 31st of the year next following the year in which the expense was incurred.


9.	TERMINATION.

During the Protection Period, Employee’s employment hereunder may be terminated under the following circumstances:

(a)Cause. The Company may terminate Employee’s employment for “Cause.” A termination of employment is for “Cause” if Employee (1) enters a guilty plea, pleads nolo contendre to, or is convicted of a felony offense that is demonstrably injurious to the Company; (2) engages in misconduct which is demonstrably injurious to the Company, monetarily or otherwise; or (3) fails to perform Employee’s material duties and responsibilities or to satisfy Employee’s material obligations as an officer or employee of the Company, or other material breach of any terms or conditions of any material written policy of the Company or any written agreement between Employee and the Company, (4) fails, after reasonable request, to cooperate with the Company or governmental authorities in connection with a civil or criminal regulatory investigation or proceeding, or other civil litigation involving the company; provided, however, that no termination of Employee’s employment shall be for Cause as set forth in clauses (2), (3) or (4), unless (i) there shall have been delivered to Employee a copy of a written Notice of Termination, at least thirty (30) days in advance of the Termination Date, setting forth that Employee was guilty of the conduct set forth in such applicable clause and specifying the particulars thereof in detail; and (ii) Employee shall have been provided an opportunity to be heard by the Board (with the assistance of Employee’s counsel if Employee so desires). Notwithstanding anything contained in this Agreement to the contrary, no failure to perform by Employee after a Notice of Termination is given to the Employee shall constitute Cause for purposes of this Agreement.

Date. Notwithstanding anything contained in this Agreement to the contrary, and subject to applicable law and the provisions of the Company’s long-term disability policy, until the Termination Date specified in a Notice of Termination relating to Employee’s Disability, Employee shall be entitled to return to Employee’s position with the Company as set forth in this Agreement, in which event no Disability Date will be deemed to have occurred.

(c)Good Reason. During the Protection Period, the Employee may terminate employment for “Good Reason.” For purposes of this Agreement, “Good Reason” shall mean the occurrence after the Effective Date of any of the events or conditions described below, without Employee’s consent.

(i)A material reduction of the Employee’s authority, duties, or responsibilities from those in effect immediately prior to the Effective Date, including a requirement that the Employee is required to report to a corporate officer or employee, instead of reporting directly to a board of directors of a publicly-traded corporation;

(ii)A material reduction in the Employee’s base salary or annual incentive target opportunity;

(iii)Any material breach by the Company of any provision of this Agreement, including, but not limited to, the Company’s failure to provide the Employee Welfare and Pension Benefits or the Pension Equalization Plan or Restoration Plan benefits, as set forth in Sections 6 and 7, provided that such failure constitutes a material breach under subsection 9(c)(v);

(iv)The Company’s requiring the Employee to be based outside a 50-mile radius from Employee’s usual and normal place of work prior to the Effective Date, except for reasonably required travel on the Company’s business which is not substantially greater than such travel requirements prior to the Effective Date; or

(v)Any other action or inaction that constitutes a material breach by the Company of the agreements under which the Employee provides services including, but not limited to, the failure of the Company to obtain an agreement, satisfactory to the Employee, from any Successor Employer or assign of the Company, to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be obligated to perform under this Agreement, as contemplated in Section 14.

In order to effectuate a termination for Good Reason under this Section 9(c), the Employee shall, within ninety (90) days after the initial existence of the condition, deliver written Notice of Termination to the Company stating the grounds for Good Reason in support of termination and specifying the Termination Date, which shall be (A) not earlier than thirty (30) days after giving the Notice of Termination, and (B) not later than one hundred eighty (180) days after giving the Notice of Termination or the last day of the Protection Period.

The Company may, within thirty (30) days after receipt of such Notice of Termination, remedy the condition, in which case the Good Reason for termination shall be deemed not to have occurred. For purposes of determining the amount of any cash payment payable to the Employee in accordance with Section 10, any reduction in compensation or benefit that would constitute Good Reason hereunder shall be deemed not to have occurred.


10.	COMPENSATION UPON TERMINATION.

Upon termination of Employee’s employment effective during the Protection Period, Employee shall be entitled to the following compensation and benefits:

(a)If Employee’s employment with the Company shall be terminated (i) by the Company for Cause or Disability, or (ii) by reason of Employee’s death, or (iii) by Employee without “Good Reason” pursuant to Section 9(c), the Company shall pay Employee all amounts earned or accrued through the Termination Date, but not paid as of the Termination Date, including all Annual Compensation, reimbursement for reasonable and necessary expenses incurred by Employee on behalf of the Company during the period ending on the Termination Date, together with accrued vacation pay, and paid-time-off (collectively “Accrued Compensation”), each in accordance with the applicable policies, plans and practices of the Company. In addition to the foregoing, if the Employee’s employment is terminated by the Company for Disability or by reason of the Employee’s death, the Company shall pay to the Employee or his beneficiaries an amount equal to the “Pro Rata Bonus” which shall mean an amount equal to 100% of the annual incentive bonus target that the Employee would have been eligible to receive for the Company’s fiscal year in which the Employee’s employment terminates, multiplied by a fraction, the numerator of which is the number of days in such fiscal year through the Termination Date and the denominator of which is 365. The Pro Rata Bonus shall be paid in a lump sum within sixty (60) days following the Termination Date.

(b)If during the Protection Period the Employee’s employment with the Company shall be terminated (other than by reason of death) (i) by the Company other than for Cause or Disability, or (ii) by Employee for Good Reason, then following the Termination Date, subject to the conditions specified below, the Employee shall be entitled to the following:

(i)The Company shall pay Employee all Accrued Compensation, payable in accordance with the applicable policies, plans and practices of the Company, and a Pro Rata Bonus, payable within sixty (60) days following the Termination Date.

(ii)The Company shall pay Employee, in lieu of any further compensation for periods subsequent to the Termination Date, a lump sum severance payment, in cash, in an amount equal to 2.99 times (2.99x) the Employee’s Severance Compensation. The lump sum severance payment described in this paragraph shall be paid within sixty (60) days after the Termination Date.

(iii)As a condition of receiving payments and benefits provided in this subsection 10(b), Employee shall execute and deliver to Company or Successor Employer the Waiver and Release Agreement (“Release”) in substantially the same form as attached hereto as Exhibit A. The severance payments and benefits shall not be paid or provided unless the Employee has executed and delivered the Release within the timeframe specified by the Company consistent with applicable laws, and the Release has become irrevocable as provided therein. Prior to the Effective Date, the Company may revise the Release to conform to applicable law, so long as the Release does not increase the obligations of Employee thereunder.

For purposes of this provision, Employee shall have a duty to inform Company as to the terms and conditions of any subsequent employment and the corresponding benefits earned from such employment. The continued coverage or provision of equivalent benefits under this subsection 10(b)(iv) or subsection 10(b)(v) shall be provided in a manner that is intended to satisfy an exception to Code Section 409A, and therefore not treated as an arrangement providing for nonqualified deferred compensation that is subject to taxation under Code Section 409A, including (i) providing such benefits on a nontaxable basis to Employee, (ii) providing for the reimbursement of medical expenses incurred during the time period during which Employee would be entitled to continuation coverage under a group health plan of the Company pursuant to Code Section 4980B (i.e., COBRA continuation coverage), (iii) providing that such benefits constitute the reimbursement or provision of in-kind benefits payable at a specified time or pursuant to a fixed schedule as permitted under Code Section 409A, or (4) such other manner as determined to be in compliance with an exception from being treated as nonqualified deferred compensation that is subject to taxation under Code Section 409A.

(v)If Employee was a participant in the Retiree Healthcare Plan immediately prior to a Change in Control, then as of Employee’s Termination Date, the Employee’s benefit under the Retiree Healthcare Plan shall be determined as if (i) Employee had completed an additional three (3) Years of Plan Participation (as defined in the Retiree Healthcare Plan), and (ii) Employee were three (3) years older for determining eligibility for plan benefits. Furthermore, if the Employee is not eligible for benefits after the age and participation adjustment, then the Retirement Medical Savings Account (after adjustment for three years of participation) will be considered vested, and upon attainment of age 55 the Employee shall be deemed eligible for Retiree Healthcare Plan benefits, with the vested Retirement Medical Savings Account available to offset premiums. At its election, the Company may provide Employee and Employee’s dependents with equivalent benefits outside the Retiree Healthcare Plan (though not by method of direct cash payment).

(vi)If Employee was a participant in the 2005 Pension Equalization Plan immediately prior to a Change in Control, then as of Employee’s Termination Date, the Employee’s benefit under the 2005 Pension Equalization Plan shall be determined as if (i) Employee had completed an additional three (3) Years of Plan Participation (as defined in the 2005 Pension Equalization Plan), and (ii) Employee received Annual Compensation (as defined in Section 5) during each additional Year of Plan Participation.

If Employee was a participant in the Restoration Plan and the Pension Plan immediately prior to a Change in Control, then as of Employee’s Termination Date, Employee’s Restoration Plan benefit shall be determined as if (i) Employee completed three (3) additional years of Credited Service under the Pension Plan, and (ii) the Employee received Annual Compensation (as define in Section 5) during each additional year of Credited Service. For purposes of this subsection 10(b)(vi), if the Employee is not entitled to any future benefit accruals in the Restoration Plan as of the Effective Date the Employee shall not receive any additional Credited Service or Annual Compensation when determining their Restoration benefit.

Furthermore, the Employee shall be made 100% vested for purposes of both the 2005 Pension Equalization Plan and Restoration Plan, if the Employee is a participant in such plans (for purposes of this subsection) and is not already fully vested.

in the Nonqualified Deferred Compensation Plan); no investment earnings shall be attributed for this additional period, and (ii) Employee received Annual Compensation (as defined in Section 5) during each additional Plan Year of participation.

For purposes of this subsection 10(b)(vii), the additional contributions under the Nonqualified Deferred Compensation Plan (Supplemental Matching Contributions, Supplemental Retirement Contributions, and Supplemental Target Contributions) shall be determined without regard to any offsets from the Retirement Savings Plan. (This has the same effect as if the Supplemental Matching Contributions and Supplemental Retirement Contributions were determined on total pay rather than only on pay over IRS pay limits.) Notwithstanding any provision herein to the contrary, if the Employee is a “specified employee” (as defined for purposes of Code Section 409A), no payment under this Agreement shall be made before the date which is six (6) months after the date of the Employee’s Termination Date, or such earlier date upon which such amount can be paid or provided under Code Section 409A without being subject to additional taxes thereunder, if such payment constitutes deferred compensation subject to Code Section 409A. To the extent that the Agreement provides for such nonqualified deferred compensation, it is intended to be compliant with Code Section 409A, and shall be interpreted and administered accordingly.


11.	OFFSET.

Employee shall not be required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise, and except as provided in Section 10(b)(iv), such payments shall not be reduced whether or not Employee obtains other employment.


12.	TAX EFFECT.

No additional payments shall be made to the Employee to account for any excise taxes, income taxes, interest or penalties the employee may incur due to receipt of any Severance Compensation or other payment, benefit, or distribution of any type by the Company pursuant to this Agreement.

Notwithstanding anything in this Agreement or any written or unwritten policy of the Company to the contrary, if it shall be determined that any payment or distribution by the Company to or for the benefit of the Employee, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement, any other agreement between the Company and the Employee or otherwise (a “Payment” or “Payments”), would constitute a parachute payment (“Parachute Payment”) within the meaning of Section 280G of the Code and would, but for this Section 12, be subject to the excise tax imposed under Section 4999 of the Code (or any successor provision thereto) or any similar tax imposed by state or local law or any interest or penalties with respect to such taxes (collectively, the “Excise Tax”), then prior to making the Payments, a calculation shall be made comparing (i) the Net Benefit (as defined below) to the Employee of the Payments after payment of the Excise Tax to (ii) the Net Benefit to the Employee if the Payments are limited to the extent necessary to avoid being subject to the Excise Tax. Only if the amount calculated under (i) above is less than the amount under (ii) above will the Payments be reduced to the minimum extent necessary to ensure that no portion of the Payments is subject to the Excise Tax. “Net Benefit” shall mean the present value of the Payments net of all federal, state, local, foreign income, employment and excise taxes. The Payments shall be reduced in a manner that maximizes the Employee’s economic position. In applying this principle, the reduction shall be made in a manner consistent with the requirements of Section 409A of the Code, and where two economically equivalent amounts are subject to reduction but payable at different times, such amounts shall be reduced on a pro rata basis but not below zero. Any determination required under this Section 12, including whether any payments or benefits are parachute payments, shall be made by the Company in its sole discretion. The Employee shall provide the Company with such information and documents as the Company may reasonably request in order to make a determination under this Section 12. The Company’s determination shall be final and binding on the Employee. The parties acknowledge that the Employee is solely responsible for the payment of any Excise Tax that is assessed based

upon a payment made pursuant to this Agreement or any other payment made by the Company pursuant to any other plan or obligation.


13.	OUTPLACEMENT SERVICES.

The Company shall, at its expense, permit the Employee to participate in outplacement assistance services, as determined by the Company, which are: (a) as to executive officers, at a level appropriate for senior management of a public company, and (b) not more than six (6) months in duration. Outplacement services shall be provided in kind; cash shall not be paid in lieu thereof, nor will cash compensation be increased if Employee declines or does not use outplacement services. All outplacement services shall be provided by the last day of the second calendar year beginning after the Employee’s Termination Date.


14.	SUCCESSORS AND ASSIGNS.

This Agreement shall be fully binding upon any Successor Employer or assign (whether direct or indirect, by purchase, merger, consolidation or otherwise) to the business and/or assets of the Company, in the same manner and to the same extent that the Company would be obligated under this Agreement as if no succession had taken place. In the case of any transaction in which a successor or assign would not by the foregoing provision, or by operation of law, be bound by this Agreement, the Company shall require such successor or assign to expressly and unconditionally assume and agree to perform all the obligations of the Company and each Employer under this Agreement, in the same manner and to the same extent that the Company and each Employer would be required to perform it if no such succession or assignment had taken place. Any failure to obtain such assumption and continuation of this Agreement shall constitute a material breach hereof. Reference to the Company in this Agreement shall, following the Effective Date, include any Successor Employer.

Neither this Agreement nor any right or interest hereunder shall be assignable or transferable by the Employee, Employee’s beneficiaries or legal representatives, except by will or by the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by the Employee’s legal personal representative.


15.	FEES AND EXPENSES.

The Company shall pay all legal fees and related expenses (including the costs of experts, evidence and counsel) reasonably and in good faith incurred by the Employee as they become due as a result of the Employee seeking to obtain or enforce any right or benefit provided by this Agreement.

For purposes of this Section 15, the Employee will not be deemed to have incurred legal fees or expenses reasonably or in good faith if, following resolution of a dispute under this Agreement, he has failed to prevail on at least one material issue in dispute. The amount of expenses eligible for reimbursement hereunder during any given calendar year shall not affect the expenses eligible for reimbursement in any other calendar year. Employee shall submit verification of expenses to the Company within sixty (60) days from the date the expense was incurred, and the Company shall reimburse eligible expenses within thirty (30) days thereafter, but in any case no later than the last day of the calendar year following the calendar year in which the expense was incurred. The right to reimbursement of legal fees and expenses hereunder may not be exchanged for cash or any other benefit.


16.	NOTICE.

the Board of Directors of the Company. All notices and communications shall be deemed to have been received on the date of delivery thereof if personally delivered, or on the third business day after the mailing thereof, except that notice of change of address shall be effective only upon receipt.


17.	NONEXCLUSIVITY OF RIGHTS.

Except as expressly provided herein, nothing in this Agreement shall prevent or limit Employee’s continuing or future participation in any benefit, bonus, incentive or other plan or program provided by the Company or any of its Subsidiaries or Affiliates and for which Employee may qualify, nor shall anything herein limit or reduce such rights as Employee may have under any other agreements with the Company or any of its Subsidiaries or Affiliates; provided however that in the event that Employee becomes eligible for any cash severance benefits under a Company severance program, plan or policy as a result of a termination during the Protection Period, then the Severance Compensation payable to Employee under this Agreement shall be reduced by any such cash severance benefits. Amounts which are vested benefits or which Employee is otherwise entitled to receive under any plan or program of the Company or any of its Subsidiaries or Affiliates shall be payable in accordance with such plan or program, except as explicitly modified by this Agreement; provided, however, and notwithstanding anything contained in this Agreement, in the event that Employee is not a participant in or eligible to participate in any Welfare Benefits or the Pension Plan, then nothing contained in this Agreement shall be deemed to provide for or suggest the right in Employee to be a participant in or be eligible to participate in the Welfare Benefits or the Pension Plan.


18.	MISCELLANEOUS.

No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by Employee and the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreement or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not expressly set forth in this Agreement.


19.	GOVERNING LAW.

This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of South Dakota.


20.	SEVERABILITY.

The provisions of this Agreement shall be deemed severable and the invalidity or unenforceability of any provision shall not affect the validity or enforceability of the other provisions hereof.


21.	NO GUARANTEED EMPLOYMENT.

Employee and the Company acknowledge that, except as may otherwise be provided under any other written agreement between Employee and the Company, the employment of Employee by the Company is “at will” and may be terminated by either Employee or the Company at any time, subject to the rights and obligations under this Agreement. Moreover, if prior to the Effective Date, Employee’s employment with the Company terminates for any reason, Employee shall have no further rights under this Agreement.


22.	SUBSIDIARY DEEMED TO BE COMPANY FOR PORTIONS OF AGREEMENT.

In the event that subsequent to the date of this Agreement the Employee becomes an employee of a Subsidiary or Affiliate of the Company, or in the event that any Employee is an employee of a Subsidiary or Affiliate of the Company, the references to “Company” in this Agreement shall be deemed to be a reference to the subsidiary or Affiliate which may employ the Employee to the full extent necessary or appropriate to preserve the intent of this Agreement; provided, however, nothing herein shall mean or suggest that any benefits are applicable hereunder upon a change in control of a Subsidiary or Affiliate rather than the Company.


23.	ENTIRE AGREEMENT.

This Agreement constitutes the entire agreement between the parties hereto and supersedes all prior agreements, if any, understandings and arrangements, oral or written, between the parties hereto with respect to the subject matter hereof.

Dated this 15^th day of November, 2019.

BLACK HILLS CORPORATION

By: /s/ Brian G. Iverson

Brian G. Iverson

Senior Vice President and General Counsel

EMPLOYEE

By: /s/ Linden R. Evans

Linden R. Evans

EXHIBIT A

WAIVER AND RELEASE AGREEMENT

This Waiver and Release Agreement (the “Waiver and Release”) is entered into by and among Black Hills Corporation (“Company”) and Linden R. Evans (“Employee”) this day of _______________, 20___.

1.General Waiver and Release. For and in consideration of the agreement of Company to provide Employee the severance benefits described in that certain Change in Control Agreement, dated as of _______________, 20___, between Employee and the Company (the “Agreement”), Employee, with the intention of binding himself and all of Employee’s heirs, executors, administrators and assigns, does hereby release, remise, acquit and forever discharge the Company, Successor Employer, their parents, affiliates, subsidiaries, predecessors, divisions, and successors, and all of their respective past and present officers, directors, stockholders, employees, agents, insurers, employee benefit plans and fiduciaries of such plans, assigns and attorneys (hereinafter collectively referred to as “Released Parties”) from any and all claims, charges, actions causes of action, sums of money due, suites, debts, covenants, contracts, agreements, rights, damages, promises, demands or liabilities (hereinafter collectively referred to as “Claims”) whatsoever, in law or in equity, whether known or unknown, suspected or unsuspected, which Employee, individually or as a member of any class, now has, owns or holds or has at any time heretofore ever had, owned or held against the Released Parties, including but not limited to all Claims which arise out of or are in any way connected with Employee’s employment with the Company or any of the Released Parties or the termination of any such employment relationship, including, but not by

way of limitation, Claims pursuant to federal, state or local statute, regulation, ordinance or common-law for (i) employment discrimination; (ii) wrongful discharge; (iii) breach of contract; (iv) tort actions of any type, including those for intentional or negligent infliction of emotional harm; and (v) unpaid benefits, wages, compensation, commissions, bonuses or incentive payments of any type, except as follows:


a.	Those obligations of the Company and its Affiliates to pay benefits upon termination of employment as set forth in the Agreement, pursuant to which this Waiver and Release is being executed and delivered;

Claims, if any, for Employee’s vested benefits under the retirement plans, savings plans, investment plans and employee welfare benefit plans, if any, of the Released Parties (within the meaning of Section 3(1) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”)), as amended; provided, however, that nothing herein is intended to or shall be construed to require the Released Parties to institute or continue in effect any particular plan or benefit sponsored by the Released Parties and the Company and all other Released Parties hereby reserve the right to amend or terminate any such plan or benefit at any time; and


c.	Any rights to indemnification or advancement of expenses to which Employee may otherwise be entitled pursuant to the Articles of Incorporation or Bylaws of any of the Released Parties, or by contract or applicable law, as a result of Employee’s service as an officer or director of any of the Released Parties.

Employee further understands and agrees that, subject to the exceptions in subparagraphs a., b. and c. above, Employee is knowingly relinquishing, waiving and forever releasing any and all remedies arising out of the aforesaid employment relationship or the termination thereof, including, without limitation, claims for back pay, front pay, liquidated damages, compensatory damages, general damages, special damages, punitive damage, exemplary damages, costs, expenses and attorneys’ fees.

2.Waiver and Release of ADEA Claims. Without limiting the generality of the foregoing, and also for and in consideration of the Company’s agreement to provide Employee severance payments and benefits as described in the Agreement, Employee specifically acknowledges and agrees that he does hereby knowingly and voluntarily release the Company and all other Released Parties from any and all claims arising under the Age Discrimination in Employment Act, 29 U.S.C. Section 621, et seq. (“ADEA”), which Employee ever had or now has from the beginning of time up to the date this Waiver and Release is executed, including, but not by way of limitation, those ADEA Claims which are in any way connected with any employment relationship or the termination of any employment relationship which existed between the Company or any other Released Parties and Employee. Employee also acknowledges that he has been provided with a notice, as required by the Older Workers Benefit Protection Act of 1990, that contains (i) information about the individuals covered under the Agreement, (ii) the eligibility factors for participation in the Agreement, (iii) the time limits applicable to the Agreement, (iv) the job titles and ages of the employees designated to participate in the Agreement, (v) and the ages of the employees in the same job classification who have not been designated to participate in the Agreement. Employee further acknowledges and agrees that the Company is hereby advising Employee to consult with an attorney prior to executing this Waiver and Release and that Employee has been given at least twenty-one (21) days to consider this Waiver and Release prior to its execution. Employee agrees that in the event that Employee executes this Waiver and Release prior to the expiration of the twenty-one (21) day period, Employee shall waive the balance of said period and Employee has decided that Employee does not need any additional time to decide whether to sign this Waiver and Release. Employee also understands that Employee may revoke this Waiver and Release of ADEA Claims at any time within seven (7) days following its execution and that, if Employee revokes this waiver and Release of ADEA Claims within such seven (7) day period, it shall not be effective or enforceable and Employee will not receive the above-described consideration or any payments provided for in the Agreement that have not been paid.

3.Denial of Liability. Employee acknowledges and agrees that neither the payment of severance payments or benefits under the Agreement nor this Waiver and Release is to be construed in any way as an admission of any liability whatsoever by Company or any of the other Released Parties, by whom liability is expressly denied.

4.No Entitlement to Further Relief. Employee acknowledges and agrees that he has not, with respect to any transaction or state of facts existing prior to the date of execution of this Waiver and Release, filed any complaints, charges or lawsuits against any of the Released Parties with any governmental agency or any court or tribunal. Employee further acknowledges and agrees that, with the exception of money provided to Employee by a governmental agency as an award for providing information as a whistleblower, Employee hereby waives any right to accept any relief or recovery, including costs and attorneys’ fees, that may arise from any charge or complaint before any federal, state or local court or administrative agency against the Released Parties.

5.Company Property and Confidential Information. Employee agrees that Employee will not retain or destroy, and will immediately return to the Company, any and all property of the Company in Employee’s possession or subject to Employee’s control, including, but not limited to, keys, credit and identification cards, personal items or equipment, customer files and information, all other files and documents relating to the Company and its business, together with all written or recorded materials, documents, computer disks, plans, records or notes or other papers belonging to the Company. Employee further agrees not to make, distribute or retain copies of any such information or property. Employee agrees to delete any digital copies of Company information that Employee may have on personal devices or storage media, after first providing a copy to the Company.

The Employee shall hold in a fiduciary capacity for the benefit of the Company all material proprietary information, knowledge or data relating to the Company or any of its affiliated companies, and their respective businesses, which shall have been obtained by the Employee during the Employee’s employment by the Company or any of its affiliated companies and which shall not be or become public knowledge. Employee agrees after termination of the Employee’s employment with the Company, the Employee shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any such information, knowledge or data to anyone other than the Company and those designated by it.

6.Non-Competition. Employee agrees that for a period of one (1) -year following the Termination Date, Employee shall not, without the written express consent of the Company, directly or indirectly, alone or as a partner, owner, officer, director, employee, or consultant of any other firm, business or entity, engage in any activity in competition with the Company; provided, however, that the foregoing shall not be construed to preclude the Employee from making any investments in any securities to the extent such securities are traded on a national exchange or over-the-counter market and such investment does not exceed five percent (5%) of the issued and outstanding voting securities of such issuer.

7.Non-Solicitation. Employee agrees that for a period of two (2) years following the Termination Date, Employee shall not, directly or indirectly, whether for Employee’s own benefit or on behalf of another: (i) hire or offer to hire any of the Company’s officers, employees or agents; (ii) persuade, or attempt to persuade, any officer, employee or agent of the Company to discontinue any relationship with the Company; or (iii) solicit or divert or attempt to divert any customer or supplier of the Company then doing business in the Company’s service territory.

8.Non-Disparagement. Employee agrees that for a period of two (2) years following the Termination Date, Employee shall not, directly or indirectly, disparage, criticize, or otherwise make derogatory statements regarding the Company or any aspect of management policies, operations, practices, or personnel of the Company. Notwithstanding the foregoing, nothing contained herein will be deemed to restrict the Employee from providing information to any governmental or regulatory agency

(or in any way limit the content of such information) to the extent the Employee is required to provide such information pursuant to applicable law or regulation; nor will the foregoing restrict the Employee from enforcing his or her rights under this Agreement.

9.Permitted Activities. Notwithstanding any other provision hereof, nothing contained in this Waiver and Release is intended to prevent Employee from filing a charge with the United States Equal Employment Opportunity Commission or any other governmental agency, providing information to a governmental agency, participating in an investigation conducted by a governmental agency, or responding to a subpoena or other court order; provided, however, that if Employee receives a subpoena or other court order relating to Employee’s employment with the Company or requesting Company information, before responding to the subpoena Employee will notify the Company of the subpoena and provide the Company a reasonable opportunity to respond and seek protection before disclosing any Company information.

10.Supersedes All Other Non-Competition, Non-Solicitation and Non- Disparagement Agreements. Employee agrees, that in the event of a Termination Date under the Agreement, the foregoing Section 6. Non-Competition, Section 7. Non- Solicitation and Section 8. Non-Disparagement supersedes any other non-competition, non-solicitation or non-disparagement agreements or provisions that may have been in place prior to the Termination Date.

11.Confidentiality Agreement. Employee acknowledges that the terms of this Waiver and Release must be kept confidential. Accordingly, Employee agrees not to disclose or publish to any person or entity, except as required by law or as necessary to prepare tax returns, the terms and conditions or sums being paid in connection with this Waiver and Release.

12.Cooperation. Employee agrees to cooperate with the Company and its attorneys in connection with all lawsuits, claims, investigations, or similar proceedings, including the provision of testimony as my reasonably be required, arising out of or in any way related to Employee’s employment by the Company or any of its Subsidiaries.

13.Acknowledgement. Employee acknowledges that Employee has carefully read and fully understands the terms of this Waiver and Release and the Agreement and that this Waiver and Release is executed by Employee voluntarily and is not based upon any representations or statements of any kind made by the Company or any of the other Released Parties. Employee further acknowledges that Employee has had a full and reasonable opportunity to consider this waiver Release and that Employee has not been pressured or in any way coerced into executing this Waiver and Release.

14.Choice of Laws. This Waiver and Release and the rights and obligation so the parties hereto shall be governed and construed in accordance with the laws of the State of South Dakota.

15.Severability. With the exception of the waiver and releases contained in Sections 1 and 2 hereof, if any provision of this Waiver and Release is unenforceable or is held to be unenforceable, such provision shall be fully severable, and this Waiver and Release and its terms shall be construed and enforced as if such unenforceable provision had never comprised a part hereof, the remaining provisions hereof shall remain in full force and effect, and the court construing the provisions shall add as a part hereof a provision as similar in terms and effect to such unenforceable provision as may be enforceable, in lieu of the unenforceable provision. In the event that both of the releases contained in Sections 1 and 2 are unenforceable or are held to be unenforceable, the parties understand and agree that the remaining provisions of this Waiver and Release shall be rendered null and void and that neither party shall have any further obligation under any provision of this Waiver and Release.

16.Defined Terms. Capitalized terms that are not defined in this Waiver and Release shall have the meanings set forth in the Agreement.

17.Entire Agreement. This document contains all terms of the Waiver and Release and supersedes and invalidates any previous agreements or contracts regarding the same subject matter. No representations, inducements, promises or agreements, oral or otherwise, which are not embodies herein shall be of any force or effect.

Please read this document carefully, as it includes a release of claims.

IN WITNESS WHEREOF, the undersigned acknowledges that Employee has read this Waiver and Release Agreement and sets Employee’s hand and seal this ____ day of __________________, 20___.

EMPLOYEE

________________________________

Linden R. Evans

BLACK HILLS CORPORATION

By: ___________________________

Title: ___________________________

Exhibit

CHANGE IN CONTROL AGREEMENT

This Change in Control Agreement (“Agreement”) dated as of November 15, 2019, is entered into by and between Black Hills Corporation (“Company”) and ________________________ (“Employee”).


1.	RECITALS.


2.	DEFINITIONS.

“AFFILIATE” shall have the meaning ascribed to such term in rule 12b-2 of the General Rules and Regulations of the Exchange Act.

“BENEFICIAL OWNER” or “BENEFICIAL OWNERSHIP” shall have the meaning ascribed to such term in Rule 13d-3 of the General Rules and Regulations under the Exchange Act.

“CAUSE” means those events or conditions described in subsections 9(a).

“CHANGE IN CONTROL” shall mean any of the following events:

(b)Individuals who, as of December 31, 2018, are members of the Board (the “Incumbent Board”), cease for any reason to constitute at least a majority of the members of the Board; provided, however, that if the election, or nomination for election by the Company’s common shareholders, of any new director was approved by a vote of at least two-thirds of the Incumbent Board, such new director shall, for purposes of this Agreement, be considered as a member of the Incumbent Board; provided further, however, that no individual shall be considered a member of the Incumbent Board if such individual initially assumed office as a result of either an actual or threatened “Election Contest” (as described in Rule 14a-11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board (a “Proxy Contest”) including by reason of any agreement intended to avoid or settle any Election Contest or Proxy Contest;

(c)Consummation, following shareholder approval, of a reorganization, merger, or consolidation of the Company, or a sale or other disposition of all or substantially all of the assets of the Company (each a “Business Combination”), unless, in each case, immediately following such Business Combination, all of the following have occurred: (i) all or substantially all of the individuals and entities who were beneficial owners of shares of the common stock of the Company immediately prior to such Business Combination beneficially own, directly or indirectly, more than fifty percent (50%) of the combined voting power of the then outstanding shares of the entity resulting from the Business Combination or any direct or indirect parent corporation thereof (including, without limitation, an entity which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one (1) or more subsidiaries) (the “Successor Entity”); (ii) no Person (excluding any Successor Entity or any employee benefit plan or related trust, of the Company or such Successor Entity) owns, directly or indirectly, thirty percent (30%) or more of the combined voting power of the then outstanding shares of common stock of the Successor Entity, except to the extent that such ownership existed prior to such Business Combination; and (iii) at least a majority of the members of the Board of Directors of the entity resulting from such Business Combination or any direct or indirect parent corporation thereof were members of the Incumbent Board at the time of the execution of the initial agreement or action of the Board providing for such Business Combination; or

“CODE” means the Internal Revenue Code of 1986, as amended from time to time, and applicable regulations and guidance thereunder.

“DISABILITY DATE” means the date subsequent to a Change in Control on which the Employee is determined to have a Disability.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“EXCHANGE ACT” means the Securities Exchange Act of 1934, as amended from time to time, or any

successor act thereto.

“GOOD REASON” means those events or conditions described in subsections 9(c) below.

“NONQUALIFIED DEFERRED COMPENSATION PLAN” means the Company’s

Nonqualified Deferred Compensation Plan as amended and restated effective January 1, 2011, and as amended or replaced from time to time thereafter prior to the Effective Date.

“PERSON” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d).

“PROTECTION PERIOD” means the time period beginning on the Effective Date and ending on the second anniversary of the Effective Date.

“RESTORATION PLAN” means the Company’s Restoration Plan as in effect on January 1, 2008 and as amended or replaced from time to time thereafter prior to the Effective Date.

“SEVERANCE COMPENSATION” means the Employee’s base salary and annual incentive target on

the day immediately prior to the Effective Date.

“SUBSIDIARY” means any corporation, partnership, limited liability company, joint venture, or other entity in which the Company has a majority voting interest.


3.	TERM OF AGREEMENT.


4.	EMPLOYMENT.


5.	COMPENSATION.

During the Protection Period, the Company or Successor Employer agrees to pay or cause to be paid to

Employee Annual Compensation at a rate at least equal to the highest rate of the Employee’s Annual Compensation as in effect at any time within one year preceding the Effective Date, and as may be increased from time to time. Such Annual Compensation shall be payable in accordance with the Company’s customary practices applicable to its officers and employees.


6.	EMPLOYEE WELFARE AND PENSION BENEFITS.


7.	2005 PENSION EQUALIZATION PLAN; RESTORATION PLAN.

In no event shall coverage during the Protection Period be on a basis less favorable in terms of benefit levels and coverage than the 2005 Pension Equalization Plan and the Restoration Plan.


8.	OTHER BENEFITS.

(a)Executive and Fringe Benefits and Paid-Time-Off. During the Protection Period, Employee shall be entitled to all executive and fringe benefits and paid-time-off generally made available by the Company or Successor Employer, as applicable, to its executives or other employees. Unless otherwise provided herein, the executive and fringe benefits and paid-time-off provided to Employee shall be on the same basis and terms as other similarly situated employees of the Company, but in no event shall be less favorable in the aggregate than the most favorable executive and fringe benefits or paid-time-off to Employee at any time within one year period preceding the Effective Date, or if more favorable, at any time thereafter.

(b)Expenses. Employee shall be entitled to receive prompt reimbursement of all expenses reasonably incurred by Employee in connection with the performance of Employee’s duties hereunder or for promoting, pursuing or otherwise furthering the business or interests of the Company or Successor Employer. All reimbursements under this Section 8(b) will be paid as promptly as administratively practicable, but in no event later than by December 31st of the year next following the calendar year in which the expense was incurred.

(c)

Indemnity. If, at the time of a Change in Control, the Employee was covered by an Indemnity Agreement and/or Directors’ and Officers’ Insurance (D & O) coverage, then the Indemnity Agreement and D & O coverage shall continue in full force and effect throughout the Protection Period, and beyond the Protection Period, with respect to claims arising out of acts or omissions of the Employee prior to a Change in Control. If, following a Change in Control, Company or the Successor Employer adopts substitute Indemnity Agreements, and/or D & O coverage, for employees having substantially the same authority, duties, and responsibilities as Employee, then Employee shall be entitled to receive the benefit of such protection with respect to claims arising from acts or omissions of Employee following a Change in Control. Payment for expenses to be reimbursed under this Section 8(c) shall be made in accordance with the time specified under the Indemnity Agreement or D & O coverage, but in no event later than by December 31st of the year next following the year in which the expense was incurred.


9.	TERMINATION.

During the Protection Period, Employee’s employment hereunder may be terminated under the following circumstances:

(a)Cause. The Company may terminate Employee’s employment for “Cause.” A termination of employment is for “Cause” if Employee (1) enters a guilty plea, pleads nolo contendre to, or is convicted of a felony offense that is demonstrably injurious to the Company; (2) engages in misconduct which is demonstrably injurious to the Company, monetarily or otherwise; (3) fails to perform Employee’s material duties and responsibilities or to satisfy Employee’s material obligations as an officer or employee of the Company, or other material breach of any terms or conditions of any material written policy of the Company or any written agreement between Employee and the Company, or (4) fails, after reasonable request, to cooperate with the Company or governmental authorities in connection with a civil or criminal regulatory investigation or proceeding, or other civil litigation involving the company; provided, however, that no termination of Employee’s employment shall be for Cause as set forth in clauses (2), (3) or (4), unless (i) there shall have been delivered to Employee a copy of a written Notice of Termination, at least thirty (30) days in advance of the Termination Date, setting forth that Employee was guilty of the conduct set forth in such applicable clause and specifying the particulars thereof in detail; and (ii) Employee shall have been provided an opportunity to be heard by the Board (with the assistance of Employee’s counsel if Employee so desires). Notwithstanding anything contained in this Agreement to the contrary, no failure to perform by Employee after a Notice of Termination is given to the Employee shall constitute Cause for purposes of this Agreement.

(b)Disability. The Company may terminate Employee’s employment after the Employee’s Disability Date. Employee shall be entitled to the compensation and benefits provided for under this Agreement for any period during the Protection Period and prior to the Employee’s Disability Date, during which Employee is unable to work due to a physical or mental infirmity, and up to the Employee’s Disability Date. Notwithstanding anything contained in this Agreement to the contrary, and subject to applicable law and the provisions of the Company’s long-term disability policy, until the Termination Date specified in a Notice of Termination relating to Employee’s Disability, Employee shall be entitled to return to Employee’s position with the Company as set forth in this Agreement, in which event no Disability Date will be deemed to have occurred.

(i)A material reduction of the Employee’s authority, duties, or responsibilities from those in effect immediately prior to the Effective Date;

(ii)A material reduction in the Employee’s base salary or annual incentive target

opportunity;

Notice of Termination, and (B) not later than one hundred eighty (180) days after giving the Notice of Termination or the last day of the Protection Period.


10.	COMPENSATION UPON TERMINATION.

Upon termination of Employee’s employment effective during the Protection Period, Employee shall be entitled to the following compensation and benefits:

(a)If Employee’s employment with the Company shall be terminated (i) by the Company for Cause or Disability, or (ii) by reason of Employee’s death, or (iii) by Employee without “Good Reason” pursuant to Section 9(c), the Company shall pay Employee all amounts earned or accrued through the Termination Date, but not paid as of the Termination Date, including all Annual Compensation, reimbursement for reasonable and necessary expenses incurred by Employee on behalf of the Company during the period ending on the Termination Date, together with accrued vacation pay, and paid time off (collectively “Accrued Compensation”), each in accordance with the applicable policies, plans and practices of the Company. In addition to the foregoing, if the Employee’s employment is terminated by the Company for Disability or by reason of the Employee’s death, the Company shall pay to the Employee or Employee’s beneficiaries an amount equal to the “Pro Rata Bonus” which shall mean an amount equal to 100% of the annual incentive bonus target that the Employee would have been eligible to receive for the Company’s fiscal year in which the Employee’s employment terminates, multiplied by a fraction, the numerator of which is the number of days in such fiscal year through the Termination Date and the denominator of which is 365. The Pro Rata Bonus shall be paid in a lump sum within sixty (60) days following the Termination Date.

(ii)The Company shall pay Employee, in lieu of any further compensation for periods subsequent to the Termination Date, a lump sum severance payment, in cash, in an amount equal to two times (2x) the Employee’s Severance Compensation. The lump sum severance payment described in this paragraph shall be paid within sixty (60) days after the Termination Date.

(iv)If Employee, prior to the Termination Date, was a participant in any Welfare Benefits, the Company or the Successor Employer, or any affiliate of the Successor Employer as determined under the rules of Code Sections 414(b) and (c), shall at its expense continue on behalf of Employee and Employee’s dependents and beneficiaries, for a period of two (2) years following the Termination Date, the Welfare Benefits or similar benefits no less favorable than the benefit levels and coverage provided to Employee prior to the Termination Date. Employee shall pay the employee portion of applicable premiums required to be paid by similarly-situated active employees (or retired employees in the case that the Employee is retired) of the Company. At its election, the Company may provide Employee and Employee’s dependents with equivalent benefits outside the Welfare Benefits plans (though not by method of direct cash payment). The Company’s obligation with respect to the foregoing benefit shall be discontinued in the event that Employee becomes covered under the health insurance coverage of a subsequent employer, other than the Successor Employer or any affiliate thereof, which does not contain any exclusion or limitation with respect to any preexisting condition of the Employee and Employee’s dependents. For purposes of this provision, Employee shall have a duty to inform Company as to the terms and conditions of any subsequent employment and the corresponding benefits earned from such employment. The continued coverage or provision of equivalent benefits under this subsection 10(b)(iv) or subsection 10(b)(v) shall be provided in a manner that is intended to satisfy an exception to Code Section 409A, and therefore not treated as an arrangement providing for nonqualified deferred compensation that is subject to taxation under Code Section 409A, including (i) providing such benefits on a nontaxable basis to Employee, (ii) providing for the reimbursement of medical expenses incurred during the time period during which Employee would be entitled to continuation coverage under a group health plan of the Company pursuant to Code Section 4980B (i.e., COBRA continuation coverage), (iii) providing that such benefits constitute the reimbursement or provision of in-kind benefits payable at a specified time or pursuant to a fixed schedule as permitted under Code Section 409A, or (4) such other manner as determined to be in compliance with an exception from being treated as nonqualified deferred compensation that is subject to taxation under Code Section 409A.

(v)If Employee was a participant in the Retiree Healthcare Plan immediately prior to a

Change in Control, then as of Employee’s Termination Date, the Employee’s benefit under the Retiree Healthcare Plan shall be determined as if (i) Employee had completed an additional two (2) Years of Plan Participation (as defined in the Retiree Healthcare Plan), and (ii) Employee were two (2) years older for determining eligibility for plan benefits. Furthermore, if the Employee is not eligible for benefits after the age and participation adjustment, then the Retirement Medical Savings Account (after adjustment for two years of participation) will be considered vested, and upon attainment of age 55 the Employee shall be deemed eligible for Retiree Healthcare Plan benefits, with the vested Retirement Medical Savings Account available to offset premiums. At its election, the Company may provide Employee and Employee’s dependents with equivalent benefits outside the Retiree Healthcare Plan (though not by method of direct cash payment).

(vi)If Employee was a participant in the 2005 Pension Equalization Plan immediately prior to a Change in Control, then as of Employee’s Termination Date, the Employee’s benefit under the 2005 Pension Equalization Plan shall be determined as if (i) Employee had completed an additional two (2) Years of Plan Participation (as defined in the 2005 Pension Equalization Plan), and (ii) Employee received Annual Compensation (as defined in Section 5) during each additional Year of Plan Participation.

If Employee was a participant in the Restoration Plan and the Pension Plan immediately prior to a Change in Control, then as of Employee’s Termination Date, Employee’s Restoration Plan benefit shall be determined as if (i) Employee completed two (2) additional years of Credited Service under the Pension Plan, and (ii) the Employee received Annual Compensation (as defined in Section 5) during each additional year of Credited Service. For purposes of this subsection 10(b)(vi), if the Employee is not entitled to any future benefit accruals in the Restoration Plan as of the Effective Date the Employee shall not receive any additional Credited Service or Annual Compensation when determining their Restoration benefit.

(i)If Employee was a participant in the Nonqualified Deferred Compensation Plan immediately prior to a Change in Control, then as of Employee’s Termination Date, Employee’s Non-Elective Account in the Nonqualified Deferred Compensation Plan shall become immediately vested and be determined as if (i) Employee had completed two (2) additional Plan Years of participation and earned the related Supplemental Matching Contributions, Supplemental Retirement Contributions, and Supplemental Target Contributions (all as defined in the Nonqualified Deferred Compensation Plan); no investment earnings shall be attributed for this additional period, and (ii) Employee received Annual Compensation (as defined in Section 5) during each additional Plan Year of participation.


(ii)	Notwithstanding any provision herein to the contrary, if the Employee is a “specified employee” (as defined for purposes of Code Section 409A), no payment under this Agreement shall be made before the date which is six (6) months after the date of the Employee’s Termination Date, or such earlier date upon which such amount can be paid or provided under

Code Section 409A without being subject to additional taxes thereunder, if such payment constitutes deferred compensation subject to Code Section 409A. To the extent that the Agreement provides for such nonqualified deferred compensation, it is intended to be compliant with Code Section 409A, and shall be interpreted and administered accordingly.


11.	OFFSET.


12.	TAX EFFECT.


13.	OUTPLACEMENT SERVICES.

The Company shall, at its expense, permit the Employee to participate in outplacement assistance services, as determined by the Company, which are: (a) as to executive officers, at a level appropriate for senior management of a public company; and (b) not more than six (6) months in duration. Outplacement services shall be provided in kind; cash shall not be paid in lieu thereof, nor will cash compensation be increased if Employee declines or does not use outplacement services. All outplacement services shall be provided by the last day of the second calendar year beginning after the Employee’s Termination Date.


14.	SUCCESSORS AND ASSIGNS.


15.	FEES AND EXPENSES.


16.	NOTICE.

For the purposes of this Agreement, notices and all other communications provided for in the Agreement (including the Notice of Termination) shall be in writing and shall be deemed to have been duly given when personally delivered or sent by certified mail, return receipt requested, postage prepaid, addressed to the last known address of Employee or in the case of the Company, to the principal executive office to the attention of the Board of Directors of the Company. All notices and communications shall be deemed to have been received on the date of delivery thereof if personally delivered, or on the third business day after the mailing thereof, except that notice of change of address shall be effective only upon receipt.


17.	NONEXCLUSIVITY OF RIGHTS.

accordance with such plan or program, except as explicitly modified by this Agreement; provided, however, and notwithstanding anything contained in this Agreement, in the event that Employee is not a participant in or eligible to participate in any Welfare Benefits or the Pension Plan, then nothing contained in this Agreement shall be deemed to provide for or suggest the right in Employee to be a participant in or be eligible to participate in the Welfare Benefits or the Pension Plan.


18.	MISCELLANEOUS.


19.	GOVERNING LAW.

This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of South Dakota.


20.	SEVERABILITY.

The provisions of this Agreement shall be deemed severable and the invalidity or unenforceability of any provision shall not affect the validity or enforceability of the other provisions hereof.


21.	NO GUARANTEED EMPLOYMENT.


22.	SUBSIDIARY DEEMED TO BE COMPANY FOR PORTIONS OF AGREEMENT.


23.	ENTIRE AGREEMENT.

Dated this 15^th day of November, 2019.

BLACK HILLS CORPORATION

By:

Linden R. Evans

President and Chief Executive Officer

EMPLOYEE

EXHIBIT A

WAIVER AND RELEASE AGREEMENT

This Waiver and Release Agreement (the “Waiver and Release”) is entered into by and among Black Hills Corporation (“Company”) and ____________________(“Employee”) this ____ day of ____________________, 20___,

1.General Waiver and Release. For and in consideration of the agreement of Company to provide Employee the severance benefits described in that certain Change in Control Agreement, dated as of ______________________, 20___, between Employee and the Company (the “Agreement”), Employee, with the intention of binding himself and all of Employee’s heirs, executors, administrators and assigns, does hereby release, remise, acquit and forever discharge the Company, Successor Employer, their parents, affiliates, subsidiaries, predecessors, divisions, and successors, and all of their respective past and present officers, directors, stockholders, employees, agents, insurers, employee benefit plans and fiduciaries of such plans, assigns and attorneys (hereinafter collectively referred to as “Released Parties”) from any and all claims, charges, actions, causes of action, sums of money due, suites, debts, covenants, contracts, agreements, rights, damages, promises, demands or liabilities (hereinafter collectively referred to as “Claims”) whatsoever, in law or in equity, whether known or unknown, suspected or unsuspected, which Employee, individually or as a member of any class, now has, owns or holds or has at any time heretofore ever had, owned or held against the Released Parties, including but not limited to all Claims which arise out of or are in any way connected with Employee’s employment with the Company or any of the Released Parties or the termination of any such employment relationship, including, but not by way of limitation, Claims pursuant to federal, state or local statute, regulation, ordinance or common-law for (i) employment discrimination; (ii) wrongful discharge; (iii) breach of contract; (iv) tort actions of any type, including those for intentional or negligent infliction of emotional harm; and (v) unpaid benefits, wages, compensation, commissions, bonuses or incentive payments of any type, except as follows:


a.	Those obligations of the Company and its Affiliates to pay benefits upon termination of employment as set forth in the Agreement, pursuant to which this Waiver and Release is being executed and delivered;


c.	Any rights to indemnification or advancement of expenses to which Employee may otherwise be entitled pursuant to the Articles of Incorporation or Bylaws of any of the Released Parties, or by contract or applicable law, as a result of Employee’s service as an officer or director of any of the Released Parties.

employment by the Company or any of its affiliated companies and which shall not be or become public knowledge. Employee agrees after termination of the Employee’s employment with the Company, the Employee shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any such information, knowledge or data to anyone other than the Company and those designated by it.

6.Non-Competition. Employee agrees that for a period of one (1) year following the Termination Date, Employee shall not, without the written express consent of the Company, directly or indirectly, alone or as a partner, owner, officer, director, employee, or consultant of any other firm, business or entity, engage in any activity in competition with the Company; provided, however, that the foregoing shall not be construed to preclude the Employee from making any investments in any securities to the extent such securities are traded on a national exchange or over-the-counter market and such investment does not exceed five percent (5%) of the issued and outstanding voting securities of such issuer.

13.Acknowledgement. Employee acknowledges that Employee has carefully read and fully

understands the terms of this Waiver and Release and the Agreement and that this Waiver and Release is executed by Employee voluntarily and is not based upon any representations or statements of any kind made by the Company or any of the other Released Parties. Employee further acknowledges that Employee has had a full and reasonable opportunity to consider this waiver Release and that Employee has not been pressured or in any way coerced into executing this Waiver and Release.

14.Choice of Laws. This Waiver and Release and the rights and obligation so the parties hereto shall be governed and construed in accordance with the laws of the State of South Dakota.

16.Defined Terms. Capitalized terms that are not defined in this Waiver and Release shall have the meanings set forth in the Agreement.

Please read this document carefully, as it includes a release of claims.

IN WITNESS WHEREOF, the undersigned acknowledges that Employee has read this Waiver and Release Agreement and sets Employee’s hand and seal this ____ day of _______________, 20--___.

EMPLOYEE

________________________________

BLACK HILLS CORPORATION

By: ___________________________

Title: ___________________________

Exhibit

EQUITY DISTRIBUTION SALES AGREEMENT AMENDMENT

This Equity Distribution Sales Agreement Amendment (the "Amendment") is entered into as of October 3, 2019, among Black Hills Corporation, a South Dakota corporation (the "Company") and MUF'G Securities Americas Inc., BofA Securities, Inc. (formerly known as Merrill Lynch, Pierce, Fenner & Smith Incorporated) and Morgan Stanley & Co. LLC, as sales agent and/or principal (each, an "Agent"). Capitalized terms used herein and not defined herein shall have the meanings assigned to them in the Amended and Restated Equity Distribution Sales

Agreement among the Company and the Agents, dated August 4, 2017 (the "Agreement").

WHEREAS, each of the parties hereto wishes to amend the Agreement in the manner set

forth below;

NOW, THEREFORE, the parties hereby agree as follows:


1.	The following text shall be added in its entirety to the Agreement.

Section 18. Recognition of the U.S. Special Resolution Regimes

(a) In the event that any Agent that is a Covered Entity becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer from such Agent of this Agreement, and any interest and obligation in or under this Agreement, will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if this Agreement, and any such interest and obligation, were governed by the laws of the United States or a state of the United States.

(b) In the event that any Agent that is a Covered Entity or a BHC Act Affiliate of such Agent becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under this Agreement that may be exercised against such Agent are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if this Agreement were governed by the laws of the United States or a state of the United States.

(i) "BHC Act Affiliate" has the meaning assigned to the term "affiliate" in, and shall be interpreted in accordance with, 12 U.S.C. $ 1841(k);

(ii) "Covered Entity" means any of the following: (i) a "covered entity" as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b); (ii) "Covered bank" as that term is defined in, and interpreted in accordance with,12 C.F.R. § 47.3(b); or (iii) a "covered FSI" as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b);

(iii) "Default Right' has the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.

(iv) "U.S. Special Resolution Regime" means each of (i) the Federal Deposit Insurance Act and the regulations promulgated thereunder and (ii) Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act and the regulations promulgated thereunder.


2.	On and after the date hereof, each reference in the Agreement to "this Agreement," "hereunder," 'hereof' or words of like import referring to the Agreement shall mean and be a reference to the Agreement, as amended by this Amendment.


3.	The Agreement, as specifically amended by this Amendment, is and shall continue to be in full force and effect and is hereby in all respects ratified and confirmed.


4.	This Amendment and any claim, controversy or dispute arising under or related to this Amendment shall be governed by, and construed in accordance with, the laws of the state of New York, without regard to its choice of law provisions.


5.	This Amendment may be executed in any number of counterparts, each of which shall be deemed to be an original, but all such counterparts shall together constitute one and the same instrument.


6.	No amendment or waiver of any provision of this Amendment, nor any consent or approval to any departure therefrom, shall in any event be effective unless the same shall be in writing and signed by the parties hereto.

[Remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties have duly executed this Amendment as of the date first written

above.

Very truly yours,

BLACK HILLS CORPORATION

By: /s/ Richard Kinzley

Name: Richard Kinzley

Title: Senior Vice President and Chief Financial Officer

Exhibit

Exhibit 21

BLACK HILLS CORPORATION SUBSIDIARIES

December 31, 2019



	Subsidiary Name	State of Origin
1.	Black Hills Colorado Electric, LLC *	Delaware
2.	Black Hills Colorado Gas, Inc. *	Colorado
3.	Black Hills Colorado IPP, LLC *	South Dakota
4.	Black Hills Colorado Wind, LLC	Delaware
5.	Black Hills Electric Generation, LLC *	South Dakota
6.	Black Hills Energy Arkansas, Inc. *	Arkansas
7.	Black Hills Energy Services Company *	Colorado
8.	Black Hills Exploration and Production, Inc. *	Wyoming
9.	Black Hills Gas, Inc.	Delaware
10.	Black Hills Gas, LLC	Delaware
11.	Black Hills Gas Distribution, LLC	Delaware
12.	Black Hills Gas Holdings, LLC	Delaware
13.	Black Hills Gas Parent Holdings II, Inc.	Delaware
14.	Black Hills Gas Resources, Inc. *	Colorado
15.	Black Hills/Iowa Gas Utility Company, LLC *	Delaware
16.	Black Hills/Kansas Gas Utility Company, LLC *	Kansas
17.	Black Hills/Nebraska Gas Utility Company, LLC *	Delaware
18.	Black Hills Non-regulated Holdings, LLC	South Dakota
19.	Black Hills Plateau Production, LLC *	Delaware
20.	Black Hills Power, Inc. *	South Dakota
21.	Black Hills Service Company, LLC *	South Dakota
22.	Black Hills Shoshone Pipeline, LLC *	Wyoming
23.	Black Hills Utility Holdings, Inc. *	South Dakota
24.	Black Hills Wyoming, LLC	Wyoming
25.	Black Hills Wyoming Gas, LLC *	Wyoming
26.	Cheyenne Light, Fuel and Power Company *	Wyoming
27.	Mallon Oil Company, Sucursal Costa Rica	Costa Rica
28.	N780BH, LLC	South Dakota
29.	Northern Iowa Windpower, LLC	Delaware
30.	Rocky Mountain Natural Gas LLC *	Colorado
31.	Wyodak Resources Development Corp. *	Delaware

* doing business as Black Hills Energy

Exhibit

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-219704 and 333-219705 on Form S-3 and Registration Statement Nos. 333-170451, 333-217679, 333-170448, 333-170452, and 333-203714 on Form S-8 of our reports dated February 14, 2020, relating to the consolidated financial statements and financial statement schedule of Black Hills Corporation and subsidiaries (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Black Hills Corporation for the year ended December 31, 2019.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 14, 2020

Exhibit

Exhibit 31.1

CERTIFICATION

I, Linden R. Evans, certify that:



1.	I have reviewed this Annual Report on Form 10-K of Black Hills Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	February 14, 2020
		/S/ LINDEN R. EVANS
		Linden R. Evans
		President and Chief Executive Officer

Exhibit

Exhibit 31.2

CERTIFICATION

I, Richard W. Kinzley, certify that:



1.	I have reviewed this Annual Report on Form 10-K of Black Hills Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	February 14, 2020
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

Exhibit

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Black Hills Corporation (the “Company”) on Form 10-K for the year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Linden R. Evans, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:



	(1)	The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	February 14, 2020

		/S/ LINDEN R. EVANS
		Linden R. Evans
		President and Chief Executive Officer

Exhibit

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Black Hills Corporation (the “Company”) on Form 10-K for the year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard W. Kinzley, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:



	(1)	The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and

	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	February 14, 2020

		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

Exhibit

Exhibit 95

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included below.

Mine Safety and Health Administration Safety Data

Safety is a core value at Black Hills Corporation and at each of its subsidiary operations. We have in place a comprehensive safety program that includes extensive health and safety training for all employees, site inspections, emergency response preparedness, crisis communications training, incident investigation, regulatory compliance training and process auditing, as well as an open dialogue between all levels of employees. The goals of our processes are to eliminate exposure to hazards in the workplace, ensure that we comply with all mine safety regulations, and support regulatory and industry efforts to improve the health and safety of our employees along with the industry as a whole.

Under the Dodd-Frank Act, each operator of a coal or other mine is required to include certain mine safety results in its periodic reports filed with the SEC. Our mining operation, consisting of Wyodak Coal Mine, is subject to regulation by the federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). Below we present the following information regarding certain mining safety and health matters for the twelve month period ended December 31, 2019. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed. The information presented includes:


•	Total number of violations of mandatory health and safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;


•	Total number of orders issued under section 104(b) of the Mine Act;


•	Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health and safety standards under section 104(d) of the Mine Act;


•	Total number of imminent danger orders issued under section 107(a) of the Mine Act; and


•	Total dollar value of proposed assessments from MSHA under the Mine Act.

The table below sets forth the total number of citations and/or orders issued by MSHA to WRDC under the indicated provisions of the Mine Act, together with the total dollar value of proposed MSHA assessments received during the twelve months ended December 31, 2019 and legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for WRDC, our only mining complex. All citations were abated within 24 hours of issue.

Mine/MSHA Identification

Mine Act Section 104 S&S Citations issued during twelve months ended

Mine Act Section 104(b)

Mine Act Section 104(d) Citations and

Mine Act Section 110(b)(2)

Mine Act Section 107(a) Imminent Danger

Total Dollar Value of Proposed MSHA

Total Number of Mining Related

Received Notice of Potential to Have Pattern Under Section

Legal Actions Pending as of Last Day of

Legal Actions Initiated During

Legal Actions Resolved During

Number

December 31

Orders

Violations

Orders

Assessments

Fatalities

104(e)

Period

2019

(#)

(a)

(#)

(yes/no)

(#)

Wyodak Coal Mine - 4800083

—

1,371

—

________________________


(a)	The types of proceedings by class: (1) Contests of citations and orders – none; (2) contests of proposed penalties – none; (3) complaints for compensation – none; (4) complaints of discharge, discrimination or interference under Section 105 of the Mine Act – none; (5) applications for temporary relief – none; and (6) appeals of judges’ decisions or orders to the FMSHRC – none.