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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, 2010
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
Rapid City, South Dakota  57701
IRS Identification Number 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.    ®
 
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, 2010                                   $1,102,103,935
 
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, 2011
Common stock, $1.00 par value
39,262,118
 
shares
 
Documents Incorporated by Reference
Portions of the Registrant's Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2011 Annual Meeting of Stockholders to be held on May 25, 2011, 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 (UNDER PROPOSED RULES)
 
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:
 
Acquisition Facility
Our $1.0 billion single-draw, senior unsecured facility from which a $383 million draw was used to provide part of the funding for our Aquila Transaction
AFUDC
Allowance for Funds Used During Construction
Annexation Agreement
Agreement with the City of Pueblo, Colorado under which the City of Pueblo annexed the property on which Colorado Electric and Black Hills Colorado IPP are constructing their generation facilities
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
BHC Pension Plan
The Pension Plan of Black Hills Corporation
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 Corporation Plan
Black Hills Corporation Retirement Savings Plan
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
Btu
British thermal unit
CAMR
Clean Air Mercury Rule
CFTC
United States Commodity Futures Trading Commission
CG&A
Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Light Pension Plan
The Cheyenne Light, Fuel and Power Company Pension Plan
Cheyenne Light Plan
Cheyenne Light, Fuel and Power Company Retirement Savings 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
CPUC
Colorado Public Utilities Commission
CT
Combustion turbine
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
EDF
EDF Trading North America, LLC
Enserco
Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-regulated Holdings
Enserco Credit Facility
The $250 million committed stand alone credit facility that supports Enserco's marketing and trading operations, which currently expires May 7, 2012
EPA
U. S. Environmental Protection Agency
Equity forward shares
Public offering of 4,000,000 shares of Black Hills Corporation common stock connected with an Equity Forward Agreement
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
Forward Agreement
Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,000,000 million shares of Black Hills Corporation common stock
Forward Agreements
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
FTC
Federal Trade Commission
GAAP
Accounting principles generally accepted in the United States of America
GCA
Gas Cost Adjustment
GHG
Greenhouse gases
GIS
Geographic information system
Global Settlement
Settlement with the 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
GSRS
Gas System Reliability Surcharge
Happy Jack
Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Hastings
Hastings Fund Management Ltd
ICE
Intercontinental Exchange
IGCC
Integrated Gasification Combined Cycle
IIF
IIF BH Investment LLC, a subsidiary of an investment entity advised by JPMorgan Asset Management

4

 

 
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 production
IPP Transaction
The July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings and IIF
IRS
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
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
NCREIF
National Council of Real Estate Investment Fiduciaries
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
NOx
Nitrogen Oxide
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
NYMEX
New York Mercantile Exchange
OCA
Office of Consumer Advocate
OPEC
Organization of the Petroleum Exporting Countries
PCA
Power Cost Adjustment

5

 

PGA
Purchased Gas Adjustment
PPA
Purchase Power 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
QF
Qualifying Facility
RCRA
Resource Conservation and Recovery Act
Revolving Credit Facility
Our $500 million credit facility used to fund working capital needs, issuance of letters of credit and other corporate purposes, expiring April 14, 2013.
RMSA
Retiree Medical Savings Account
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.
Valencia
Valencia Power, LLC, a former subsidiary of Black Hills Non-regulated Holdings that was sold as part of our IPP Transaction
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
 
ACCOUNTING PRONOUNCEMENTS
 
ASC
Accounting Standards Codification
ASC 310-10-50
ASC 310-10-50, "Receivables - Disclosures"
ASC 715
ASC 715, "Compensation - Retirement Benefits"
ASC 805
ASC 805, "Business Combinations"
ASC 810
ASC 810, "Consolidations"
ASC 810-10-15
ASC 810-10-15, "Consolidation of Variable Interest Entities"
ASC 815
ASC 815, "Derivatives and Hedging"
ASC 820
ASC 820, "Fair Value Measurements and Disclosures"
ASC 932-10-S99
ASC 932-10-S99, "Extractive Activities - Oil and Gas, SEC Materials"
ASC 940-325-S99
ASC 940-325-S99, "Financial Services - Broker and Dealers, Investments - Other"
 
 

6

 

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 or foreign exchange 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 arising from the enactment of the Energy Policy Act of 2005 and subsequent rules and regulations promulgated thereunder;
 
•    
The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our energy marketing activities and to hedge our expected production of 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 independent power production or exploration and production activities;
 
•    
Our ability to successfully integrate and profitably operate any future acquisitions;
 
•    
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;
 
•    
Our ability to receive regulatory approval to recover in rate base our expenditures for new power generation facilities or other utility infrastructure;

7

 

 
•    
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, currency exchange rate 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;
 
•    
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;
 
•    
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;

8

 

 
•    
Additional liabilities for environmental conditions, including remediation and reclamation obligations, under environmental laws;
 
•    
Our ability to successfully complete labor negotiations with labor unions with whom 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 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.
 

9

 

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, Coal Mining, and Energy Marketing segments, as shown below. At December 31, 2010, we had 2,124 employees, 705 of whom were represented by union locals.
 
Business Group
Financial Segment
 
 
Utilities
Electric Utilities
 
Gas Utilities
 
 
Non-regulated Energy
Oil and Gas
 
Power Generation
 
Coal Mining
 
Energy Marketing
 
Our Electric Utilities segment generates, transmits and distributes electricity to approximately 201,000 customers in South Dakota, Wyoming, Colorado and Montana and includes the operations of Cheyenne Light, a combination electric and gas utility, and its approximately 34,500 gas utility customers in Wyoming. Our Gas Utilities segment serves approximately 527,000 natural gas utility customers in Colorado, Nebraska, Iowa and Kansas. Our Electric Utilities own 687 MWs of generation and 8,038 miles of electric transmission and distribution lines, and our Gas Utilities own 626 miles of intrastate gas transmission pipelines and 19,638 miles of gas distribution mains and service lines. Our Electric and Gas Utilities generated income from continuing operations of $74.6 million for the year ended December 31, 2010 and had total assets of $2.6 billion at December 31, 2010.
 
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 Coal Mining segment produces coal at our coal mine near Gillette, Wyoming, and our Energy Marketing segment is engaged in marketing of natural gas, crude oil, coal, power, environmental products and related services, in the United States and Canada. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy primarily under long-term contracts. In 2008, we sold seven IPP plants previously reported in our Power Generation segment, which resulted in the operations of these plants being reported as discontinued operations. Our Non-regulated Energy Group generated income from continuing operations of $13.6 million in the year ended December 31, 2010 and had total assets of $1.1 billion at December 31, 2010.
 
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, particularly Note 17 to the Consolidated Financial Statements in this Annual Report on Form 10-K.
 

10

 

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 201,000 customers in South Dakota, Wyoming, Colorado and Montana. Additionally, Cheyenne Light distributes natural gas to approximately 34,500 natural gas utility customers in Wyoming. Our electric generating facilities and purchased power contracts supply electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including affiliates.
 
We conduct natural gas utility operations on a state-by-state basis through our Colorado Gas, Iowa Gas, Kansas Gas, and Nebraska Gas subsidiaries. Our Gas Utilities distribute and transport natural gas to our customers through our distribution network to approximately 527,000 customers in Colorado, Iowa, Kansas and Nebraska. We also provide related services that include appliance repairs, gas technical services and the sale of temporarily-available, contractual pipeline capacity from our suppliers.
 
In addition to our regulated operations, we also provide services through our Service Guard product line to approximately 63,000 customers in Colorado, Iowa, Kansas and Nebraska. Service Guard primarily provides appliance repair services through company technicians and third party service providers.
 
Electric Utilities Segment
 
Capacity and Demand
 
Uninterrupted system peak demands for the Electric Utilities for each of the last three years are listed below:
 
 
System Peak Demand (in MW)
 
 
 
 
 
 
 
 
 
 
 
 
 
2010
 
2009
 
2008
 
 
Summer
Winter
 
Summer
Winter
 
Summer
 
Winter
 
 
 
 
 
 
 
 
 
 
 
 
Black Hills Power
396
377
 
387
392
 
409
 
407
 
Cheyenne Light
176
164
 
169
171
 
166
 
168
 
Colorado Electric
384
289
 
365
296
 
306
(a) 
298
(a) 
Total Electric Utilities Peak Demands
956
830
 
921
859
 
881
 
873
 
__________________________
(a)    For the period July 14, 2008 to December 31, 2008.
 

11

 

Regulated Power Plants
 
As of December 31, 2010, our Electric Utilities' ownership interests in electric generation plants were as follows:
 
Unit
Fuel
Type
Location
Ownership
Interest %
Owned Capacity (MW)
Year
Installed
 
 
 
 
 
 
Black Hills Power:
 
 
 
 
 
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
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 (4):
 
 
 
 
 
W.N. Clark #1-2 (5)
Coal
Canon City, CO
100.0
%
42.0
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
 
 
 
686.9
 
________________________
(1)    Construction of Wygen III, a 110 MW mine-mouth coal-fired power plant was completed in April 2010. Black Hills Power operates the plant and owns a 52% interest in the facility, MDU owns a 25% interest and the City of Gillette owns a 23% interest. Our WRDC coal mine furnishes all of the coal fuel supply for the plant.
(2)    Wyodak is a 362 MW mine-mouth coal-fired plant 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 coal 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)    The construction of two 90 MW gas-fired power generation facilities is underway to support the customers of Colorado Electric. These facilities are expected to be completed by December 31, 2011.
(5)    In December 2010, Colorado Electric received a final order from CPUC which approved the retirement of its W.N. Clark coal-fired generation facility by December 31, 2013 and granted a presumption of need in the amount of 42 MW for replacement of the plant. Colorado Electric will file a Certificate of Public Convenience and Necessity to provide justification for an additional 50 MW of generating capacity to allow the construction of a third 92 MW GE LMS100 natural gas-fired generator at the Pueblo Airport Generation Station where two 90 MW facilities are currently under construction.
 

12

 

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
2010
2009
   2008(1)
 
 
 
 
Coal
$
12.77
 
$
13.99
 
$
11.41
 
 
 
 
 
Gas and Oil
$
131.28
 
$
85.52
 
$
88.60
 
 
 
 
 
Total Average Fuel Cost
$
13.57
 
$
15.22
 
$
13.18
 
 
 
 
 
Purchased Power(2)
$
30.23
 
$
28.93
 
$
38.06
 
________________________
(1)    2008 includes Colorado Electric from July 14, 2008 through December 31, 2008.
(2)    Includes Happy Jack commencing in October 2008, and Silver Sage commencing in October 2009.
 
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
2010
2009
2008
 
 
 
 
Coal-fired
42
%
39
%
44
%
 
 
 
 
Gas and Oil
 
1
 
1
 
Total Generated
42
 
40
 
45
 
 
 
 
 
Purchased
58
 
60
 
55
 
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 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 PSCo expiring at the end of 2011, whereby Colorado Electric purchases a majority of its power. The contract provides for 300 MW of capacity and energy in 2011;
 
•    
Colorado Electric's 20-year PPA with Black Hills Colorado IPP, beginning on January 1, 2012 and expiring in 2031, which will provide 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines, which are currently under construction;
 
•    
Cheyenne Light's PPA with Black Hills Wyoming expiring in August 2011 whereby Black Hills Wyoming provides 40 MW of energy and capacity from its Gillette CT.

13

 

 
•    
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 which is equivalent to the estimated initial per MW price of new construction of the Wygen III facility. This 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;
 
•    
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, provides 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:
 
•    
In conjunction with MDU's April 2009 purchase of a 25% ownership interest in Wygen III, an agreement to supply 74 MW of capacity and energy through 2016 was modified. The sales to MDU have been integrated into Black Hills Power's control area and are considered part of our firm native load. MWs from the Wygen III unit are deemed to supply a portion of the required 74 MW. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;
 
•    
Black Hills Power's agreement with the City of Gillette to dispatch the City of Gillette's 23% of Wygen III's net generating capacity for the life of the plant. Upon the City of Gillette's July 2010 purchase of a 23% ownership interest in Wygen III, a seven year PPA with the City of Gillette that went into effect in April 2010, was terminated. The City of Gillette's 23 MW of Wygen III capacity has been integrated into Black Hills Power's control area and are considered part of our firm native load. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we 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 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 capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
 
2010-2017
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 five-year PPA with MEAN which commenced in May 2010 whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III; 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. The agreements become effective on March 14, 2011, and terminate prior agreements under which Cheyenne Light supplies Basin Electric with 80 MW of energy and capacity, and Basin Electric supplies Cheyenne Light with 80 MW of energy and capacity.
 

14

 

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.
 
At December 31, 2010, our regulated 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
565
 
2,933
 
Black Hills Power - Jointly Owned (1)
SD, WY
47
 
 
Cheyenne Light
SD, WY
25
 
1,176
 
Colorado Electric
CO
260
 
3,032
 
 
(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.
 
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 used by an affiliate entity. This agreement commenced during 2010.
 
Operating Statistics
 
The following tables summarize sales revenues, quantities and customers for our Electric Utilities. Amounts shown for 2008 include Colorado Electric from our July 14, 2008 acquisition date through December 31, 2008.
 

15

 

Sales Revenues (in thousands)
 
 
 
 
2010
2009
2008
Residential:
 
 
 
Black Hills Power
$
53,549
 
$
48,586
 
$
46,854
 
Cheyenne Light
29,506
 
29,198
 
31,394
 
Colorado Electric
76,596
 
66,548
 
32,620
 
Total Residential
159,651
 
144,332
 
110,868
 
 
 
 
 
Commercial:
 
 
 
Black Hills Power
65,997
 
59,897
 
58,289
 
Cheyenne Light
52,765
 
51,280
 
51,609
 
Colorado Electric
66,490
 
56,002
 
28,531
 
Total Commercial
185,252
 
167,179
 
138,429
 
 
 
 
 
Industrial:
 
 
 
Black Hills Power
22,621
 
20,014
 
21,432
 
Cheyenne Light
10,542
 
11,121
 
9,716
 
Colorado Electric
28,812
 
31,067
 
16,280
 
Total Industrial
61,975
 
62,202
 
47,428
 
 
 
 
 
Municipal:
 
 
 
Black Hills Power
3,029
 
2,735
 
2,734
 
Cheyenne Light
1,293
 
932
 
973
 
Colorado Electric
10,443
 
4,408
 
2,289
 
Total Municipal
14,765
 
8,075
 
5,996
 
 
 
 
 
Contract Wholesale:
 
 
 
Black Hills Power
22,996
 
25,358
 
26,643
 
 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
36,354
 
32,212
 
63,770
 
Cheyenne Light
9,750
 
8,565
 
6,105
 
Colorado Electric
10,859
 
14,008
 
11,194
 
Total Off-system Wholesale
56,963
 
54,785
 
81,069
 
 
 
 
 
Other Sales Revenue:
 
 
 
Black Hills Power
25,217
 
18,277
 
12,950
 
Cheyenne Light
3,230
 
718
 
394
 
Colorado Electric
2,374
 
4,226
 
1,346
 
Total Other Sales Revenue
30,821
 
23,221
 
14,690
 
 
 
 
 
Total Sales Revenues
$
532,423
 
$
485,152
 
$
425,123
 
 

16

 

Quantities Generated and Purchased (MWh)
 
 
2010
2009
2008
Generated -
 
 
 
Coal-fired:
 
 
 
Black Hills Power
1,987,037
 
1,721,074
 
1,731,838
 
Cheyenne Light
734,241
 
766,943
 
740,051
 
Colorado Electric
257,896
 
252,603
 
138,424
 
Total Coal
2,979,174
 
2,740,620
 
2,610,313
 
 
 
 
 
Gas and Oil-fired:
 
 
 
Black Hills Power
19,269
 
46,723
 
61,801
 
Cheyenne Light
 
 
 
Colorado Electric
930
 
2,705
 
306
 
Total Gas and Oil
20,199
 
49,428
 
62,107
 
 
 
 
 
Total Generated:
 
 
 
Black Hills Power
2,006,306
 
1,767,797
 
1,793,639
 
Cheyenne Light
734,241
 
766,943
 
740,051
 
Colorado Electric
258,826
 
255,308
 
138,730
 
Total Generated
2,999,373
 
2,790,048
 
2,672,420
 
 
 
 
 
Purchased -
 
 
 
Black Hills Power
1,440,579
 
1,686,455
 
1,703,088
 
Cheyenne Light
696,756
 
651,201
 
590,622
 
Colorado Electric
1,969,896
 
1,991,058
 
1,028,029
 
Total Purchased
4,107,231
 
4,328,714
 
3,321,739
 
 
 
 
 
Total Generated and Purchased
7,106,604
 
7,118,762
 
5,994,159
 
 
 
 

17

 

Quantity (MWh)
 
 
 
 
2010
2009
2008
Residential:
 
 
 
Black Hills Power
547,193
 
529,825
 
524,413
 
Cheyenne Light
261,607
 
255,134
 
255,345
 
Colorado Electric
628,553
 
589,526
 
284,294
 
Total Residential
1,437,353
 
1,374,485
 
1,064,052
 
 
 
 
 
Commercial:
 
 
 
Black Hills Power
720,119
 
723,360
 
699,734
 
Cheyenne Light
603,323
 
583,986
 
586,151
 
Colorado Electric
726,005
 
666,563
 
330,870
 
Total Commercial
2,049,447
 
1,973,909
 
1,616,755
 
 
 
 
 
Industrial:
 
 
 
Black Hills Power
382,562
 
353,041
 
414,421
 
Cheyenne Light
161,082
 
174,792
 
144,179
 
Colorado Electric
347,673
 
452,584
 
235,218
 
Total Industrial
891,317
 
980,417
 
793,818
 
 
 
 
 
Municipal:
 
 
 
Black Hills Power
33,908
 
33,948
 
34,368
 
Cheyenne Light
6,477
 
3,456
 
3,669
 
Colorado Electric
113,689
 
37,244
 
19,740
 
Total Municipal
154,074
 
74,648
 
57,777
 
 
 
 
 
Contract Wholesale:
 
 
 
Black Hills Power
468,782
 
645,297
 
665,795
 
 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
1,163,058
 
1,009,574
 
1,074,398
 
Cheyenne Light
311,524
 
309,122
 
246,542
 
Colorado Electric
274,942
 
373,495
 
230,333
 
Total Off-system Wholesale
1,749,524
 
1,692,191
 
1,551,273
 
 
 
 
 
Total Quantity Sold:
 
 
 
Black Hills Power
3,315,622
 
3,295,045
 
3,413,129
 
Cheyenne Light
1,344,013
 
1,326,490
 
1,235,886
 
Colorado Electric
2,090,862
 
2,119,412
 
1,100,455
 
Total Quantity Sold
6,750,497
 
6,740,947
 
5,749,470
 
 
 
 
 
Losses and Company Use:
 
 
 
Black Hills Power
131,263
 
159,207
 
83,598
 
Cheyenne Light
86,984
 
91,654
 
94,787
 
Colorado Electric
137,860
 
126,954
 
66,304
 
Total Losses and Company Use
356,107
 
377,815
 
244,689
 
 
 
 
 
Total Energy
7,106,604
 
7,118,762
 
5,994,159
 
 

18

 

Degree Days
 
2010
2009
2008
 
Actual
Variance from
30-Year Average
Actual
Variance from
30-Year Average
Actual
Variance from
30-Year Average
Heating Degree Days:
 
 
 
 
 
 
Actual -
 
 
 
 
 
 
Black Hills Power
7,272
 
1
 %
7,753
 
8
 %
7,676
 
6
 %
Cheyenne Light
7,033
 
(5
)%
7,411
 
 %
7,435
 
1
 %
Colorado Electric
5,518
 
(1
)%
5,546
 
(1
)%
2,204
 
(5
)%
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
Actual -
 
 
 
 
 
 
Black Hills Power
532
 
(11
)%
354
 
(41
)%
482
 
(19
)%
Cheyenne Light
345
 
26
 %
203
 
(26
)%
372
 
36
 %
Colorado Electric
1,074
 
16
 %
804
 
(13
)%
500
 
(12
)%
 
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. 
 
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. 
 

19

 

Electric Customers at Year-End
 
2010
2009
2008
Residential:
 
 
 
Black Hills Power
54,811
 
54,470
 
53,765
 
Cheyenne Light
34,913
 
35,943
 
35,205
 
Colorado Electric
81,902
 
81,622
 
81,561
 
Total Residential
171,626
 
172,035
 
170,531
 
 
 
 
 
Commercial:
 
 
 
Black Hills Power
12,779
 
12,261
 
12,213
 
Cheyenne Light
4,132
 
4,932
 
4,563
 
Colorado Electric
11,185
 
11,101
 
11,155
 
Total Commercial
28,096
 
28,294
 
27,931
 
 
 
 
 
Industrial:
 
 
 
Black Hills Power
40
 
38
 
40
 
Cheyenne Light
2
 
2
 
2
 
Colorado Electric
63
 
90
 
93
 
Total Industrial
105
 
130
 
135
 
 
 
 
 
Contract Wholesale:
 
 
 
Black Hills Power
3
 
3
 
3
 
 
 
 
 
Other Electric Customers:
 
 
 
Black Hills Power
309
 
143
 
3,010
 
Cheyenne Light
254
 
13
 
6
 
Colorado Electric
510
 
499
 
480
 
Total Other Electric Customers
1,073
 
655
 
3,496
 
 
 
 
 
Total Customers:
 
 
 
Black Hills Power
67,942
 
66,915
 
69,031
 
Cheyenne Light
39,301
 
40,890
 
39,776
 
Colorado Electric
93,660
 
93,312
 
93,289
 
Total Customers
200,903
 
201,117
 
202,096
 

20

 

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:
 
 
2010
2009
2008
 
 
 
 
Sales Revenues (in thousands):
 
 
 
Residential
$
22,562
 
$
21,495
 
$
28,059
 
Commercial
10,801
 
9,821
 
13,751
 
Industrial
3,425
 
3,537
 
5,668
 
Other Sales Revenues
803
 
760
 
818
 
Total Sales Revenues
$
37,591
 
$
35,613
 
$
48,296
 
 
 
 
 
Sales Margins (in thousands):
 
 
 
Residential
$
10,004
 
$
10,219
 
$
10,083
 
Commercial
3,376
 
3,266
 
3,177
 
Industrial
427
 
509
 
483
 
Other Sales Margins
720
 
760
 
818
 
Total Sales Margins
$
14,527
 
$
14,754
 
$
14,561
 
 
 
 
 
Volumes Sold (Dth):
 
 
 
Residential
2,636,839
 
2,516,699
 
2,582,248
 
Commercial
1,572,638
 
1,502,002
 
1,501,025
 
Industrial
667,062
 
722,776
 
689,945
 
Total Volumes Sold
4,876,539
 
4,741,477
 
4,773,218
 
 
 
 
 
Customers
34,461
 
33,942
 
33,243
 
 
Gas Utilities Segment
 
At December 31, 2010, 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
122
 
2,967
 
871
 
Nebraska
51
 
3,406
 
3,462
 
Iowa
170
 
2,753
 
2,313
 
Kansas
283
 
2,578
 
1,288
 
Total
626
 
11,704
 
7,934
 
 

21

 

Operating Statistics
 
The following tables summarize revenues, sales margins, volumes, degree days and customers for our Gas Utilities. Amounts shown for 2008 include Gas Utilities from our July 14, 2008 acquisition date through December 31, 2008.
Revenues (in thousands)
2010
2009
2008
 
 
Residential:
 
 
 
Colorado
$
55,211
 
$
62,732
 
$
27,928
 
Nebraska
120,365
 
127,120
 
60,624
 
Iowa
105,255
 
113,781
 
47,338
 
Kansas
69,859
 
70,848
 
31,456
 
Total Residential
350,690
 
374,481
 
167,346
 
 
 
 
 
Commercial:
 
 
 
Colorado
11,880
 
13,357
 
6,356
 
Nebraska
40,720
 
43,472
 
20,705
 
Iowa
46,762
 
54,587
 
26,003
 
Kansas
21,953
 
22,629
 
10,092
 
Total Commercial
121,315
 
134,045
 
63,156
 
 
 
 
 
Industrial:
 
 
 
Colorado
1,409
 
1,348
 
1,495
 
Nebraska
3,126
 
3,425
 
1,640
 
Iowa
2,243
 
2,191
 
1,581
 
Kansas
14,312
 
11,057
 
14,667
 
Total Industrial
21,090
 
18,021
 
19,383
 
 
 
 
 
Other Sales Revenue:
 
 
 
Colorado
97
 
100
 
39
 
Nebraska
1,960
 
2,077
 
907
 
Iowa
836
 
1,073
 
457
 
Kansas
3,451
 
3,213
 
1,600
 
Total Other Sales Revenue
6,344
 
6,463
 
3,003
 
 
 
 
 
Total Distribution:
 
 
 
Colorado
68,597
 
77,537
 
35,818
 
Nebraska
166,171
 
176,094
 
83,876
 
Iowa
155,096
 
171,632
 
75,379
 
Kansas
109,575
 
107,747
 
57,815
 
Total Distribution
499,439
 
533,010
 
252,888
 
 
 
 
 
Transportation:
 
 
 
Colorado
784
 
732
 
278
 
Nebraska
11,289
 
10,569
 
4,703
 
Iowa
3,708
 
3,876
 
1,609
 
Kansas
5,471
 
5,389
 
2,409
 
Total Transportation
21,252
 
20,566
 
8,999
 
 
 
 
 
Total Regulated:
 
 
 
Colorado
69,381
 
78,269
 
36,096
 
Nebraska
177,460
 
186,663
 
88,579
 
Iowa
158,804
 
175,508
 
76,988
 
Kansas
115,046
 
113,136
 
60,224
 
Total Regulated Revenues
520,691
 
553,576
 
261,887
 
 
 
 
 
Non-regulated Services
30,016
 
26,736
 
15,189
 
 
 
 
 
Total Revenues
$
550,707
 
$
580,312
 
$
277,076
 

22

 

 
Sales Margins (in thousands)
2010
2009
2008
 
 
Residential:
 
 
 
Colorado
$
18,153
 
$
17,443
 
$
5,984
 
Nebraska
49,074
 
44,638
 
19,460
 
Iowa
44,269
 
42,734
 
16,335
 
Kansas
29,591
 
28,999
 
12,436
 
Total Residential
141,087
 
133,814
 
54,215
 
 
 
 
 
Commercial:
 
 
 
Colorado
3,215
 
3,176
 
1,131
 
Nebraska
11,965
 
11,785
 
4,952
 
Iowa
11,616
 
12,749
 
5,210
 
Kansas
6,544
 
6,484
 
2,693
 
Total Commercial
33,340
 
34,194
 
13,986
 
 
 
 
 
Industrial:
 
 
 
Colorado
360
 
375
 
232
 
Nebraska
379
 
431
 
173
 
Iowa
235
 
244
 
105
 
Kansas
1,878
 
1,766
 
1,041
 
Total Industrial
2,852
 
2,816
 
1,551
 
 
 
 
 
Other Sales Margins:
 
 
 
Colorado
97
 
101
 
39
 
Nebraska
1,960
 
2,077
 
907
 
Iowa
836
 
1,073
 
457
 
Kansas
2,722
 
2,312
 
1,177
 
Total Other Sales Margins
5,615
 
5,563
 
2,580
 
 
 
 
 
Total Distribution:
 
 
 
Colorado
21,825
 
21,095
 
7,386
 
Nebraska
63,378
 
58,931
 
25,492
 
Iowa
56,956
 
56,800
 
22,107
 
Kansas
40,735
 
39,561
 
17,347
 
Total Distribution
182,894
 
176,387
 
72,332
 
 
 
 
 
Transportation:
 
 
 
Colorado
784
 
732
 
278
 
Nebraska
11,289
 
10,569
 
4,703
 
Iowa
3,708
 
3,876
 
1,609
 
Kansas
5,470
 
5,389
 
2,409
 
Total Transportation
21,251
 
20,566
 
8,999
 
 
 
 
 
Total Regulated:
 
 
 
Colorado
22,609
 
21,827
 
7,664
 
Nebraska
74,667
 
69,500
 
30,195
 
Iowa
60,664
 
60,676
 
23,716
 
Kansas
46,205
 
44,950
 
19,756
 
Total Regulated Sales Margins
204,145
 
196,953
 
81,331
 
 
 
 
 
Non-regulated Services
12,845
 
11,643
 
3,895
 
 
 
 
 
Total Sales Margins
$
216,990
 
$
208,596
 
$
85,226
 
 

23

 

 
 
Volumes (in Dth)
2010
2009
2008
 
 
 
 
Residential:
 
 
 
Colorado
6,284,559
 
6,355,275
 
2,344,549
 
Nebraska
12,210,574
 
12,619,682
 
5,115,805
 
Iowa
10,556,045
 
10,976,268
 
4,126,150
 
Kansas
6,926,928
 
6,878,243
 
2,682,850
 
Total Residential
35,978,106
 
36,829,468
 
14,269,354
 
 
 
 
 
Commercial:
 
 
 
Colorado
1,473,924
 
1,444,360
 
563,169
 
Nebraska
5,009,105
 
5,189,630
 
2,133,433
 
Iowa
6,061,954
 
6,597,035
 
2,749,234
 
Kansas
2,673,805
 
2,696,870
 
1,063,356
 
Total Commercial
15,218,788
 
15,927,895
 
6,509,192
 
 
 
 
 
Industrial:
 
 
 
Colorado
259,985
 
263,134
 
164,112
 
Nebraska
544,457
 
581,892
 
248,256
 
Iowa
354,435
 
333,324
 
196,841
 
Kansas
2,718,767
 
2,524,126
 
1,586,306
 
Total Industrial
3,877,644
 
3,702,476
 
2,195,515
 
 
 
 
 
Other Volumes:
 
 
 
Colorado
 
 
 
Nebraska
1,341
 
1,400
 
320
 
Iowa
69,306
 
68,290
 
18,301
 
Kansas
120,445
 
141,909
 
60,917
 
Total Other Volumes
191,092
 
211,599
 
79,538
 
 
 
 
 
Total Distribution:
 
 
 
Colorado
8,018,468
 
8,062,769
 
3,071,830
 
Nebraska
17,765,477
 
18,392,604
 
7,497,814
 
Iowa
17,041,740
 
17,974,917
 
7,090,526
 
Kansas
12,439,945
 
12,241,148
 
5,393,429
 
Total Distribution
55,265,630
 
56,671,438
 
23,053,599
 
 
 
 
 
Transportation:
 
 
 
Colorado
808,859
 
807,999
 
347,822
 
Nebraska
27,327,173
 
25,311,501
 
12,930,165
 
Iowa
17,422,525
 
14,915,602
 
6,312,050
 
Kansas
14,320,893
 
14,069,182
 
7,215,038
 
Total Transportation
59,879,450
 
55,104,284
 
26,805,075
 
 
 
 
 
Total Volumes:
 
 
 
Colorado
8,827,327
 
8,870,768
 
3,419,652
 
Nebraska
45,092,650
 
43,704,105
 
20,427,979
 
Iowa
34,464,265
 
32,890,519
 
13,402,576
 
Kansas
26,760,838
 
26,310,330
 
12,608,467
 
Total Volumes
115,145,080
 
111,775,722
 
49,858,674
 
 
 

24

 

Degree Days
 
2010
2009
2008
 
Actual
Variance From
30-Year Average
Actual
Variance From
30-Year Average
Actual *
Variance From
30-Year Average *
Heating Degree Days:
 
 
 
 
 
 
Colorado
5,803
 
(9
)%
6,299
 
2
 %
2,376
 
(7
)%
Nebraska
6,222
 
(5
)%
6,238
 
5
 %
2,458
 
 %
Iowa
6,934
 
(1
)%
7,279
 
6
 %
2,909
 
3
 %
Kansas
4,918
 
 %
4,989
 
 %
1,897
 
(3
)%
Combined
6,101
 
(3
)%
6,285
 
(11
)%
2,471
 
 %
___________
* Gas Utilities acquired on July 14, 2008.
 
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.  For service areas that have weather normalization operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days.  The combined heating degree days are calculated based on a weighted average of total customers by state. 
 

25

 

The following table summarizes the Gas Utilities' customers as of December 31:
 
Customers
2010
2009
2008
 
 
 
 
Residential:
 
 
 
Colorado
66,766
 
65,586
 
64,601
 
Nebraska
176,244
 
179,873
 
177,432
 
Iowa
134,782
 
133,712
 
133,442
 
Kansas
97,844
 
97,446
 
96,593
 
Total Residential
475,636
 
476,617
 
472,068
 
 
 
 
 
Commercial:
 
 
 
Colorado
3,620
 
3,590
 
3,579
 
Nebraska
15,221
 
15,218
 
15,034
 
Iowa
15,300
 
15,403
 
15,467
 
Kansas
9,469
 
9,510
 
9,463
 
Total Commercial
43,610
 
43,721
 
43,543
 
 
 
 
 
Industrial:
 
 
 
Colorado
208
 
207
 
208
 
Nebraska
149
 
149
 
149
 
Iowa
93
 
90
 
84
 
Kansas
1,394
 
1,351
 
1,267
 
Total Industrial
1,844
 
1,797
 
1,708
 
 
 
 
 
Transportation:
 
 
 
Colorado
22
 
22
 
21
 
Nebraska
4,270
 
4,579
 
4,758
 
Iowa
392
 
389
 
397
 
Kansas
1,054
 
1,077
 
1,174
 
Total Transportation
5,738
 
6,067
 
6,350
 
 
 
 
 
Other:
 
 
 
Colorado
 
 
 
Nebraska
2
 
2
 
2
 
Iowa
68
 
71
 
69
 
Kansas
8
 
8
 
8
 
Total Other
78
 
81
 
79
 
 
 
 
 
Total Customers:
 
 
 
Colorado
70,616
 
69,405
 
68,409
 
Nebraska
195,886
 
199,821
 
197,375
 
Iowa
150,635
 
149,665
 
149,459
 
Kansas
109,769
 
109,392
 
108,505
 
Total Customers
526,906
 
528,283
 
523,748
 

26

 

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 in comparison to other investor-owned electric utilities. 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 revenues are normally recognized in the heating season consisting of the first and fourth quarters.
 
Competition
 
We face competition from other utilities and non-affiliated IPP companies for the right to provide power and capacity for Colorado Electric. However, 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.
 
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 our utilities are allowed to charge for their 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 through to the customer. In Kansas and Nebraska, we are also allowed to recover the portion of uncollectible accounts related to gas costs through the gas cost adjustments. In Kansas, we have a weather normalization tariff that provides a pass-through mechanism for weather margin variability that occurs from the level used to establish base rates to be paid by the customer. In Kansas, we also have 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.
 
We produce and distribute power in four states. The regulatory provisions for recovering the costs to produce electricity vary by state. 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 changes above or below the threshold.
 

27

 

Until April 1, 2010 South Dakota had three adjustment mechanisms: transmission, steam plant fuel (coal) and conditional energy cost adjustment. 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 energy cost adjustment 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 energy cost adjustment 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 Colorado, we have a cost adjustment for increases or decreases in purchased power and fuel costs and a transmission cost adjustment. The cost adjustment 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 transmission cost adjustment 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.
 
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.
 
The above mechanisms allow the utilities 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, such as the transmission cost adjustment in Colorado, the utility has the opportunity to earn its authorized return on new capital investment.
 
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, 2010, we were subject to the following renewable energy portfolio standards or objectives:
 
•    
South Dakota. South Dakota has adopted a renewable portfolio objective that encourages 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.
 
•    
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 renewable resources with one-half of the renewable 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. Our current strategy is to incorporate renewable energy as required to comply with the standards.
 

28

 

Wyoming is also exploring the implementation of renewable energy portfolio 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 the Aquila Transaction, 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 two of our non-regulated subsidiaries, Black Hills Wyoming and Enserco, 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, enforce 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.
 

29

 

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
9/2008
1/2009
$
4.5
 
$
3.8
 
10.8
%
57.0
%
43.0
%
Black Hills Power (4)
Electric
9/2009
4/2010
$
32.0
 
$
15.2
 
Global Settlement
 
Global Settlement
 
Global Settlement
 
Black Hills Power (5)
Electric
10/2009
6/2010
$
3.8
 
$
3.1
 
10.5
%
52.0
%
48.0
%
Colorado Electric (6)
Electric
1/2010
8/2010
$
22.9
 
$
17.9
 
10.5
%
52.0
%
48.0
%
 
(1)    
On December 1, 2009, Nebraska Gas filed with the NPSC a $12.1 million rate case requesting a gas revenue increase to recover operating costs and distribution system investments. The proposed increase in revenue was approximately 6.5%. Interim rates, subject to refund for the entire amount of the proposed increase, went into effect on March 1, 2010. On August 18, 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 plan for refund has been approved by the NPSC. An appeal was filed by the OCA relating to the entire rate case decision. However, the NPSC denied this appeal. Subsequently, the OCA filed an appeal in September 2010 appealing a portion of the Commission's order addressing our affiliate transactions. The appeal is still outstanding.
 
(2)    
On June 8, 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)    
On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of Black Hills Power's open access transmission tariff, and increased the utility's annual transmission revenue requirement by approximately $3.8 million. The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt. New annual rates went into effect on January 1, 2009.
 
(4)    
On September 30, 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 past 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 margins 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 ending 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

30

 

 
(5)    
On October 19, 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.
 
(6)    
On January 6, 2010, Colorado Electric filed a rate case with CPUC requesting a $22.9 million electric revenue increase to recover increased operating expenses associated with 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 margins 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 has therefore required that the off-system sales margins earned beginning August 6, 2010 be deferred on the balance sheet until settlement of the sharing mechanism. Colorado Electric is preparing a proposal for a sharing mechanism to be filed with the CPUC.
 
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. The ultimate cost could be significantly different from the amounts estimated.
 
Environmental Expenditure Estimates
Total
(in millions)
 
 
2011
$
12.7
 
2012
3.8
 
2013
0.6
 
Total
$
17.1
 
 
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 late in 2011, which could have a significant impact on all of our generating fleet.
 

31

 

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 as of June 23, 2010, Greenhouse Gases. 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 that year. 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 2040. For future plants, we plan to secure the requisite number of allowances by reducing SO2 emissions through the use of low sulfur fuels, installation of "back end" control technology, use of banked allowances, and if necessary, the purchase of allowances on the open market. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such new projects.
 
Title V of the Clean Air Act requires that all of our generating facilities obtain operating permits. All of our existing facilities have received Title V permits, with the exception of Wygen II and Wygen III. Those facilities are allowed to operate under their construction permit until the Title V permits are issued by the state. The Title V application for Wygen II was submitted in 2008, with the permit expected early in 2011. The Wygen III Title V application was submitted in January 2011, with the permit expected in late 2011. Both applications were filed in accordance with regulatory requirements.
 
On April 29, 2010, the EPA published proposed Industrial and Commercial Boiler regulations, which provide for hazardous air pollutant-related emission limits and monitoring requirements for both major and area sources of hazardous air pollutants. The final rule has a court ordered deadline of February 21, 2011 and we will evaluate once final. If issued as proposed, will have a significant impact on our Neil Simpson I, Osage, Ben French and W.N. Clark facilities. The regulation currently has a three year compliance window and will require engineering evaluations to determine economic viability of continued operations of these units. In our current opinion, the regulations as proposed on April 29, 2010 will lead to retirement of these units within three years of the effective date of the final rule.
 
The EPA is obligated under a court-approved consent decree to sign a proposed electric utility hazardous air pollutant rule (Utility MACT) by March 16, 2011 and sign its notice of final rule making by November 16, 2011. It is anticipated that affected units will have three years from the rule effective date to be in compliance. In 2010, we participated in the EPA's effort to gather data for rule development. Certain requirements of that regulation could have significant impacts on the Neil Simpson II, Wygen II, Wygen III and Wyodak plants.
 
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. 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 greenhouse gases, 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.
 

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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 within three years of promulgation of the EPA's proposed Industrial and Commercial Boiler Hazardous Air Pollutant Regulation, or in the absence of such regulation, to retire the units by the end of 2017. 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 which, after legislative approval, will be a state regulation and will be submitted to EPA Region VIII for approval.
 
In June 2011, the EPA is scheduled to issue proposed Electric Utility New Source Performance Standards for greenhouse gases. As the regulations are not yet proposed we cannot ascertain their impacts but we anticipate they will be applicable to Wygen III. In 2011 it is anticipated the EPA will finalize a more stringent ozone ambient air standard. 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 would evaluate Neil Simpson II, Wygen II and Wygen III for further reductions in NOx emissions.
 
Mercury regulations
 
Approximately 60% of our electric generating capacity is coal-fired. The EPA is scheduled to propose the Utility MACT rule by March 16, 2011 which will, among other pollutants, address mercury emissions at Neil Simpson II, Wygen II and Wygen III.
 
The effects of any new rules regarding mercury reduction cannot be determined at this time and may require us to make significant investments at our power generating facilities. 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 assets that includes wind sources and a fuel mix of coal and natural gas. Of these fuels, coal-fired power plants are the most significant sources of CO2 emissions. Although we cannot predict specifically how, if or when, greenhouse gases 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, we will be reporting 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, greenhouse gas 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 and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.
 

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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. Federal legislation for renewable energy portfolio standards is also under consideration. We anticipate significant additional costs to comply with any federally 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. We have suspended operations at the Osage power plant as of October 1, 2010. It has an on-site ash impoundment that is near capacity. An application to close the impoundment was filed with the State of Wyoming on November 3, 2010 and any future ash disposal will be at the Wyodak coal mine. Our W.N. Clark plant sends coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. Agreements are in place that require PacifiCorp and MEAN to be responsible for any such costs related to the solid waste from their ownership interest in the Wyodak plant and Wygen I plant, respectively.
 
Additional unexpected material costs could also result in the future if any regulator determines that solid waste from the burning of coal contains a hazardous material that requires special treatment, including previously disposed solid waste. In that event, the regulatory authority could hold entities that disposed of such waste responsible for remedial treatment. On June 21, 2010, the EPA published in the Federal Register the proposed coal combustion residuals regulations. The regulations are complex and contain various options for ash management that the EPA will be selecting from to form the final version of the rule. We cannot determine the likely impact on our operations until the final version of the rule is known, which is currently expected to be mid-2011. However, if ash becomes subject to regulations as a hazardous waste, implementation requirements could have a material impact on our financial position or results of operations.
 
Past Operations
 
Some federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment.
 
As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites. In 2010, we undertook a third party review to obtain an updated estimate of remedial costs. From that review, obligations are estimated at between $3.6 million and $6.8 million. The acquisition also provided for a $1.0 million insurance recovery, now valued at $1.1 million, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.
 
We have received rate orders that enable us to recover environmental cleanup costs in certain jurisdictions. In other jurisdictions, there is regulatory precedent for recovery of these costs. We are also pursuing recovery or agreements with other potentially responsible parties when and where permitted.
 

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Non-regulated Energy Group
 
Our Non-regulated Energy Group, which operates through various subsidiaries, produces natural gas and crude oil primarily in the Rocky Mountain region; produces and sells electric capacity and energy through ownership of a portfolio of generating plants; produces and stores coal; and engages in natural gas, crude oil, coal, power and environmental marketing. The Non-regulated Energy Group consists of four business segments for reporting purposes:
 
•    
Oil and Gas;
 
•    
Power Generation;
 
•    
Coal Mining; and
 
•    
Energy Marketing.
 
Oil and Gas Segment
 
Our Oil and Gas segment, which conducts business through BHEP and its subsidiaries, acquires, explores for, develops and produces natural gas and crude oil for sale into commodity markets. As of December 31, 2010, the principal assets of our Oil and Gas segment included: (i) operating interests in oil and natural gas properties, including properties in the San Juan Basin (primarily New Mexico, including holdings within the tribal lands of the Jicarilla Apache and Southern Ute Nations), the Powder River Basin (Wyoming) and the Piceance Basin (primarily in Colorado); (ii) non-operated interests in oil and natural gas properties including wells located in the Williston (Bakken Shale primarily in North Dakota), Wind River (Wyoming), Bearpaw Uplift (Montana), Arkoma (Oklahoma), Anadarko (Texas) and Sacramento (California) basins; and (iii) a 44.7% ownership interest in the Newcastle gas processing plant and associated gathering system located in Weston County, Wyoming. The plant, operated by Western Gas Partners, LP, is adjacent to our producing properties in that area, and BHEP's production accounts for the majority of the facility's throughput. We also own natural gas gathering, compression and treating facilities serving the operated San Juan and Piceance Basin properties and working interests in similar facilities serving our non-operated Montana and Wyoming properties.
 
At December 31, 2010, we had total reserves of approximately 131 Bcfe, of which natural gas comprised 73% and oil comprised 27% of total reserves. The majority of our reserves are located in select oil and natural gas producing basins in the Rocky Mountain region. Approximately 28% of our reserves are located in the San Juan Basin of northwestern New Mexico, primarily in the East Blanco Field of Rio Arriba County, 26% are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field of Weston and Niobrara counties and 25% are located in the Piceance Basin of western Colorado.
 
Delivery Commitments
 
None of our oil and gas production is sold under long-term product delivery commitments.
 
Summary Oil and Gas Reserve Data
 
The summary information presented concerning our estimated proved developed and undeveloped oil and gas reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by CG&A, an independent consulting and engineering firm located in Fort Worth, Texas. Reserves in 2010 and 2009 were determined consistent with SEC requirements using a 12-month average price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results. Our 2008 reserves were determined based on the previous guidelines utilizing the price on the last day of the reporting period. (Oil (in Mbbl) is multiplied by six to convert to MMcfe). Additional information on our oil and gas reserves, related financial data and the SEC requirements can be found in Note 21 to the Consolidated Financial Statements in this Annual Report on Form 10-K.
 

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The Company believes it maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interest and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. The Company's internal engineers and our independent reserve engineering firm, CG&A, work independently and concurrently to develop reserve volume estimates. Current revenue and expense information is obtained from the Company's accounting records, which are subject to external quarterly reviews, annual audits and internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. The Company's current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updated with current information, and all relevant technical support materials have been assembled, CG&A meets with the Company's technical personnel to review field performance and future development plans in order to further verify their validity. Following these reviews the reserve database, including updated cost, price and ownership data, is furnished to CG&A so that they can prepare their independent reserve estimates and final report. Access to the Company's reserve database is restricted to specific members of the engineering department.
 
CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas and has over 22 years of practical experience in petroleum engineering and over 20 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
 
BHEP's Manager of Planning and Analysis is the technical person primarily responsible for overseeing our third party reserve estimates. He has over 30 years of Exploration and Production industry experience as a geologist. He has over 20 years of experience working closely with internal and third party qualified reserve estimators in major and mid-sized oil and gas companies. He holds a Bachelor of Science degree in Geology and a Masters in Business Administration.
 
The following tables set forth summary information concerning our estimated proved developed and undeveloped reserves, by basin, as of December 31, 2010, 2009 and 2008:
 
Proved Reserves
 
December 31, 2010
 
Total
Piceance
San Juan
Williston
Powder River
Other
Developed -
 
 
 
 
 
 
Natural Gas (MMcf)
67,656
 
11,475
 
36,281
 
679
 
10,180
 
9,041
 
Oil (Mbbl)
4,434
 
 
11
 
508
 
3,891
 
24
 
Total Developed (MMcfe)
94,260
 
11,475
 
36,347
 
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