BKH 10K 12 31 2011


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, 2011
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________________ to __________________
 
Commission File Number 001-31303
 
BLACK HILLS CORPORATION
Incorporated in South Dakota
625 Ninth Street
IRS Identification Number
 
Rapid City, South Dakota  57701
46-0458824
Registrant's telephone number, including area code
(605) 721-1700
 
 
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange
on which registered
Common stock of $1.00 par value
 
New York Stock Exchange

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

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

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes           x           No           o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes           x           No           o

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

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

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes           o           No           x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
 
At June 30, 2011                                  $1,169,775,169

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, 2012
Common stock, $1.00 par value
43,929,272

shares

Documents Incorporated by Reference
Portions of the Registrant's Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2012 Annual Meeting of Stockholders to be held on May 23, 2012, are incorporated by reference in Part III of this Form 10-K.





TABLE OF CONTENTS

 
 
 
  Page
 
 
 
GLOSSARY OF TERMS AND ABBREVIATIONS
 
 
 
 
 
 
 
 
ACCOUNTING PRONOUNCEMENTS
 
 
 
 
 
 
 
 
WEBSITE ACCESS TO REPORTS
 
 
 
 
 
 
 
 
FORWARD-LOOKING INFORMATION
 
Part I
 
 
 
 
 
ITEMS 1. and 2.
BUSINESS AND PROPERTIES
 
 
 
 
 
 
 
ITEM 1A.
RISK FACTORS
 
 
 
 
 
 
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS
 
 
 
 
 
 
 
ITEM 3.
LEGAL PROCEEDINGS
 
 
 
 
 
 
 
ITEM 4.
SPECIALIZED DISCLOSURES
 
Part II
 
 
 
 
 
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
 
 
 
 
 
 
ITEM 6.
SELECTED FINANCIAL DATA
 
 
 
 
 
 
 
ITEMS 7. and 7A.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
 
 
 
 
 
 
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
 
 
 
 
 
 
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
 
 
 
 
 
 
ITEM 9A.
CONTROLS AND PROCEDURES
 
 
 
 
 
 
 
ITEM 9B.
OTHER INFORMATION
 
Part III
 
 
 
 
 
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
 
 
 
 
 
 
ITEM 11.
EXECUTIVE COMPENSATION
 
 
 
 
 
 
 
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
 
 
 
 
 
 
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
 
 
 
 
 
 
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
 
 
 
 
 
 
 
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
 
 
 
 
 
 
 
SIGNATURES
 
 
 
 
 
 
 
 
INDEX TO EXHIBITS
 

2



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
AOCI
Accumulated Other Comprehensive Income
Aquila
Aquila, Inc.
Aquila Transaction
Our July 14, 2008 acquisition of five utilities from Aquila
ARO
Asset Retirement Obligations
Basin Electric
Basin Electric Power Cooperative
Bbl
Barrel
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
BHC
Black Hills Corporation; the Company
BHCCP
Black Hills Corporation Credit Policy
BHCRPP
Black Hills Corporation Risk Policies and Procedures
BHEP
Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
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

3




City of Gillette
The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23% of Wygen III power plant for the City of Gillette
CO2
Carbon dioxide
Colorado Electric
Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas
Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Cooling Degree Day
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees.  The warmer the climate, the greater the number of cooling degree days.  Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another.  Normal degree days are based on the National Weather Service data for selected locations over a 30 year average. 
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CT
Combustion turbine
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
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE
United States Department of Energy
Dth
Dekatherms
EBITDA
Earnings before interest, taxes, depreciation and amortization, a Non-GAAP measurement
ECA
Energy Cost Adjustment
Enserco
Enserco Energy Inc., a 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, Colorado 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
ERISA
Employee Retirement Income Security Act
EWG
Exempt Wholesale Generator
FASB
Financial Accounting Standards Board
FERC
United States Federal Energy Regulatory Commission
Fitch
Fitch Ratings
FTC
Federal Trade Commission
GAAP
Accounting principles generally accepted in the United States of America
GCA
Gas Cost Adjustment
GE
General Electric Company
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
Hastings
Hastings Fund Management Ltd

4



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. 
IGCC
Integrated Gasification Combined Cycle
IIF
IIF BH Investment LLC, a subsidiary of an investment entity advised by J.P. Morgan Asset Management
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 to affiliates of Hastings and IIF
IRS
United States Internal Revenue Service
IUB
Iowa Utilities Board
J.P. Morgan
J.P. Morgan Securities LLC
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
KCC
Kansas Corporation Commission
kV
Kilovolt
KW
Kilowatt
KWh
Kilowatt-hour
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
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
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
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
NOx
Nitrogen oxide

5



NOL
Net operating loss
NPA
Nebraska Power Association
NPDES
National Pollutant Discharge Elimination System
NPSC
Nebraska Public Service Commission
NQDC
Non-Qualified Deferred Compensation Plan initially adopted in 1999
NYMEX
New York Mercantile Exchange
OCA
Office of Consumer Advocate
OPEC
Organization of the Petroleum Exporting Countries
OSHA
Occupational Safety & Health Administration
PCA
Power Cost Adjustment
Peak demand
Peak demand represents the highest point of customer usage for a single hour
PGA
Purchased Gas Adjustment
PPA
Power Purchase Agreement
PPACA
Patient Protection and Affordable Care Act of 2010
PSCo
Public Service Company of Colorado
PUD
Proved undeveloped reserves
PUHCA 2005
Public Utility Holding Company Act of 2005
PURPA
Public Utility Regulatory Policies Act of 1978
RCRA
Resource Conservation and Recovery Act
Revolving Credit Facility
Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, originally expiring April 14, 2013. We entered into a new facility in February 2012 which expires in 2017.
S&S
Significant and Substantial as defined by Mine Safety Act
SCADA
Supervisory Control and Data Acquisition
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.
TCA
Transmission Cost Adjustment
Twin Eagle
Twin Eagle Resource Management, LLC
VEBA
Voluntary Employee Benefit Association
VIE
Variable Interest Entity
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



6



ACCOUNTING PRONOUNCEMENTS

ASC
Accounting Standards Codification
ASC 220
ASC 220, "Comprehensive Income"
ASC 820
ASC 820, "Fair Value Measurements and Disclosures"
ASC 932-10-S99
ASC 932-10-S99, "Extractive Activities - Oil and Gas, SEC Materials"
ASU
Accounting Standards Update
ASU 2011-04
ASU 2011-04, "Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS"
ASU 2011-05
ASU 2011-05, "Comprehensive Income: Presentation of Comprehensive Income"
ASU 2011-08
ASU 2011-08, "Intangibles - Goodwill and Other: Testing Goodwill for Impairment"
ASU 2011-12
ASU 2011-12, "Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05"
IFRS
International Financial Reporting Standards



7



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 Annual Report on Form 10-K includes "forward-looking statements" as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. These forward-looking statements are based on assumptions that we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the Risk Factors set forth in Item 1A of this Form 10-K and the other reports we file with the SEC from time to time, and the following:

Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidations and changes in competition, and (ii) general economic and political conditions, including tax rates or policies and inflation rates;

The timing, volatility and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets;

Our ability to comply, or to make expenditures required to comply, with changes in laws and regulations, particularly those relating to energy markets, taxation, safety and protection of the environment, and our ability to recover those expenditures in customer rates, where applicable;

Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, which may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain, or which could require closure of one or more of our generating units;

Changes in business, regulatory compliance and financial reporting practices and subsequent rules and regulations;

The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our activities to hedge our expected production of crude oil and natural gas and on our use of interest rate derivative instruments;

Changes in state laws or regulations that could cause us to curtail our business activities;

Our ability to successfully integrate and profitably operate any future acquisitions;

Our ability to successfully complete the sale of Enserco Energy Inc. to Twin Eagle Resource Management, LLC for net cash proceeds of approximately $160 million to $170 million, subject to working capital and other closing adjustments;

Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel, transportation, transmission and purchased power in our regulated utilities;


8



Our ability to receive regulatory approval to recover in rate base our expenditures for new power generation facilities or other utility infrastructure;

Our ability to recover our borrowing costs, including debt service costs, in our customer rates;

The extent of our success in connecting natural gas supplies to gathering, processing and pipeline systems;

Our ability to minimize losses related to defaults on amounts due from customers and counterparties, including counterparties to trading and other commercial transactions;

The timing and extent of scheduled and unscheduled outages of power generation facilities;

Our ability to complete the permitting, construction, start-up and operation of power generating facilities in a cost-effective and timely manner;

Our ability to accurately estimate demand from our customers for natural gas;

Weather and other natural phenomena;

Our ability to meet forecasted production volumes for our oil and gas properties, which may be dependent upon issuance by federal, state and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force and equipment, or the possibility of reductions in our drilling program resulting from the current economic climate and commodity prices, which also may prevent us from maintaining production rates and replacing reserves for our oil and gas properties;

The amount of collateral required to be posted from time to time in our transactions;

Our ability to effectively use derivative financial instruments to hedge commodity and interest rate risks;

Our ability to provide accurate estimates of proved oil and gas reserves, coal reserves and future production rates and associated costs;

Price risk due to marketable securities held as investments in employee benefit plans;

Our ability to successfully maintain our corporate credit rating;

The impact of the pending sale of Enserco Energy Inc., our non-regulated energy marketing business, on reducing our risk profile, improving our credit metrics and enhancing our ability to produce more stable cash flows and earnings;

Our ability to access revolving credit capacity and comply with loan covenants;

Capital market conditions and market uncertainties related to interest rates, which may affect our ability to raise capital on favorable terms;

The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock;

Our ability to continue paying our regular quarterly dividend;

Our ability to obtain permanent financing for capital expenditures on reasonable terms either through long-term debt or issuance of equity;

The effect of accounting policies issued periodically by accounting standard-setting bodies;

The accounting treatment and earnings impact associated with interest rate swaps;

The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

9




The possibility that we may be required to take impairment charges under the SEC's full cost ceiling test for the accumulated costs of our natural gas and oil reserves;

The outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements on our financial condition or results of operations;

Additional liabilities for environmental conditions, including remediation and reclamation obligations, under environmental laws;

Our ability to successfully complete labor negotiations with labor unions with which we have collective bargaining agreements and for which we are currently in, or are soon to be in, contract renewal negotiations; and

The cost and effect on our business, including insurance, resulting from terrorist actions and cyber-attacks or responses to such actions or events.


New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.


10



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" and "our"), is a diversified energy company headquartered in Rapid City, South Dakota. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941. It was formed through the purchase and combination of several existing electric utilities and related assets, some of which had served customers in the Black Hills region since 1883. In 1956, the Company began producing, selling and marketing various forms of energy through its non-regulated business.

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

For more than 15 years, we have also owned and operated an energy marketing business, Enserco, which engages in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. In the fourth quarter of 2011, we made the decision to sell Enserco, which constitutes our entire non-regulated Energy Marketing segment. On January 18, 2012, we entered into a definitive agreement to sell all of the outstanding stock of Enserco, which resulted in the Energy Marketing segment being reported as discontinued operations. This transaction is expected to close in the first quarter of 2012. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment to discontinued operations on a consistent basis. See Note 23 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

Business Group
Financial Segment
Utilities
Electric Utilities
 
Gas Utilities
 
 
Non-regulated Energy
Oil and Gas
 
Power Generation
 
Coal Mining

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 201,500 electric customers in South Dakota, Wyoming, Colorado and Montana and includes the operations of Cheyenne Light, a combination electric and gas utility, and its approximately 34,800 gas utility customers in Wyoming. Our Gas Utilities segment serves approximately 528,800 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 865 MWs of generation and 8,496 miles of electric transmission and distribution lines, and our Gas Utilities own 624 miles of intrastate gas transmission pipelines and 19,747 miles of gas distribution mains and service lines. Our Electric and Gas Utilities generated net income of $81.9 million for the year ended December 31, 2011 and had total assets of $3.0 billion at December 31, 2011.

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 Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy primarily to other utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyoming. Our Non-regulated Energy Group generated net income of $0.9 million for the year ended December 31, 2011 and had total assets of $0.6 billion at December 31, 2011.

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 17 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.


11



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 201,500 customers in South Dakota, Wyoming, Colorado and Montana. Additionally, Cheyenne Light distributes natural gas to approximately 34,800 natural gas utility customers in Wyoming. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

We conduct natural gas utility operations on a state-by-state basis through our Colorado Gas, Nebraska Gas, Iowa Gas and Kansas Gas subsidiaries. Our Gas Utilities distribute and transport natural gas through our distribution network to approximately 528,800 customers in Colorado, Nebraska, Iowa and Kansas. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

In addition to our regulated operations, we also provide non-regulated services through our Service Guard and Tech Services product lines. Service Guard primarily provides appliance repair services to approximately 63,000 residential customers through company technicians and third party service providers in Colorado, Iowa, Kansas and Nebraska most 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 MW)
 
 
 
 
 
 
 
 
 
 
 
 
 
2011
 
2010
 
2009
 
 
Summer
Winter
 
Summer
Winter
 
Summer
 
Winter
 
 
 
 
 
 
 
 
 
 
 
 
Black Hills Power
452
408
 
396
377
 
387
 
392
 
Cheyenne Light
181
175
 
176
164
 
169
 
171
 
Colorado Electric
392
297
 
384
289
 
365
 
296
 
Total Electric Utilities Peak Demands
1,025
880
 
956
830
 
921
 
859
 



12



Regulated Power Plants

As of December 31, 2011, our Electric Utilities' ownership interests in electric generation plants were as follows:

Unit
Fuel
Type
Location
Ownership
Interest %
Owned/Leased Capacity (MW)
Year
Installed
Black Hills Power:
 
 
 
 
 
Wygen III (1)
Coal
Gillette, WY
52.0%
57.2
2010
Neil Simpson II
Coal
Gillette, WY
100.0%
90.0
1995
Wyodak (2)
Coal
Gillette, WY
20.0%
72.4
1978
Osage (3)
Coal
Osage, WY
100.0%
34.5
1948-1952
Ben French
Coal
Rapid City, SD
100.0%
25.0
1960
Neil Simpson I
Coal
Gillette, WY
100.0%
21.8
1969
Neil Simpson CT
Gas
Gillette, WY
100.0%
40.0
2000
Lange CT
Gas
Rapid City, SD
100.0%
40.0
2002
Ben French Diesel #1-5
Oil
Rapid City, SD
100.0%
10.0
1965
Ben French CTs #1-4 (4)
Gas/Oil
Rapid City, SD
100.0%
100.0
1977-1979
Cheyenne Light:
 
 
 
 
 
Wygen II
Coal
Gillette, WY
100.0%
95.0
2008
Colorado Electric:
 
 
 
 
 
Pueblo Airport Generation
Gas
Pueblo, CO
100.0%
180.0
2011
Capital Lease - Colorado IPP (5)
Gas
Pueblo, CO
—%
200.0
2011
W.N. Clark #1-2 (6)
Coal
Canon City, CO
100.0%
40.0
1955, 1959
Pueblo #6
Gas
Pueblo, CO
100.0%
20.0
1949
Pueblo #5
Gas
Pueblo, CO
100.0%
9.0
1941, 2001
AIP Diesel
Oil
Pueblo, CO
100.0%
10.0
2001
Diesel #1-5
Oil
Pueblo, CO
100.0%
10.0
1964
Diesel #1-5
Oil
Rocky Ford, CO
100.0%
10.0
1964
Total MW Owned Capacity
 
 
 
1,064.9
 
________________________
(1)
Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power has a 52% ownership interest in Wygen III, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our WRDC coal mine furnishes all of the fuel supply for the plant.
(2)
Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by Black Hills Power. This baseload plant is operated by PacifiCorp and our WRDC coal mine furnishes all of the fuel supply for the plant.
(3)
Operations at the Osage plant were suspended October 1, 2010 due to the availability of more economical generation alternatives.
(4)
Upon expiration of the contract with PacifiCorp in June 2012 (see below), the capacity of these units will be decreased to 80 MW.
(5)
Colorado Electric entered into a 20-year PPA with Black Hills Colorado IPP for 200 MW of power from their gas-fired plants. This PPA, accounted for as a capital lease, was effective on January 1, 2012 upon completion of construction of the plants.
(6)
In December 2010, Colorado Electric received a final order from the CPUC that approved the retirement of its W.N. Clark coal-fired generation facility by December 31, 2013.


13



The following table shows the Electric Utilities' annual average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh (dollars per MWh):
Fuel Source
2011
2010
2009
Coal
$
15.89

$
12.77

$
13.99

 



Gas and Oil
$
150.00

$
131.28

$
85.52

 



Total Average Fuel Cost
$
16.77

$
13.57

$
15.22

 



Purchased Power - Coal, Gas and Oil
$
28.80

$
29.57

$
28.44

 
 
 
 
Purchased Power - Renewable Sources
$
46.71

$
45.76

$
43.66


The following table shows our Electric Utilities' power supply, by resource as a percent of the total power supply for our energy needs:
Power Supply
2011
2010
2009
Coal-fired
38
%
42
%
39
%
Gas and Oil


1

Total Generated
38

42

40

Purchased
62

58

60

Total
100
%
100
%
100
%

Purchased Power. Various agreements have been executed 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 in 2023, which provides for the purchase of 50 MW of coal-fired baseload power;

Black Hills Power's reserve capacity integration agreement with PacifiCorp expiring in June 2012, which makes available 100 MW of reserve capacity in connection with the utilization of the Ben French CT units;

Colorado Electric's PPA with Black Hills Colorado IPP expiring in 2031, which provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines;

Colorado Electric's PPA with PSCo expiring at December 31, 2012, whereby Colorado Electric purchases 50 MW of economy energy;

Colorado Electric's PPA with Cargill expiring at December 31, 2013, whereby Colorado Electric purchases 50 MW of economy energy;

Cheyenne Light's PPA with Black Hills Wyoming expiring in August 2014, whereby Black Hills Wyoming provides 40 MW of energy and capacity from its Gillette CT;

Cheyenne Light's PPA with Black Hills Wyoming expiring December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Cheyenne Light to purchase Black Hills Wyoming's ownership interest in the Wygen I facility between 2013 and 2019. The purchase price related to the option is $2.55 million per MW. This option price is reduced annually by an amount of annual depreciation assuming a facility life of 35 years;

Cheyenne Light's 20-year PPA with Duke Energy expiring in 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 50% of the facility's output to Black Hills Power;

14




Cheyenne Light and Black Hills Power's Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light's excess energy; and

Cheyenne Light's 20-year PPA with Duke Energy expiring in 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 20 MW of energy from Silver Sage to Black Hills Power.

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

MDU owns a 25% 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 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;

The City of Gillette owns a 23% 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 MW from our 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 their operating component of spinning reserves;

Black Hills Power's agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchase over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
2012-2017
20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019
15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021
12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023
10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II;

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

Cheyenne Light's agreement with Basin Electric, whereby Cheyenne Light will supply 40 MW of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 MW of capacity and energy from Basin Electric through March 31, 2013.

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 or fewer kV). We also jointly own high voltage lines with Basin Electric and Powder River Energy Corporation.


15



At December 31, 2011, our Electric Utilities owned or leased the electric transmission and distribution lines shown below:
Utility
State
Transmission
(in Line Miles)
Distribution
(in Line Miles)
Black Hills Power
SD, WY
618

2,999

Black Hills Power - Jointly Owned (1)
SD, WY
47


Cheyenne Light
SD, WY
25

1,235

Colorado Electric
CO
243

3,329


(1)
Through Black Hills Power, we own 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. Black Hills Power's electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids.

Black Hills Power has firm point-to-point transmission access to deliver up to 50 MW of power on PacifiCorp's transmission system to wholesale customers in the Western region through 2023.

Black Hills Power also has firm network transmission access to deliver power on PacifiCorp's system to Sheridan, Wyoming to serve our power sales contract with MDU through 2017, with the right to renew pursuant to the terms of PacifiCorp's transmission tariff.

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

Shared Services Agreement. 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.



16



Operating Statistics

The following tables summarize sales revenue, quantities and customers for our Electric Utilities:
Revenue - Electric (in thousands)
2011
2010
2009
 
 
 
 
Residential:
 
 
 
Black Hills Power
$
59,826

$
53,549

$
48,586

Cheyenne Light
31,287

29,506

29,198

Colorado Electric
84,646

76,596

66,548

Total Residential
175,759

159,651

144,332

 
 
 
 
Commercial:
 
 
 
Black Hills Power
72,889

65,997

59,897

Cheyenne Light
55,331

52,765

51,280

Colorado Electric
73,355

66,490

56,002

Total Commercial
201,575

185,252

167,179

 
 
 
 
Industrial:
 
 
 
Black Hills Power
25,723

22,621

20,014

Cheyenne Light
11,629

10,542

11,121

Colorado Electric
33,332

28,812

31,067

Total Industrial
70,684

61,975

62,202

 
 
 
 
Municipal:
 
 
 
Black Hills Power
3,172

3,029

2,735

Cheyenne Light
1,765

1,293

932

Colorado Electric
12,912

10,443

4,408

Total Municipal
17,849

14,765

8,075

 
 
 
 
Subtotal Retail Revenue - Electric
465,867

421,643

381,788

 
 
 
 
Contract Wholesale:
 
 
 
Black Hills Power
18,105

22,996

25,358

 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
34,889

36,354

32,212

Cheyenne Light
9,371

9,750

8,565

Colorado Electric *
13,018

10,859

14,008

Total Off-system Wholesale
57,278

56,963

54,785

 
 
 
 
Other Revenue:
 
 
 
Black Hills Power
31,027

25,217

18,277

Cheyenne Light
2,449

3,230

718

Colorado Electric
2,787

2,374

4,226

Total Other Revenue
36,263

30,821

23,221

 



Total Revenue - Electric
$
577,513

$
532,423

$
485,152

_____________________
*
Off-system sales revenue had been deferred by Colorado Electric from August 2010 until December 2011, when the CPUC approved a sharing mechanism as part of the rate case settlement allowing Colorado Electric a 25% share of off-system sales operating income. Revenue in 2011 represents off-system sales from August 2010 through December 2011.

17




Quantities Generated and Purchased (MWh)
2011
2010
2009
 
 
 
 
Generated -
 
 
 
Coal-fired:
 
 
 
Black Hills Power
1,717,008

1,987,037

1,721,074

Cheyenne Light
674,518

734,241

766,943

Colorado Electric
268,317

257,896

252,603

Total Coal
2,659,843

2,979,174

2,740,620

 
 
 
 
Gas and Oil-fired:
 
 
 
Black Hills Power
15,221

19,269

46,723

Cheyenne Light



Colorado Electric
2,342

930

2,705

Total Gas and Oil
17,563

20,199

49,428

 
 
 
 
Total Generated:
 
 
 
Black Hills Power
1,732,229

2,006,306

1,767,797

Cheyenne Light
674,518

734,241

766,943

Colorado Electric
270,659

258,826

255,308

Total Generated
2,677,406

2,999,373

2,790,048

 
 
 
 
Purchased -
 
 
 
Black Hills Power
1,720,640

1,440,579

1,686,455

Cheyenne Light
745,983

696,756

651,201

Colorado Electric
1,948,321

1,969,896

1,991,058

Total Purchased (a)
4,414,944

4,107,231

4,328,714

 
 
 
 
Total Generated and Purchased
7,092,350

7,106,604

7,118,762

_______________
(a) Includes 189,255 MWh, 167,520 MWh, and 105,830 MWh in 2011, 2010 and 2009, respectively of wind power purchased.


18



Quantities (MWh)
2011
2010
2009
 
 
 
 
Residential:
 
 
 
Black Hills Power
550,935

547,193

529,825

Cheyenne Light
264,492

261,607

255,134

Colorado Electric
629,752

628,553

589,526

Total Residential
1,445,179

1,437,353

1,374,485

 
 
 
 
Commercial:
 
 
 
Black Hills Power
720,978

720,119

723,360

Cheyenne Light
601,162

603,323

583,986

Colorado Electric
720,060

726,005

666,563

Total Commercial
2,042,200

2,049,447

1,973,909

 
 
 
 
Industrial:
 
 
 
Black Hills Power
408,337

382,562

353,041

Cheyenne Light
172,840

161,082

174,792

Colorado Electric
351,862

347,673

452,584

Total Industrial
933,039

891,317

980,417

 
 
 
 
Municipal:
 
 
 
Black Hills Power
34,235

33,908

33,948

Cheyenne Light
9,827

6,477

3,456

Colorado Electric
126,320

113,689

37,244

Total Municipal
170,382

154,074

74,648

 
 
 
 
Subtotal Retail Quantities Sold
4,590,800

4,532,191

4,403,459

 
 
 
 
Contract Wholesale:
 
 
 
Black Hills Power
349,520

468,782

645,297

 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
1,226,548

1,163,058

1,009,574

Cheyenne Light
278,528

311,524

309,122

Colorado Electric
282,929

274,942

373,495

Total Off-system Wholesale
1,788,005

1,749,524

1,692,191

 
 
 
 
Total Quantity Sold:
 
 
 
Black Hills Power
3,290,553

3,315,622

3,295,045

Cheyenne Light
1,326,849

1,344,013

1,326,490

Colorado Electric
2,110,923

2,090,862

2,119,412

Total Quantity Sold
6,728,325

6,750,497

6,740,947

 
 
 
 
Losses and Company Use:
 
 
 
Black Hills Power
162,316

131,263

159,207

Cheyenne Light
93,652

86,984

91,654

Colorado Electric
108,057

137,860

126,954

Total Losses and Company Use
364,025

356,107

377,815

 
 
 
 
Total Energy
7,092,350

7,106,604

7,118,762






19



Customers at End of Year
2011
2010
2009
Residential:
 
 
 
Black Hills Power
54,955

54,811

54,470

Cheyenne Light
35,159

34,913

35,943

Colorado Electric
81,811

81,902

81,622

Total Residential
171,925

171,626

172,035

 
 
 
 
Commercial:
 
 
 
Black Hills Power
12,864

12,779

12,261

Cheyenne Light
4,277

4,132

4,932

Colorado Electric
11,206

11,185

11,101

Total Commercial
28,347

28,096

28,294

 
 
 
 
Industrial:
 
 
 
Black Hills Power
45

40

38

Cheyenne Light
2

2

2

Colorado Electric
68

63

90

Total Industrial
115

105

130

 
 
 
 
Other Electric Customers:
 
 
 
Black Hills Power
311

309

143

Cheyenne Light
243

254

13

Colorado Electric
506

510

499

Total Other Electric Customers
1,060

1,073

655

 
 
 
 
Subtotal Retail Customers
201,447

200,900

201,114

 
 
 
 
Contract Wholesale:
 
 
 
Black Hills Power
3

3

3

 
 
 
 
Total Customers:
 
 
 
Black Hills Power
68,178

67,942

66,915

Cheyenne Light
39,681

39,301

40,890

Colorado Electric
93,591

93,660

93,312

Total Customers at Year-End
201,450

200,903

201,117


20



Degree Days
2011
2010
2009
 
Actual
Variance from
30-Year Average
Actual
Variance from
30-Year Average
Actual
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
Black Hills Power
7,579

5%
7,272

1%
7,753

8%
Cheyenne Light
7,321

(1)%
7,033

(5)%
7,411

—%
Colorado Electric
5,749

3%
5,518

(1)%
5,546

(1)%
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
Black Hills Power
700

17%
532

(11)%
354

(41)%
Cheyenne Light
431

58%
345

26%
203

(26)%
Colorado Electric
1,259

37%
1,074

16%
804

(13)%

Cheyenne Light Natural Gas Distribution

Cheyenne Light's natural gas distribution system serves natural gas customers in Cheyenne and other portions of Laramie County, Wyoming. The following table summarizes certain operating information:

 
2011
2010
2009
 
 
 
 
Revenue - Gas (in thousands):
 
 
 
Residential
$
22,044

$
22,562

$
21,495

Commercial
10,264

10,801

9,821

Industrial
3,597

3,425

3,537

Other Sales Revenue
913

803

760

Total Revenue - Gas
$
36,818

$
37,591

$
35,613

 
 
 
 
Gross Margin (in thousands):
 
 
 
Residential
$
10,426

$
10,004

$
10,219

Commercial
3,345

3,376

3,266

Industrial
504

427

509

Other Gross Margin
545

720

760

Total Gross Margin
$
14,820

$
14,527

$
14,754

 
 
 
 
Volumes Sold (Dth):
 
 
 
Residential
2,585,056

2,636,839

2,516,699

Commercial
1,538,616

1,572,638

1,502,002

Industrial
689,935

667,062

722,776

Total Volumes Sold
4,813,607

4,876,539

4,741,477

 
 
 
 
Customers at Year-End
34,807

34,461

33,942




21



Gas Utilities Segment

At December 31, 2011, our Gas Utilities owned the gas transmission and distribution lines by state shown below (in line miles):

 
Intrastate Gas
Transmission Pipelines
Gas Distribution
Mains
Gas Distribution
Service Lines
 
 
 
 
Colorado
124

2,987

886

Nebraska
44

3,432

3,481

Iowa
170

2,762

2,321

Kansas
286

2,582

1,296

Total
624

11,763

7,984



22



Operating Statistics

The following tables summarize revenue, gross margin, volumes, degree days and customers for our Gas Utilities:
Revenue (in thousands)
2011
2010
2009
 
 
Residential:
 
 
 
Colorado
$
58,102

$
55,211

$
62,732

Nebraska
125,493

120,365

127,120

Iowa
106,292

105,255

113,781

Kansas
65,185

69,859

70,848

Total Residential
355,072

350,690

374,481

 
 
 
 
Commercial:
 
 
 
Colorado
12,172

11,880

13,357

Nebraska
40,659

40,720

43,472

Iowa
46,179

46,762

54,587

Kansas
20,362

21,953

22,629

Total Commercial
119,372

121,315

134,045

 
 
 
 
Industrial:
 
 
 
Colorado
2,063

1,409

1,348

Nebraska
860

3,126

3,425

Iowa
2,521

2,243

2,191

Kansas
19,571

14,312

11,057

Total Industrial
25,015

21,090

18,021

 
 
 
 
Other Sales Revenue:
 
 
 
Colorado
96

97

100

Nebraska
1,971

1,960

2,077

Iowa
550

836

1,073

Kansas
3,031

3,451

3,213

Total Other Sales Revenue
5,648

6,344

6,463

 
 
 
 
Total Distribution:
 
 
 
Colorado
72,433

68,597

77,537

Nebraska
168,983

166,171

176,094

Iowa
155,542

155,096

171,632

Kansas
108,149

109,575

107,747

Total Distribution
505,107

499,439

533,010

 
 
 
 
Transportation:
 
 
 
Colorado
846

784

732

Nebraska
11,175

11,289

10,569

Iowa
3,935

3,708

3,876

Kansas
5,909

5,471

5,389

Total Transportation
21,865

21,252

20,566

 
 
 
 
Total Regulated:
 
 
 
Colorado
73,279

69,381

78,269

Nebraska
180,158

177,460

186,663

Iowa
159,477

158,804

175,508

Kansas
114,058

115,046

113,136

Total Regulated Revenue
526,972

520,691

553,576

 
 
 
 
Non-regulated Services
27,612

30,016

26,736

 
 
 
 
Total Revenue
$
554,584

$
550,707

$
580,312


23




Gross Margin (in thousands)
2011
2010
2009
 
 
Residential:
 
 
 
Colorado
$
17,711

$
18,153

$
17,443

Nebraska
51,640

49,074

44,638

Iowa
47,491

44,269

42,734

Kansas
29,701

29,591

28,999

Total Residential
146,543

141,087

133,814

 
 
 
 
Commercial:
 
 
 
Colorado
2,960

3,215

3,176

Nebraska
11,643

11,965

11,785

Iowa
11,702

11,616

12,749

Kansas
6,603

6,544

6,484

Total Commercial
32,908

33,340

34,194

 
 
 
 
Industrial:
 
 
 
Colorado
450

360

375

Nebraska
217

379

431

Iowa
288

235

244

Kansas
2,373

1,878

1,766

Total Industrial
3,328

2,852

2,816

 
 
 
 
Other Sales Margins:
 
 
 
Colorado
96

97

101

Nebraska
1,971

1,960

2,077

Iowa
549

836

1,073

Kansas
2,455

2,722

2,312

Total Other Sales Margins
5,071

5,615

5,563

 
 
 
 
Total Distribution:
 
 
 
Colorado
21,217

21,825

21,095

Nebraska
65,471

63,378

58,931

Iowa
60,030

56,956

56,800

Kansas
41,132

40,735

39,561

Total Distribution
187,850

182,894

176,387

 
 
 
 
Transportation:
 
 
 
Colorado
846

784

732

Nebraska
11,175

11,289

10,569

Iowa
3,935

3,708

3,876

Kansas
5,909

5,470

5,389

Total Transportation
21,865

21,251

20,566

 
 
 
 
Total Regulated:
 
 
 
Colorado
22,063

22,609

21,827

Nebraska
76,646

74,667

69,500

Iowa
63,965

60,664

60,676

Kansas
47,041

46,205

44,950

Total Regulated Gross Margin
209,715

204,145

196,953

 
 
 
 
Non-regulated Services
12,908

12,845

11,643

 
 
 
 
Total Gross Margin
$
222,623

$
216,990

$
208,596



24





Volumes (in Dth)
2011
2010
2009
 
 
 
 
Residential:
 
 
 
Colorado
6,437,860

6,284,559

6,355,275

Nebraska
12,076,979

12,210,574

12,619,682

Iowa
10,490,129

10,556,045

10,976,268

Kansas
6,853,163

6,926,928

6,878,243

Total Residential
35,858,131

35,978,106

36,829,468

 
 
 
 
Commercial:
 
 
 
Colorado
1,472,747

1,473,924

1,444,360

Nebraska
4,833,604

5,009,105

5,189,630

Iowa
6,192,167

6,061,954

6,597,035

Kansas
2,676,439

2,673,805

2,696,870

Total Commercial
15,174,957

15,218,788

15,927,895

 
 
 
 
Industrial:
 
 
 
Colorado
344,576

259,985

263,134

Nebraska
120,779

544,457

581,892

Iowa
409,723

354,435

333,324

Kansas
3,743,735

2,718,767

2,524,126

Total Industrial
4,618,813

3,877,644

3,702,476

 
 
 
 
Other Volumes:
 
 
 
Colorado



Nebraska

1,341

1,400

Iowa

69,306

68,290

Kansas
112,253

120,445

141,909

Total Other Volumes
112,253

191,092

211,599

 
 
 
 
Total Distribution:
 
 
 
Colorado
8,255,183

8,018,468

8,062,769

Nebraska
17,031,362

17,765,477

18,392,604

Iowa
17,092,019

17,041,740

17,974,917

Kansas
13,385,590

12,439,945

12,241,148

Total Distribution
55,764,154

55,265,630

56,671,438

 
 
 
 
Transportation:
 
 
 
Colorado
869,570

808,859

807,999

Nebraska
24,972,560

27,327,173

25,311,501

Iowa
18,358,692

17,422,525

14,915,602

Kansas
15,015,310

14,320,893

14,069,182

Total Transportation
59,216,132

59,879,450

55,104,284

 
 
 
 
Total Volumes:
 
 
 
Colorado
9,124,753

8,827,327

8,870,768

Nebraska
42,003,922

45,092,650

43,704,105

Iowa
35,450,711

34,464,265

32,890,519

Kansas
28,400,900

26,760,838

26,310,330

Total Volumes
114,980,286

115,145,080

111,775,722




25



Degree Days
 
2011
2010
2009
 
Actual
Variance From
30-Year Average
Actual
Variance From
30-Year Average
Actual
Variance From
30-Year Average
Heating Degree Days (a):
 
 
 
 
 
 
Colorado
5,991

(7)%
5,803

(9)%
6,299

2%
Nebraska
6,190

(4)%
6,222

(5)%
6,238

5%
Iowa
7,013

(1)%
6,934

(1)%
7,279

6%
Kansas (b)
4,954

(1)%
4,918

—%
4,989

—%
Combined
6,143

(3)%
6,101

(3)%
6,285

(11)%
________________
(a)
The combined heating degree days are calculated based on a weighted average of total customers by state. 
(b)
In Kansas where we have a weather normalization mechanism, normal degree days are used instead of actual degree days in computing the total number of heating degree days. 
 

26



The following table summarizes the Gas Utilities' customers as of December 31:

Customers
2011
2010
2009
 
 
 
 
Residential:
 
 
 
Colorado
67,496

66,766

65,586

Nebraska
176,386

176,244

179,873

Iowa
135,161

134,782

133,712

Kansas
98,043

97,844

97,446

Total Residential
477,086

475,636

476,617

 
 
 
 
Commercial:
 
 
 
Colorado
3,678

3,620

3,590

Nebraska
15,664

15,221

15,218

Iowa
15,398

15,300

15,403

Kansas
9,453

9,469

9,510

Total Commercial
44,193

43,610

43,721

 
 
 
 
Industrial:
 
 
 
Colorado
209

208

207

Nebraska
141

149

149

Iowa
94

93

90

Kansas
1,365

1,394

1,351

Total Industrial
1,809

1,844

1,797

 
 
 
 
Transportation:
 
 
 
Colorado
30

22

22

Nebraska
4,128

4,270

4,579

Iowa
393

392

389

Kansas
1,142

1,054

1,077

Total Transportation
5,693

5,738

6,067

 
 
 
 
Other:
 
 
 
Colorado



Nebraska

2

2

Iowa

68

71

Kansas
7

8

8

Total Other
7

78

81

 
 
 
 
Total Customers:
 
 
 
Colorado
71,413

70,616

69,405

Nebraska
196,319

195,886

199,821

Iowa
151,046

150,635

149,665

Kansas
110,010

109,769

109,392

Total Customers at Year-End
528,788

526,906

528,283


27



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 patterns 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 require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-affiliated IPP companies for the right to provide electric energy and capacity for Colorado Electric when resource plans require additional resources.
 
Regulation and Rates

State Regulation

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 our costs, 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 state to secure bonds or other securities.

We distribute natural gas in five states. All of our Gas Utilities, and Cheyenne Light's natural gas distribution, have gas cost adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to the customer. In Kansas and Nebraska, we are allowed to recover the portion of uncollectible accounts related to gas costs through the gas cost adjustments. In Kansas, we also 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 Nebraska, legislation was passed in 2009 to authorize the NPSC to provide for more timely recovery from our customers for certain capital expenditures between rate cases. In October 2011, the IUB adopted rules that allow rate-regulated natural gas utilities to implement automatic adjustment mechanisms for recovery of certain costs, primarily safety-related and government-mandated investment in infrastructure, between general rate proceedings.

We produce and/or distribute power in four states. The regulatory provisions for recovering the costs to produce electricity vary by state. Certain states have approved specific mechanisms which 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. In some instances, the utility has the opportunity to earn its authorized return on new capital investment. The mechanisms we have in place are:

In South Dakota, Wyoming, Colorado and Montana, we have cost adjustment mechanisms for our Electric Utilities that serve a purpose similar to the cost adjustment mechanisms in our Gas Utilities. At Cheyenne Light, our pass-through mechanism relating to transmission, fuel and purchased power costs is subject to a $1.0 million threshold: we collect or refund 95% of the increase or decrease that exceeds the $1.0 million threshold, and we absorb the increase or retain the savings for costs below the threshold as well as the 5% not collected or refunded above the threshold.

28




Until April 1, 2010, South Dakota had three adjustment mechanisms: transmission, steam plant fuel (coal) and conditional ECA. The transmission and steam plant fuel adjustment clauses required an annual adjustment to rates for actual costs. Therefore, any savings or increased costs were passed on to the South Dakota customers. The conditional ECA related to purchased power and natural gas used to generate electricity. These costs were subject to calendar year $2.0 million and $1.0 million thresholds where Black Hills Power absorbed the first $2.0 million of increased costs or retained the first $1.0 million in savings. Beyond these thresholds, costs or savings were passed on to South Dakota customers through annual calendar-year filings.

In South Dakota beginning April 1, 2010, the steam plant fuel and conditional ECA were combined into a single cost adjustment called the Fuel and Purchased Power Adjustment clause. The Fuel and Purchased Power Adjustment clause provides for the direct recovery of increased fuel and purchased power costs incurred to serve South Dakota customers. As of April 1, 2010, the Fuel and Purchased Power Adjustment clause was modified in the rate case settlement to contain a power marketing operating income sharing mechanism in which South Dakota customers will receive a credit equal to 65% of power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. In Wyoming beginning June 1, 2010 a similar Fuel and Purchase Power Cost Adjustment was instituted.

In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect June 1, 2011 and recovers all the costs associated with plant additions.

In Colorado, we have an ECA for increases or decreases in purchased power and fuel costs and a TCA for transmission cost adjustments. The ECA clause provides for the direct recovery of increased purchased power and fuel costs or the issuance of credits for decreases in purchased power and fuel costs. The TCA is a rider to the customer's bill which allows the utility to earn an authorized return on new transmission investment and recovery of operations and maintenance costs related to transmission.

Effective January 1, 2012, the CPUC approved adjustments to the ECA. These adjustments allow for the recovery of transmission expenses paid to other providers, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs, where the customer receives 75% through 2013. This sharing percentage increases to 90% to the customer in 2014.

In Colorado, beginning in November 2010, the CPUC approved the implementation of a Purchased Capacity Cost Adjustment, the purpose of which is to recover the increase in capacity cost related to Colorado Electric's purchase power agreement with PSCo. This Purchase Capacity Cost Adjustment expired on January 1, 2012 in conjunction with expiration of the PPA with PSCo and the commencement of Colorado Electric's PPA with Colorado IPP.

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. At December 31, 2011, we were subject to the following renewable energy portfolio standards or objectives:

South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015. Absent a specific renewable energy mandate in South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers.

Montana. Montana established a renewable portfolio standard that requires Black Hills Power to obtain a percentage of its retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 5% for compliance years 2008-2009; (ii) 10% for compliance years 2010-2014; and (iii) 15% for compliance year 2015 and thereafter. Utilities can meet this standard by entering into long-term purchase contracts for electricity bundled with renewable-energy credits, by purchasing the renewable-energy credits separately, or by a combination of both. The law includes cost caps that limit the additional cost utilities must pay for renewable energy and allows cost recovery from ratepayers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards.

29




Colorado. Colorado has adopted a renewable energy standard that requires our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 12% of retail sales from 2011 to 2014; (ii) 20% of retail sales from 2015 to 2019; and (iii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The law limits the net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) to 2% and 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, and our current strategy is to incorporate renewable energy as required to comply with the standards.

Wyoming. Wyoming is also exploring the implementation of renewable energy portfolio standards but has not currently adopted standards.

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.

In connection with our acquisition of the Gas Utilities, the CPUC, NPSC, IUB and KCC approved orders or settlement agreements providing that, among other things, (i) our utilities in those jurisdictions cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and (ii) neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. In addition to the restrictions described above, each state in which we conduct utility operations imposes restrictions on affiliate transactions, including inter-company loans.

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 ratemaking 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 utility subsidiaries provide FERC-jurisdictional services subject to FERC's oversight.

Our Electric Utilities and our non-regulated subsidiaries, Black Hills Colorado Electric 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 gave FERC authority 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.


30



The following summarizes our recent state and federal rate case and surcharge activity (dollars in millions):

 
 
 
 
 
 
 
Approved Capital Structure
 
Type of Service
Date Requested
Date Effective
Amount Requested
Amount Approved
Return on Equity
Equity
Debt
Nebraska Gas (1)
Gas
12/2009
9/2010
$
12.1

$
8.3

10.1
%
52.0
%
48.0
%
Iowa Gas
Gas
6/2008
7/2009
$
13.6

$
10.8

10.1
%
51.4
%
48.6
%
Iowa Gas (2)
Gas
6/2010
2/2011
$
4.7

$
3.4

Global Settlement
Global Settlement
Global Settlement
Colorado Gas
Gas
6/2008
4/2009
$
2.7

$
1.4

10.3
%
50.5
%
49.5
%
Kansas Gas
Gas
5/2009
10/2009
$
0.5

$
0.5

10.2
%
50.7
%
49.3
%
Black Hills Power (3)
Electric
9/2009
4/2010
$
32.0

$
15.2

Global Settlement
Global Settlement
Global Settlement
Black Hills Power (4)
Electric
10/2009
6/2010
$
3.8

$
3.1

10.5
%
52.0
%
48.0
%
Black Hills Power (5)
Electric
1/2011
6/2011
Not Applicable
$
3.1

Not Applicable
Not Applicable
Not Applicable
Colorado Electric (6)
Electric
1/2010
8/2010
$
22.9

$
17.9

10.5
%
52.0
%
48.0
%
Colorado Electric (7)
Electric
4/2011
1/2012
$
40.2

$
28.0

9.8%-10.2%

49.1
%
50.9
%
Cheyenne Light (8)
Electric/Gas
12/2011
pending
$
8.5

pending

pending

pending

pending


(1)
In December 2009, Nebraska Gas filed a rate case with the NPSC and interim rates went into effect on March 1, 2010. In August 2010, NPSC issued a decision approving an annual revenue increase of approximately $8.3 million, based on a return on equity of 10.1% with a capital structure of 52% equity effective September 1, 2010. A refund to customers for the difference between interim rates and approved rates was completed in the first quarter of 2011. The Nebraska Public Advocate has filed an appeal with the District Court which has been denied. Subsequently, the Nebraska Public Advocate has filed a notice of appeal in the Court of Appeals. This appeal is still outstanding.

(2)
In June 2010, Iowa Gas filed a request with the IUB for a $4.7 million revenue increase to recover the cost of capital investments made in our gas distribution system and other expense increases incurred since December 2008. Interim rates, subject to refund, equal to a $2.6 million increase in revenues went into effect on June 18, 2010. In August 2010, we reached a settlement with the OCA for a revenue increase of $3.4 million. This settlement agreement was modified and re-filed on January 11, 2011. The modified settlement excludes the integrity investment tracker and the three-year rate moratorium included in the original settlement agreement filed on September 1, 2010, which was not approved by the IUB. Approval from the IUB was received on February 10, 2011.

(3)
In September 2009, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the previous four years. In March 2010, the SDPUC approved a $24.1 million increase in interim rates, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million and a base rate increase of $22.0 million with an effective date of April 1, 2010. The approved capital structure and return on equity are confidential. A refund was provided to customers in the third quarter of 2010.

As part of the settlement stipulation, Black Hills Power agreed: (1) to credit customers 65% of off-system sales operating income with a minimum credit of $2.0 million per year; (2) that rates will include a South Dakota Surplus Energy Credit of $2.5 million in year one (fiscal year ended March 2011), $2.25 million in fiscal year two, $2.0 million in fiscal year three and zero thereafter; and (3) a moratorium until April 2013 for any base rate increase excluding any extraordinary events as defined in the stipulation agreement; while (4) the SDPUC agreed to adjust the off-system sales portion of the Fuel and Purchased Power Adjustment Clause for the methodology to directly assign renewable resources and firm purchases to the customer load.

31




(4)
In October 2009, Black Hills Power filed a rate case with the WPSC requesting a $3.8 million electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. On May 4, 2010, Black Hills Power filed a settlement stipulation agreement with the WPSC for a $3.1 million increase in annual revenues. On May 13, 2010, WPSC approved these new rates based on a return on equity of 10.5% with a capital structure of 52% equity and 48% debt. New rates went into effect on June 1, 2010.

(5)
In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase of $3.1 million.

(6)
In January 2010, Colorado Electric filed a rate case with the CPUC requesting an electric revenue increase primarily related to the recovery of rising costs from electricity supply contracts, as well as recovery for investment in equipment and electricity distribution facilities necessary to maintain and strengthen the reliability of the electric delivery system in Colorado. On August 5, 2010, the CPUC approved a settlement agreement for $17.9 million in annual revenues with a return on equity of 10.5% and a capital structure of 52% equity and 48% debt. New rates were effective August 6, 2010.

Included in the rate case order was a provision that off-system sales margin be shared with customers commencing August 6, 2010. The percentage of margin to be shared with the customers was not resolved at the time of the rate case settlement. The CPUC required that the off-system gross margin earned beginning August 6, 2010 be deferred. The determination of a sharing mechanism for off-system sales was considered as part of the rate case filed with the CPUC by Colorado Electric discussed below.

(7)
In April 2011, Colorado Electric filed a request with the CPUC for an annual revenue increase of $40.2 million, or 18.8%, to recover costs and a return on capital associated with the 180 MW generating facility that commenced commercial operation on January 1, 2012, associated infrastructure assets and other utility expenses, including the PPA with Colorado IPP. On December 22, 2011, the CPUC issued an order approving an annual base rate increase of $10.5 million with a rate of return ranging from 9.8% to 10.2% with a capital structure of 49.1% equity and 50.9% debt. New rates were effective January 1, 2012. In addition, approximately $17.5 million of other costs including fuel, purchased power and new transmission will be recovered through normal cost adjustment mechanisms.
 
The provisions of the order also provided for a sharing mechanism for off-system sales. Colorado Electric has agreed to credit customers 75% for off-system sales margin less certain operating costs, with Colorado Electric retaining 25% through December 31, 2013. The customers' sharing percentage increases to 90% starting in 2014.

(8)
On December 1, 2011, Cheyenne Light filed requests for electric and natural gas revenue increases with the WPSC to recover investment in infrastructure and other costs. Cheyenne Light is seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue.

32



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 the cost of new generation. The ultimate cost could be significantly different from the amounts estimated.

        
Environmental Expenditure Estimates
Total
(in millions)
2012
$
12

2013
39

2014
13

Total
$
64


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. We are not aware of any proposed regulations that will have a significant impact on our operations. Additionally, the EPA regulates surface water oil pollution through its oil pollution prevention regulations. All of our facilities under this program have their required plans in place. Also, the EPA is scheduled to issue updated regulations for wastewater discharge for electric generating units in early 2012, which could have a significant impact on all of our generating fleet.

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, NOx, 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 program as part of the federal acid rain program. Each allowance gives the owner the right to emit one ton of SO2, and certain facilities are allocated allowances based on their historical operating data. At the end of each year, each emitting unit must have enough allowances to cover its emissions for the year just ended. Allowances may be traded so affected units that expect to emit more SO2 than their allocated allowances may purchase allowances in the open market.

Title IV applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen II, Wygen III and Wyodak plants. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2041. 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.


33



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. Wygen III is allowed to operate under its 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 2012. The application was filed in accordance with regulatory requirements.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, which impose emission limits, fuel requirements and monitoring requirements. The rule has an effective date of May 20, 2011 and a compliance deadline of March 21, 2014. This rule has a significant impact on our Neil Simpson I, Osage and Ben French facilities. Engineering evaluations have been completed as to the economic viability of continued operations of these units. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than December 31, 2013. It is our expectation that the Neil Simpson I, Osage and Ben French units will be closed prior to the March 21, 2014 compliance deadline.

On December 16, 2011, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (Utility MACT Rule), which became effective on February 16, 2012. Affected units will have three years from the rule effective date to be in compliance, with a pathway defined to apply for a one year extension due to certain circumstances. Certain requirements of that regulation could have significant impacts on the Neil Simpson II, Wygen II, Wygen III and Wyodak plants. Neil Simpson II, Wygen II, Wygen III and the Wyodak plant are expected to be in compliance within the compliance time frame. Significant modifications may be required to ensure compliance at Neil Simpson II and we are working toward that goal. Preliminary estimates of capital requirements to comply with this rule are $30 million to $50 million.

On June 23, 2010, the EPA published in the Federal Register 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 of a new major source as defined by EPA regulations. Existing permitted facilities will see monitoring and reporting requirements incorporated into their operating permits upon renewal. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could result in more stringent emission control practices and technologies. As Wyoming state law prohibits regulation of GHG, the EPA will review and develop requirements for that portion of a new source construction permit or for a major modification of an existing source. It is anticipated this additional process will add several months to the permitting process. In addition, unlike a Wyoming issued permit, an appeal of an EPA issued GHG air permit to construct requires an automatic stay to the project, meaning that construction cannot commence until the appeal is resolved. This aspect adds considerable risk to new construction projects as well as to major modifications to existing projects.

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. This act has a significant impact on our W.N. Clark facility and on October 29, 2010, Colorado Electric filed testimony with the CPUC that included a proposal recommending retirement of the W.N. Clark facility. On December 15, 2010, the CPUC issued an order approving closure of the W.N. Clark plant by December 31, 2013. On January 7, 2011, the State Air Quality Control Commission adopted the CPUC order into the Colorado State Implementation Plan and following legislative approval, that plan was submitted in May 2011 to the EPA Region VIII for approval.

In June 2011, the EPA was scheduled to issue proposed Electric Utility New Source Performance Standards for GHG. That publication date has been extended to mid-2012. As the regulations are not yet proposed, we cannot ascertain their impacts but we anticipate they may be applicable to Wygen III. In 2011, it was anticipated the EPA would expedite the issuance of a more stringent ozone ambient air standard. However, the President of the United States postponed this revision and placed it back on its normal review cycle, which is scheduled to occur in 2013. 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 NOx emissions.

In 2011, the State of Wyoming issued a letter addressing startup and shutdown emissions at Neil Simpson II, requiring the facility to include those emissions in consideration of compliance with the permitted emission limits. This represents a significant change in requirements from the original air permit issued in 1993. As this facility was not designed and built according to those requirements, we are currently undergoing engineering evaluations to determine methods and costs of compliance. We anticipate that the State of Wyoming will eventually issue the same requirements for Wygen I and Wygen II.


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Regional Haze

In January 2011, the states of Wyoming and South Dakota submitted their plans to EPA Region VIII, identifying NOx, 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 within the next five years, Ben French, Neil Simpson I and Osage will be included. This is based on recent activity by EPA Region VIII, where they have rejected at least in part, states' emission reduction plans. Colorado submitted a revised plan to the EPA in May 2011, addressing the additional required emission reductions, which for the first time included our W.N. Clark facility. In 2011, the EPA partially rejected North Dakota's Regional Haze Plan, and issued a Federal Implementation Plan, dictating new lower emission limits for certain facilities. As Ben French, Neil Simpson 1 and Osage have no SO2 or NOx post combustion emission controls and are in close proximity to the two Class I Areas in western South Dakota, we fully expect they will be brought into the program. This could occur in the very near future, if the EPA rejects the South Dakota and/or Wyoming Plans, or it could occur in five years, when the plans undergo the required five year review to assess visibility improvement progress. Costs to comply will be significant and have been included as part of the engineering review conducted to assess impacts of the EPA's Industrial and Commercial Boiler Area Source regulations. It is our expectation Ben French, Osage and Neil Simpson I will be closed prior to March 21, 2014.

Mercury Regulations

Approximately 50% of our electric generating capacity is coal-fired. On December 16, 2011, the EPA signed the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS) and this regulation became effective February 16, 2012. Affected units will have three years from the rule effective date to be in compliance with a pathway defined to apply for a one year extension due to certain circumstances. This rule will address mercury emissions, among other pollutants, at Neil Simpson II, Wygen II and Wygen III.

The MATS rule will require significant investments at our power generating facilities. Of our affected units, it is anticipated that Neil Simpson II will require the most extensive investments. The state air permit for Wygen II and Wygen III provides mercury emission limits and monitoring requirements with which we are in compliance. Wygen II has been utilized for study and review of mercury emission control technology and has mercury monitors in place. In 2009, we added mercury monitors to our Neil Simpson II plant. The Wygen III plant, which commenced operations in 2010, also has mercury monitors. Federal multi-pollutant legislation is also being considered that would require reductions similar to the EPA rules and may add requirements for the reduction of GHG emissions.

Greenhouse Gas Regulations

We utilize a diversified energy portfolio of power generation assets that includes a fuel mix of coal and natural gas as well as 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. Although we cannot predict specifically how, if or when, GHG will be regulated, any federally mandated GHG reductions or limits on CO2 emissions could have a material impact on our financial position, results of operations, 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. As 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 2011, we reported 2010 GHG emissions from our Power Generation and Gas Utilities in order to comply with the EPA's GHG Annual Inventory regulation, issued in 2009. 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 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 condition 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.

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In connection with GHG initiatives, many states have enacted, and others are considering, renewable energy portfolio standards that require electric utilities to meet certain thresholds for the production or use of renewable energy. Colorado Electric is subject to renewable energy portfolio standards in Colorado. Black Hills Power is subject to mandatory renewable energy portfolio standards in Montana and voluntary standards in South Dakota. In the near future, we expect similar (if not more challenging) renewable energy portfolio standards to be mandated at the federal level or in other state jurisdictions in which we operate. We anticipate significant additional costs to comply with any federal or state mandated renewable energy standards, which we would expect to pass on to our customers. However, 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.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Under appropriate 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 Wyodak, Neil Simpson I, Ben French, Neil Simpson II, Wygen II and Wygen III plants are deposited in mined areas at the WRDC coal mine. These disposal areas are located below some shallow water aquifers in the mine. In 2009, the State of Wyoming confirmed their past approval of this practice but may re-evaluate and limit ash disposal to mined areas that are above future 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 October 1, 2010, we suspended operations at the Osage power plant. It has an on-site ash impoundment that is near capacity. An application to close the impoundment wa