Edgar Filing: BLACK HILLS CORP /SD/

BKH 10K 12 31 2013

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, 2013



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. o

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, 2013 $2,135,998,459

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, 2014
Common stock, $1.00 par value	44,503,454	shares

Documents Incorporated by Reference

Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2014 Annual Meeting of Stockholders to be held on April 29, 2014, 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	6

		FORWARD-LOOKING INFORMATION	7
Part I
	ITEMS 1. and 2.	BUSINESS AND PROPERTIES	8

	ITEM 1A.	RISK FACTORS	51

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	64

	ITEM 3.	LEGAL PROCEEDINGS	64

	ITEM 4.	SPECIALIZED DISCLOSURES	64
Part II
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	64

	ITEM 6.	SELECTED FINANCIAL DATA	66

	ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	69

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	113

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	189

	ITEM 9A.	CONTROLS AND PROCEDURES	189

	ITEM 9B.	OTHER INFORMATION	189
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	191

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	191

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	191

		SIGNATURES	203

		INDEX TO EXHIBITS	204

GLOSSARY OF TERMS AND ABBREVIATIONS

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



AFUDC	Allowance for Funds Used During Construction
AltaGas	AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCI	Accumulated Other Comprehensive Income
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by the FASB
ATRA	American Taxpayer Relief Act of 2012
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 currently being constructed in Cheyenne, Wyo. by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 megawatt facility in 2014.
City of Gillette	The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23 percent 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
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
Equity Forward Agreement	Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,413,519 million shares of Black Hills Corporation common stock, including the over-allotment shares
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.
Idaho generating facilities	Partnership investment owned 50 percent by Black Hills Electric Generation, sold Jan. 18, 2011
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
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
NA	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 (7 Gallons equals 1 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
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
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
RCRA	Resource Conservation and Recovery Act
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 2017
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.
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 percent 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)
VEBA	Voluntary Employee Benefit Association
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

Website Access to Reports

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

Forward-Looking Information

This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

PART I


ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

History and Organization

Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a growth-oriented, vertically-integrated energy company headquartered in Rapid City, S.D. 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 203,500 electric customers in South Dakota, Wyoming, Colorado and Montana and also distributes natural gas to approximately 35,500 gas utility customers of Cheyenne Light in and around Cheyenne, Wyo. Our Gas Utilities segment serves approximately 538,000 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 790 megawatts of generation and 8,599 miles of electric transmission and distribution lines, and our Gas Utilities own 604 miles of intrastate gas transmission pipelines and 19,998 miles of gas distribution mains and service lines. Our Utilities Group generated net income of $85 million for the year ended Dec. 31, 2013, and had total assets of $3.3 billion at Dec. 31, 2013.

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, Wyo., and sells the coal primarily under long-term contracts to 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 $18 million for the year ended Dec. 31, 2013, and had total assets of $0.5 billion at Dec. 31, 2013.

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 Feb. 29, 2012, we sold Enserco, representing our entire Energy Marketing segment, which resulted in this segment being classified 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 203,500 customers; and also distribute natural gas to approximately 35,500 natural gas utility customers of Cheyenne Light in or around Cheyenne, Wyo. 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 538,000 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 62,000 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.

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 megawatts)
	2013		2012		2011
	Summer	Winter	Summer	Winter	Summer	Winter
Black Hills Power	422	403	449	362	452	408
Cheyenne Light	185	192	187	174	181	175
Colorado Electric	381	280	400	284	392	297
Total Electric Utilities Peak Demands	988	875	1,036	820	1,025	880

Regulated Power Plants

As of Dec. 31, 2013, 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⁾:
Wygen III⁽²⁾	Coal	Gillette, Wyo.	52%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyo.	100%	90.0	1995
Wyodak ⁽³⁾	Coal	Gillette, Wyo.	20%	72.4	1978
Osage ⁽⁴⁾	Coal	Osage, Wyo.	100%	34.5	1948-1952
Ben French ⁽⁴⁾	Coal	Rapid City, S.D.	100%	25.0	1960
Neil Simpson I ⁽⁴⁾	Coal	Gillette, Wyo.	100%	21.8	1969
Neil Simpson CT	Gas	Gillette, Wyo.	100%	40.0	2000
Lange CT	Gas	Rapid City, S.D.	100%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, S.D.	100%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, S.D.	100%	80.0	1977-1979
Cheyenne Light ⁽¹⁾:
Wygen II	Coal	Gillette, Wyo.	100%	95.0	2008
Colorado Electric ⁽⁵⁾:
Busch Ranch Wind Farm⁽⁶⁾	Wind	Pueblo, Colo.	50%	14.5	2012
Pueblo Airport Generation	Gas	Pueblo, Colo.	100%	180.0	2011
AIP Diesel	Oil	Pueblo, Colo.	100%	10.0	2001
Diesel #1-5	Oil	Pueblo, Colo.	100%	10.0	1964
Diesel #1-5	Oil	Rocky Ford, Colo.	100%	10.0	1964
Total Megawatt Capacity				790.4

________________________

(1)

Construction of a 132 megawatt gas-fired power generation facility is underway to support the customers of Black Hills Power and Cheyenne Light. The facility will include one simple-cycle, 37 megawatt combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 megawatt unit that will be jointly owned by Cheyenne Light (40 megawatts) and Black Hills Power (55 megawatts). This facility is expected to be completed in the fourth quarter of 2014.


(2)	Wygen III, a 110 megawatt mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power has a 52 percent ownership interest, MDU owns 25 percent and the City of Gillette owns the remaining 23 percent interest. Our WRDC coal mine supplies all of the fuel for the plant.


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

(4)

Operations at Osage were suspended Oct. 1, 2010, and Ben French was suspended on Aug. 31, 2012, due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. Osage, Ben French and Neil Simpson I will be retired on or before March 21, 2014. While the net book value of these plants is estimated to be immaterial at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates and costs will be deferred as Regulatory assets on the accompanying Consolidated Balance Sheets.


(5)	Colorado Electric’s W.N. Clark (42 megawatts) and Pueblo Units #5 and #6 (29 megawatts) were retired as of Dec. 31, 2013.


(6)	Busch Ranch Wind Farm, a 29 megawatt wind farm, is operated by Colorado Electric. Colorado Electric has a 50 percent ownership interest in the wind farm and AltaGas owns the remaining 50 percent. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 megawatts of power from the wind farm. The wind farm became operational Oct. 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 megawatt-hour for the years ended Dec. 31 is as follows:



Fuel Source (dollars per megawatt-hour)	2013		2012		2011
Coal	$	10.89	$	14.42	$	15.89

Natural Gas	$	53.53	$	52.08	$	74.64

Diesel Oil	$	233.47	$	280.29	$	405.47

Total Average Fuel Cost	$	14.65	$	16.05	$	16.77

Purchased Power - Coal, Gas and Oil	$	29.95	$	26.70	$	28.80

Purchased Power - Renewable Sources	$	49.20	$	47.45	$	46.71

Our Electric Utilities’ power supply, by resource as a percent of the total power supply for our energy needs for the years ended Dec. 31 is as follows:



Power Supply	2013		2012		2011
Coal	36	%	37	%	38	%
Gas, Oil and Wind	4		2		—
Total Generated	40		39		38
Purchased	60		61		62
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 Dec. 31, 2023, which provides for the purchase of 50 megawatts of coal-fired baseload power;


•	Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031, which provides 200 megawatts 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 Dec. 31, 2014, whereby Colorado Electric purchases between 25 megawatts and 50 megawatts of economy energy based on various timing intervals throughout 2014;


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


•	Cheyenne Light’s PPA with Black Hills Wyoming expiring on Aug. 31, 2014, whereby Black Hills Wyoming provides 40 megawatts of energy and capacity from its Gillette CT;

•

Cheyenne Light’s PPA with Black Hills Wyoming expiring on Dec. 31, 2022, whereby Black Hills Wyoming provides 60 megawatts 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 megawatt adjusted for capital additions and reduced by depreciation over a 35 year life beginning Jan. 1, 2009 (approximately $5 million per year);


•	Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 3, 2028, which provides up to 29.4 megawatts of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility’s output to Black Hills Power;


•	Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 30, 2029, which provides up to 30 megawatts of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 megawatts 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 percent ownership 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 megawatts from its other generation facilities or from system purchases with reimbursement of costs by MDU;

•

The City of Gillette owns a 23 percent ownership 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 megawatts 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 megawatts 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:



2014-2017	20 megawatts - 10 megawatts contingent on Wygen III and 10 megawatts contingent on Neil Simpson II
2018-2019	15 megawatts - 10 megawatts contingent on Wygen III and 5 megawatts contingent on Neil Simpson II
2020-2021	12 megawatts - 6 megawatts contingent on Wygen III and 6 megawatts contingent on Neil Simpson II
2022-2023	10 megawatts - 5 megawatts contingent on Wygen III and 5 megawatts contingent on Neil Simpson II;


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


•	Cheyenne Light’s agreement with Basin Electric, whereby Cheyenne Light will supply 40 megawatts of capacity and energy through Sept. 30, 2014, and a separate agreement whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014.

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 Dec. 31, 2013, our Electric Utilities owned the electric transmission and distribution lines shown below:



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
Black Hills Power	South Dakota, Wyoming	1,179	2,462
Black Hills Power - Jointly Owned ⁽¹⁾	South Dakota, Wyoming	44	—
Cheyenne Light	South Dakota, Wyoming	25	1,246
Colorado Electric	Colorado	581	3,062

__________________________

(1)

Black Hills Power owns 35 percent 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 percent 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 megawatts from West to East, and 200 megawatts 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 megawatts 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, Wyo., 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.


•	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	2013		2012		2011
	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	7,582	9%	6,206	(13)%	7,579	5%
Cheyenne Light	7,386	4%	6,304	(11)%	7,321	(1)%
Colorado Electric	5,740	1%	4,921	(13)%	5,749	3%
Combined ^(a)	6,691	5%	5,629	(12)%	6,675	4%

Cooling Degree Days:
Black Hills Power	724	8%	937	47%	700	17%
Cheyenne Light	520	48%	568	63%	431	58%
Colorado Electric	1,230	28%	1,322	47%	1,259	37%
Combined (^a)	918	24%	1,043	47%	908	33%

________________

(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)	2013		2012		2011
Residential:
Black Hills Power	$	64,566	$	58,523	$	59,826
Cheyenne Light	35,778		32,053		31,287
Colorado Electric ^(a)	95,631		91,550		84,646
Total Residential	195,975		182,126		175,759

Commercial:
Black Hills Power	80,289		73,858		72,889
Cheyenne Light	57,444		55,600		55,331
Colorado Electric	87,732		82,849		73,355
Total Commercial	225,465		212,307		201,575

Industrial:
Black Hills Power	27,705		25,656		25,723
Cheyenne Light	20,803		16,105		11,629
Colorado Electric	38,037		37,540		33,332
Total Industrial	86,545		79,301		70,684

Municipal:
Black Hills Power	3,421		3,268		3,172
Cheyenne Light	1,918		1,807		1,765
Colorado Electric	13,106		13,373		12,912
Total Municipal	18,445		18,448		17,849

Subtotal Retail Revenue - Electric	526,430		492,182		465,867

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	21,956		20,290		18,105

Off-system/Power Marketing Wholesale:
Black Hills Power	29,580		31,905		34,889
Cheyenne Light	8,712		8,365		9,371
Colorado Electric ^(b)	8,329		6,003		13,018
Total Off-system/Power Marketing Wholesale	46,621		46,273		57,278

Other Revenue: ^(c)
Black Hills Power	26,510		29,809		31,027
Cheyenne Light	1,916		2,336		2,449
Colorado Electric	4,612		4,652		2,787
Total Other Revenue	33,038		36,797		36,263

Total Revenue - Electric	$	628,045	$	595,542	$	577,513

_____________________


(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)	Off-system sales revenue during part of 2010 was deferred until a sharing mechanism was approved by the CPUC in December 2011. As a result, Colorado Electric had deferred $8.4 million in off-system revenue which was all recognized in December 2011.


(c)	Other revenue primarily consists of transmission revenue.



Quantities Generated and Purchased (megawatt-hour)	2013	2012	2011
Generated -
Coal-fired:
Black Hills Power	1,768,483	1,796,936	1,717,008
Cheyenne Light	688,318	587,832	674,518
Colorado Electric ^(a)	—	222,647	268,317
Total Coal - fired	2,456,801	2,607,415	2,659,843

Natural Gas and Oil:
Black Hills Power	33,374	33,183	15,221
Cheyenne Light	—	—	—
Colorado Electric	247,758	84,874	2,342
Total Natural Gas and Oil	281,132	118,057	17,563

Wind:
Colorado Electric	45,765	12,433	—
Total Wind	45,765	12,433	—

Total Generated:
Black Hills Power	1,801,857	1,830,119	1,732,229
Cheyenne Light	688,318	587,832	674,518
Colorado Electric	293,523	319,954	270,659
Total Generated	2,783,698	2,737,905	2,677,406

Purchased -
Black Hills Power	1,441,286	1,678,090	1,720,640
Cheyenne Light	779,677	807,659	745,983
Colorado Electric	1,886,627	1,794,229	1,948,321
Total Purchased ^(b)	4,107,590	4,279,978	4,414,944

Total Generated and Purchased	6,891,288	7,017,883	7,092,350

_______________


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


(b)	Includes wind power of 222,069 megawatt-hours, 199,079 megawatt-hours and 189,255 megawatt-hours in 2013, 2012 and 2011, respectively.



Quantities (megawatt-hour)	2013	2012	2011
Residential:
Black Hills Power	555,204	532,342	550,935
Cheyenne Light	272,490	261,792	264,492
Colorado Electric	619,857	614,521	629,752
Total Residential	1,447,551	1,408,655	1,445,179

Commercial:
Black Hills Power	730,701	731,785	720,978
Cheyenne Light	544,636	577,141	601,162
Colorado Electric	703,604	723,216	720,060
Total Commercial	1,978,941	2,032,142	2,042,200

Industrial:
Black Hills Power	404,009	407,301	408,337
Cheyenne Light	281,727	224,448	172,840
Colorado Electric	371,102	358,490	351,862
Total Industrial	1,056,838	990,239	933,039

Municipal:
Black Hills Power	34,344	35,933	34,235
Cheyenne Light	9,848	9,631	9,827
Colorado Electric	114,732	121,480	126,320
Total Municipal	158,924	167,044	170,382

Subtotal Retail Quantity Sold	4,642,254	4,598,080	4,590,800

Contract Wholesale:
Total Contract Wholesale - Black Hills Power	357,193	340,036	349,520

Off-system Wholesale:
Black Hills Power	1,002,847	1,263,457	1,226,548
Cheyenne Light	234,566	229,062	278,528
Colorado Electric	219,349	160,430	282,929
Total Off-system Wholesale	1,456,762	1,652,949	1,788,005

Total Quantity Sold:
Black Hills Power	3,084,298	3,310,854	3,290,553
Cheyenne Light	1,343,267	1,302,074	1,326,849
Colorado Electric	2,028,644	1,978,137	2,110,923
Total Quantity Sold	6,456,209	6,591,065	6,728,325

Other Uses, Losses or Generation, net ^(a):
Black Hills Power	158,845	197,355	162,316
Cheyenne Light	124,728	93,417	93,652
Colorado Electric	151,506	136,046	108,057
Total Other Uses, Losses and Generation, net	435,079	426,818	364,025

Total Energy	6,891,288	7,017,883	7,092,350

________________________


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



Customers at End of Year	2013	2012	2011
Residential:
Black Hills Power	55,840	55,296	54,955
Cheyenne Light	35,780	35,438	35,159
Colorado Electric	82,371	81,795	81,811
Total Residential	173,991	172,529	171,925

Commercial:
Black Hills Power	12,888	12,857	12,864
Cheyenne Light	4,471	4,276	4,277
Colorado Electric	11,060	11,220	11,206
Total Commercial	28,419	28,353	28,347

Industrial:
Black Hills Power	46	44	45
Cheyenne Light	3	2	2
Colorado Electric	61	61	68
Total Industrial	110	107	115

Other Electric Customers:
Black Hills Power	310	308	311
Cheyenne Light	232	240	243
Colorado Electric	469	475	506
Total Other Electric Customers	1,011	1,023	1,060

Subtotal Retail Customers	203,531	202,012	201,447

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

Total Customers:
Black Hills Power	69,087	68,508	68,178
Cheyenne Light	40,486	39,956	39,681
Colorado Electric	93,961	93,551	93,591
Total Electric Customers at End of Year	203,534	202,015	201,450

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:



	2013		2012		2011
Revenue - Gas (in thousands):
Residential	$	23,047	$	19,327	$	22,044
Commercial	10,326		8,613		10,264
Industrial	3,050		2,715		3,597
Other Sales Revenue	840		769		913
Total Revenue - Gas	$	37,263	$	31,424	$	36,818

Gross Margin - Gas (in thousands):
Residential	$	12,706	$	10,712	$	10,426
Commercial	3,993		2,963		3,345
Industrial	598		551		504
Other Gross Margin	881		766		545
Total Gross Margin - Gas	$	18,178	$	14,992	$	14,820

Quantities Sold (Dth):
Residential	2,728,797		2,215,858		2,585,056
Commercial	1,653,021		1,447,522		1,538,616
Industrial	652,539		598,408		689,935
Total Quantities Sold	5,034,357		4,261,788		4,813,607

Gas Customers at Year-End	35,494		35,021		34,807

Gas Utilities Segment

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



System Infrastructure (in line miles) as of	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
Dec. 31, 2013	Intrastate Gas Transmission Pipelines	Gas Distribution Mains	Gas Distribution Service Lines
Colorado	126	3,011	917
Nebraska	44	3,468	3,509
Iowa	170	2,653	2,433
Kansas	264	2,701	1,306
Total	604	11,833	8,165

Degree Days



	2013		2012		2011
	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	6,310	1%	5,186	(18)%	5,991	(7)%
Nebraska	6,516	8%	5,198	(15)%	6,190	(1)%
Iowa	7,743	14%	6,093	(10)%	7,013	(4)%
Kansas ^(a)	5,294	8%	4,190	(15)%	4,954	(1)%
Combined^(b)	6,922	9%	5,518	(13)%	6,455	(3)%

________________


(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)	2013			2012		2011
Residential:
Colorado	$	53,296		$	48,406	$	58,102
Nebraska	122,197			98,339		125,493
Iowa	98,498			82,669		106,292
Kansas	67,501			55,096		65,185
Total Residential	341,492			284,510		355,072

Commercial:
Colorado	10,515			9,558		12,172
Nebraska	37,190			30,894		40,659
Iowa	47,494			36,550		46,179
Kansas	21,440			15,677		20,362
Total Commercial	116,639			92,679		119,372

Industrial:
Colorado	1,661			1,963		2,063
Nebraska	900			876		860
Iowa	3,436			2,458		2,521
Kansas	15,753			13,614		19,571
Total Industrial	21,750			18,911		25,015

Other:
Colorado	(17		)	181		96
Nebraska	2,265			2,066		1,971
Iowa	543			452		550
Kansas	2,326			5,124		3,031
Total Other Sales Revenue	5,117			7,823		5,648

Distribution:
Colorado	65,455			60,108		72,433
Nebraska	162,552			132,175		168,983
Iowa	149,971			122,129		155,542
Kansas	107,020			89,511		108,149
Total Distribution	484,998			403,923		505,107

Transportation:
Colorado	1,033			866		846
Nebraska	12,943			10,589		11,175
Iowa	4,809			4,128		3,935
Kansas	6,472			5,762		5,909
Total Transportation	25,257			21,345		21,865

Total Regulated Revenue	510,255			425,268		526,972

Non-regulated Services	29,434			28,813		27,612

Total Revenue	$	539,689		$	454,081	$	554,584



Gross Margin (in thousands)	2013			2012		2011
Residential:
Colorado	$	18,244		$	16,400	$	17,711
Nebraska	53,367			46,982		51,640
Iowa	42,961			39,561		47,491
Kansas	32,111			28,734		29,701
Total Residential	146,683			131,677		146,543

Commercial:
Colorado	3,009			2,680		2,960
Nebraska	11,560			10,201		11,643
Iowa	13,060			11,071		11,702
Kansas	7,436			6,097		6,603
Total Commercial	35,065			30,049		32,908

Industrial:
Colorado	519			581		450
Nebraska	250			249		217
Iowa	321			257		288
Kansas	2,220			2,362		2,373
Total Industrial	3,310			3,449		3,328

Other:
Colorado	(17		)	181		96
Nebraska	2,266			2,066		1,971
Iowa	543			452		549
Kansas	1,723			4,787		2,455
Total Other Sales Margins	4,515			7,486		5,071

Distribution:
Colorado	21,755			19,842		21,217
Nebraska	67,443			59,498		65,471
Iowa	56,885			51,341		60,030
Kansas	43,490			41,980		41,132
Total Distribution	189,573			172,661		187,850

Transportation:
Colorado	1,033			866		846
Nebraska	12,943			10,589		11,175
Iowa	4,809			4,128		3,935
Kansas	6,472			5,762		5,909
Total Transportation	25,257			21,345		21,865

Total Regulated Gross Margin:
Colorado	22,788			20,708		22,063
Nebraska	80,386			70,087		76,646
Iowa	61,694			55,469		63,965
Kansas	49,962			47,742		47,041
Total Regulated Gross Margin	214,830			194,006		209,715

Non-regulated Services	14,396			14,726		12,908

Total Gross Margin	$	229,226		$	208,732	$	222,623



Distribution Quantities Sold and Transportation (in Dth)	2013	2012	2011
Residential:
Colorado	6,969,741	5,869,817	6,437,860
Nebraska	12,717,565	9,555,073	12,076,979
Iowa	11,359,220	8,732,301	10,490,129
Kansas	7,174,085	5,681,199	6,853,163
Total Residential	38,220,611	29,838,390	35,858,131

Commercial:
Colorado	1,506,227	1,284,082	1,472,747
Nebraska	4,770,370	3,952,067	4,833,604
Iowa	7,056,978	5,304,162	6,192,167
Kansas	2,867,696	2,121,063	2,676,439
Total Commercial	16,201,271	12,661,374	15,174,957

Industrial:
Colorado	405,047	463,566	344,576
Nebraska	150,227	158,445	120,779
Iowa	648,173	492,633	409,723
Kansas	3,355,930	3,675,678	3,743,735
Total Industrial	4,559,377	4,790,322	4,618,813

Wholesale and Other:
Kansas	116,234	68,419	112,253
Total Wholesale and Other	116,234	68,419	112,253

Distribution Quantities Sold:
Colorado	8,881,015	7,617,465	8,255,183
Nebraska	17,638,162	13,665,585	17,031,362
Iowa	19,064,371	14,529,096	17,092,019
Kansas	13,513,945	11,546,359	13,385,590
Total Distribution Quantities Sold	59,097,493	47,358,505	55,764,154

Transportation:
Colorado	1,015,791	850,156	869,570
Nebraska	28,171,610	26,649,759	24,972,560
Iowa	20,176,525	18,294,228	18,358,692
Kansas	14,457,620	14,686,679	15,015,310
Total Transportation	63,821,546	60,480,822	59,216,132

Total Distribution Quantities Sold and Transportation:
Colorado	9,896,806	8,467,621	9,124,753
Nebraska	45,809,772	40,315,344	42,003,922
Iowa	39,240,896	32,823,324	35,450,711
Kansas	27,971,565	26,233,038	28,400,900
Total Distribution Quantities Sold and Transportation	122,919,039	107,839,327	114,980,286



Customers at End of Year	2013	2012	2011
Residential:
Colorado	70,410	68,927	67,496
Nebraska	178,389	176,953	176,386
Iowa	137,525	135,897	135,161
Kansas	99,315	98,516	98,043
Total Residential	485,639	480,293	477,086

Commercial:
Colorado	3,737	3,681	3,678
Nebraska	15,739	15,626	15,664
Iowa	15,418	15,398	15,398
Kansas	9,832	9,584	9,453
Total Commercial	44,726	44,289	44,193

Industrial:
Colorado	207	213	209
Nebraska	136	136	141
Iowa	94	94	94
Kansas	1,358	1,261	1,365
Total Industrial	1,795	1,704	1,809

Transportation:
Colorado	36	36	30
Nebraska	4,240	4,115	4,128
Iowa	421	412	393
Kansas	1,171	1,166	1,142
Total Transportation	5,868	5,729	5,693

Wholesale:
Kansas	7	7	7
Total Wholesale	7	7	7

Total Customers:
Colorado	74,390	72,857	71,413
Nebraska	198,504	196,830	196,319
Iowa	153,458	151,801	151,046
Kansas	111,683	110,534	110,010
Total Customers at End of Year	538,035	532,022	528,788

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. In the past, various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate, but none of these initiatives have been adopted to date, with the exception of Montana. 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	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	NA
	WY	10.5%	8.6%	48%/52%	$27.0	6/2010	ECA, TCA	50% subject to symmetrical deadband
	MT	15.0%	11.7%	47%/53%		1983	ECA	NA
	FERC	10.8%	9.1%	43%/57%		2/2009	FERC Transmission Tariff	NA
Cheyenne Light - Electric	WY	9.6%	8.0%	46%/54%	$243.5	7/2012	ECA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment	NA
Cheyenne Light - Gas	WY	9.6%	8.0%	46%/54%	$43.6	7/2012	GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery of Acquisition Adjustment	NA
Colorado Electric	CO	9.8%- 10.2%	8.5%	50.9%/49.1%	$405.7	1/2012	ECA, TCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment	75% through 2013; 90% thereafter

Gas Utilities:
Colorado Gas	CO	9.6%	8.4%	50%/50%	$64.0	12/2012	GCA, Energy Efficiency Cost Recovery/DSM	NA
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	NA
Kansas Gas	KS	Global Settlement	Global Settlement	49.3%/50.7%	$80.9	6/2007	GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA	NA
Iowa Gas	IA	Global Settlement	Global Settlement	Global Settlement	$110.2	2/2011	GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism	NA

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

Some of the mechanisms we have in place include the following:

•

In September 2013, the SDPUC approved a construction financing rider for Black Hills Power effective April 1, 2013, which allows for recovery of construction financing costs from customers during the construction period of Cheyenne Prairie in lieu of traditional AFUDC. The rider allows Black Hills Power to earn and collect a rate of return during the construction period on the total project cost that relates to South Dakota customers. This rider is similar to the rider approved by WPSC effective Nov. 1, 2012, which allows Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period of Cheyenne Prairie on approximately 60 percent of the total project cost that relates to Wyoming customers. These riders increased gross margin by approximately $6.9 million in 2013.

•

In Wyoming, Cheyenne Light has annual cost adjustment mechanisms that allow us to pass the prudently-incurred cost of fuel and purchased power through to electric customers. Until July 1, 2012, at Cheyenne Light, our pass-through mechanism relating to transmission and the ECA was subject to a $1.0 million threshold: we collected or refunded 95 percent of the increase or decrease that exceeded the $1.0 million threshold, and we absorbed the increase or retained the savings for costs below the threshold as well as the 5 percent not collected or refunded above the threshold. Effective July 1, 2012, the $1.0 million threshold and its accompanying 95/5 percent distribution methodology was eliminated and replaced by a sharing mechanism that returned 85 percent to the customer and allowed the company to retain 15 percent.

•

In South Dakota, Black Hills Power has an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power 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 percent 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.

•

In Colorado, we have a quarterly ECA rider (the rider was semi-annual until Aug. 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, where the customer received 75 percent through 2013. This sharing percentage increases to 90 percent to the customers in 2014 and thereafter. 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 us an annual Transmission Cost Adjustment (TCA) rider, from which we recover nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism.

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 weather normalization tariff that provides a pass-through mechanism for weather margin variability that occurs from the level used to establish base rates to be paid by the customer, as well as tariffs that provide for more timely recovery for certain capital expenditures and fluctuations in property taxes.


•	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 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
Iowa Gas⁽¹⁾	Gas	12/2012	4/25/2013	$	0.9	$	0.2
Black Hills Power⁽²⁾	Electric	12/2012	6/16/2013	$	13.7	$	8.8
Black Hills Power ⁽³⁾	Electric	12/2012	4/1/2013	$	9.2	$	7.7
Nebraska Gas ⁽⁴⁾	Gas	8/2013	11/2013	$	1.4	$	1.4
Cheyenne Light ⁽⁵⁾	Electric/Gas	12/2013	pending	$	14.1	pending
Black Hills Power⁽⁶⁾	Electric	01/2014	pending	$	2.8	pending

(1)

Iowa Gas filed a request for a Capital Infrastructure Automatic Adjustment Mechanism with the IUB in December 2012, which reflected a request for recovery of costs since our prior rate case in 2010. On March 15, 2013, the IUB determined that certain capital infrastructure investments were not eligible for recovery through this mechanism and on March 26, 2013, Iowa Gas filed a revised proposed tariff. On April 15, 2013, the IUB approved a Capital Infrastructure Automatic Adjustment Mechanism effective April 25, 2013 for $0.2 million. This adjustment mechanism requires an annual filing. Therefore, subsequent filings will vary in size based on eligible infrastructure replacements and the timing of future general rate case filings.

(2)

In December 2012, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase of $13.7 million, or 9.94 percent, to recover investment in distribution and transmission lines, generation plant upgrades, environmental compliance and increased operating costs. On Sept. 17, 2013, the SDPUC approved a rate increase of $8.8 million, or 6.4 percent, effective June 16, 2013.

(3)

In December 2012, Black Hills Power filed a request with the SDPUC to use a construction financing rider during the construction of Cheyenne Prairie in lieu of traditional AFUDC. This rider is similar to the one approved by the WPSC in 2012 for Cheyenne Light and Black Hills Power for Wyoming customers. On Jan. 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, and on Sept. 17, 2013, the SDPUC approved the construction financing rider effective April 1, 2013. The rider allows Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40 percent share of the total project cost that relates to South Dakota customers.


(4)	In August 2013, Nebraska Gas filed with the NPSC an application requesting authority to establish an Infrastructure System Replacement Cost Recovery Charge mechanism. In an order dated Nov. 25, 2013, the NPSC approved a settlement with the Public Advocate that provided for a revenue increase of $1.4 million.


(5)	In December 2013, Cheyenne Light filed a rate case with the WPSC requesting electric and natural gas revenue increases of $12.8 million and $1.3 million, respectively, to recover investment in Cheyenne Prairie, existing infrastructure and increased operating costs. The filing seeks a return on equity of 10.25 percent and a capital structure of 54 percent equity and 46 percent debt.


(6)	In January 2014, Black Hills Power filed a rate case with the WPSC requesting an electric revenue increase of $2.8 million to recover investment in Cheyenne Prairie, existing infrastructure and increasing operating costs. The filing seeks a return on equity of 10.25 percent and a capital structure of 53 percent equity and 47 percent debt.

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 Dec. 31, 2013, 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 two percent 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) 12 percent of retail sales through 2014; (ii) 20 percent of retail sales from 2015 to 2019; and (iii) 30 percent of retail sales by 2020. Of these amounts, 3 percent 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 percent. 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. In 2014, our Colorado Electric subsidiary will conduct an all-source solicitation to acquire additional electricity which may include electricity from renewable energy resources. In 2014, our Colorado Electric subsidiary will also file its renewable energy standard plan with the CPUC for the years 2015 through 2017.

•

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. However, 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 percent 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, Black Hills Service Company 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)
2014	$	5.7
2015	4.5
2016	5.1
Total	$	15.3

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 stormwater 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, with an estimated implementation date of May 2014. 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 II, 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 2043. 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 and Pueblo Airport Generating Station. Wygen III and Pueblo Airport 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 2014. The Pueblo Airport Generating Station Title V application was filed in September 2012, with the permit expected in 2014. Both applications were filed in accordance with regulatory requirements.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates on Dec. 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule has 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 Aug. 31, 2012. We plan to permanently retire Osage, Ben French and Neil Simpson I on or before 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 Dec. 31, 2013. The W.N. Clark facility suspended operations Dec. 31, 2012, and was retired on Dec. 31, 2013, in accordance with the Colorado Clean Air Clean Jobs Act.

On Feb. 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.

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. 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 EPA’s GHG program. Wyoming adopted and submitted a GHG regulatory program to the EPA, which the EPA approved and published in the Nov. 22, 2013 Federal Register. As of Dec. 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.

On Jan. 8, 2014, the EPA re-proposed Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units. These standards may apply to the LM 6000 to be constructed by Colorado Electric at Pueblo Airport Generating Station that is currently under permit review. As proposed, the rule will limit simple-cycle turbines to one-third of their generating capacity based on a three-year average. We expect multiple revisions and legal actions before the final rule is issued, so we cannot be certain of impacts from this rule.

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 2014 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 our diesel generator engines were required to comply with the EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations were completed, emission control equipment was installed and emission testing confirmed compliance with those requirements.

The EPA is expected to propose a more stringent ozone ambient air standard in 2014. If the lower range of the proposed standard is selected, it is anticipated that Campbell County, Wyoming would be a non-attainment area. Under those conditions, the State of Wyoming may evaluate Neil Simpson II, Wygen II and Wygen III 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 will be converting startup fuel from diesel to natural gas. In the future the State of Wyoming may require similar changes to Wygen I and Wygen II.

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, some of our plants will be included. Ben French, Osage and Neil Simpson I will be permanently retired on or prior to March 21, 2014. If this was not the case, it is highly probable these plants along with Neil Simpson II, would be included in revised regulations.

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 Dec. 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 announced the suspension of operations and retirements for the following plants:



Plant	Company	Megawatts		Type of Plant	Date Suspended	Planned or Actual Retirement Date	Age of Plant (in years)
Osage	Black Hills Power		34.5	Coal	Oct. 1, 2010	March 21, 2014	64
Ben French	Black Hills Power		25.0	Coal	Aug. 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	Dec. 31, 2012	Dec. 31, 2013	57
Pueblo Unit #5	Colorado Electric		9.0	Gas	Dec. 31, 2012	Dec. 31, 2013	71
Pueblo Unit #6	Colorado Electric		20.0	Gas	Dec. 31, 2012	Dec. 31. 2013	63
	Total MW		152.3

In addition, Neil Simpson II is expected to be included in the Wyoming Regional Haze Plan update due to the EPA in 2016. The Wyodak Power Plant is included in EPA's currently proposed Regional Haze Federal Implementation Plan, which includes additional NOx controls. On Jan. 30, 2014, the EPA published the final Wyoming Regional Haze Federal Implementation Plan in the Federal Register, which requires significant NO_x control upgrades to be completed at the Wyodak Power Plant within five years. Our share of those costs is estimated at $20 million. We anticipate this ruling will be litigated.

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. The EPA intends to finalize the first GHG emission standards sometime in June 2014, which will apply to new steam electric generating units, as described above. 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 EPA will also be developing GHG emission standards for existing steam electric generating units. We expect the EPA to issue a proposed rule in 2014 and 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 2011, the EPA’s GHG Tailoring Rule went into effect, requiring GHG emissions to be addressed in new major source construction permits, and to be addressed upon renewal of Title V Operating Permits. 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. In 2013, we reported 2011 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.

As of Oct. 1, 2010, we suspended operations at the Osage power plant and it is scheduled to be retired on or before March 21, 2014. This plant has an on-site ash impoundment that is near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed and 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 post closure monitoring will continue for 30 years. As of Aug. 31, 2012, we suspended operations at Ben French, which is scheduled to close on or before March 21, 2014. We will also close Neil Simpson I on or before March 21, 2014.

Our W.N. Clark plant, which suspended operations on Dec. 31, 2012 and was retired on Dec. 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 site in Pueblo, Colo., 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 require 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 June 21, 2010, the EPA published its proposed coal combustion residuals regulations. The regulations are complex and contain various options for ash management that the EPA will select from to form the final version of the rule. We cannot determine the likely impact on our operations until the final version of the rule is known, which appears to be scheduled for some time in 2014. If ash becomes subject to regulations as a hazardous waste, implementation requirements could have a material impact on our financial position, results of operations or cash flows.

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 to end in September 2014.

As of Dec. 31, 2013, we estimate a range of approximately $2.9 million to $6.3 million to remediate the MGP site in Council Bluffs, Iowa, of which we could be responsible for up to 25 percent of the costs. There are potentially other responsible parties relating to the site in Council Bluffs, Iowa; however, at this time no parties have been named nor have we determined the degree to which they are responsible. There are currently no regulatory requirements or deadlines for cleanup.

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.

Non-regulated Energy Group

Our Non-regulated Energy Group, which operates through various subsidiaries, produces and sells electric capacity and energy through a portfolio of generating plants, produces and sells coal from our mine located in the Powder River Basin in Wyoming and acquires, explores for, develops and produces natural gas and crude oil primarily in the Rocky Mountain region. The Non-regulated Energy Group consists of three business segments for reporting purposes:


•	Power Generation


•	Coal Mining


•	Oil and Gas

Power Generation Segment

Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops and operates our non-regulated power plants. As of Dec. 31, 2013, we held varying interests in independent power plants operating in Wyoming and Colorado with a total net ownership of approximately 309 megawatts.

Portfolio Management

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

As of Dec. 31, 2013, the power plant ownership interests held by our Power Generation segment included:



Power Plants	Fuel Type	Location	Ownership Interest	Owned Capacity (MW)	In Service Date
Gillette CT	Gas	Gillette, Wyo.	100.0%	40.0	2001
Wygen I	Coal	Gillette, Wyo.	76.5%	68.9	2003
Pueblo Airport Generation ⁽¹⁾	Gas	Pueblo, Colo.	100.0%	200.0	2012
				308.9

_________________________


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

Black Hills Wyoming - Gillette CT. The Gillette CT is a simple-cycle, gas-fired combustion turbine located at our Gillette, Wyo., energy complex. The facility’s energy and capacity is sold to Cheyenne Light under a PPA that expires in August 2014. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical. On May 6, 2013, Black Hills Wyoming entered into an agreement to sell the Gillette CT to the City of Gillette, Wyo. The sale is expected to close in August 2014 upon the expiration of the existing PPA with Cheyenne Light. This sale is subject to FERC approval and certain other requirements included in the contract.

Black Hills Wyoming - Wygen I. The Wygen I generation facility is a mine-mouth, coal-fired power plant with a total capacity of 90 megawatts located at our Gillette, Wyo., energy complex. We own 76.5 percent of the plant and MEAN owns the remaining 23.5 percent. We sell 60 megawatts of unit contingent capacity and energy from this plant to Cheyenne Light under a PPA that expires on Dec. 31, 2022