Edgar Filing: BLACK HILLS CORP /SD/

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K



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

For the fiscal year ended December 31, 2018



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

For the transition period from ___________________ to __________________

Commission File Number 001-31303

BLACK HILLS CORPORATION



Incorporated in South Dakota	7001 Mount Rushmore Road	IRS Identification Number
	Rapid City, South Dakota 57702	46-0458824
Registrant’s telephone number, including area code (605) 721-1700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common stock of $1.00 par value		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 x No o

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 o No x

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

Yes x No o

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 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 x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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



	Large accelerated filer x		Accelerated filer o

	Non-accelerated filer o		Smaller reporting company o

			Emerging growth company o

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.

At June 30, 2018 $3,239,030,444

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, 2019
Common stock, $1.00 par value	60,003,965	shares

Documents Incorporated by Reference

Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2019 Annual Meeting of Stockholders to be held on April 30, 2019, 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

	ITEM 1A.	RISK FACTORS	32

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	42

	ITEM 3.	LEGAL PROCEEDINGS	42

	ITEM 4.	MINE SAFETY DISCLOSURES	42
Part II
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	43

	ITEM 6.	SELECTED FINANCIAL DATA	44

	ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	46

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	85

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	161

	ITEM 9A.	CONTROLS AND PROCEDURES	161

	ITEM 9B.	OTHER INFORMATION	161
Part III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	162

	ITEM 11.	EXECUTIVE COMPENSATION	162

	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	163

	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	163

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	163

Part IV

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	164

	ITEM 16.	FORM 10-K SUMMARY	167

		SIGNATURES	168

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
AltaGas	AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCI	Accumulated Other Comprehensive Income
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
APSC	Arkansas Public Service Commission
Arkansas Gas	Includes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations (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
Basin Electric	Basin Electric Power Cooperative
Bbl	Barrel
Bcf	Billion cubic feet
BHC	Black Hills Corporation; the Company
BHEP	Black Hills Exploration and Production, Inc., our previous Oil and Gas segment. As of December 31, 2018, we have completed the exit of the Oil and Gas business.
BHSC	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Colorado IPP	Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Gas	Black Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC.
Black Hills Gas Holdings	Black Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility companies
Black Hills Energy Colorado Electric	Includes Colorado Electric’s utility operations
Black Hills Energy Colorado Gas	Includes Black Hills Energy Colorado Gas utility operations, as well as RMNG
Black Hills Energy Iowa Gas	Includes Black Hills Energy Iowa gas utility operations
Black Hills Energy Kansas Gas	Includes Black Hills Energy Kansas gas utility operations
Black Hills Energy Nebraska Gas	Includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations
Black Hills Energy Services	A Choice Gas supplier acquired in the SourceGas Acquisition
Black Hills Energy South Dakota Electric	Includes Black Hills Power’s operations in South Dakota, Wyoming and Montana
Black Hills Energy Wyoming Electric	Includes Cheyenne Light’s electric utility operations
Black Hills Energy Wyoming Gas	Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Black Hills Gas Distribution	Black Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC.
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
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	Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm.
Busch Ranch II	Busch Ranch II wind project is under construction as a 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement.
Ceiling Test	Related to our Oil and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.
CAPP	Customer Appliance Protection Plan - acquired in the SourceGas Acquisition
CFTC	United States Commodity Futures Trading Commission
CG&A	Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural-gas fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
Choice Gas Program	The unbundling of the natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution distributes the gas and Black Hills Energy Services is one of the Choice Gas suppliers.
City of Gillette	Gillette, Wyoming
Colorado Electric	Black Hills Colorado Electric, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Gas	Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Interstate Gas (CIG)	Colorado Interstate Natural Gas Pricing Index
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 Credit Agreement.
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
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.
CVA	Credit Valuation Adjustment
DART	Days Away Restricted Transferred (number of cases with days away from work or job transfer or restrictions multiplied by 200,000 then divided by total hours worked for all employees during the year covered)
DC	Direct current
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	Electricity purchased by one utility from another utility to take the place of electricity that would have cost more to produce on the utility’s own system
EIA	Environmental Improvement Adjustment
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.
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
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 dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Happy Jack	Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
IPP	Independent power producer
IPP Transaction	The July 11, 2008 sale of seven of our IPP plants
IRS	United States Internal Revenue Service
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Loveland Area Project	Part of the Western Area Power Association transmission system
MAPP	Mid-Continent Area Power Pool
MATS	Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
Mbbl	Thousand barrels of oil
Mcf	Thousand cubic feet
Mcfd	Thousand cubic feet per day
Mcfe	Thousand cubic feet equivalent
MDU	Montana Dakota Utilities Co., a regulated utility division of MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
MGP	Manufactured Gas Plant
MMBtu	Million British thermal units
MMcf	Million cubic feet
MMcfe	Million cubic feet equivalent



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 Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
NERC	North American Electric Reliability Corporation
NGL	Natural Gas Liquids (1 barrel equals 6 Mcfe)
NOAA	National Oceanic and Atmospheric Administration
NOAA Climate Normals	This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NO_x	Nitrogen oxide
NOL	Net operating loss
NPSC	Nebraska Public Service Commission
NWPL	Northwest Interstate Natural Gas Pricing Index
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OSHA	Occupational Safety & Health Administration
OSM	U.S. Department of the Interior’s Office of Surface Mining
PCA	Power Cost Adjustment
PCCA	Power Capacity Cost Adjustment
Peak View	60 MW wind generating project owned by Colorado Electric, placed in service on November 7, 2016 and adjacent to Busch Ranch I Wind Farm
PPA	Power Purchase Agreement
PSCo	Public Service Company of Colorado
PUHCA 2005	Public Utility Holding Company Act of 2005
REPA	Renewable Energy Purchase Agreement
Revolving Credit Facility	Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2023
RMNG	Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas Distribution in western Colorado (doing business as Black Hills Energy)
RSNs	Remarketable junior subordinated notes, issued on November 23, 2015
SAIDI	System Average Interruption Duration Index
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Service Guard	Home appliance repair product offering for both natural gas and electric
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	SourceGas Holdings, LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas Acquisition	The acquisition of SourceGas Holdings LLC by Black Hills Utility Holdings



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	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
SSIR	System Safety and Integrity Rider
System Peak Demand	Represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.
TCA	Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017
TCIR	Total Case Incident Rate (average number of work-related injuries incurred by 100 workers during a one-year period)
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
VEBA	Voluntary Employee Benefit Association
VIE	Variable Interest Entity
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
Winter Storm Atlas	An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	Includes Cheyenne Light’s electric utility operations
Wyoming Gas	Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations

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, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

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 Wyodak coal 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 212,000 electric customers in Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 939 MW of generation and 8,858 miles of electric transmission and distribution lines.

Our Gas Utilities segment serves approximately 1,054,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate approximately 4,700 miles of intrastate gas transmission pipelines and 41,158 miles of gas distribution mains and service lines, seven natural gas storage sites, over 45,000 horsepower of compression and nearly 600 miles of gathering lines.

Our Power Generation segment produces electric power from its wind, natural gas and coal 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 the coal primarily under long-term contracts to mine-mouth electric generation facilities owned by our Electric Utilities and Power Generation businesses.

Electric Utilities Segment

We conduct electric utility operations through our South Dakota, Wyoming and Colorado subsidiaries. Our Electric Utilities generate, transmit and distribute electricity to approximately 212,000 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services through our Tech Services product lines.

Capacity and Demand. System peak demands for the Electric Utilities for each of the last three years are listed below:



	System Peak Demand (in MW)
	2018		2017		2016
	Summer	Winter	Summer	Winter	Summer	Winter
South Dakota Electric	437	379	447	402	438	389
Wyoming Electric ^(a)	254	238	249	230	236	230
Colorado Electric ^(b)	413	313	398	299	412	302
Total Electric Utilities’ Peak Demands	1,104	930	1,094	931	1,086	921

________________________


(a)	The July 2018 summer peak load of 254 surpassed previous summer peak record load of 249 set in July 2017. The December 2018 winter peak load of 238 surpassed the previous winter peak record load of 230 set in December 2016.


(b)	The July 2018 summer peak load of 413 surpassed previous summer peak record load of 412 set in July 2016. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011.

Regulated Power Plants. As of December 31, 2018, our Electric Utilities’ ownership interests in electric generating plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
South Dakota Electric:
Cheyenne Prairie ^(a)	Gas	Cheyenne, Wyoming	58%	55.0	2014
Wygen III^(b)	Coal	Gillette, Wyoming	52%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyoming	100%	90.0	1995
Wyodak ^(c)	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 ^(a)	Gas	Cheyenne, Wyoming	42%	40.0	2014
Cheyenne Prairie CT ^(a)	Gas	Cheyenne, Wyoming	100%	37.0	2014
Wygen II	Coal	Gillette, Wyoming	100%	95.0	2008
Colorado Electric ^(e):
Busch Ranch I Wind Farm^(d)	Wind	Pueblo, Colorado	50%	14.5	2012
Peak View Wind Farm	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
Total MW Capacity				939.1

________________________


(a)	Cheyenne Prairie, a 132 MW natural gas-fired power generation facility supports 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).


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


(c)	Wyodak, 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 coal mine supplies all of the fuel for the plant.

(d)

Busch Ranch I Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and Black Hills Electric Generation owns the remaining 50%. Black Hills Electric Generation purchased the remaining 50% from AltaGas on December 11, 2018. Colorado Electric has a PPA with Black Hills Electric Generation for its 14.5 MW of power from the wind farm. The terms of the PPA are the same as the previous PPA with AltaGas.


(e)	On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation for the 60 MW Busch Ranch II wind project. The project is currently under construction and is expected to be in service by the end of 2019.

The Electric Utilities’ annual 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)	2018		2017		2016
Coal	$	11.10	$	10.95	$	11.27

Natural Gas	$	33.42	$	34.05	$	30.59

Diesel Oil ^(a)	$	329.27	$	210.11	$	149.13

Total Average Fuel Cost	$	13.53	$	12.80	$	12.99

Purchased Power - Coal, Gas and Oil	$	45.62	$	45.63	$	48.36

Purchased Power - Renewable Sources	$	54.31	$	53.08	$	51.95

______________


(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	2018		2017		2016
Coal	32	%	32	%	33	%
Gas, Oil and Wind	10		8		7
Total Generated	42		40		40
Purchased ^(a)	58		60		60
Total	100	%	100	%	100	%

______________


(a)	Wind represents approximately 6%, 6% and 7% of our purchased power in 2018, 2017, and 2016, respectively.

Purchased Power. We have executed various agreements to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Key contracts include:


•	South Dakota Electric’s PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase of 50 MW of coal-fired baseload power;


•	Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, which provides 200 MW of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is reported and accounted for as a capital lease within our business segments and is eliminated on the accompanying Consolidated Financial Statements;


•	Colorado Electric’s PPA with Black Hills Electric Generation, which provides up to 14.5 MW of wind energy from Black Hills Electric Generation’s owned interest in the Busch Ranch I Wind Farm. This PPA is the same as the previous agreement with AltaGas, which expires on October 16, 2037;

•

Wyoming Electric’s PPA with Black Hills Wyoming expiring on December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019. On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019.

The purchase price related to the option is $2.1 million per MW (65 MWs), adjusted for all depreciated capital additions since 2009, and reduced by depreciation (approximately $5 million per year) over a 35-year life beginning January 1, 2009. The net book value of Wygen I at December 31, 2018 was $75 million and if Wyoming Electric had exercised the purchase option at year-end 2018, the estimated purchase price would have been approximately $139 million;


•	Wyoming Electric’s 20-year PPA with Duke Energy expiring on September 3, 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility’s output to South Dakota Electric;


•	Wyoming Electric’s 20-year PPA with Duke Energy expiring on September 30, 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of the facility’s output to South Dakota Electric;


•	Wyoming Electric and South Dakota Electric’s Generation Dispatch Agreement requires South Dakota Electric to purchase all of Wyoming Electric’s excess energy; and


•	South Dakota Electric’s PPA with Platte River Power Authority to purchase up to 12 MW of wind energy through Platte River Power Authority’s agreement with Silver Sage. This agreement will expire September 30, 2029.

Power Sales Agreements. Our Electric Utilities have various long-term power sales agreements. Key agreements include:


•	MDU owns a 25% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from its other generation facilities or from system purchases with reimbursement of costs by MDU;


•	South Dakota Electric has an agreement through December 31, 2023 to provide MDU capacity and energy up to a maximum of 50 MW;

•

The City of Gillette owns a 23% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from its other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, South Dakota Electric will also provide the City of Gillette its operating component of spinning reserves;


•	South Dakota Electric has an agreement through December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals; and

•

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 in 2028. The terms of the contract run 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:



2019-2020	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2022	15 MW - 7 MW contingent on Wygen III and 8 MW contingent on Neil Simpson II
2022-2023	15 MW - 8 MW contingent on Wygen III and 7 MW contingent on Neil Simpson II
2023-2028	10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Transmission and Distribution. Through our Electric Utilities, we own electric transmission systems composed of high voltage transmission lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly own high voltage lines with Basin Electric and Powder River Energy Corporation.

At December 31, 2018, our Electric Utilities owned the electric transmission and distribution lines shown below:



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
South Dakota Electric	South Dakota, Wyoming	1,231	2,539
South Dakota Electric - Jointly Owned ^(a)	South Dakota, Wyoming	44	—
Wyoming Electric	Wyoming	49	1,291
Colorado Electric	Colorado	598	3,106

__________________________

(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 United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the SPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. South Dakota Electric’s electric system is located in the WECC region. 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.

South Dakota Electric has firm point-to-point transmission access to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the WECC region through December 31, 2023.

South Dakota Electric also 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.

In order to serve Wyoming Electric’s existing load, Wyoming Electric has a network transmission agreement with Western Area Power Association’s Loveland Area Project.

Colorado Electric is party to a joint dispatch agreement with PSCo and Platte River Power Authority. 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.

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 charges for the use of assets 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 Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.


•	Jointly Owned Facilities -


◦	South Dakota Electric, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby South Dakota Electric charges the City of Gillette and MDU for administrative services, plant operations and maintenance for its share of the Wygen III generating facility for the life of the plant.


◦	Colorado Electric and Black Hills Electric Generation are parties to a shared joint ownership agreement whereby Colorado Electric charges Black Hills Electric Generation for operations and maintenance for its share of the Busch Ranch I Wind Farm.

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. Because our Electric Utilities have a diverse customer and revenue base, and we have historically optimized the utilization of our electric power supply resources, the impact on our operations may not be as significant when weather conditions are warmer in the winter and cooler in the summer.

Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas. Various 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. The 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, the rates of other utilities, 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

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, TCA, Energy Efficiency Cost Recovery/DSM	70%
	SD		7.76%			5/2014	Transmission Facility Adjustment (TFA) Tariff	N/A
	SD		7.76%			6/2011	Environmental Improvement Adjustment (EIA) Tariff	N/A
	FERC	10.8%	8.76%	43%/57%		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
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

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. Some states in which our utilities operate also allow the utility operating in that state to automatically adjust rates periodically for the cost of new transmission or environmental improvements and, in some instances, the utility has the opportunity to earn its authorized return on new capital investment immediately.

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

South Dakota Electric has:

•

An approved annual Environmental Improvement Adjustment (EIA) tariff which recovers costs associated with generation plant environmental improvements. South Dakota Electric also has a Transmission Facility Adjustment (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. See Note 13 in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

•

An annual adjustment clause which provides for the over or under recovery of fuel 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%. During the six-year moratorium period effective July 1, 2017, 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.

In Wyoming, Wyoming Electric has:


•	An annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power 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.


•	An approved FERC Transmission Tariff that determines the revenue component of Wyoming Electric’s open access transmission tariff.

In Colorado, 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.

Tariff Filings

On December 17, 2018, South Dakota Electric and Wyoming Electric filed for approval of new, voluntary renewable energy tariffs to serve customer requests for renewable energy resources. Requests to approve the voluntary tariffs, known as Renewable Ready Service Tariffs, were submitted to the SDPUC and WPSC. The renewable ready tariffs would provide large commercial and industrial customers and governmental agencies an option to purchase utility-scale renewable energy. As proposed, customers would be able to enter into contracts with Black Hills Energy to purchase renewable energy for periods of five to 25 years.

On September 28, 2018, Wyoming Electric filed for approval of a new innovative tariff to serve blockchain business customers in Wyoming. Request to approve the blockchain tariff, known as Blockchain Interruptible Service (“BCIS”) tariff, was submitted to the WPSC. The BCIS tariff, as proposed, was designed in response to blockchain business recruiting initiatives of the state of Wyoming and would provide the opportunity for Wyoming Electric to attract blockchain business and continue to provide safe and reliable service without negatively impacting existing customers.

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

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



Degree Days	2018		2017		2016
	Actual	Variance from 30-Year Average ^(b)	Actual	Variance from 30-Year Average ^(b)	Actual	Variance from 30-Year Average ^(b)
Heating Degree Days:
South Dakota Electric	7,749	8%	6,870	(4)%	6,402	(10)%
Wyoming Electric	7,036	(7)%	6,623	(12)%	6,363	(14)%
Colorado Electric	5,119	4%	4,693	(16)%	4,658	(16)%
Combined ^(a)	6,405	3%	5,826	(11)%	5,595	(13)%

Cooling Degree Days:
South Dakota Electric	488	(23)%	709	11%	646	(4)%
Wyoming Electric	430	24%	429	23%	460	31%
Colorado Electric	1,420	58%	1,027	14%	1,358	42%
Combined ^(a)	902	29%	798	14%	935	26%

________________


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


(b)	30-Year Average is from NOAA Climate Normals.



	Electric Revenue (in thousands)						Quantities Sold (MWh)
	2018		2017		2016		2018	2017	2016
Residential	$	218,558	$	210,172	$	208,725	1,450,585	1,390,952	1,395,097
Commercial	250,894		258,754		258,768		2,034,917	2,038,495	2,067,486
Industrial	124,668		122,958		118,181		1,682,074	1,598,755	1,515,553
Municipal	17,871		18,144		17,821		160,913	160,882	162,383
Subtotal Retail Revenue - Electric	611,991		610,028		603,495		5,328,489	5,189,084	5,140,519
Contract Wholesale	33,688		30,435		17,037		900,854	722,659	246,630
Off-system/Power Marketing Wholesale	24,800		21,111		22,355		673,994	661,263	769,843
Other ^(a)	40,972		43,076		34,394		—	—	—
Total Revenue and Energy Sold	711,451		704,650		677,281		6,903,337	6,573,006	6,156,992
Other Uses, Losses or Generation, net	—		—		—		470,250	468,179	433,400
Total Revenue and Energy	711,451		704,650		677,281		7,373,587	7,041,185	6,590,392
Less cost of fuel and purchased power	277,093		268,405		261,349
Gross Margin ^(b)	$	434,358	$	436,245	$	415,932

__________


(a)	Other revenue in 2018 reflects the impact of revenue reserved in accordance with the TCJA.


(b)	Non-GAAP measure.



	Electric Revenue (in thousands)						Gross Margin ^(a) (in thousands)						Quantities Sold (MWh) ^(b)
	2018		2017		2016		2018		2017		2016		2018	2017	2016
South Dakota Electric	$	298,080	$	288,433	$	267,632	$	205,194	$	200,795	$	192,606	3,360,396	3,187,392	2,767,315
Wyoming Electric	162,153		165,127		157,606		83,516		89,371		85,036		1,861,273	1,762,117	1,677,421
Colorado Electric	251,218		251,090		252,043		145,648		146,079		138,290		2,151,918	2,091,676	2,145,656
Total Revenue, Gross Margin, and Quantities Sold	$	711,451	$	704,650	$	677,281	$	434,358	$	436,245	$	415,932	7,373,587	7,041,185	6,590,392

________________


(a)	Non-GAAP measure.


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



Quantities Generated and Purchased (MWh)	2018	2017	2016

Coal-fired	2,368,506	2,230,617	2,201,757
Natural Gas and Oil	446,373	307,815	343,001
Wind	253,180	239,472	80,582
Total Generated	3,068,059	2,777,904	2,625,340
Purchased	4,305,528	4,263,281	3,965,052
Total Generated and Purchased	7,373,587	7,041,185	6,590,392



Quantities Generated and Purchased (MWh)	2018	2017	2016
Generated:
South Dakota Electric	1,734,222	1,581,915	1,585,870
Wyoming Electric	852,391	798,024	805,351
Colorado Electric	481,446	397,965	234,119
Total Generated	3,068,059	2,777,904	2,625,340
Purchased:
South Dakota Electric	1,626,174	1,605,477	1,181,445
Wyoming Electric	1,008,882	964,093	872,070
Colorado Electric	1,670,472	1,693,711	1,911,537
Total Purchased	4,305,528	4,263,281	3,965,052

Total Generated and Purchased	7,373,587	7,041,185	6,590,392



Customers at End of Year	2018	2017	2016
Residential	181,459	179,911	178,333
Commercial	29,299	29,354	29,086
Industrial	84	86	88
Other	1,030	914	1,001
Total Electric Customers at End of Year	211,872	210,265	208,508



Customers at End of Year	2018	2017	2016
South Dakota Electric	72,533	72,184	71,353
Wyoming Electric	42,694	42,130	41,531
Colorado Electric	96,645	95,951	95,624
Total Electric Customers at End of Year	211,872	210,265	208,508

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 1,054,000 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 through Black Hills Energy Services. Black Hills Energy Services has approximately 47,000 retail distribution customers in Nebraska and Wyoming providing unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, install and service air, heating and water-heating equipment, and provide associated repair service and appliance protection plans under various trade names. Service Guard and CAPP provide appliance repair services to approximately 62,000 and 28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

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 with Colorado Interstate Gas Company, Enable Gas Transmission, Tallgrass Interstate Gas Transmission, Natural Gas Pipeline Company of America, Northern Natural Gas, Panhandle Eastern Pipeline Company, Southern Star Central Gas Pipeline, Black Hills Shoshone Pipeline, TransColorado Gas Transmission, WBI Energy Transmission, Rocky Mountain Natural Gas, Ozark Gas Transmission, Liberty Utilities, Texas Eastern Transmission Pipeline, WestGas InterState Pipeline, Public Service Company of Colorado and Red Cedar Gas Gathering.

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, 2018:



State	Working Capacity (Mcf)	Cushion Gas (Mcf) ^(a)	Total Capacity (Mcf)	Maximum Daily Withdrawal Capability (Mcfd)
State	Working Capacity (Mcf)	Cushion Gas (Mcf) ^(a)	Total Capacity (Mcf)	Maximum Daily Withdrawal Capability (Mcfd)
Arkansas	8,442,700	12,950,000	21,392,700	196,000
Colorado	2,360,895	6,165,315	8,526,210	30,000
Wyoming	5,733,900	17,145,600	22,879,500	32,950
Total	16,537,495	36,260,915	52,798,410	258,950

________________


(a)	Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.

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, 2018	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
Arkansas	932	4,803	1,122
Colorado	689	6,699	2,457
Nebraska	1,263	8,539	3,203
Iowa	164	2,791	2,667
Kansas	325	2,868	1,347
Wyoming	1,327	3,447	1,215
Total	4,700	29,147	12,011



Degree Days	2018		2017		2016
	Actual	Variance From 30-Year Average ^(c)	Actual	Variance From 30-Year Average ^(c)	Actual	Variance From 30-Year Average ^(c)
Heating Degree Days:
Arkansas ^(a)	4,169	3%	3,295	(19)%	2,397	(41)%
Colorado	6,136	(7)%	5,728	(14)%	5,762	(13)%
Nebraska	6,563	6%	5,554	(10)%	5,457	(12)%
Iowa	7,192	6%	6,149	(9)%	5,997	(11)%
Kansas ^(a)	5,242	7%	4,452	(9)%	4,307	(12)%
Wyoming	7,425	(1)%	7,123	(5)%	6,750	(10)%
Combined^(b)	6,628	2%	5,862	(10)%	5,823	(11)%

________________

(a)

Arkansas Gas has a weather normalization mechanism in effect during the months of November through April for customers with residential and certain business rate schedules. Kansas Gas has a weather normalization mechanism within its residential and business rate structure. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, while Kansas uses multiple locations. The weather normalization mechanisms in both Arkansas and Kansas minimize weather impact on gross margins (a non-GAAP measure).


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


(c)	30-Year Average is from NOAA climate normals.

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 utilities commissions in the states where they operate. The 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, the rates of other utilities, 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.

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 recovery mechanisms, we have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow us to recover certain costs, such as those related to energy efficiency plans 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/Regulatory Mandate and Relocations Rider, 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, 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/DSM/Capital Infrastructure Automatic Adjustment Mechanism, 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
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 (Northwest Wyoming)	WY	9.6%	7.75%	46%/54%	$12.9	9/2018	GCA
Wyoming Gas	WY	9.9%	7.98%	46%/54%	$59.6	10/2014	GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment
Wyoming Gas Dist.	WY	9.92%	7.98%	49.66%/ 50.34%	$100.5	1/2011	Choice Gas Program, Purchased GCA, Usage Per Customer Adjustment

__________


(a)	Arkansas Gas return on rate base adjusted to remove current liabilities from rate case 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 and agricultural customers. Jurisdictional Nebraska rate base of $69.8 million excludes those amounts allocated to serve non-jurisdictional and agricultural customers and is used for calculation of jurisdictional base rates.

All of our Gas Utilities, except where Choice Gas 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	DSM/Energy Efficiency	Integrity Additions	Bad Debt	Weather Normal	Pension Recovery	Gas Cost	Billing Determinant Adjustment	Revenue Decoupling
Arkansas Gas	þ	þ		þ		þ	þ
Colorado Gas	þ					þ
Colorado Gas Dist.	þ					þ
RMNG	N/A	þ	N/A	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 Dist.		þ	þ
Wyoming Gas ^(a)	þ					þ
Wyoming Gas Dist.						þ		þ

__________

(a) DSM/Energy Efficiency is only applicable to Cheyenne Light.

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

Operating Statistics

2016 includes results from the acquired SourceGas utilities starting February 12, 2016.



	Revenue (in thousands)							Gross Margin ^(a)(in thousands)							Quantities Sold and Transported (Dth)
	2018			2017		2016		2018			2017		2016		2018	2017	2016

Residential	$	567,785		$	499,852	$	433,106	$	276,858		$	255,626	$	228,512	65,352,164	54,645,598	49,390,451
Commercial	214,718			197,054		162,547		82,529			78,249		67,375		30,753,361	27,315,871	24,037,861
Industrial	26,466			24,454		21,245		7,056			6,226		5,601		6,309,211	5,855,053	5,737,430
Other ^(b)	(7,899		)	8,647		12,694		(7,899		)	8,647		12,694		—	—	—
Total Distribution	801,070			730,007		629,592		358,544			348,748		314,182		102,414,736	87,816,522	79,165,742

Transportation and Transmission	141,854			135,824		139,490		141,850			135,824		139,282		148,299,003	141,600,080	126,927,565

Total Regulated	942,924			865,831		769,082		500,394			484,572		453,464		250,713,739	229,416,602	206,093,307

Non-regulated Services	82,383			81,799		69,261		62,760			53,455		32,714		—	—	—

Total Revenue, Gross Margin and Quantities Sold	$	1,025,307		$	947,630	$	838,343	$	563,154		$	538,027	$	486,178	250,713,739	229,416,602	206,093,307

__________


(a)	Non-GAAP measure.


(b)	Other revenue and Gross Margin in 2018 reflects the impact of revenue reserved in accordance with the TCJA.



	Revenue (in thousands)						Gross Margin ^(a)(in thousands)						Quantities Sold & Transported (Dth)
	2018		2017		2016		2018		2017		2016		2018	2017	2016

Arkansas	$	176,660	$	153,691	$	106,958	$	100,917	$	94,007	$	69,840	30,931,390	26,491,537	19,177,438
Colorado	188,002		180,852		153,003		99,851		100,718		86,016		29,857,063	28,436,744	23,656,891
Nebraska	278,969		252,631		244,992		164,513		154,259		146,831		81,658,938	73,890,509	67,796,021
Iowa	161,843		143,446		130,776		68,384		66,619		64,170		40,668,682	37,013,645	35,383,990
Kansas	112,306		105,576		100,670		55,226		53,841		54,247		31,387,672	28,251,947	26,463,314
Wyoming	107,527		111,434		101,944		74,263		68,583		65,074		36,209,994	35,332,220	33,615,653
Total Revenue, Gross Margin and Quantities Sold	$	1,025,307	$	947,630	$	838,343	$	563,154	$	538,027	$	486,178	250,713,739	229,416,602	206,093,307

__________


(a)	Non-GAAP measure.



Customers at End of Year	2018	2017	2016

Residential	821,624	806,744	800,980
Commercial ^(a)	82,498	86,461	84,049
Industrial	2,221	2,214	2,050
Transportation/Other	147,550	146,839	143,673
Total Customers at End of Year	1,053,893	1,042,258	1,030,752

__________


(a)	The decrease is 2018 is due to customer class reclassification to residential at our Colorado Gas utilities.



Customers at End of Year	2018	2017	2016

Arkansas	171,978	169,303	166,512
Colorado	186,759	181,876	177,394
Nebraska	291,723	290,264	289,653
Iowa	158,485	157,444	156,014
Kansas	114,840	114,082	112,957
Wyoming	130,108	129,289	128,222
Total Customers at End of Year	1,053,893	1,042,258	1,030,752

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, 2018, 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 are currently in compliance with these standards.

On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation to purchase 60 MW of wind energy through a 25-year PPA. The Busch Ranch II wind project is currently under construction and is expected to be in service by the end of 2019. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard. This renewable energy project was originally submitted in response to Colorado Electric’s electric resource plan filed June 3, 2016, which also provides for additional small solar and community solar gardens as part of the compliance plan.

On November 7, 2016, Colorado Electric took ownership of Peak View, a $109 million, 60 MW wind project located near Colorado Electric's Busch Ranch I Wind Farm. Peak View achieved commercial operation on November 7, 2016. This renewable energy project was originally submitted in response to Colorado Electric’s all-source generation request on May 5, 2014. The CPUC’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Energy Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which, Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility.

•

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 prudently incorporate renewable energy into our resource supply. Mandatory portfolio standards have increased and would 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. Black Hills Corporation is a holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and holding companies 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.

Our Electric Utilities, Black Hills Colorado IPP and Black Hills Wyoming 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 and operates our non-regulated power plants. As of December 31, 2018, we held varying interests in independent power plants operating in Wyoming and Colorado with a total net ownership of approximately 283 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 substantial majority of our non-regulated generating capacity under contracts having terms greater than one year.

As of December 31, 2018, 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	Coal	Gillette, Wyoming	76.5%	68.9	2003
Pueblo Airport Generation ^(a)	Gas	Pueblo, Colorado	50.1%	200.0	2012
Busch Ranch I	Wind	Pueblo, Colorado	50.0%	14.5	2012
				283.4

_________________________


(a)	Black Hills Colorado IPP owns and operates this facility. This facility provides capacity and energy to Colorado Electric under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital lease on the accompanying Consolidated Financial Statements.

Black Hills Wyoming - Wygen I. 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%. We sell 60 MW of unit-contingent capacity and energy from this plant to Wyoming Electric under a PPA that expires on December 31, 2022. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical to do so. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s

ownership interest in the Wygen I facility through 2019. See the purchased power discussion within the Electric Utilities segment above about Wyoming Electric’s 2018 integrated resource plan which included a recommendation to the WPSC to acquire Wygen I.

Black Hills Colorado IPP - Pueblo Airport Generation. The Pueblo Airport Generating Station consists of two 100 MW combined-cycle gas-fired power generation plants located at a site shared with Colorado Electric. The plants commenced operation on January 1, 2012 and the assets are accounted for as a capital lease under a 20-year PPA with Colorado Electric, which expires on December 31, 2031. Under the PPA with Colorado Electric, any excess capacity and energy shall be for the benefit of Colorado Electric.

Black Hills Electric Generation (BHEG) - Busch Ranch I. On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in the 29 MW Busch Ranch I Wind Farm, previously owned by AltaGas. Black Hills Electric Generation will provide its share of energy from the wind farm to Colorado Electric through a new PPA which has the same terms as the PPA it replaces that Colorado Electric had with AltaGas, expiring in October 2037.

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. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes. The operating results for Black Hills Colorado IPP remain consolidated with Black Hills Electric Generation, as Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest.

The following table summarizes MWh for our Power Generation segment:



Quantities Sold, Generated and Purchased (MWh) ^(a)	2018	2017	2016
Sold
Black Hills Colorado IPP ^(b)	1,000,577	943,618	1,223,949
Black Hills Wyoming ^(c)	582,938	645,810	644,564
Black Hills Electric Generation	5,873	—	—
Total Sold	1,589,388	1,589,428	1,868,513

Generated
Black Hills Colorado IPP ^(b)	1,000,577	943,618	1,223,949
Black Hills Wyoming ^(c)	501,945	577,124	543,546
Black Hills Electric Generation	5,873	—	—
Total Generated	1,508,395	1,520,742	1,767,495

Purchased
Black Hills Wyoming	83,213	69,377	85,993
Total Purchased	83,213	69,377	85,993

____________________


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


(b)	The decrease in 2017 was driven by the joint dispatch agreement Colorado Electric joined in 2017. See details of this agreement above in the Electric Utilities segment.


(c)	The decrease in 2018 was driven by a planned outage at Wygen I.

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


•	Economy Energy PPA and other ancillary agreements

◦

Black Hills Wyoming has ancillary agreements with the City of Gillette, Wyoming to operate CTII, and provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreements include 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.


•	Operating and Maintenance Services Agreement

◦

In conjunction with the sale of the noncontrolling interest on April 14, 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 is in effect from 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.


•	Shared Services Agreements


◦	South Dakota Electric, Wyoming Electric and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges 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 Generating Station.


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


•	Jointly Owned Facilities


◦	Black Hills Wyoming and MEAN are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance on its share of the Wygen I generating facility over the life of the plant.


◦	Black Hills Electric Generation and Colorado Electric both own 50% of the Busch Ranch I Wind Farm. Black Hills Electric Generation purchased its 50% share in Busch Ranch I from AltaGas on December 11, 2018. See details of the PPA and ownership agreement discussed previously in the Electric Utilities segment.

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 three EWGs: Wygen I, 200 MW (two 100 MW combined-cycle gas-fired units) at the

Pueblo Airport Generating Station, and Black Hills Electric Generation’s interest in Busch Ranch I. 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 primarily low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC coal mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin. The Powder River Basin contains one of the largest coal reserves in the United States. We produced approximately 4.1 million tons of coal in 2018.

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, 2018 was 2.20 which increased from the prior year as we continued mining in areas with higher overburden. We expect our stripping ratio to be approximately 2.26 by the end of 2019 as we mine in areas with comparable overburden.

Mining rights to the coal are based on four federal leases and one state lease. The federal leases expire between April 30, 2019 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, 2018, we estimated our recoverable coal reserves to be approximately 189 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 coal reserve life is equal to approximately 46 years at the current production levels. Our recoverable coal reserve estimates are periodically updated to reflect past coal 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 coal reserves include reserves that can be economically and legally extracted at the time of their determination. We use various assumptions in preparing our estimate of recoverable coal reserves. See Risk Factors under Mining for further details.

Substantially all of our coal 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 of coal 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 of coal each year. This contract is for the life of the plant;

•

The 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 0.375 million tons of coal per year for its 20% share of the power plant, subject to adjustments for planned outages. This contract expires December 31, 2022;


•	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 of coal 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 of coal 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 of coal 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 coal sales to a specified return on our coal mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above A-rated utility bonds 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 coal supply agreement described above. The agreement includes a price adjustment in 2019. The price adjustment essentially allows us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment is based on the market price of coal plus considerations for the avoided costs of rail transportation and a coal unloading facility, which PacifiCorp would have to incur if it purchased coal from another mine. In addition, the agreement also provides for the monthly escalation of coal price based on an escalation factor.

The current contract price ($19.08 per ton as of December 2018) is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of a coal 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). With respect to the 2019 coal price re-opener, we expect the transportation and unloading costs to escalate slightly. The current trailing 12-month spot price of 8,400 Btu Powder River Basin coal, ending March 2019, is approximately one dollar less than the price used for the 2014 price re-opener.

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 10-Year Corporate 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.

Competition. Our primary strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically, off-site sales have been to consumers within a close proximity to the mine. Rail transport market opportunities for WRDC coal are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC coal 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 plan that provides 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 coal 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 $16 million for reclamation costs as of December 31, 2018. Mining regulatory requirements continue to increase, which impose additional cost on the mining process.

Environmental Matters

South Dakota and Wyoming Power Generation. Based on current regulations, technology and plans, the following table contains our current estimates of capital expenditures expected to be incurred over the next three years to comply with current environmental laws and regulations as described below, including regulations that cover water, air, soil and other pollutants, but excluding plant closures and the cost of new generation. The ultimate cost could be significantly different from the amounts estimated.



Environmental Expenditure Estimates	Total (in thousands)
2019	$	1,503
2020	1,088
2021	710
Total	$	3,301

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 from our natural gas operations 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 has not been sent for publication. This rule will have an impact on the Wyodak Plant. Until the EPA issues the rule for publication, we can not 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.

Regional Haze (Impacts to the Wyodak Power 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. Our 20% share of this capital investment for the facility would be approximately $40 million if PacifiCorp is required to install a Selective Catalytic Reactor for NO_xcontrol. The case is currently held in abeyance at the 10^th circuit court while a settlement reached between one of the interested parties and the EPA is implemented.

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. Our Gas Utilities are managing FMGP sites in Iowa and Nebraska. We are currently in discussions with EPA, state regulators, and/or other third-parties to determine the ultimate resolution to these sites. As of December 31, 2018, we are working on the site in Council Bluffs, Iowa, and the site in McCook, Nebraska. We have been contacted by a third-party who indicated it intends to manage and pay for the clean-up at the McCook Nebraska site.

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 and poses significantly less risk than the Clean Power Plan. The 60-day comment period has ended and the EPA is reviewing comments prior to issuing a final 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 coal ash is used for backfill reclamation in the 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 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 the fourth quarter of 2017.


•	In Arkansas, Nebraska, Iowa, Colorado, Kansas and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 805,000 square feet utilized by our Gas Utilities.


•	In South Dakota, Wyoming, Colorado and Montana we own various office, service center, storage, shop and warehouse space totaling approximately 240,000 square feet utilized by our Electric Utilities and Mining segments.

In addition to our owned properties, we lease 194,361 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, 2018, we had 2,863 full-time employees in continuing operations. Approximately 25% of our employees are represented by a collective bargaining agreement. We have not experienced any labor stoppages in recent years. At December 31, 2018, approximately 23% of our total employees and 18% of our Electric and Gas Utilities employees were eligible for regular or early retirement.

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



	Number of Employees
Corporate	499
Electric Utilities and Gas Utilities	2,301
Mining and Power Generation	63
Total	2,863

At December 31, 2018, 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
South Dakota Electric	128	IBEW Local 1250	March 31, 2022
Wyoming Electric	42	IBEW Local 111	June 30, 2019
Colorado Electric	103	IBEW Local 667	April 15, 2023
Iowa Gas	106	IBEW Local 204	July 31, 2020
Kansas Gas	19	Communications Workers of America, AFL-CIO Local 6407	December 31, 2019
Nebraska Gas	99	IBEW Local 244	March 13, 2022
Nebraska Gas ^(a)	146	CWA Local 7476	October 30, 2019
Wyoming Gas ^(a)	85	CWA Local 7476	October 30, 2019
Total	728

__________


(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.


ITEM 1A.	RISK FACTORS

The nature of our business subjects us to a number of uncertainties and risks. The following 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. These important factors and other matters discussed herein could cause our future actual results or outcomes to differ materially.

OPERATING RISKS

Our financial performance depends on the successful operation of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.

Operating electric generating facilities, the coal mine and electric and natural gas transmission and distribution systems involves risks, including:

•

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;

•

Interruptions to supply of fuel and other commodities used in generation and distribution. Our utilities purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel 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;


•	Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;


•	Operating hazards such as leaks, mechanical problems and accidents, including explosions affecting our natural gas distribution system, which could impact public safety, reliability and customer confidence;


•	Operational limitations imposed by environmental and other regulatory requirements;


•	Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak Plant;


•	Labor relations. Approximately 25% of our employees are represented by a total of eight collective bargaining agreements;


•	Our ability to transition and replace our retirement-eligible utility employees. At December 31, 2018, approximately 18% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement;


•	Inability to recruit and retain skilled technical labor; and


•	Disruption in the functioning of our information technology and network infrastructure which are 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.

Changes in the interpretation of the Tax Cuts and Jobs Act (“TCJA”) could adversely affect us.

On December 22, 2017, the TCJA was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes a decrease in the U.S. federal corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and modifies or repeals many business deductions and credits. The new tax law contains several provisions that impacted our 2017 and 2018 financial results.

The TCJA includes provisions limiting interest deductibility in certain circumstances. While we expect to maintain deductibility of interest expense, the lower tax rate reduces the tax benefits associated with interest deductibility on holding company debt that is not recovered in the regulatory construct.

If there are future changes and amendments to the TCJA, and if we are unable to obtain reasonable outcomes with our utility regulators in passing future benefits of the TCJA back to customers, or if our interpretations on the provisions of depreciation or interest deductibility in the TCJA change, our results of operations, financial position or cash flows could be materially impacted.

Construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve significant risks which could reduce profitability.

The construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve many risks, including:


•	The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;


•	Contractual restrictions upon the timing of scheduled outages;


•	The cost of supplying or securing replacement power during scheduled and unscheduled outages;


•	The unavailability or increased cost of equipment;


•	The cost of recruiting and retaining or the unavailability of skilled labor;


•	Supply interruptions, work stoppages and labor disputes;


•	Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;


•	Opposition by members of public or special-interest groups;


•	Weather interferences;


•	Availability and cost of fuel supplies;


•	Unexpected engineering, environmental and geological problems; and


•	Unanticipated cost overruns.

The ongoing operation of our facilities involves many of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.

Operating results can be adversely affected by variations from normal weather conditions.

Our utility businesses are seasonal businesses and weather 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 seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These events could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial position and cash flows.

Our Mining operations are subject to operating risks that are beyond our control which could affect our profitability and production levels. Our surface mining operations could be disrupted or materially affected due to adverse weather or natural disasters such as heavy snow, strong winds, rain or flooding.

Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.

A portion of our net income is attributable to sales of wholesale and off-system electricity and natural gas. Energy prices are influenced by many factors outside our control, including, among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions, and the rules, regulations and actions of system operators in those markets. As a result, wholesale power markets may be subject to significant, unpredictable price fluctuations over relatively short periods of time.

Our Mining operations require reliable supply of replacement parts, explosives, fuel, tires and steel-related products. If the cost of these increase significantly, or if sources of supplies and mining equipment become unavailable to meet our replacement demands, our productivity and profitability could be lower than our current expectations.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions, emerging technologies or responses to price increases.

Our revenues, results of operations and financial condition 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 demand-side management programs, economic conditions impacting decreases in 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 results of operations, financial position or cash flows.

Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations.

Our Electric Utilities, Gas Utilities and Power Generation segments rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to customers, to supply our natural gas-fired power plants and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.

Our utilities are subject to pipeline safety and system integrity laws and regulations that may require significant capital expenditures or significant increases in operating costs.

Compliance with pipeline safety and system integrity laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers through rates. Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers through rates and could result in a material impact on our results of operations, financial position or cash flows.

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 that could give rise to additional costs and cause a substantial loss to us.

Inherent in our natural gas and electricity transmission and distribution activities, as well as in our transportation and storage of natural gas and our Mining operations, are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. These events could impact the safety of employees or others and result in injury or loss of human life, and cause significant damage to property or natural resources (including public lands), environmental pollution, impairment of our operations and substantial financial losses to us. Particularly for our transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be substantial. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events not fully covered by our insurance could have a material adverse effect on our financial position, results of operations or cash flows.

Threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our businesses, or the businesses of third parties, may impact our operations in unpredictable ways.

Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power, deliver natural gas and by delaying their development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources and could adversely affect our reputation among customers and the public.

A cyber attack may disrupt our operations, or lead to a loss or misuse of confidential and proprietary information and create a potential liability.

We use and operate sophisticated control, SCADA, and information technology systems and network infrastructure. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees. Cyber attacks targeting our electronic control systems used at our generating facilities and for electric and gas distribution systems, could result in a full or partial disruption of our electric and/or gas operations. Cyber 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 as a result of a cyber attack 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 due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber attacks. If our information technology systems or our third-party vendors’ systems were to fail or be breached by a cyber attack or a computer virus and be unable to recover in a timely way, we would be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised which could have a material adverse effect not only on our financial results, but on our public reputation as well.

Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now 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 operations and/or our financial results.

Certain Federal laws, including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated 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.

Our current or future development and expansion activities may not be successful, which could impair our ability to execute our growth strategy.

Execution of our growth plan is dependent on successful ongoing and future development and expansion activities. We can provide no assurance that we will be able to complete development projects or expansion activities we undertake or continue to develop attractive opportunities for growth. Factors that could cause our development and expansion activities to be unsuccessful include:


•	Our inability to obtain required governmental permits;


•	Our inability to complete capital projects in a timely manner;


•	Our inability to secure just and reasonable utility rates through regulatory proceedings;


•	Our inability to obtain financing on acceptable terms, or at all;


•	The possibility that one or more credit rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business;


•	Our inability to attract and retain management or other key personnel;


•	Our inability to negotiate acceptable construction, fuel supply, power sales or other material agreements;


•	Reduced growth in the demand for utility services in the markets we serve;


•	Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves or our power generation capacity;


•	Fuel prices or fuel supply constraints;


•	Pipeline capacity and transmission constraints;


•	Competition within our industry and with producers of competing energy sources; and


•	Changes in tax rates and policies.

Utilities

Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable.

Our regulated Electric Utilities 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 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 the state public utility commissions will judge all of our costs, including our direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a 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.

If market or other conditions adversely affect operations or require us to make changes to our business strategy in any of our utility businesses, we may be forced to record a non-cash goodwill impairment charge. Any significant impairment of our goodwill related to these utilities would cause a decrease in our assets and a reduction in our net income and shareholders’ equity.

We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2018. A substantial portion of the goodwill is related to the SourceGas Acquisition and the Aquila Transaction. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of our businesses, we may be forced to record a non-cash impairment charge, which would reduce our reported assets, net income and shareholders’ equity. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes in economic conditions and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more business segments, which may result in an impairment charge.

Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.

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. 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.

Mining

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.

We conduct surface mining operations that are subject to operations, reclamation and closure standards. We estimate our total reclamation liabilities based on permit requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers and by government regulators. The estimated liability can change significantly if actual costs vary from our original assumptions or if government regulations change significantly. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates. The resulting estimated reclamation obligations could change significantly if actual amounts or the timing of these expenses change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial position.

Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three-dimensional structural modeling, and any inaccuracies in interpretation or modeling could materially affect the estimated quantity and quality of our reserves.

The process of estimating coal reserves is uncertain and requires interpretations and modeling. Significant inaccuracies in interpretation or modeling could materially affect the quantity and quality of our reserve estimates. The accuracy of reserve estimates is a function of engineering and geological interpretation, conditions encountered during actual reserve recovery and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that require reserve revisions either upward or downward from prior reserve estimates.

FINANCING RISKS

Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, cost of capital and other operating costs.

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 to complete new financings on reasonable terms, or at all. A credit rating downgrade, particularly to a sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.

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 natural gas 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.

Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to accounting requirements associated with such activities.

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. The difference in accounting may result in volatility in reported results, even though the expected profit margin may be essentially unchanged from the dates the transactions were consummated.

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 other assumptions could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or cash flows.

As discussed 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 (the pension plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria) and several defined post-retirement healthcare plans and non-qualified retirement plans that cover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial

assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.

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. Our operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to us. 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 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.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position or cash flows.

A future recession 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.

Increasing costs associated with our healthcare plans and other benefits may adversely affect our results of operations, financial position or liquidity.

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, as well as changes to the cost of our plans, and the increasing costs and funding requirements associated with our healthcare plans may adversely affect our results of operations, financial position or cash flows.

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.

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 may adversely impact operations, financial results and materially increase our generation and production costs, which could render some of our generating units uneconomical to operate and maintain.

To the extent climate change occurs, our businesses could be adversely impacted. We believe it is likely that any such resulting impacts would occur very gradually over a very long period of time and thus would be difficult to quantify. Warmer temperatures in our natural gas service territories, or cooler temperatures in our electric service territories could adversely affect financial results through lower natural gas volumes delivered, lower MWh sold and associated lower revenues.

We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming and Colorado. 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”.

Due to uncertainty as to the final outcome of federal climate regulation, legal challenges, state CPP developments or regulatory changes under the Clean Air Act, 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.

The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and any failure to do so, could adversely affect our results of operations, financial position or liquidity.

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 and the use of alternative energy sources for power generation as mandated by states could reduce coal consumption.

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 results of operations, financial position or cash flows could be adversely impacted.


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 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.

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, 2018, we had 3,689 common shareholders of record and approximately 41,000 beneficial owners, representing all 50 states, the District of Columbia and 7 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 30, 2019 meeting, our Board of Directors declared a quarterly dividend of $0.505 per share, equivalent to an annual dividend of $2.02 per share. The 2019 equivalent rate of $2.02 per share would mark 2019 as the 49^th consecutive annual dividend increase for the Company.

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 2018.

ISSUER PURCHASES OF EQUITY SECURITIES



There were no equity securities acquired for the twelve months ended December 31, 2018.


ITEM 6.	SELECTED FINANCIAL DATA

(Minor differences may result due to rounding)



Years Ended December 31,	2018			2017			2016			2015			2014
(dollars in thousands, except per share amounts)

Total Assets	$	6,963,327		$	6,658,902		$	6,541,773		$	4,626,643		$	4,216,752

Property, Plant and Equipment
Total property, plant and equipment	$	6,000,015		$	5,567,518		$	5,315,296		$	3,849,309		$	3,606,931
Accumulated depreciation and depletion	(1,145,136		)	(1,026,088		)	(929,119		)	(794,695		)	(714,762		)
Total property, plant and equipment, net	$	4,854,879		$	4,541,430		$	4,386,177		$	3,054,614		$	2,892,169