Edgar Filing: BLACK HILLS CORP /SD/

BKH 10K 12 2014

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, 2014



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, 2014 $2,696,775,649

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, 2015
Common stock, $1.00 par value	44,676,072	shares

Documents Incorporated by Reference

Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2015 Annual Meeting of Stockholders to be held on April 28, 2015, 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	7
Part I
	ITEMS 1. and 2.	BUSINESS AND PROPERTIES	8

	ITEM 1A.	RISK FACTORS	53

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	67

	ITEM 3.	LEGAL PROCEEDINGS	67

	ITEM 4.	MINE SAFETY DISCLOSURES	67
Part II
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	67

	ITEM 6.	SELECTED FINANCIAL DATA	68

	ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	71

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	116

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	188

	ITEM 9A.	CONTROLS AND PROCEDURES	188

	ITEM 9B.	OTHER INFORMATION	188
Part III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	189

	ITEM 11.	EXECUTIVE COMPENSATION	190

	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	190

	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	190

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	190

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	191

		SIGNATURES	195

		INDEX TO EXHIBITS	196

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
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
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
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 Light Pension Plan	The Cheyenne Light, Fuel and Power Company Pension Plan
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.
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion turbine
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
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
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
IFRS	International Financial Reporting Standards
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
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
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordable Care Act of 2010
PSCo	Public Service Company of Colorado
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
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
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.
S&S	Significant and substantial
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
WTI	West Texas Intermediate Crude

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 principally 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 205,400 electric customers in South Dakota, Wyoming, Colorado and Montana and also distributes natural gas to approximately 36,000 gas utility customers of Cheyenne Light in and around Cheyenne, Wyoming. Our Gas Utilities segment serves approximately 543,200 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 841 MW of generation and 8,660 miles of electric transmission and distribution lines, and our Gas Utilities own 645 miles of intrastate gas transmission pipelines and 19,058 miles of gas distribution mains and service lines. Our Utilities Group generated net income of $101 million for the year ended December 31, 2014, and had total assets of $3.7 billion at December 31, 2014.

Our Power Generation segment produces electric power from our 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. Our Non-regulated Energy Group generated net income of $28 million for the year ended December 31, 2014, and had total assets of $0.5 billion at December 31, 2014.

For more than 15 years, prior to February 2012, we also owned and operated Enserco, an energy marketing business that engaged in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. On February 29, 2012, we sold Enserco, representing our entire Energy Marketing segment, which resulted in this segment being reclassified as discontinued operations. See Note 21 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

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 4 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.

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 205,400 customers; and also distribute natural gas to approximately 36,000 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 on a state-by-state basis 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 543,200 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 63,000 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)
	2014		2013		2012
	Summer	Winter	Summer	Winter	Summer	Winter
Black Hills Power	410	389	422	403	449	362
Cheyenne Light	198	197	185	192	187	174
Colorado Electric	384	298	381	280	400	284
Total Electric Utilities Peak Demands	992	884	988	875	1,036	820

Regulated Power Plants

As of December 31, 2014, 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 ⁽¹⁾:
Cheyenne Prairie ⁽²⁾	Gas	Cheyenne, Wyoming	58%	55.0	2014
Wygen III⁽³⁾	Coal	Gillette, Wyoming	52%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyoming	100%	90.0	1995
Wyodak ⁽⁴⁾	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 ⁽²⁾	Gas	Cheyenne, Wyoming	42%	40.0	2014
Cheyenne Prairie CT ⁽²⁾	Gas	Cheyenne, Wyoming	100%	37.0	2014
Wygen II	Coal	Gillette, Wyoming	100%	95.0	2008
Colorado Electric:
Busch Ranch Wind Farm⁽⁵⁾	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)

The Osage, Ben French, and Neil Simpson I generating plants, having a combined capacity of 81.3 MW, were retired on March 21, 2014 due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. The remaining net book value of these plants is deferred as a Regulatory asset on the accompanying Consolidated Balance Sheets. We have requested recovery for the remaining net book values of these plants and prudent decommissioning costs of these units. The WPSC granted approval to our request in the Wyoming rate case approved in August 2014, and our request with the SDPUC is pending with a decision expected in March 2015.

(2)

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).


(3)	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.


(4)	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.


(5)	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 wind farm became operational October 16, 2012.

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 megawatt-hour)	2014		2013		2012
Coal	$	10.92	$	10.89	$	14.42

Natural Gas	$	77.31	$	53.53	$	52.08

Diesel Oil	$	174.04	$	233.47	$	280.29

Total Average Fuel Cost	$	14.82	$	14.65	$	16.05

Purchased Power - Coal, Gas and Oil	$	35.21	$	29.95	$	26.70

Purchased Power - Renewable Sources	$	50.27	$	49.20	$	47.45

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	2014		2013		2012
Coal	34	%	36	%	37	%
Gas, Oil and Wind	4		4		2
Total Generated	38		40		39
Purchased	62		60		61
Total	100	%	100	%	100	%

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 accounted for as a capital lease on the accompanying Consolidated Financial Statements;


•	Colorado Electric’s PPA with Cargill expiring on December 31, 2015, which provides for the purchase of 50 MW of energy during heavy load timing intervals;


•	Colorado Electric’s PPA with Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW of energy during light 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. 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 energy from Silver Sage 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;


•	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:



2015-2017	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; and


•	Black Hills Power’s PPA with MEAN, whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III through May 2015.

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, 2014, 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	1,182	2,474
Black Hills Power - Jointly Owned ⁽¹⁾	South Dakota, Wyoming	44	—
Cheyenne Light	South Dakota, Wyoming	48	1,257
Colorado Electric	Colorado	585	3,070

__________________________

(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 also 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	2014		2013		2012
	Actual	Variance from 30-Year Average ^(b)	Actual	Variance from 30-Year Average ^(b)	Actual	Variance from 30-Year Average ^(b)
Heating Degree Days:
Black Hills Power	7,373	4%	7,582	9%	6,206	(13)%
Cheyenne Light	7,100	—%	7,386	4%	6,304	(11)%
Colorado Electric	5,534	—%	5,740	1%	4,921	(13)%
Combined ^(a)	6,473	2%	6,691	5%	5,629	(12)%

Cooling Degree Days:
Black Hills Power	481	(28)%	724	8%	937	47%
Cheyenne Light	336	(5)%	520	48%	568	63%
Colorado Electric	919	(4)%	1,230	28%	1,322	47%
Combined ^(a)	654	(12)%	918	7%	1,043	47%

________________

(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)	2014		2013		2012
Residential:
Black Hills Power	$	69,712	$	64,566	$	58,523
Cheyenne Light	36,634		35,778		32,053
Colorado Electric ^(a)	94,391		95,631		91,550
Total Residential	200,737		195,975		182,126

Commercial:
Black Hills Power	91,882		80,289		73,858
Cheyenne Light	59,758		57,444		55,600
Colorado Electric	90,909		87,732		82,849
Total Commercial	242,549		225,465		212,307

Industrial:
Black Hills Power	28,451		27,705		25,656
Cheyenne Light	29,066		20,803		16,105
Colorado Electric	39,219		38,037		37,540
Total Industrial	96,736		86,545		79,301

Municipal:
Black Hills Power	3,409		3,421		3,268
Cheyenne Light	1,930		1,918		1,807
Colorado Electric	13,312		13,106		13,373
Total Municipal	18,651		18,445		18,448

Subtotal Retail Revenue - Electric	558,673		526,430		492,182

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	21,206		21,956		20,290

Off-system/Power Marketing Wholesale:
Black Hills Power	28,002		29,580		31,905
Cheyenne Light	8,179		8,712		8,365
Colorado Electric	5,726		8,329		6,003
Total Off-system/Power Marketing Wholesale	41,907		46,621		46,273

Other Revenue: ^(b)
Black Hills Power	25,826		26,510		29,809
Cheyenne Light	2,253		1,916		2,336
Colorado Electric ^(c)	7,691		4,612		4,652
Total Other Revenue	35,770		33,038		36,797

Total Revenue - Electric	$	657,556	$	628,045	$	595,542

_____________________


(a)	2013 includes $0.7 million and 2012 includes $2.1 million in construction savings incentives from the construction of the Pueblo Airport Generating Station.


(b)	Other revenue primarily consists of transmission revenue.


(c)	Increase in 2014 is primarily due to $1.8 million in technical service revenues for facility improvements at one of our large industrial customers.



Quantities Generated and Purchased (MWh)	2014	2013	2012
Generated -
Coal-fired:
Black Hills Power ^(a)	1,591,061	1,768,483	1,796,936
Cheyenne Light	697,220	688,318	587,832
Colorado Electric ^(b)	—	—	222,647
Total Coal - fired	2,288,281	2,456,801	2,607,415

Natural Gas and Oil:
Black Hills Power ^(c)	44,984	33,374	33,183
Cheyenne Light ^(c)	12,534	—	—
Colorado Electric ^(d)	140,942	247,758	84,874
Total Natural Gas and Oil	198,460	281,132	118,057

Wind:
Colorado Electric	48,318	45,765	12,433
Total Wind	48,318	45,765	12,433

Total Generated:
Black Hills Power	1,636,045	1,801,857	1,830,119
Cheyenne Light	709,754	688,318	587,832
Colorado Electric	189,260	293,523	319,954
Total Generated	2,535,059	2,783,698	2,737,905

Purchased -
Black Hills Power	1,446,630	1,441,286	1,678,090
Cheyenne Light	766,475	779,677	807,659
Colorado Electric	1,898,232	1,886,627	1,794,229
Total Purchased ^(e)	4,111,337	4,107,590	4,279,978

Total Generated and Purchased	6,646,396	6,891,288	7,017,883

_______________


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


(b)	W.N. Clark suspended operations in 2012.


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


(d)	Decrease in 2014 generation primarily due to increased commodity prices that impacted power marketing sales.


(e)	Includes wind power of 224,229 MWh, 222,069 MWh, and 199,079 MWh in 2014, 2013 and 2012, respectively.



Quantities (MWh)	2014	2013	2012
Residential:
Black Hills Power	542,008	555,204	532,342
Cheyenne Light	261,038	272,490	261,792
Colorado Electric	598,872	619,857	614,521
Total Residential	1,401,918	1,447,551	1,408,655

Commercial:
Black Hills Power	782,238	730,701	731,785
Cheyenne Light	528,689	544,636	577,141
Colorado Electric	685,094	703,604	723,216
Total Commercial	1,996,021	1,978,941	2,032,142

Industrial:
Black Hills Power	399,648	404,009	407,301
Cheyenne Light	382,306	281,727	224,448
Colorado Electric	432,167	371,102	358,490
Total Industrial	1,214,121	1,056,838	990,239

Municipal:
Black Hills Power	32,076	34,344	35,933
Cheyenne Light	9,425	9,848	9,631
Colorado Electric	122,247	114,732	121,480
Total Municipal	163,748	158,924	167,044

Subtotal Retail Quantity Sold	4,775,808	4,642,254	4,598,080

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	340,871	357,193	340,036

Off-system Wholesale:
Black Hills Power	808,257	1,002,847	1,263,457
Cheyenne Light	191,069	234,566	229,062
Colorado Electric	119,315	219,349	160,430
Total Off-system Wholesale	1,118,641	1,456,762	1,652,949

Total Quantity Sold:
Black Hills Power	2,905,098	3,084,298	3,310,854
Cheyenne Light	1,372,527	1,343,267	1,302,074
Colorado Electric	1,957,695	2,028,644	1,978,137
Total Quantity Sold	6,235,320	6,456,209	6,591,065

Other Uses, Losses or Generation, net ^(a):
Black Hills Power	177,577	158,845	197,355
Cheyenne Light	103,702	124,728	93,417
Colorado Electric	129,797	151,506	136,046
Total Other Uses, Losses and Generation, net	411,076	435,079	426,818

Total Energy	6,646,396	6,891,288	7,017,883

________________________


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



Customers at End of Year	2014	2013	2012
Residential:
Black Hills Power	56,511	55,840	55,296
Cheyenne Light	36,253	35,780	35,438
Colorado Electric	82,710	82,371	81,795
Total Residential	175,474	173,991	172,529

Commercial:
Black Hills Power ^(a)	13,173	12,888	12,857
Cheyenne Light	4,489	4,471	4,276
Colorado Electric	11,156	11,060	11,220
Total Commercial	28,818	28,419	28,353

Industrial:
Black Hills Power ^(a)	23	46	44
Cheyenne Light	4	3	2
Colorado Electric	66	61	61
Total Industrial	93	110	107

Other Electric Customers:
Black Hills Power	325	310	308
Cheyenne Light	224	232	240
Colorado Electric	469	469	475
Total Other Electric Customers	1,018	1,011	1,023

Subtotal Retail Customers	205,403	203,531	202,012

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

Total Customers:
Black Hills Power	70,035	69,087	68,508
Cheyenne Light	40,970	40,486	39,956
Colorado Electric	94,401	93,961	93,551
Total Electric Customers at End of Year	205,406	203,534	202,015

________________________


(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:



	2014		2013		2012
Revenue - Gas (in thousands):
Residential	$	24,426	$	23,047	$	19,327
Commercial	11,279		10,326		8,613
Industrial	2,945		3,050		2,715
Other Sales Revenue	1,104		840		769
Total Revenue - Gas	$	39,754	$	37,263	$	31,424

Gross Margin - Gas (in thousands):
Residential	$	11,615	$	12,706	$	10,712
Commercial	3,582		3,993		2,963
Industrial	525		598		551
Other Gross Margin	1,104		881		766
Total Gross Margin - Gas	$	16,826	$	18,178	$	14,992

Quantities Sold (Dth):
Residential	2,515,243		2,728,797		2,215,858
Commercial	1,482,904		1,653,021		1,447,522
Industrial	539,848		652,539		598,408
Total Quantities Sold	4,537,995		5,034,357		4,261,788

Gas Customers at Year-End	36,033		35,494		35,021

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, 2014	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
Colorado	126	3,030	942
Nebraska	44	3,482	2,474
Iowa	182	2,690	2,373
Kansas	293	2,755	1,312
Total	645	11,957	7,101

Degree Days



	2014		2013		2012
	Actual	Variance From 30-Year Average (c)	Actual	Variance From 30-Year Average (c)	Actual	Variance From 30-Year Average (c)
Heating Degree Days:
Colorado	6,108	(3)%	6,310	1%	5,186	(18)%
Nebraska	6,193	2%	6,516	8%	5,198	(15)%
Iowa	7,875	16%	7,743	14%	6,093	(10)%
Kansas ^(a)	5,099	4%	5,294	8%	4,190	(15)%
Combined^(b)	6,780	7%	6,922	9%	5,518	(13)%

________________


(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)	2014		2013			2012
Residential:
Colorado	$	58,439	$	53,296		$	48,406
Nebraska	135,052		122,197			98,339
Iowa	124,145		98,498			82,669
Kansas	74,128		67,501			55,096
Total Residential	391,764		341,492			284,510

Commercial:
Colorado	12,233		10,515			9,558
Nebraska	39,947		37,190			30,894
Iowa	60,640		47,494			36,550
Kansas	24,966		21,440			15,677
Total Commercial	137,786		116,639			92,679

Industrial:
Colorado	1,909		1,661			1,963
Nebraska	830		900			876
Iowa	4,386		3,436			2,458
Kansas	16,963		15,753			13,614
Total Industrial	24,088		21,750			18,911

Other:
Colorado	118		(17		)	181
Nebraska	2,440		2,265			2,066
Iowa	724		543			452
Kansas	2,836		2,326			5,124
Total Other Sales Revenue	6,118		5,117			7,823

Distribution:
Colorado	72,699		65,455			60,108
Nebraska	178,269		162,552			132,175
Iowa	189,895		149,971			122,129
Kansas	118,893		107,020			89,511
Total Distribution	559,756		484,998			403,923

Transportation:
Colorado	968		1,033			866
Nebraska	14,272		12,943			10,589
Iowa	4,934		4,809			4,128
Kansas	7,448		6,472			5,762
Total Transportation	27,622		25,257			21,345

Total Regulated Revenue	587,378		510,255			425,268

Non-regulated Services	30,390		29,434			28,813

Total Revenue	$	617,768	$	539,689		$	454,081



Gross Margin (in thousands)	2014		2013			2012
Residential:
Colorado	$	18,100	$	18,244		$	16,400
Nebraska	54,996		53,367			46,982
Iowa	44,134		42,961			39,561
Kansas	32,809		32,111			28,734
Total Residential	150,039		146,683			131,677

Commercial:
Colorado	3,048		3,009			2,680
Nebraska	11,708		11,560			10,201
Iowa	13,206		13,060			11,071
Kansas	8,115		7,436			6,097
Total Commercial	36,077		35,065			30,049

Industrial:
Colorado	464		519			581
Nebraska	239		250			249
Iowa	294		321			257
Kansas	2,336		2,220			2,362
Total Industrial	3,333		3,310			3,449

Other:
Colorado	118		(17		)	181
Nebraska	2,441		2,266			2,066
Iowa	724		543			452
Kansas	1,990		1,723			4,787
Total Other Sales Margins	5,273		4,515			7,486

Distribution:
Colorado	21,730		21,755			19,842
Nebraska	69,384		67,443			59,498
Iowa	58,358		56,885			51,341
Kansas	45,250		43,490			41,980
Total Distribution	194,722		189,573			172,661

Transportation:
Colorado	968		1,033			866
Nebraska	14,272		12,943			10,589
Iowa	4,934		4,809			4,128
Kansas	7,448		6,472			5,762
Total Transportation	27,622		25,257			21,345

Total Regulated Gross Margin:
Colorado	22,698		22,788			20,708
Nebraska	83,656		80,386			70,087
Iowa	63,292		61,694			55,469
Kansas	52,698		49,962			47,742
Total Regulated Gross Margin	222,344		214,830			194,006

Non-regulated Services	14,572		14,396			14,726

Total Gross Margin	$	236,916	$	229,226		$	208,732



Distribution Quantities Sold and Transportation (in Dth)	2014	2013	2012
Residential:
Colorado	6,718,508	6,969,741	5,869,817
Nebraska	13,068,132	12,717,565	9,555,073
Iowa	12,172,281	11,359,220	8,732,301
Kansas	7,313,273	7,174,085	5,681,199
Total Residential	39,272,194	38,220,611	29,838,390

Commercial:
Colorado	1,537,704	1,506,227	1,284,082
Nebraska	4,644,645	4,770,370	3,952,067
Iowa	7,182,173	7,056,978	5,304,162
Kansas	3,043,685	2,867,696	2,121,063
Total Commercial	16,408,207	16,201,271	12,661,374

Industrial:
Colorado	354,630	405,047	463,566
Nebraska	122,662	150,227	158,445
Iowa	630,912	648,173	492,633
Kansas	3,384,797	3,355,930	3,675,678
Total Industrial	4,493,001	4,559,377	4,790,322

Wholesale and Other:
Kansas	150,014	116,234	68,419
Total Wholesale and Other	150,014	116,234	68,419

Distribution Quantities Sold:
Colorado	8,610,842	8,881,015	7,617,465
Nebraska	17,835,439	17,638,162	13,665,585
Iowa	19,985,366	19,064,371	14,529,096
Kansas	13,891,769	13,513,945	11,546,359
Total Distribution Quantities Sold	60,323,416	59,097,493	47,358,505

Transportation:
Colorado	950,819	1,015,791	850,156
Nebraska	30,669,764	28,171,610	26,649,759
Iowa	19,959,462	20,176,525	18,294,228
Kansas	15,883,098	14,457,620	14,686,679
Total Transportation	67,463,143	63,821,546	60,480,822

Total Distribution Quantities Sold and Transportation:
Colorado	9,561,661	9,896,806	8,467,621
Nebraska	48,505,203	45,809,772	40,315,344
Iowa	39,944,828	39,240,896	32,823,324
Kansas	29,774,867	27,971,565	26,233,038
Total Distribution Quantities Sold and Transportation	127,786,559	122,919,039	107,839,327



Customers at End of Year	2014	2013	2012
Residential:
Colorado	72,360	70,410	68,927
Nebraska	180,014	178,389	176,953
Iowa	138,503	137,525	135,897
Kansas	99,359	99,315	98,516
Total Residential	490,236	485,639	480,293

Commercial:
Colorado	3,788	3,737	3,681
Nebraska	15,900	15,739	15,626
Iowa	15,303	15,418	15,398
Kansas	10,547	9,832	9,584
Total Commercial	45,538	44,726	44,289

Industrial:
Colorado	205	207	213
Nebraska	147	136	136
Iowa	90	94	94
Kansas	1,277	1,358	1,261
Total Industrial	1,719	1,795	1,704

Transportation:
Colorado	34	36	36
Nebraska	4,151	4,240	4,115
Iowa	418	421	412
Kansas	1,145	1,171	1,166
Total Transportation	5,748	5,868	5,729

Wholesale:
Kansas	8	7	7
Total Wholesale	8	7	7

Total Customers:
Colorado	76,387	74,390	72,857
Nebraska	200,212	198,504	196,830
Iowa	154,314	153,458	151,801
Kansas	112,336	111,683	110,534
Total Customers at End of Year	543,249	538,035	532,022

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, there has been no material impact to 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	7.93%	Global Settlement	$440.2	6/2013	ECA, TCA, Energy Efficiency Cost Recovery/DSM	65%
	SD		8.16%			6/2011	Environmental Improvement Cost Recovery Adjustment Tariff	N/A
	MT	15.0%	11.7%	47%/53%		1983	ECA	N/A
	FERC	10.8%	9.1%	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%	8.4%	50%/50%	$64.0	12/2012	GCA, Energy Efficiency Cost Recovery/DSM	N/A
Nebraska Gas	NE	10.1%	9.1%	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:

•

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. Until October 1, 2014, at Cheyenne Light, our pass-through sharing mechanism relating to transmission and the PCA, returned 85% to the customer, and the Company retained 15%. Effective October 1, 2014, coal and coal related costs are passed through under an 85% / 15% distribution methodology, and purchased power costs, transmission, and natural gas costs are passed through under a 95% / 5% distribution methodology.

•

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 65% of off-system power marketing operating income. The modification also adjusts the 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.


•	In South Dakota, we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011, which recovers costs associated with generation plant environmental improvements.


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


•	We have an approved FERC Transmission Tariff that determines the revenue component of Cheyenne Light’s open access transmission tariff.

•

In Colorado, we have a quarterly ECA rider (the rider was semi-annual until August 1, 2013) 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%). Through 2013, this sharing percentage allowed 75% to the customers. 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.


•	On December 19, 2014, Colorado Electric received approval from the CPUC to implement a rider effective January 1, 2015 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.

Pending 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
Cheyenne Light ^(a)	Electric/Gas	12/2013	10/2014	$	14.1	$	9.2
Black Hills Power^(b)	Electric	1/2014	10/2014	$	2.8	$	2.2
Black Hills Power^(c)	Electric	3/2014	10/2014	$	14.6	pending
Iowa Gas ^(d)	Gas	2/2014	4/2014	$	0.5	$	0.5
Kansas Gas ^(e)	Gas	4/2014	1/2015	$	7.3	$	5.2
Colorado Electric ^(f)	Electric	4/2014	1/2015	$	4.0	$	3.1

____________________

(a)

On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 54% equity and 46% debt. The WPSC’s decision provides Cheyenne Light 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.

(b)

On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt. The WPSC’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.

(c)

On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. We expect a final decision from the SDPUC on our rate request by the end of the first quarter of 2015. Interim rates will be trued up as necessary based on the final approval.


(d)	On April 15, 2014, the IUB approved a capital investment recovery surcharge increase of $0.5 million.


(e)	On April 29, 2014, Kansas Gas filed a rate request with the KCC to increase annual revenue to recover infrastructure and increased operating costs. On October 24, 2014, a settlement agreement was reached between Kansas Gas, the KCC and intervenors to increase base rates by $5.2 million. On December 16, 2014, Kansas Gas received approval from the KCC to increase base rates by $5.2 million.

(f)

On April 30, 2014, Colorado Electric filed a rate request with the CPUC to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The filing also requested to implement a rider 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. On December 19, 2014, Colorado Electric received approval from the CPUC 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 the rider.

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, 2014, 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 May 5, 2014, Colorado Electric issued an all-source generation request for approximately 42 MW of summer seasonal firm capacity in 2017, 2018 and 2019 and up to 60 MW of eligible renewable energy resources to serve its customers in southern Colorado. Colorado IPP submitted solar and wind bids in response to this request. On December 23, 2014, the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that Colorado IPP’s bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration.

•

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 millions)
2015	$	2.9
2016	3.5
2017	1.9
Total	$	8.3

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. The EPA has a September 2015 deadline to issue a final regulation. These rules may have an impact on the Wyodak Plant, potentially requiring a modification to the methods of handling coal ash. 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 2044. 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 2015. The Pueblo Airport Generating Station Title V application was filed in September 2012, with the permit expected in 2015. The Cheyenne Prairie Generating Station Title V application will be submitted in 2015. All applications were or will be 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 have a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain very 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. Neil Simpson II, Wygen II, Wygen III and the Wyodak plant are expected to be in compliance with MATS by the compliance deadline, without incurring significant costs.

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 2015 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.

On December 17, 2014, the EPA proposed a more stringent ozone ambient air standard. This rule is expected to be finalized in October 2015. If the lower range of the proposed standard is selected, it is anticipated the Gillette and Cheyenne, Wyoming regions would be non-attainment areas. Also, the Colorado front-range non-attainment area is expected to be expanded. Under those conditions, the states could evaluate our projects for further reductions in NO_x emissions.

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 have converted startup fuel from diesel to natural gas to support start-up requirements and future Greenhouse Gas 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 in the next required revisions due in 2016, Neil Simpson II will be included. Ben French, Osage and Neil Simpson I were permanently retired on March 21, 2014.

In the 2010 legislative session, the State of Colorado passed House Bill 1365, the Colorado Clean Air Clean Jobs Act, a coordinated utility plan to reduce air emissions from coal fired power plants and promote the use of natural gas and other low emitting resources. One purpose of this Act was to require utilities to consider a spectrum of regulations when evaluating their emission reduction plans, with the final package ultimately comprising Colorado's Regional Haze Plan that would be submitted to EPA for approval. As required by the Act, we retired the W.N. Clark facility on December 31, 2013.

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	NA	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.

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. Since there are no emission standards or caps currently in place, we cannot predict how this requirement will impact our existing facilities upon permit renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emission control practices and technologies.

Wyoming passed GHG legislation in 2012 and 2013, enabling the state to implement the EPA’s GHG program. Wyoming adopted and submitted a GHG regulatory program to the EPA, which the EPA approved and published in the November 22, 2013 Federal Register. As of December 23, 2013, Wyoming has full jurisdiction over the GHG permitting program which includes the transfer of the Cheyenne Prairie EPA GHG air permit, to the state of Wyoming. This eliminates the increased time, expense and considerable risk of obtaining a permit from the EPA.

The EPA was expected to finalize the first GHG emission standards for new steam electric generating units by the end of 2014. This rule, with its very low proposed CO₂ emissions standards, effectively prohibits new coal-fired power plants from being constructed until carbon capture and sequestration becomes technically and economically feasible. It also restricts simple-cycle natural gas turbines to one-third of their generating capacity based on a three-year average. The rule has not yet been finalized and may be delayed to coincide with the existing source rule finalization in June 2015.

On June 2, 2014, the EPA proposed the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation and increase the utilization of existing gas generation, increase renewable energy and demand side management. This rule, expected to be final in June 2015, could have a significant impact on our coal and natural gas generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. While we cannot predict the terms of the regulation, any federally mandated GHG reductions or limits on CO₂ emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows.

In 2014, we reported 2013 GHG emissions from our Power Generation and Gas Utilities in order to comply with the EPA’s GHG Annual Inventory regulation, issued in 2009. We continue to report annual GHG emissions as required by the EPA. In addition to federal legislative activity, GHG regulations have been proposed in various states and alleged climate change issues are the subject of a number of lawsuits, the outcome of which could impact the utility industry. We will continue to review GHG impacts as legislation or regulation develops and litigation is resolved.

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 and the closure of certain generating facilities. 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 customers and other purchasers of the power generated by our non-regulated power plants, including utility affiliates. Any unrecovered costs could have a material impact on our results of operations, financial position or cash flows. 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.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Under state permits, we dispose of all solid wastes collected as a result of burning coal at our power plants in approved solid waste disposal sites. Ash and waste from flue gas and sulfur removal from the Ben French, Wyodak, Neil Simpson I, Neil Simpson II, Wygen II and Wygen III plants are deposited in mined areas at the WRDC coal mine. These disposal areas are currently located below some shallow water aquifers in the mine. In 2009, the State of Wyoming confirmed its past approval of this practice but may re-evaluate and limit ash disposal to mined areas that are above groundwater aquifers. This change would increase disposal costs, which cannot be quantified until the exact requirements are known. None of the solid waste from the burning of coal is currently classified as hazardous material, but the waste does contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. We conducted investigations which concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality.

We permanently retired the Osage power plant on March 21, 2014. This plant had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed and the state issued an approval of closure activities on October 21, 2014. Post-closure monitoring activities will continue for 30 years. In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work has been completed and the state issued an approval of closure activities on October 21, 2014. Post closure monitoring will continue for 30 years. As of August 31, 2012, we suspended operations at Ben French and the plant was permanently retired on March 21, 2014. The Ben French temporary ash holding area was closed in accordance with state guidelines, with the state issuing a closure certification on March 14, 2014.

Our W.N. Clark plant, which suspended operations on December 31, 2012 and was retired on December 31, 2013, sent coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.

For our Pueblo Airport Generation Station in Pueblo, Colorado, we posted a bond with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility.

Agreements are in place that requires PacifiCorp and MEAN to be responsible for any costs related to the solid waste from their ownership interest in the Wyodak plant and Wygen I plant, respectively. As operator of Wygen III, Black Hills Power has a similar agreement in place for any such costs related to solid waste from Wygen III. Under their separate but related operating agreement, Black Hills Power, MDU and the City of Gillette each share the costs for solid waste from Wygen III according to their respective ownership interests.

Additional unexpected material costs could also result in the future if any regulatory agency determines that solid waste from the burning of coal contains a hazardous material that requires special treatment, including previously disposed solid waste. In that event, the regulatory authority could hold entities that dispose of such waste responsible for remedial treatment. On December 19, 2014, the EPA Administrator signed coal ash regulations designating coal ash as a solid waste. These regulations are not applicable to our operations as all our coal ash is used as mine backfill. However, we are reviewing the requirements as it is expected the U.S. Office of Surface Mining will eventually develop their own regulations, potentially using these requirements as a guide.

Manufactured Gas Processing

Some 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.

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for a $1.0 million insurance recovery, now valued at approximately $1.3 million, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas received $1.9 million from the successor to the operator for Nebraska Gas to remediate two sites in Nebraska (Blair and Plattsmouth). The successor is responsible for remediation activity at the two remaining sites in Nebraska (Columbus and Norfolk). Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska’s Voluntary Cleanup Program. Site remediation was completed in September 2012. Both Nebraska sites will be required to monitor groundwater quality for a minimum two-year period ending in 2015.

As of December 31, 2014, we estimate a range of approximately $2.7 million to $6.3 million to remediate the MGP site in Council Bluffs, Iowa, of which we could be responsible for up to 25% of the costs. In 2014, we began the process of evaluating legal and corporate successorship avenues for cost recovery from other potential responsible parties. At this time no parties have been formally named nor have we determined the degree to which they are responsible. There are currently no regulatory requirements or deadlines for cleanup.

As part of the Aquila Transaction, we also acquired the former Lawrence, Kansas MGP site which was partially addressed through a removal action conducted in the early 2000s under the supervision of the Kansas Department of Health and Environment. An existing warehouse that is the last remnant of the former MGP site will be removed in 2015 to enable environmental characterization of the area beneath the building. We estimate remaining site activities will not exceed $150,000.

Prior to Black Hills Corporation’s ownership, Aquila received rate orders that approved recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of current and future remediation costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.