Edgar Filing: BLACK HILLS CORP /SD/

10-K

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, 2015



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	625 Ninth Street	IRS Identification Number
	Rapid City, South Dakota 57701	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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post 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. x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company 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, 2015 $1,925,452,517

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, 2016
Common stock, $1.00 par value	51,194,387	shares

Documents Incorporated by Reference

Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2016 Annual Meeting of Stockholders to be held on April 26, 2016, 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	7

		FORWARD-LOOKING INFORMATION	8
Part I
	ITEMS 1. and 2.	BUSINESS AND PROPERTIES	8

	ITEM 1A.	RISK FACTORS	54

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	69

	ITEM 3.	LEGAL PROCEEDINGS	69

	ITEM 4.	MINE SAFETY DISCLOSURES	70
Part II
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	70

	ITEM 6.	SELECTED FINANCIAL DATA	71

	ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	74

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	121

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	196

	ITEM 9A.	CONTROLS AND PROCEDURES	196

	ITEM 9B.	OTHER INFORMATION	197
Part III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	198

	ITEM 11.	EXECUTIVE COMPENSATION	198

	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	199

	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	199

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	199

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	200

		SIGNATURES	205

		INDEX TO EXHIBITS	206

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AC	Alternating Current
AFUDC	Allowance for Funds Used During Construction
AltaGas	AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCI	Accumulated Other Comprehensive Income
APSC	Arkansas Public Service Commission
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by the FASB
Baseload plant	A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate.
Basin Electric	Basin Electric Power Cooperative
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation; the Company
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, includes Black Hills Gas Resources, Inc. and Black Hills Plateau Production LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.
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 direct wholly-owned subsidiary of Black Hills Electric Generation
Black Hills Energy	The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
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
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
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	Busch Ranch Wind Farm
Ceiling Test	Related to our Oil and Gas segment, 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, with consideration of price changes only to the extent provided by contractual arrangements, attributable to proved natural gas, crude oil and NGL reserves using a discount rate defined by the SEC plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unevaluated properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the excluded properties and unevaluated properties included in the amortization base.
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



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.
City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23% of Wygen III power plant for the City of Gillette.
CO₂	Carbon dioxide
Colorado Electric	Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas	Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
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.
Cost of Service Gas Program	A program our utility subsidiaries submitted applications for with respective state utility regulators in Iowa, Kansas, Nebraska, South Dakota, Colorado and Wyoming, seeking approval for a Cost of Service Gas Program designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
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
De-designated interest rate swaps	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under the accounting for derivatives and hedges but subsequently de-designated in December 2008. These swaps were settled in November 2013.
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DSM	Demand Side Management
DRSPP	Dividend Reinvestment and Stock Purchase Plan
Dth	Dekatherms
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
Energy West	Energy West Wyoming, Inc., a subsidiary of Gas Natural, Inc. Energy West is an acquisition we closed on July 1, 2015.
Enserco	Enserco Energy Inc., a formerly wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presented in discontinued operations throughout this Annual Report filed on Form 10-K
EPA	United States Environmental Protection Agency
EPA Region VIII	EPA Region VIII (Mountains and Plains) located in Denver serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations
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 RNSs due 2028.
EWG	Exempt Wholesale Generator



FASB	Financial Accounting Standards Board
FDIC	Federal Depository Insurance Corporation
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
GADS	Generation Availability Data System
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.
IEEE	Institute of Electrical and Electronics Engineers
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP	Independent power producer
IPP Transaction	The July 11, 2008 sale of seven of our IPP plants
IRS	United States Internal Revenue Service
IUB	Iowa Utilities Board
JPB	Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette.
KCC	Kansas Corporation Commission
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Loveland Area Project	Part of the Western Area Power Association transmission system
MACT	Maximum Achievable Control Technology
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
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 Plants
MGTC	MGTC, Inc., a gas utility in northeast Wyoming serving 400 customers. MGTC is an acquisition we closed on January 1, 2015.
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
Native load	Energy required to serve customers within our service territory
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
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
NOPA	Notice of Proposed Adjustment
NPDES	National Pollutant Discharge Elimination System
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
OSHA	Occupational Safety & Health Administration
OTC	Over-the-counter
PCA	Power Cost Adjustment
PCCA	Power Capacity Cost Adjustment
Peak View Wind Project	New $109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PPB	Parts per billion
PUD	Proved undeveloped reserves
PUHCA 2005	Public Utility Holding Company Act of 2005
Quad O Regulation	40 CFR 60 Subpart OOOO - Standards of performance for crude oil and natural gas production, transmission and distribution
RCRA	Resource Conservation and Recovery Act
Recourse Leverage Ratio	Any indebtedness outstanding at such time, divided by Capital at such time. Capital being consolidated net-worth plus all recourse indebtedness.
RICE	Reciprocating Internal Combustion Engines
REPA	Renewable Energy Purchase Agreement
Revolving Credit Facility	Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2019
RMSA	Retirement Medical Savings Account
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
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.



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)
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 Holdings, LLC
Spinning Reserve	Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages
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.
TCIR	Total Case Incident Rate (average number of work-related injuries incurred by 100 workers during a one-year period)
TIPA	Tax Increase Prevention Act of 2014
VEBA	Voluntary Employee Benefit Association
VOC	Volatile Organic Compound
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

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 growth-oriented, vertically-integrated energy 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, we began producing, selling and marketing various forms of energy through non-regulated businesses.

We operate in the United States with two major business groups: Utilities and Non-regulated Energy. Our Utilities Group is comprised of regulated Electric Utilities and regulated Gas Utilities segments, and our Non-regulated Energy Group is comprised of Power Generation, Coal Mining and Oil and Gas segments.



Business Group	Financial Segment
Utilities	Electric Utilities
	Gas Utilities

Non-regulated Energy	Power Generation
	Coal Mining
	Oil and Gas

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 207,200 electric customers in South Dakota, Wyoming, Colorado and Montana and also distributes natural gas to approximately 44,200 gas utility customers of Cheyenne Light in and around Cheyenne, Wyoming. Our Gas Utilities segment serves approximately 547,300 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 841 MW of generation and 8,703 miles of electric transmission and distribution lines, and our Gas Utilities own 645 miles of intrastate gas transmission pipelines and 19,494 miles of gas distribution mains and service lines. Our Utilities Group generated net income of $117 million for the year ended December 31, 2015, and had total assets of $3.7 billion at December 31, 2015.

Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyoming, and sells the coal primarily under long-term contracts to mine-mouth electric generation facilities including our own regulated and non-regulated generating plants. Our Oil and Gas segment engages in the exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region. In 2015, we began transitioning the Oil and Gas business to support utilities through a Cost of Service Gas Program. See the Key Elements of our Business Strategy in Item 7. Our Non-regulated Energy Group generated net income (loss) of $(135) million for the year ended December 31, 2015, and had total assets of $0.3 billion at December 31, 2015.

SourceGas Acquisition: On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC from investment funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co., pursuant to the purchase and sale agreement executed on July 12, 2015. SourceGas primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado. The combined company will serve approximately 1.2 million customers in eight states. Financial results for the SourceGas utilities will be reported under our Gas Utilities segment. For additional information on this acquisition, see the Key Elements of our Business Strategy in Item 7 and Note 2 - SourceGas Acquisition in the Notes to Consolidated Financial Statements in Item 8.

Segment reporting transition of Cheyenne Light’s Natural Gas distribution

Through December 31, 2015, Cheyenne Light’s natural gas operations have been included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. Effective January 1, 2016, the natural gas operations of Cheyenne Light will be reported under our Gas Utilities Segment. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which will be led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations will be reported in our Electric Utilities Segment, which will be led by the Group Vice President, Electric Utilities.

Segment Financial Information

We discuss our business strategy and other prospective information in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations. Financial information regarding our business segments is incorporated herein by reference to Item 8 - Financial Statements and Supplementary Data, and particularly Note 5 to the Consolidated Financial Statements, in this Annual Report on Form 10-K.

Discontinued Operations in the accompanying financial information includes the results of our Energy Marketing segment sold in February 2012. The buyer asserted certain purchase price adjustments, some that we accepted, and several that we disputed. The disputed claims were substantially resolved through a binding arbitration decision dated January 17, 2014. We expensed an additional $1.1 million in 2013 related to the claims assigned to arbitration from purchase price adjustments we accepted through a partial settlement agreement with the buyer. Results for 2013 include the resolution of all previously unresolved purchase price adjustments.

Business Group Overview

Utilities Group

We conduct electric utility operations and combination electric and gas utility operations through three subsidiaries: Black Hills Power (South Dakota, Wyoming and Montana), Cheyenne Light (Wyoming), and Colorado Electric (Colorado). Our Electric Utilities generate, transmit and distribute electricity to approximately 207,200 customers; and also distribute natural gas to approximately 44,200 natural gas utility customers of Cheyenne Light in and around Cheyenne, Wyoming. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

We conduct natural gas utility operations through our Colorado Gas, Nebraska Gas, Iowa Gas and Kansas Gas subsidiaries. Our Gas Utilities distribute and transport natural gas through our distribution network to approximately 547,300 customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services through our Service Guard and Tech Services product lines. Service Guard primarily provides appliance repair services to approximately 64,000 residential customers through company technicians and third party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing customer-owned gas infrastructure facilities, typically through one-time contracts, with a limited number of on-going monthly maintenance agreements. Tech Services also provides electrical system construction services to large industrial customers of our electric utilities.

Electric Utilities Segment

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)
	2015		2014		2013
	Summer	Winter	Summer	Winter	Summer	Winter
Black Hills Power	424	369	410	389	422	403
Cheyenne Light ^(a)	212	202	198	197	185	192
Colorado Electric	392	303	384	298	381	280
Total Electric Utilities Peak Demands	1,028	874	992	884	988	875

________________________


(a)	Both 2015 summer and winter peaks are records set in July and December, respectively.

Regulated Power Plants

As of December 31, 2015, our Electric Utilities’ ownership interests in electric generation plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Black Hills Power:
Cheyenne Prairie ⁽¹⁾	Gas	Cheyenne, Wyoming	58%	55.0	2014
Wygen III⁽²⁾	Coal	Gillette, Wyoming	52%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyoming	100%	90.0	1995
Wyodak ⁽³⁾	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
Cheyenne Light:
Cheyenne Prairie ⁽¹⁾	Gas	Cheyenne, Wyoming	42%	40.0	2014
Cheyenne Prairie CT ⁽¹⁾	Gas	Cheyenne, Wyoming	100%	37.0	2014
Wygen II	Coal	Gillette, Wyoming	100%	95.0	2008
Colorado Electric:
Busch Ranch Wind Farm⁽⁴⁾	Wind	Pueblo, Colorado	50%	14.5	2012
Pueblo Airport Generation	Gas	Pueblo, Colorado	100%	180.0	2011
AIP Diesel	Oil	Pueblo, Colorado	100%	10.0	2001
Diesel #1-5	Oil	Pueblo, Colorado	100%	10.0	1964
Diesel #1-5	Oil	Rocky Ford, Colorado	100%	10.0	1964
Total MW Capacity				841.1

________________________

(1)

Cheyenne Prairie, a 132 MW natural gas-fired power generation facility was placed into commercial operations on October 1, 2014 to support the customers of Black Hills Power and Cheyenne Light. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Cheyenne Light and one combined-cycle, 95 MW unit that is jointly-owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW).


(2)	Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power 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.


(3)	Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by Black Hills Power. This baseload plant is operated by PacifiCorp and our WRDC coal mine supplies all of the fuel for the plant.


(4)	Busch Ranch Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and AltaGas owns the remaining 50%. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 MW of power from the wind farm.

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 is as follows:



Fuel Source (dollars per MWh)	2015		2014		2013
Coal	$	10.89	$	10.92	$	10.89

Natural Gas	$	51.14	$	77.31	$	53.53

Diesel Oil	$	303.16	$	174.04	$	233.47

Total Average Fuel Cost	$	14.62	$	14.82	$	14.65

Purchased Power - Coal, Gas and Oil	$	47.81	$	35.21	$	29.95

Purchased Power - Renewable Sources	$	50.92	$	50.27	$	49.20

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 is as follows:



Power Supply	2015		2014		2013
Coal	33	%	34	%	36	%
Gas, Oil and Wind	4		4		4
Total Generated	37		38		40
Purchased ⁽¹⁾	63		62		60
Total	100	%	100	%	100	%

__________________________


(1)	Wind represents approximately 5% of our purchased power for 2015, 2014 and 2013.

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:


•	Black Hills Power’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 Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW of energy during heavy load timing intervals;


•	Colorado Electric’s PPA with AltaGas expiring on October 16, 2037, which provides up to 14.5 MW of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Project;

•

Cheyenne Light’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 Cheyenne Light to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019 and would be subject to WPSC and FERC approval in order to obtain regulatory treatment. The purchase price related to the option is $2.6 million per MW adjusted for capital additions and reduced by depreciation over a 35-year life beginning January 1, 2009 (approximately $5 million per year);


•	Cheyenne Light’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 Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50% of the facility’s output to Black Hills Power;


•	Cheyenne Light’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 Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 MW of the facility’s output to Black Hills Power; and


•	Cheyenne Light and Black Hills Power’s Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light’s excess energy.

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, Black Hills Power will provide MDU with 25 MW from its other generation facilities or from system purchases with reimbursement of costs by MDU;


•	Black Hills Power has an agreement through December 31, 2023 to serve 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, Black Hills Power 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, Black Hills Power will also provide the City of Gillette its operating component of spinning reserves; and


•	Black Hills Power’s agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. 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:



2016-2017	20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	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, 2015, our Electric Utilities owned the electric transmission and distribution lines shown below:



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
Black Hills Power	South Dakota, Wyoming	1,179	2,485
Black Hills Power - Jointly Owned ⁽¹⁾	South Dakota, Wyoming	44	—
Cheyenne Light	South Dakota, Wyoming	44	1,269
Colorado Electric	Colorado	585	3,097

__________________________

(1)

Black Hills Power 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 MAPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. Black Hills Power'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.

Black Hills Power 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 2023.

Black Hills Power 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 2017, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

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

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


•	Shared Services Agreements -


◦	Black Hills Power, Cheyenne Light, 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.


◦	Black Hills Power and Cheyenne Light receive certain staffing and management services from BHSC for Cheyenne Prairie.


•	Jointly Owned Facilities -


◦	Black Hills Power, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby Black Hills Power charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant.


◦	Colorado Electric and AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric charges AltaGas for operations and maintenance for their share of the Busch Ranch Wind Farm.

Operating Statistics

The following tables summarize information for our Electric Utilities:



Degree Days	2015			2014			2013
	Actual	Variance from Prior Year	Variance from 30-Year Average ^(b)	Actual	Variance from Prior Year	Variance from 30-Year Average ^(b)	Actual	Variance from 30-Year Average ^(b)
Heating Degree Days:
Black Hills Power	6,521	(12)%	(8)%	7,373	(3)%	4%	7,582	9%
Cheyenne Light	6,404	(10)%	(10)%	7,100	(4)%	—%	7,386	4%
Colorado Electric	4,846	(12)%	(12)%	5,534	(4)%	—%	5,740	1%
Combined ^(a)	5,729	(11)%	(10)%	6,473	(3)%	2%	6,691	5%

Cooling Degree Days:
Black Hills Power	577	20%	(14)%	481	(34)%	(28)%	724	8%
Cheyenne Light	407	21%	16%	336	(35)%	(5)%	520	48%
Colorado Electric	1,270	38%	32%	919	(25)%	(4)%	1,230	28%
Combined ^(a)	861	32%	16%	654	(29)%	(12)%	918	7%

________________


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


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



Revenue - Electric (in thousands)	2015		2014		2013
Residential:
Black Hills Power	$	72,659	$	69,712	$	64,566
Cheyenne Light	39,587		36,634		35,778
Colorado Electric	97,418		94,391		95,631
Total Residential	209,664		200,737		195,975

Commercial:
Black Hills Power	100,511		91,882		80,289
Cheyenne Light	64,207		59,758		57,444
Colorado Electric	93,821		90,909		87,732
Total Commercial	258,539		242,549		225,465

Industrial:
Black Hills Power	33,336		28,451		27,705
Cheyenne Light	36,594		29,066		20,803
Colorado Electric	42,325		39,219		38,037
Total Industrial	112,255		96,736		86,545

Municipal:
Black Hills Power	3,626		3,409		3,421
Cheyenne Light	2,179		1,930		1,918
Colorado Electric	12,058		13,312		13,106
Total Municipal	17,863		18,651		18,445

Subtotal Retail Revenue - Electric	598,321		558,673		526,430

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	17,537		21,206		21,956

Off-system/Power Marketing Wholesale:
Black Hills Power	23,241		28,002		29,580
Cheyenne Light	5,215		8,179		8,712
Colorado Electric	1,270		5,726		8,329
Total Off-system/Power Marketing Wholesale	29,726		41,907		46,621

Other Revenue: ^(a)
Black Hills Power	26,954		25,826		26,510
Cheyenne Light	2,374		2,253		1,916
Colorado Electric ^(b)	4,931		7,691		4,612
Total Other Revenue	34,259		35,770		33,038

Total Revenue - Electric	$	679,843	$	657,556	$	628,045

_____________________


(a)	Other revenue primarily consists of transmission revenue.


(b)	Results for 2014 include $1.8 million in technical service revenues for facility improvements at one of our large industrial customers.



Quantities Generated and Purchased (MWh)	2015	2014	2013
Generated:
Coal-fired:
Black Hills Power ^(a)	1,537,744	1,591,061	1,768,483
Cheyenne Light	690,633	697,220	688,318
Total Coal - fired	2,228,377	2,288,281	2,456,801

Natural Gas and Oil:
Black Hills Power ^(b)	80,944	44,984	33,374
Cheyenne Light ^(b)	48,644	12,534	—
Colorado Electric ^(c)	100,732	140,942	247,758
Total Natural Gas and Oil	230,320	198,460	281,132

Wind:
Colorado Electric	41,043	48,318	45,765
Total Wind	41,043	48,318	45,765

Total Generated:
Black Hills Power	1,618,688	1,636,045	1,801,857
Cheyenne Light	739,277	709,754	688,318
Colorado Electric	141,775	189,260	293,523
Total Generated	2,499,740	2,535,059	2,783,698

Purchased:
Black Hills Power	1,422,015	1,446,630	1,441,286
Cheyenne Light	791,351	766,475	779,677
Colorado Electric	1,952,625	1,898,232	1,886,627
Total Purchased ^(d)	4,165,991	4,111,337	4,107,590

Total Generated and Purchased	6,665,731	6,646,396	6,891,288

_______________


(a)	Neil Simpson I was retired on March 21, 2014.


(b)	Cheyenne Prairie was placed into commercial service on October 1, 2014.


(c)	Decreases in 2015 and 2014 generation primarily due to changes in commodity prices that impacted power marketing sales.


(d)	Includes wind power of 227,396 MWh, 224,229 MWh and 222,069 MWh in 2015, 2014 and 2013, respectively.



Quantities (MWh)	2015	2014	2013
Residential:
Black Hills Power	521,828	542,008	555,204
Cheyenne Light	256,964	261,038	272,490
Colorado Electric	621,109	598,872	619,857
Total Residential	1,399,901	1,401,918	1,447,551

Commercial:
Black Hills Power	792,466	782,238	730,701
Cheyenne Light	532,218	528,689	544,636
Colorado Electric	706,872	685,094	703,604
Total Commercial	2,031,556	1,996,021	1,978,941

Industrial:
Black Hills Power	429,140	399,648	404,009
Cheyenne Light	498,141	382,306	281,727
Colorado Electric	472,360	432,167	371,102
Total Industrial	1,399,641	1,214,121	1,056,838

Municipal:
Black Hills Power	31,924	32,076	34,344
Cheyenne Light	9,714	9,425	9,848
Colorado Electric	117,858	122,247	114,732
Total Municipal	159,496	163,748	158,924

Subtotal Retail Quantity Sold	4,990,594	4,775,808	4,642,254

Contract Wholesale:
Total Contract Wholesale - Black Hills Power ^(a)	260,893	340,871	357,193

Off-system Wholesale:
Black Hills Power	837,120	808,257	1,002,847
Cheyenne Light	121,659	191,069	234,566
Colorado Electric	41,306	119,315	219,349
Total Off-system Wholesale	1,000,085	1,118,641	1,456,762

Total Quantity Sold:
Black Hills Power	2,873,371	2,905,098	3,084,298
Cheyenne Light	1,418,696	1,372,527	1,343,267
Colorado Electric	1,959,505	1,957,695	2,028,644
Total Quantity Sold	6,251,572	6,235,320	6,456,209

Other Uses, Losses or Generation, net ^(b):
Black Hills Power	167,332	177,577	158,845
Cheyenne Light	111,932	103,702	124,728
Colorado Electric	134,895	129,797	151,506
Total Other Uses, Losses and Generation, net	414,159	411,076	435,079

Total Energy	6,665,731	6,646,396	6,891,288

________________________


(a)	Decrease in 2015 is primarily from the expiration in March 2015 of a 5 MW unit contingent capacity contract we had with MEAN.


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



Customers at End of Year	2015	2014	2013
Residential:
Black Hills Power	57,178	56,511	55,840
Cheyenne Light	36,438	36,253	35,780
Colorado Electric	83,285	82,710	82,371
Total Residential	176,901	175,474	173,991

Commercial:
Black Hills Power ^(a)	13,197	13,173	12,888
Cheyenne Light	4,760	4,489	4,471
Colorado Electric	11,215	11,156	11,060
Total Commercial	29,172	28,818	28,419

Industrial:
Black Hills Power ^(a)	20	23	46
Cheyenne Light	4	4	3
Colorado Electric	63	66	61
Total Industrial	87	93	110

Other Electric Customers:
Black Hills Power	335	325	310
Cheyenne Light	220	224	232
Colorado Electric	469	469	469
Total Other Electric Customers	1,024	1,018	1,011

Subtotal Retail Customers	207,184	205,403	203,531

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	3	3	3

Total Customers:
Black Hills Power	70,733	70,035	69,087
Cheyenne Light	41,422	40,970	40,486
Colorado Electric	95,032	94,401	93,961
Total Electric Customers at End of Year	207,187	205,406	203,534

________________________


(a)	Change in customers is due to classification change to Commercial billing in 2014 based on customer’s business type.

Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities is Cheyenne Light’s natural gas distribution system. The following table summarizes certain operating information for the natural gas distribution operations of Cheyenne Light:



	2015		2014		2013
Revenue - Gas (in thousands):
Residential	$	23,554	$	24,426	$	23,047
Commercial	12,916		11,279		10,326
Industrial	4,106		2,945		3,050
Other Sales Revenue	3,585		1,104		840
Total Revenue - Gas	$	44,161	$	39,754	$	37,263

Gross Margin - Gas (in thousands):
Residential	$	13,011	$	11,615	$	12,706
Commercial	4,678		3,582		3,993
Industrial	733		525		598
Other Gross Margin	3,585		1,104		881
Total Gross Margin - Gas	$	22,007	$	16,826	$	18,178

Quantities Sold (Dth):
Residential	2,583,049		2,515,243		2,728,797
Commercial	2,073,213		1,482,904		1,653,021
Industrial	845,774		539,848		652,539
Total Quantities Sold^(a)	5,502,036		4,537,995		5,034,357

Gas Customers at Year-End ^(a)	44,154		36,033		35,494

__________


(a)	Increase primarily represents the customer additions from Cheyenne Light’s 2015 system acquisitions of Energy West and MGTC.

Gas Utilities Segment

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, 2015	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
Colorado	128	3,064	968
Nebraska	44	3,504	2,494
Iowa	180	2,719	2,624
Kansas	293	2,801	1,320
Total	645	12,088	7,406

Degree Days



	2015			2014			2013
	Actual	Variance From Prior Year	Variance From 30-Year Average ^(c)	Actual	Variance From Prior Year	Variance From 30-Year Average ^(c)	Actual	Variance From 30-Year Average ^(c)
Heating Degree Days:
Colorado	5,527	(10)%	(12)%	6,108	(3)%	(3)%	6,310	1%
Nebraska	5,350	(14)%	(12)%	6,193	(5)%	2%	6,516	8%
Iowa	6,629	(16)%	(2)%	7,875	2%	16%	7,743	14%
Kansas ^(a)	4,432	(13)%	(9)%	5,099	(4)%	4%	5,294	8%
Combined^(b)	5,838	(14)%	(8)%	6,780	(2)%	7%	6,922	9%

________________


(a)	Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins.


(b)	The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism.


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

Operating Statistics



Revenue (in thousands)	2015		2014		2013
Residential:
Colorado	$	55,216	$	58,439	$	53,296
Nebraska	111,090		135,052		122,197
Iowa	90,865		124,145		98,498
Kansas	61,420		74,128		67,501
Total Residential	318,591		391,764		341,492

Commercial:
Colorado	10,744		12,233		10,515
Nebraska	32,798		39,947		37,190
Iowa	39,314		60,640		47,494
Kansas	21,802		24,966		21,440
Total Commercial	104,658		137,786		116,639

Industrial:
Colorado	1,433		1,909		1,661
Nebraska	1,339		830		900
Iowa	2,633		4,386		3,436
Kansas	12,887		16,963		15,753
Total Industrial	18,292		24,088		21,750

Other:
Colorado	464		118		(17		)
Nebraska	2,271		2,440		2,265
Iowa	580		724		543
Kansas	4,475		2,836		2,326
Total Other	7,790		6,118		5,117

Distribution:
Colorado	67,857		72,699		65,455
Nebraska	147,498		178,269		162,552
Iowa	133,392		189,895		149,971
Kansas	100,584		118,893		107,020
Total Distribution	449,331		559,756		484,998

Transportation:
Colorado	1,037		968		1,033
Nebraska	13,427		14,272		12,943
Iowa	4,762		4,934		4,809
Kansas	7,280		7,448		6,472
Total Transportation	26,506		27,622		25,257

Total Regulated Revenue	475,837		587,378		510,255

Non-regulated Services	31,302		30,390		29,434

Total Revenue	$	507,139	$	617,768	$	539,689



Gross Margin (in thousands)	2015		2014		2013
Residential:
Colorado	$	18,153	$	18,100	$	18,244
Nebraska	51,168		54,996		53,367
Iowa	41,638		44,134		42,961
Kansas	31,789		32,809		32,111
Total Residential	142,748		150,039		146,683

Commercial:
Colorado	2,921		3,048		3,009
Nebraska	10,822		11,708		11,560
Iowa	11,662		13,206		13,060
Kansas	8,409		8,115		7,436
Total Commercial	33,814		36,077		35,065

Industrial:
Colorado	395		464		519
Nebraska	393		239		250
Iowa	253		294		321
Kansas	2,529		2,336		2,220
Total Industrial	3,570		3,333		3,310

Other:
Colorado	464		118		(17		)
Nebraska	2,271		2,441		2,266
Iowa	580		724		543
Kansas	4,405		1,990		1,723
Total Other	7,720		5,273		4,515

Distribution:
Colorado	21,933		21,730		21,755
Nebraska	64,654		69,384		67,443
Iowa	54,133		58,358		56,885
Kansas	47,132		45,250		43,490
Total Distribution	187,852		194,722		189,573

Transportation:
Colorado	1,037		968		1,033
Nebraska	13,427		14,272		12,943
Iowa	4,762		4,934		4,809
Kansas	7,280		7,448		6,472
Total Transportation	26,506		27,622		25,257

Total Regulated Gross Margin:
Colorado	22,970		22,698		22,788
Nebraska	78,081		83,656		80,386
Iowa	58,895		63,292		61,694
Kansas	54,412		52,698		49,962
Total Regulated Gross Margin	214,358		222,344		214,830

Non-regulated Services	15,290		14,572		14,396

Total Gross Margin	$	229,648	$	236,916	$	229,226



Distribution Quantities Sold and Transportation (in Dth)	2015	2014	2013
Residential:
Colorado	6,575,261	6,718,508	6,969,741
Nebraska	10,751,376	13,068,132	12,717,565
Iowa	9,648,973	12,172,281	11,359,220
Kansas	6,091,041	7,313,273	7,174,085
Total Residential	33,066,651	39,272,194	38,220,611

Commercial:
Colorado	1,404,624	1,537,704	1,506,227
Nebraska	4,026,689	4,644,645	4,770,370
Iowa	5,492,230	7,182,173	7,056,978
Kansas	2,768,486	3,043,685	2,867,696
Total Commercial	13,692,029	16,408,207	16,201,271

Industrial:
Colorado	288,212	354,630	405,047
Nebraska	246,184	122,662	150,227
Iowa	481,760	630,912	648,173
Kansas	3,346,525	3,384,797	3,355,930
Total Industrial	4,362,681	4,493,001	4,559,377

Wholesale and Other:
Kansas	14,902	150,014	116,234
Total Wholesale and Other	14,902	150,014	116,234

Distribution Quantities Sold:
Colorado	8,268,097	8,610,842	8,881,015
Nebraska	15,024,249	17,835,439	17,638,162
Iowa	15,622,963	19,985,366	19,064,371
Kansas	12,220,954	13,891,769	13,513,945
Total Distribution Quantities Sold	51,136,263	60,323,416	59,097,493

Transportation:
Colorado	1,019,933	950,819	1,015,791
Nebraska	28,968,737	30,669,764	28,171,610
Iowa	19,867,265	19,959,462	20,176,525
Kansas	15,865,783	15,883,098	14,457,620
Total Transportation	65,721,718	67,463,143	63,821,546

Total Distribution Quantities Sold and Transportation:
Colorado	9,288,030	9,561,661	9,896,806
Nebraska	43,992,986	48,505,203	45,809,772
Iowa	35,490,228	39,944,828	39,240,896
Kansas	28,086,737	29,774,867	27,971,565
Total Distribution Quantities Sold and Transportation	116,857,981	127,786,559	122,919,039



Customers at End of Year	2015	2014	2013
Residential:
Colorado	74,345	72,360	70,410
Nebraska	180,897	180,014	178,389
Iowa	139,205	138,503	137,525
Kansas	99,013	99,359	99,315
Total Residential	493,460	490,236	485,639

Commercial:
Colorado	3,825	3,788	3,737
Nebraska	15,948	15,900	15,739
Iowa	15,433	15,303	15,418
Kansas	10,813	10,547	9,832
Total Commercial	46,019	45,538	44,726

Industrial:
Colorado	224	205	207
Nebraska	145	147	136
Iowa	98	90	94
Kansas	1,377	1,277	1,358
Total Industrial	1,844	1,719	1,795

Transportation:
Colorado	40	34	36
Nebraska	4,271	4,151	4,240
Iowa	460	418	421
Kansas	1,161	1,145	1,171
Total Transportation	5,932	5,748	5,868

Wholesale:
Kansas ^(a)	—	8	7
Total Wholesale	—	8	7

Total Customers:
Colorado	78,434	76,387	74,390
Nebraska	201,261	200,212	198,504
Iowa	155,196	154,314	153,458
Kansas	112,364	112,336	111,683
Total Customers at End of Year	547,255	543,249	538,035

________________________


(a)	Change in customers is due to classification change to Commercial billing in 2015 based on customer’s business type.

Utilities Group Business Characteristics

Seasonal Variations of Business

Our Electric Utilities and Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity and natural gas 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. Conversely, for our Gas Utilities, 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.

Competition

We generally have limited competition for the retail distribution of electricity and 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 would be aimed at increasing competition or providing for distributed generation. To date, these initiatives have had no 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. 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

Current Rates

Our 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 illustrates information about certain enacted regulatory provisions with respect to the states in which the Utilities Group operates:



Subsidiary	Jurisdic-tion	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Capital Structure Debt/Equity	Authorized Rate Base (in millions)	Effective Date	Tariff and Rate Matters	Percentage of Power Marketing Activity Shared with Customers
Electric Utilities:
Black Hills Power	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, Vegetation Management	70%
	SD		8.16%			6/2011	Environmental Improvement Cost Recovery Adjustment Tariff	N/A
	MT	15.0%	11.73%	47%/53%		1983	ECA	N/A
	FERC	10.8%	9.10%	43%/57%		2/2009	FERC Transmission Tariff	N/A
Cheyenne Light - 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
Cheyenne Light - Gas	WY	9.9%	7.98%	46%/54%	$59.6	10/2014	GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment	N/A
Colorado Electric	CO	9.83%	7.55%	50.2%/49.8%	$448.3	1/2015	ECA, TCA, PCCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment, Construction Rider	90%

Gas Utilities:
Colorado Gas	CO	9.6%	8.41%	50%/50%	$64.0	12/2012	GCA, Energy Efficiency Cost Recovery/DSM	N/A
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	N/A
Kansas Gas	KS	Global Settlement	Global Settlement	Global Settlement	$127.4	1/2015	GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA	N/A
Iowa Gas	IA	Global Settlement	Global Settlement	Global Settlement	$110.2	2/2011	GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism	N/A

We produce and/or distribute electricity in four states: Colorado, South Dakota, Wyoming and Montana. 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 case. 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.

Some of the mechanisms we have in place include the following by utility and state:

In South Dakota, Black Hills Power has:

•

An annual adjustment clause which provides for the direct recovery of increased fuel and purchased power cost incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 70% of off-system power marketing operating income. The ECA allows methodology 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 vegetation management recovery mechanism that allows for recovery of and a return on prudently-incurred vegetation management costs.


•	An approved annual Environmental Improvement Cost Recovery Adjustment tariff which recovers costs associated with generation plant environmental improvements.


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

In Wyoming, Cheyenne Light has:


•	An annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. As of October 1, 2014, the annual cost adjustment allows for recovery of 85% of coal and coal related costs, and recovery of 95% of purchased power costs, transmission, and natural gas costs.


•	An approved FERC Transmission Tariff that determines the revenue component of Cheyenne Light’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, symmetrical interest, 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. Additionally, Colorado allows an annual TCA rider that includes nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism.


•	Effective January 1, 2015, a rider to recover a return on the construction costs of a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

We distribute natural gas in five states: Colorado, Iowa, Nebraska, Kansas and Wyoming. All of our Gas Utilities and Cheyenne Light’s natural gas distribution have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer between rate cases. Some of the mechanisms we have in place include the following:


•	In Kansas, we have a tariff pass-through mechanism for weather normalization, as well as tariffs that provide timely recovery of certain capital expenditures and property tax fluctuations.


•	In Kansas and Nebraska, we are allowed to recover the portion of uncollectible accounts related to gas costs through GCAs.


•	In Iowa, we have a Capital Infrastructure Automatic Adjustment Mechanism that allows for recovery of certain capital infrastructure investments.


•	In Nebraska, we have an Infrastructure System Replacement Cost mechanism that allows for recovery of certain capital infrastructure investments.

Rates and Rate Activity

The following table summarizes recent activity of certain state and federal rate cases, riders and surcharges (dollars in millions):



	Type of Service	Date Requested	Effective Date	Revenue Amount Requested		Revenue Amount Approved
Kansas Gas ^(a)	Gas	4/2014	1/2015	$	7.3	$	5.2
Colorado Electric ^(b)	Electric	4/2014	1/2015	$	4.0	$	3.1
Black Hills Power^(c)	Electric	3/2014	10/2014	$	14.6	$	6.9
Iowa Gas ^(d)	Gas	3/2015	6/2015	$	0.9	$	0.9
Nebraska Gas ^(e)	Gas	4/2015	8/2015	$	1.5	$	1.5

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(a)	In January 2015, Kansas Gas implemented new base rates in accordance with the rate request approval received on December 16, 2014 from the KCC to increase base rates by $5.2 million. This increase in base rates allows Kansas Gas to recover infrastructure and increased operating costs. The approval was a Global Settlement and did not stipulate return on equity and capital structure.

(b)

In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider also allows Colorado Electric to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

(c)

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an increase for Black Hills Power of $6.9 million in annual electric revenue. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides Black Hills Power a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas-fired facility. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.


(d)	On March 17, 2015, Iowa Gas filed with the IUB for a capital investment recovery surcharge increase of $0.9 million. Iowa Gas received approval from the IUB on May 28, 2015.


(e)	On April 6, 2015, Nebraska Gas filed with the NPSC for a capital investment recovery surcharge increase of $1.5 million. Nebraska Gas received approval from the NPSC on July 27, 2015.

Cost of Service Gas Program Filings

On September 30, 2015, Black Hills Corp.’s utility subsidiaries submitted applications with respective state utility regulators seeking approval for a Cost of Service Gas Program in Iowa, Kansas, Nebraska, South Dakota and Wyoming. An application was submitted in Colorado on November 2, 2015. The Cost of Service Gas Program is designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program. If approved, our non-utility affiliate will acquire natural gas reserves and/or drill wells to produce natural gas for the program for up to 50% of weather normalized annual firm demand for our utilities. The proposed Cost of Service Gas Program model has a capital structure of 60% equity and 40% debt, and seeks a utility-like return. Based on historical performance, the cost of production is expected to be more stable and predictable than the spot market price of natural gas.

We currently have hearing dates with the commissions in all six states. The scheduled hearing for Iowa is in March 2016, for Nebraska in April 2016, for Kansas and Wyoming in May 2016, for South Dakota in June 2016, and for Colorado in July 2016. The program is not necessarily dependent on approvals from all states, however, the total program volumes depend on the sum of volumes approved by the various state commissions. Our long-term target for the program is up to 50% (38 Bcf) of annual demand for our gas utilities and gas-fired electric generation.

Other 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. At December 31, 2015, 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% 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 June 23, 2015, Colorado Electric filed for a CPCN with the CPUC to acquire the planned 60 MW Peak View Wind Project, to be located near Colorado Electric's Busch Ranch wind farm. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. The project will be built by Invenergy Wind Development Colorado LLC and is expected to be completed in the fourth quarter of 2016. On September 24, 2015, Colorado Electric filed an uncontested Settlement Agreement that would approve the build transfer proposal. The settlement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which Colorado Electric can propose base rate recovery. The settlement requires Colorado Electric 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 for the first 10 years. The Commission determined it did not need to hold a hearing regarding the settlement and considered and approved the project on October 21, 2015. Pending final approvals and permits, Colorado Electric will purchase the project for approximately $109 million through progress payments throughout 2016, with ownership transfer occurring just before achieving commercial operation.

•

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, Black Hills Power 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 Black Hills Power from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers we have 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, seeking to minimize associated rate increases for our utility customers. Mandatory portfolio standards have increased and may continue to increase the power supply costs of our Electric Utility 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, 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 Utility 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. Black Hills Power owns and operates FERC-jurisdictional interstate transmission facilities and provides 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 centralized service company subsidiaries, BHSC and Black Hills Utility Holdings, we are subject to FERC’s authority under PUHCA 2005.

Environmental Matters

We are subject to numerous federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel and the public. These laws and regulations affect a broad range of our utility activities and generally regulate: (i) the protection of air and water quality; (ii) the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of and emergency response in connection with hazardous and toxic materials and wastes, including asbestos; and (iii) the protection of plant and animal species and minimization of noise emissions.

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)
2016	$	2,300
2017	1,572
2018	2,589
Total	$	6,461

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 NPDES 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. This rule will have an impact on the Wyodak Plant, requiring conversion to a dry method of handling coal ash and further restrictions of constituent concentrations in any off-site discharges. The terms of this new regulation become effective at the next permit renewal, which will be in 2020. Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities subject to these regulations have compliant prevention plans in place.

Air Emissions

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO₂, NO_x, mercury, particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Clean Air Act

Title IV of the Clean Air Act created an SO₂ allowance trading regime as part of the federal acid rain program. Each allowance gives the owner the right to emit one ton of SO₂.Certain facilities are allocated allowances based on their historical operating data. At the end of each year, each emitting unit must possess allowances sufficient to cover its emissions for the preceding year. Allowances may be traded, so affected units that expect to emit more SO₂ than their allocated allowances may purchase allowances on the open market.

Title IV applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen II, Wygen III, Pueblo Airport Generating Station, Cheyenne Prairie and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2045. For future plants, we plan to secure the requisite number of allowances by reducing SO₂ emissions through the use of low sulfur fuels, installation of “back end” control technology, use of banked allowances and if necessary, the purchase of allowances on the open market. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such new projects.

Title V of the Clean Air Act requires that all of our generating facilities obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen III, Pueblo Airport Generating Station and Cheyenne Prairie Generating Station. Wygen III, Pueblo Airport Generating Station and Cheyenne Prairie Generating Station are allowed to operate under their construction permit until the Title V permit is issued by the state. The Title V application for Wygen III was submitted in January 2011, with the permit expected in 2016. The Pueblo Airport Generating Station Title V application was filed in September 2012, with the permit expected in 2016. The Cheyenne Prairie Generating Station Title V application was submitted in 2015. All applications were filed in accordance with regulatory requirements.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates on December 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. Due to costs to retrofit these plants, we suspended operations at the Osage plant in October 2010 and suspended operations at the Ben French facility on August 31, 2012. We permanently retired Osage, Ben French and Neil Simpson I on March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than December 31, 2013. The W.N. Clark facility suspended operations December 31, 2012 and was retired on December 31, 2013 in accordance with the Colorado Clean Air Clean Jobs Act.

On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), with an effective date of April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. Affected units had a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain limited circumstances. The current state air permits for Wygen II and Wygen III provide mercury emission limits and monitoring requirements with which we are in compliance. Neil Simpson II, Wygen II and Wygen III have been utilized for internal study and review of mercury emission control technology and have mercury monitors in place. Due to mercury absorbent issues encountered in 2015, the state of Wyoming approved a one year compliance deadline extension to April 16, 2016 for Neil Simpson II, Wygen II and Wygen III, for mercury only. The other components of the MATS rule remain in effect and these plants are in compliance with those requirements. The Wyodak plant is in compliance with all requirements of the MATS regulation.

In August 2012, the EPA proposed revisions to the Electric Utility New Source Performance Standards for stationary combustion turbines. This rule is expected to be finalized in 2016 and, as proposed, will be applicable to the Pueblo Airport Generating Station, Cheyenne Prairie and eventually all the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NO_x emission limitations.

By May 3, 2013, all of our diesel generator engines were required to comply with the EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations were completed, emission control equipment was installed and emission testing confirmed compliance with those requirements.

The EPA published a more stringent ozone ambient standard on October 26, 2015. This regulation lowered the ozone standard from 75 to 70 ppb which will result in a continuation of the Denver, Colorado and Colorado North Front Range non-attainment status. Wyoming monitoring data from the Gillette and Cheyenne, Wyoming regions indicate compliance with the new limit. The primary impact on Black Hills operations could potentially be tighter NOx emission limits on new power generation units.

In 2011, the State of Wyoming issued a letter requiring Neil Simpson II to include startup and shutdown SO₂ and NO_x emissions when evaluating compliance with permitted emission limits. This represented a significant change from requirements provided in the original 1993 air permit. Minor engineered design changes were made to improve scrubber performance during startup. Those changes enabled the unit to meet the new requirements. The unit was previously fitted with state of the art low NO_x burners that support compliance with this new requirement. Also in 2014, Neil Simpson II, Wygen II and Wygen III converted startup fuel from diesel to natural gas to support potential start-up requirements and future GHG state compliance plans.

Regional Haze

In January 2011, the states of Wyoming and South Dakota submitted their plans to EPA Region VIII, identifying NO_x, SO₂ and particulate matter emission reductions intended to meet the Class I Areas (National Parks and Wilderness Areas) visibility improvement requirements under the EPA’s Regional Haze Program. Although none of our South Dakota or Wyoming power plants were included in those plans, we anticipate that Neil Simpson II will eventually be included in required five year progress reports. The state of Wyoming is currently developing their initial progress report for submittal in the spring of 2016. Neil Simpson II is not currently a discussion item in that report.

A number of our power plants have been subject to new state and EPA regulations issued in recent years. As the result of these regulations and the associated costs to retrofit many of our older generating plants, we have since permanently retired the following plants:



Plant	Company	MW		Type of Plant	Date Suspended	Actual Retirement Date	Age of Plant (in years)
Osage	Black Hills Power		34.5	Coal	October 1, 2010	March 21, 2014	64
Ben French	Black Hills Power		25.0	Coal	August 31, 2012	March 21, 2014	52
Neil Simpson I	Black Hills Power		21.8	Coal	N/A	March 21, 2014	43
W.N. Clark	Colorado Electric		42.0	Coal	December 31, 2012	December 31, 2013	57
Pueblo Unit #5	Colorado Electric		9.0	Gas	December 31, 2012	December 31, 2013	71
Pueblo Unit #6	Colorado Electric		20.0	Gas	December 31, 2012	December 31. 2013	63
	Total MW		152.3

The Wyodak Power Plant is included in EPA's January 30, 2014 Regional Haze Federal Implementation Plan, which includes significant additional NO_x controls by March 1, 2019. Our share of those costs is estimated at $20 million. The State of Wyoming and PacifiCorp filed requests for reconsideration and Administrative Stay with EPA and the United States Court of Appeals for the 10th Circuit. On September 9, 2014, the 10th Circuit stayed EPA’s NO_x requirement for Wyodak pending outcome of the appeal, which is anticipated to be settled by the summer of 2016.

Greenhouse Gas Regulations

We utilize a diversified energy portfolio of power generation assets that include a fuel mix of coal, natural gas and wind sources, and minimal quantities of both solar and hydroelectric power. Of these generation resources, coal-fired power plants are the most significant sources of CO₂ emissions.

On June 3, 2010, the EPA promulgated the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event we establish a new major source of GHG emissions, as defined by EPA regulations. Upon renewal of operating permits for existing permitted facilities, monitoring and reporting requirements will be implemented. This rule established the basis for EPA’s October 23, 2015 suite of GHG emission rules for existing, new, modified and reconstructed facilities. The portion of this rule-making that applies to existing power generation sources is known as the Clean Power Plan (CPP). The portion of this rule-making that applies to new generating units effectively prohibits new coal-fired power plants from being constructed until carbon capture and sequestration becomes technically and economically feasible. The basis of the CPP regulation is to decrease existing coal-fired generation, increase the utilization of existing gas-fired combined cycle generation, increase renewable energy and increase use of demand side management. States are required to develop and submit compliance plans to EPA, with the initial