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EX-31.1 - EXHIBIT 31.1 - BLACK HILLS POWER INCexhibit311bhp122010.htm
EX-32.2 - EXHIBIT 32.2 - BLACK HILLS POWER INCexhibit322bhp122010.htm
EX-31.2 - EXHIBIT 31.2 - BLACK HILLS POWER INCexhibit312bhp122010.htm
EX-32.1 - EXHIBIT 32.1 - BLACK HILLS POWER INCexhibit321bhp122010.htm
EX-23 - AUDITOR CONSENT - BLACK HILLS POWER INCexhibit23auditorconsent.htm
 

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
®
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 1-07978
 
BLACK HILLS POWER, INC.
Incorporated in South Dakota
 
IRS Identification Number 46-0111677
625 Ninth Street, Rapid City, South Dakota 57701
 
 
 
Registrant's telephone number, including area code: (605) 721-1700
 
 
 
Securities registered pursuant to Section 12(b) of the Act: None
 
 
 
Securities registered pursuant to Section 12(g) of the Act: None
 
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    ®
 
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    x    No    ®
 
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    ®
 
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    ®    No    ®
 
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.
This paragraph is not applicable to the Registrant.        x
 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer    ®    Accelerated filer    ®    Non-accelerated filer    x     Smaller reporting company     ®
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes    ®    No    x
 
State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
 
All outstanding shares are held by the Registrant's parent company, Black Hills Corporation. Accordingly, the aggregate market value of the voting common stock of the Registrant held by non-affiliates is $0.
 
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 February 28, 2011
Common stock, $1.00 par value
23,416,396 shares
 
Reduced Disclosure
The Registrant meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
 

1

 

TABLE OF CONTENTS
 
 
 
 
 
Page
 
 
 
 
GLOSSARY OF TERMS
 
 
 
ITEMS 1. and 2.
BUSINESS AND PROPERTIES
 
Safe Harbor for Forward Looking Information
 
General and Regulations
 
 
 
ITEM 1A.
RISK FACTORS
 
 
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS
 
 
 
ITEM 3.
LEGAL PROCEEDINGS
 
 
 
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
 
 
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
 
 
 
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
 
 
 
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
 
 
 
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
 
 
 
SIGNATURES
 
 
 
 
INDEX TO EXHIBITS
 

2

 

GLOSSARY OF TERMS AND ABBREVIATIONS
 
The following terms and abbreviations appear in the text of this report and have the definitions described below:
 
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income
ASC
Accounting Standards Codification
ASC 310-10-50
ASC 310-10-50, "Disclosure About the Credit Quality of Financing Receivables and the Allowance for Credit Losses"
ASC 810-10-15
ASC 810-10-15, "Consolidation of Variable Interest Entities"
Basin Electric
Basin Electric Power Cooperative
BHC
Black Hills Corporation, Parent
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Parent Company, that was formerly known as Black Hills Energy, Inc.
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Wyoming
Black Hills Wyoming, LLC, an indirect, wholly-owned subsidiary of Black Hills Electric Generation, Inc., a subsidiary of Black Hills Non-regulated Holdings
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
City of Gillette
The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23% of the 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
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
Enserco
Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-Regulated Holdings, LLC
EPA
U.S. Environmental Protection Agency
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
Happy Jack
Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
IRS
Internal Revenue Service
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.
KV
Kilovolt
LIBOR
London Interbank Offered Rate
MACT
Maximum Achievable Control Technology
MAPP
Mid-Continent Area Power Pool
MDU
Montana Dakota Utilities Company
MEAN
Municipal Energy Agency of Nebraska
MMBtu
Million British thermal units
 

3

 

Moody's
Moody's Investor Services, Inc.
MTPSC
Montana Public Service Commission
MW
Megawatts
MWh
Megawatt-hours
NOL
Net operating loss
NQDC
Non-Qualified Deferred Compensation Plan
PPA
Power Purchase Agreement
PPACA
Patient Protection and Affordable Care Act of 2010
PSD
Prevention of Significant Deterioration
PUHCA
Public Utility Holding Company Act of 2005
RMSA
Retiree Medical Savings Account
SDPUC
South Dakota Public Utilities Commission
SEC
U. S. Securities and Exchange Commission
Silver Sage
Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
SO2
Sulfur Dioxide
S&P
Standard & Poor's Rating Services
WECC
Western Electricity Coordinating Council
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC
 

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PART I
 
ITEMS 1 and 2.    BUSINESS AND PROPERTIES
 
Safe Harbor for 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. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Forward-looking statements involve risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potentials," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurances that such indicated results will be realized. 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 following:
 
•    
Our ability to obtain adequate cost recovery for our electric utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel and purchased power and our ability to add power generation assets into regulatory rate base;
 
•    
Our ability to successfully maintain or improve our corporate credit rating;
 
•    
Our ability to obtain from utility commissions any requisite determination of prudency to support resource planning and development programs we propose to implement;
 
•    
The timing and extent of scheduled and unscheduled outages;
 
•    
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;
 
•    
Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005 and subsequent rules and regulations promulgated thereunder;
 
•    
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 remedy any deficiencies that may be identified in the review of our internal controls;
 
•    
Our ability to successfully complete labor negotiations with our union;
 
•    
The timing, volatility and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost and availability of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets;
 
•    
Our ability to effectively use derivative financial instruments to hedge commodity risks;
 
•    
Our ability to minimize defaults on amounts due from customers and counterparty transactions;
 
•    
Our ability to comply, or to make expenditures required to comply with changes in laws and regulations, particularly those relating to taxation, safety and protection of the environment and to recover those expenditures in customer rates, where applicable;
 
•    
Liabilities related to environmental conditions, including remediation and reclamation obligations under environmental laws;

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•    
Federal and state laws concerning climate changes and air emissions, including emission reduction mandates 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;
 
•    
Our ability to recover our borrowing costs, including debt service costs, in our customer rates;
 
•    
Weather and other natural phenomena;
 
•    
Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidations and changes in competition, (ii) changing conditions in the credit markets, and (iii) general economic and political conditions, including tax rates or policies and inflation rates;
 
•    
The effect of accounting policies issued periodically by accounting standard-setting bodies;
 
•    
The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events;
 
•    
The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements on our financial condition or results of operations;
 
•    
Capital market conditions, which may affect our ability to raise capital on favorable terms;
 
•    
Price risk due to marketable securities held as investments in benefit plans; and
 
•    
Other factors discussed from time to time in our other filings with the SEC.
 
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.
 

6

 

General
 
We are a regulated electric utility serving customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation.
 
Unless the context otherwise requires, references in this Form 10-K to "the Company," "we," "us" and "our" refer to Black Hills Power, Inc.
 
We engage in the generation, transmission and distribution of electricity. We have a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends to our Parent, and our overall performance and growth.
 
As of December 31, 2010, our ownership interests in electric generation plants were as follows:
 
Unit
Fuel
Type
Location
Ownership
Interest %
Owned Capacity (MW)
Year
Installed
Wygen III (1)
Coal
Gillette, WY
52
%
57.2
 
2010
Neil Simpson II
Coal
Gillette, WY
100
%
90.0
 
1995
Wyodak (2)
Coal
Gillette, WY
20
%
72.4
 
1978
Osage (3)
Coal
Osage, WY
100
%
34.5
 
1948-1952
Ben French
Coal
Rapid City, SD
100
%
25.0
 
1960
Neil Simpson I
Coal
Gillette, WY
100
%
21.8
 
1969
Neil Simpson CT
Gas
Gillette, WY
100
%
40.0
 
2000
Lange CT
Gas
Rapid City, SD
100
%
40.0
 
2002
Ben French Diesel #1-5
Oil
Rapid City, SD
100
%
10.0
 
1965
Ben French CTs #1-4
Gas/Oil
Rapid City, SD
100
%
100.0
 
1977-1979
                    
(1)    Construction of Wygen III, a 110 MW mine-mouth coal-fired power plant was completed in April 2010. We operate the plant and own a 52% interest in the facility, MDU owns a 25% interest and the City of Gillette owns a 23% interest. The WRDC coal mine furnishes all of the coal fuel supply for the plant.
(2)    Wyodak is a 362 MW mine-mouth coal-fired power plant owned 80% by PacifiCorp and we own 20%. This baseload plant is operated by PacifiCorp and the 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.
 
Distribution and Transmission. Our distribution and transmission system serves approximately 68,000 electric customers, with an electric transmission system of 565 miles of high voltage lines (greater than 69 KV) and 2,933 miles of lower voltage lines. In addition, we jointly own 47 miles of high voltage lines with Basin Electric. Our service territory covers areas of western South Dakota, northeastern Wyoming and southeastern Montana with a strong and stable economic base. Approximately 83% of our retail electric revenues in 2010 were generated in South Dakota. We are subject to regulation by the SDPUC, the WPSC and the MTPSC.
 
The following are characteristics of our distribution and transmission businesses:
 
•    
We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2010 was comprised of 29% commercial, 23% residential, 10% contract wholesale, 16% wholesale off-system, 10% industrial and 12% municipal sales and other revenue.

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•    
We own 35% and Basin Electric owns 65% 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 the Eastern United States, respectively. This transmission tie provides transmission access to both the WECC region in the West and the MAPP region in the East. Our system is located in the WECC region. The total transfer capacity of the tie is 200 MW from West to East and 200 MW from East to West. This transmission tie allows us to buy and sell energy in the Eastern interconnection without having to isolate and physically reconnect load or generation between the two electrical transmission grids. The transmission tie accommodates scheduling transactions in both directions simultaneously. This transfer capability provides additional opportunity to sell our excess generation or to make economic purchases to serve our native load and our contract obligations, and to take advantage of the power price differentials between the two electric grids. Additionally, our system is capable of directly interconnecting up to 80 MW of generation or load to the Eastern transmission grid. Transmission constraints within the MAPP transmission system may limit the amount of capacity that may be directly interconnected to the Eastern system at any given time.
 
•    
We have 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.
 
•    
We have firm network transmission access to deliver power on PacifiCorp's system to Sheridan, Wyoming to serve our power sales contract with MDU through 2016, with the right to renew pursuant to the terms of PacifiCorp's transmission tariff.
 
Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts 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 our 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 its 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;
 
•    
An agreement with the City of Gillette to dispatch the City'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 effective April 2010, was terminated. The City of Gillette's 23 MW of Wygen III capacity has been integrated into our 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 we will also provide the City of Gillette their operating component of spinning reserves;
 
•    
An agreement under which we 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; and
 
•    
A 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.
 

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Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide 491 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. Approximately 58% of our energy requirements in 2010 came from coal-fired and 42% was supplied under the following purchased power contracts:
 
•    
A PPA with PacifiCorp expiring in 2023, involving the purchase by us of 50 MW of coal-fired baseload power;
 
•    
A reserve capacity integration agreement with PacifiCorp expiring in 2012, which makes available to us 100 MW of reserve capacity in connection with the utilization of the Ben French Combustion Turbine units;
 
•    
A 20-year PPA with Cheyenne Light expiring in 2028, under which we will purchase up to 20 MW of wind energy through Cheyenne Light's agreement with Happy Jack;
 
•    
A 20-year PPA with Cheyenne Light expiring in 2029, under which we will purchase up to 20 MW of wind energy through Cheyenne Light's agreement with Silver Sage; and
 
•    
A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light's excess energy.
 
Since 1995, we have been a net producer of energy. Our 2010 winter peak system load was 377 MW and our 2010 summer peak load was 396 MW. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and economically feasible. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market, and through short-term sales contracts primarily in the WECC and MAPP regions. Our 301 MW of low-cost, coal-fired resources supports most of our native load requirements and positions us for wholesale off-system sales.
 
Shared Services Agreement. During 2010, we entered into a shared services agreement with Cheyenne Light and Black Hills Wyoming whereby each entity charges for the use of assets and the performance of services being used by or performed for an affiliate entity. The revenues and expenses associated with these assets are not eliminated as they are included in rate base.
 
Regulations
 
Rate Regulation
 
Rates for our retail electric service are subject to regulation by the SDPUC for customers in South Dakota, the WPSC for customers in Wyoming and the MTPSC for customers in Montana. Any changes in retail rates are subject to approval by the respective regulatory body. We have rate adjustment mechanisms in Montana and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. We are also subject to the jurisdiction of FERC with respect to accounting practices and wholesale electricity sales. We have been granted market-based rate authority by FERC and are not required to file cost-based tariffs for wholesale electric rates. Rates charged by us for use of our transmission system are subject to regulation by FERC.
 
Until April 1, 2010 South Dakota had three adjustment mechanisms: transmission, steam plant fuel and conditional energy cost adjustment. The transmission and steam plant fuel adjustment clauses would either pass along or give credits back to South Dakota customers based on actual costs incurred on a yearly basis. The conditional energy cost adjustment related to purchased power and natural gas used to generate electricity. These costs were subject to $2.0 million and $1.0 million thresholds where we absorbed the first $2.0 million of increased costs or retained the first $1.0 million in savings. Beyond these thresholds, costs or refunds 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. The Fuel and Purchased Power Adjustment clause was modified in the rate case settlement for our power marketing. It now contains a power marketing operating income sharing mechanism in which South Dakota customers will receive a credit equal to 65% of power marketing operating income and 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.
 

9

 

Rate Increase Settlement
 
South Dakota
 
On September 30, 2009, we 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. We requested a $32.0 million, or 26.6%, increase in annual utility revenues. In March 2010, the SDPUC approved a 20% increase in interim revenues, 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, or 12.7%, and a base rate increase of $22 million, or 19.4% 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, we agreed (1) to credit customers 65% of power marketing operating income with a minimum 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 year two, $2.0 million in year three and zero thereafter; and (3) a moratorium until April 2013 for any base rate increases excluding any extraordinary events as defined in the stipulation agreement; while (4) the SDPUC agreed to adjust the power marketing sales portion of the Fuel and Purchased Power Adjustment clause to directly assign renewable resources and firm purchases to the customer load.
 
Wyoming
 
On October 19, 2009, we filed a rate case with the WPSC requesting an electric revenue increase of $3.8 million 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, we 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. Rates went into effect on June 1, 2010.
 
FERC Transmission Tariff
 
On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of our open access transmission tariff, and increased our 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. The new annual rates had an effective date of January 1, 2009.
 
Environmental Regulations
 
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. We have incurred, and expect to incur, capital, operating and maintenance costs to comply with the operations of our plants. While the requirements are evolving, it is virtually certain that environmental requirements placed on the operations will continue to be more restrictive.
 
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.
 
Regulatory Accounting
 
We follow accounting for regulated utility operations and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. If rate recovery becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our regulated operations. In the event we determine that we no longer meet the accounting criteria for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material.
 

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New Accounting Pronouncements
 
See Note 1 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2010 or pending adoption.
 
ITEM 1A.    RISK FACTORS
 
The following specific risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company. These factors and other matters discussed herein are important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward looking statements included elsewhere in this document.
 
We may not raise our retail rates without prior approval of the SDPUC, WPSC or the MTPSC. If we seek rate relief, we could experience delays, reduced or partial rate recovery, or disallowances in rate proceedings. Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and are, therefore, not recoverable.
 
Our electricity operations are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. Our returns could be threatened by plant outages, machinery failures, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause our costs to increase and operating margins to decline. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.
 
To some degree, we are permitted to recover certain costs (such as increased fuel, purchased power costs and transmission, as applicable) without having to file a rate case. To the extent we pass through such costs to customers and a state public utility commission subsequently determines that such costs should not have been paid by customers, we may be required to refund such costs to customers. Any such costs not recovered through rates, or any such refund, could negatively affect our revenues, cash flows and results of operations.
 
The global financial crisis in recent years made the credit markets less accessible and created a shortage of available credit. Should a similar financial crisis occur in the future, we may be unable to obtain the financing needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.
 
Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the Federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.
 

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Our financial performance depends on the successful operations of our facilities.
 
Operating electric generating facilities involves risks, including:
 
•    
Operational limitations imposed by environmental and other regulatory requirements.
 
•    
Interruptions to supply of fuel and other commodities used in generation.
 
•    
Breakdown or failure of equipment or processes.
 
•    
Inability to recruit and retain skilled technical labor.
 
•    
Labor relations.
 
•    
Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity that we sell to our retail and wholesale customers. If transmission is interrupted, our ability to sell or deliver product and satisfy our contractual obligations may be hindered.
 
The global financial crisis has affected our counterparty credit risk.
 
As a consequence of the global financial crisis in recent years, the creditworthiness of many of our contractual counterparties (particularly financial institutions) has deteriorated. Although we aggressively monitor and evaluate changes in our counterparties' credit quality and adjust the credit limits based upon such changes, our credit guidelines, controls and limits may not protect us from increasing counterparty credit risk. To the extent the financial crisis causes our credit exposure to contractual counterparties to increase materially, such increased exposure could have a material adverse effect on our results of operations, cash flows and financial condition.
 
National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows.
 
Prolonged economic weakness may lead to an increase in late payments from retail and commercial utility customers, as well as our non-utility customers (including marketing counterparties). If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.
 
Our credit ratings could be lowered below investment grade in the future. If this were to occur, our access to capital and our cost of capital and other costs would be negatively affected.
 
Our credit rating on our First Mortgage Bonds is "A3" by Moody's, "BBB+" by S&P and A- by Fitch. Any reduction in our ratings by the rating agencies could adversely affect our ability to refinance or repay our existing debt and to complete new financings. In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations. A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.
 
Construction, expansion, refurbishment and operation of power generating and transmission facilities involve significant risks which could lead to lost revenues or increased expenses.
 
The construction, expansion, refurbishment and operation of power generating and transmission facilities involve many risks, including:
 
•    
The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;
 
•    
Contract restrictions upon the timing of scheduled outages;
 
•    
Cost of supplying or securing replacement power during scheduled and unscheduled outages;
 
•    
The unavailability or increased cost of equipment;
 

12

 

•    
The cost of recruiting and retaining or the unavailability of skilled labor;
 
•    
Supply interruptions, work stoppages and labor disputes;
 
•    
Capital and operating costs to comply with increasingly stringent environmental laws and regulations;
 
•    
Opposition by members of the public or special-interest groups;
 
•    
Weather interferences;
 
•    
Unexpected engineering, environmental and geological problems; and
 
•    
Unanticipated cost overruns.
 
The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses, or cause us to incur higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses or liquidated damage payments.
 
Because prices in the wholesale power markets are volatile, our revenues and expenses may fluctuate.
 
A portion of the variability of our net income in recent years has been attributable to off-system wholesale electricity sales. The related power prices are influenced by many factors outside our control, including among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions and the rules, regulations and actions of the system operators in those markets.
 
Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant, unpredictable price fluctuations over relatively short periods of time.
 
Our operating results can be adversely affected by milder weather.
 
Our utility business is a seasonal business and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. Accordingly, our utility operations have historically generated less revenues and income when weather conditions are cooler in the summer and warmer in the winter. Unusually mild summers and winters therefore could have an adverse effect on our financial condition and results of operations.
 
Our business is subject to substantial governmental regulation and permitting requirements as well as environmental liabilities. We may be adversely affected if we fail to achieve or maintain compliance with existing or future regulations or requirements, or by the potentially high cost of complying with such requirements or addressing environmental liabilities.
 
Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to operate, which could require significant capital expenditures and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines; claims for property damage or personal injury; or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures and have a detrimental effect on our business.
 
We strive to comply with all applicable environmental laws and regulations. Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect our results of operation and financial condition. We expect our environmental compliance expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate.

13

 

 
Municipal governments may seek to limit or deny franchise privileges.
 
Municipal governments within our utility service territories possess the power of condemnation, and could seek a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.
 
Federal and state laws concerning climate change and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.
 
We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations, which could have a material impact on our costs or operations.
 
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. We are currently evaluating the final rules. We expect the rules to have significant impact at our Neil Simpson I, Osage, and Ben French facilities. The regulation currently has a three year compliance window and will require engineering evaluation to determine economic viability of continued operations at these units. In our current opinion, the proposed regulations 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 rule) by March 16, 2011 and sign its notice of final rulemaking 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 our parent company participated in the EPA's efforts to gather data for rule development. Certain requirements of that regulation could have significant impacts on our Neil Simpson II, Wygen III and Wyodak facilities.
 
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 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 emissions control practices and technologies.
 
Due to uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation upon our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a "cap and trade" structure is implemented, the impact will also be affected by the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the effect of carbon regulation on natural gas and coal prices.
 
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. 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.
 

14

 

Increased risks of regulatory penalties could negatively impact our business.
 
The Energy Policy Act of 2005 increased the FERC civil penalty authority for violation of FERC statutes, rules and orders.  FERC can now impose penalties of $1.0 million per violation, per day, and other regulatory agencies that impose compliance requirements relative to our business also have civil penalty authority.  In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the North American Electric Reliability Corporation, with similar penalty authority for violations. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations.  If a serious violation did occur, and penalties were imposed by FERC or another federal agency, this action could have a material adverse effect on our operations and/or our financial results.
 
We may be vulnerable to cyber attacks and terrorism.
 
Man-made problems such as computer viruses, terrorism, theft and sabotage, may disrupt our operations and harm our operating results. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Our technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, our generation plants, fuel storage facilities, transmission and distribution facilities may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.
 
Ongoing changes in the United States electric utility industry, including state and federal regulatory changes, a potential increase in the number or geographic scale of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.
 
The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:
 
•    
The Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935;
 
•    
Industry consolidation;
 
•    
Consumer demands;
 
•    
Transmission constraints;
 
•    
Renewable resource supply requirements;
 
•    
Resistance to the siting of utility infrastructure or to the granting of right-of-ways;
 
•    
Technological advances; and
 
•    
Greater availability of natural gas-fired power generation, and other factors.
 
FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses. Deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry, which could adversely affect our financial condition or results of operations.
 
In addition, the independent system operators who oversee many of the wholesale power markets have in the past imposed, and may in the future continue to impose price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

15

 

 
Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations.
 
If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against others within industries in which we operate highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities in particular.
 
Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.
 
We have a defined benefit pension plan that covers a substantial portion of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.
 
An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.
 
Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and operating effectiveness of internal controls. During their assessment of these controls, management or our independent auditors may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists.
 
Increasing costs associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
 
The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
 
In March 2010, the President of the United States signed PPACA as amended by the Health Care and Education Reconciliation Act of 2010 (collectively the “2010 Acts”). The 2010 Acts will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the organization and the specific impacts on a company’s employees. Certain provisions of the 2010 Acts became effective during our open enrollment period (November 1, 2010) while other provisions of the 2010 Acts will be effective in future years. Although the constitutional validity of the 2010 Acts is the subject of numerous lawsuits now pending in the federal courts, the outcome of which is uncertain, the 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes. The ultimate extent and cost of these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available, and as the results of pending litigation become final.
 
 
ITEM 1B.    UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 3.    LEGAL PROCEEDINGS
 
Information regarding our legal proceedings is incorporated herein by reference to the "Legal Proceedings" sub caption within Item 8, Note 13, "Commitments and Contingencies," of our Notes to Financial Statements in this Annual Report on Form 10-K.
 

16

 

PART II
 
ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER        
MATTERS
 
All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.
 

17

 

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
 
For the years ended December 31,
2010
2009
2008
 
(in thousands)
 
 
 
 
Revenue
$
229,763
 
$
207,079
 
$
232,674
 
Fuel and purchased power
87,757
 
91,349
 
113,672
 
Gross margin
142,006
 
115,730
 
119,002
 
 
 
 
 
Operating expenses
92,976
 
80,925
 
80,366
 
Gain on sale of operating assets
(6,238
)
 
 
Operating income
55,268
 
34,805
 
38,636
 
 
 
 
 
Interest expense, net
(16,513
)
(11,164
)
(10,111
)
Other income
3,254
 
7,802
 
3,785
 
Income tax expense
(10,741
)
(8,304
)
(9,551
)
Net income
$
31,268
 
$
23,139
 
$
22,759
 
 
The following tables provide certain electric utility operating statistics for the years ended December 31 (dollars in thousands):
 
Electric Revenue
 
 
 
 
 
 
Customer Base
2010
Percentage Change
2009
Percentage Change
2008
Residential
$
53,549
 
10
 %
$
48,586
 
4
 %
$
46,854
 
Commercial
65,997
 
10
 
59,897
 
3
 
58,289
 
Industrial
22,621
 
13
 
20,014
 
(7
)
21,432
 
Municipal
3,029
 
11
 
2,735
 
-
2,734
 
Total retail sales
145,196
 
11
 
131,232
 
1
 
129,309
 
Contract wholesale
22,996
 
(9
)
25,358
 
(5
)
26,643
 
Wholesale off-system
36,354
 
13
 
32,212
 
(49
)
63,770
 
Total electric sales
204,546
 
8
 
188,802
 
(14
)
219,722
 
Other revenue
25,217
 
38
 
18,277
 
41
 
12,952
 
Total revenue
$
229,763
 
11
 %
$
207,079
 
(11
)%
$
232,674
 
 
Megawatt-Hours Sold
 
 
 
 
 
 
Customer Base
2010
Percentage Change
2009
Percentage Change
2008
Residential
547,193
 
3
 %
529,825
 
1
 %
524,413
 
Commercial
720,119
 
(0
)
723,360
 
3
 
699,734
 
Industrial
382,562
 
8
 
353,041
 
(15
)
414,421
 
Municipal
33,908
 
(0
)
33,948
 
(1
)
34,368
 
Total retail sales
1,683,782
 
3
 
1,640,174
 
(2
)
1,672,936
 
Contract wholesale
468,782
 
(27
)
645,297
 
(3
)
665,795
 
Wholesale off-system
1,163,058
 
15
 
1,009,574
 
(6
)
1,074,398
 
 Total electric sales
3,315,622
 
1
 
3,295,045
 
(3
)
3,413,129
 
Losses and company use
131,263
 
(18
)
159,207
 
90
 
83,598
 
 Total energy
3,446,885
 
(0
)%
3,454,252
 
(1
)%
3,496,727
 
 

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We established a summer peak load of 430 MW in July 2007 and a winter peak load of 407 MW in December 2008. We own 491 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.
 
 
2010
2009
2008
Regulated power plant fleet availability:
 
 
 
Coal-fired plants
93.5
%
90.3
%
93.5
%
Other plants
95.7
%
97.7
%
89.2
%
Total availability
94.4
%
93.5
%
91.6
%
 
Resources
2010
Percentage Change
2009
Percentage Change
2008
 
 
 
 
 
 
MWh generated:
 
 
 
 
 
Coal
1,987,037
 
15
 %
1,721,074
 
(1
)%
1,731,838
 
Gas
19,269
 
(59
)
46,723
 
(24
)
61,801
 
 
2,006,306
 
13
 
1,767,797
 
(1
)
1,793,639
 
 
 
 
 
 
 
MWh purchased
1,440,579
 
(15
)
1,686,455
 
(1
)
1,703,088
 
Total resources
3,446,885
 
(0
)%
3,454,252
 
(1
)%
3,496,727
 
 
 
2010
2009
2008
Heating and cooling degree days:
 
 
 
Actual
 
 
 
Heating degree days
7,272
 
7,753
 
7,676
 
Cooling degree days
532
 
354
 
482
 
 
 
 
 
Variance from 30-year average:
 
 
 
Heating degree days
1
 %
8
 %
6
 %
Cooling degree days
(11
)%
(41
)%
(19
)%
 
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

 

2010 Compared to 2009
 
Net income was $31.3 million in 2010 compared to $23.1 million in 2009 as a result of:
 
Gross margin: Gross margin increased $26.3 million primarily due to an $18.5 million increase related to the impact of the outcome of our rate cases, an increase of $3.0 million in off-system sales margin resulting from a change in methodology used to allocate the lowest cost resource, and increased intercompany revenues of $2.4 million due to a new shared services agreement related to resources utilized by affiliated entities.
 
Operations and maintenance: Operations and maintenance expenses increased $12.1 million primarily due to additional costs of $6.8 million associated with Wygen III which commenced commercial operation on April 1, 2010, and costs of $2.0 million associated with a major overhaul at the Ben French plant.
 
Gain on sale of operating assets: A $6.2 million gain on sale was recognized on the sale of a 23% ownership interest in the Wygen III generating facility to the City of Gillette.
 
Interest expense, net: Interest expense, net increased $5.3 million primarily due to higher net interest expense of $2.9 million compared to the same period in the prior year resulting from higher rates on long-term debt compared to rates on short-term debt and a decrease of $2.1 million in AFUDC-borrowed.
 
Other income: Other income decreased $4.5 million primarily due to a decrease of $3.1 million in AFUDC-equity associated with the construction of our Wygen III facility. Additionally, 2009 included a gain of $1.1 million from the sale of SO2 emission credits and a gain of $0.5 million on the sale of a 25% ownership interest in the Wygen III facility.
 
Income tax expense: The effective tax rate for 2010 was comparable to the same period in the prior year.
 
2009 Compared to 2008
 
Net income was $23.1 million in 2009 compared to $22.8 million in 2008 as a result of:
 
Gross margin: Gross margin decreased $3.3 million primarily due to a $7.6 million decrease in wholesale off-system margins as a result of a 46% decrease in energy prices, a 6% decrease in total MWh sold in the power markets, a $1.0 million decrease in retail and wholesale margins primarily due to increased coal costs and a 2% decrease in MWh sold related to lower cooling degree days, partially offset by a $6.5 million increase in other margins primarily due to an increase in transmission rates effective January 1, 2009.
 
Operating expenses: Operating expenses were comparable to the same period in prior year.
 
Interest expense, net: Interest expense, net increased $1.1 million primarily due to a new debt issuance.
 
Other income: Other income increased $4.0 million primarily due to an increase of $2.2 million in AFUDC-equity attributable to the ongoing construction of Wygen III, the sale of SO2 emission credits for $1.1 million and a gain of $0.5 million on the sale of a 25% ownership interest in Wygen III facility which was under construction.
 
Income tax expense: The effective tax rate decreased primarily due to the favorable tax impact as a result of the increase in AFUDC-equity.
 
Rate Increase Settlement
 
South Dakota
 
On September 30, 2009, we 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 of $2.6 million was provided to customers in the third quarter of 2010.
 

20

 

As part of the settlement stipulation, we agreed (1) to credit customers 65% of power marketing operating income with a minimum 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 power marketing sales portion of the Fuel and Purchased Power Adjustment clause to directly assign renewable resources and firm purchases to the customer load.
 
Wyoming
 
On October 19, 2009, we 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, we 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. Rates went into effect on June 1, 2010.
 
FERC Transmission Tariff
 
On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of our open access transmission tariff, and increased our 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. The new annual rates had an effective date of January 1, 2009.
 
Wygen III Power Plant Project
 
The 110 MW coal-fired electric generation facility was completed and commenced commercial operations on April 1, 2010. Total cost of construction was approximately $232.3 million, which includes AFUDC. In April 2009, we sold a 25% ownership interest to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date for the on-going construction of the facility. MDU reimbursed us monthly for its 25% share of the total costs paid to complete the project. In July 2010, we sold an additional 23% ownership interest in Wygen III to the City of Gillette for $62.0 million. Under both agreements, we retain responsibility for operation of the facility with a life-of-plant site lease. MDU and the City of Gillette will pay us for administrative services and share in the costs of operating the plant for the life of the facility. Coal supply agreements are in place between WRDC, MDU and the City of Gillette.
 
Critical Accounting Estimates
 
We prepare our financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management's judgment in application. There are also areas which require management's judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results.
 
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, "Business Description and Summary of Significant Accounting Policies" of our Notes to Financial Statements in this Annual Report on Form 10-K.
 
Impairment of Long-lived Assets
 
We evaluate for impairment, the carrying values of our long-lived assets whenever indicators of impairment exist.
 
For long-lived assets with finite lives, this evaluation is based upon our projections of anticipated future cash flows (undiscounted and without interest charges) from the assets being evaluated. If the sum of the anticipated future cash flows over the expected useful life of the assets is less than the assets' carrying value, then a permanent non-cash write-down equal to the difference between the assets' carrying value and the assets' fair value is required to be charged to earnings. In estimating future cash flows, we generally use a probability weighted average expected cash flow method with assumptions based on those used for internal budgets. The determination of future cash flows, and, if required, fair value of a long-lived asset is by its nature a highly subjective judgment. Significant assumptions are required in the forecast of future operating results used in the

21

 

preparation of the long-term estimated cash flows. Changes in these estimates could have a material effect on the evaluation of our long-lived assets. There have been no impairments taken in 2010 , 2009 or 2008.
 
Pension and Other Postretirement Benefits
 
The Company, as described in Note 10 to the Financial Statements in this Annual Report on Form 10-K, has defined benefit pension plan and post-retirement healthcare plans. Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.
 
In July 2009, the Board of Directors froze our Defined Benefit Pension Plan to certain new participants and transferred certain existing participants to an age and service based defined contribution plan, effective January 1, 2010. Plan assets and obligations for the Black Hills Corporation Plan which covers eligible employees of Black Hills Power were revalued as of July 31, 2009 in conjunction with the curtailment of the plan. As a result, we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009. In July 2009, the Board of Directors of Black Hills Corporation also approved amendments to the BHC Retiree Healthcare Plan. This plan covers eligible employees of Black Hills Power. Effective January 1, 2010, the amendment changed the plan from a cost sharing plan to an RMSA for non-union employees.
 
In September 2010, the bargaining unit participants in the Defined Benefit Pension Plan voted to freeze all new bargaining unit employees from participation in the Plan and to freeze the benefits of current bargaining unit participants except for the following group: those bargaining unit participants who are both 1) age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently fore-go the additional age and points based employer contribution under the Company's 401(k) retirement savings plan. As a result of this freeze, we recognized a pre-tax curtailment expense of less than $0.1 million in the fourth quarter of 2010. Pension Plan benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. These changes are effective January 1, 2011.
 
Valuation of Deferred Tax Assets
 
We use the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. The amount of deferred tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized.
 
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of the current and any future tax audits could significantly impact the amounts provided for income taxes in our financial statements.
 
Contingencies
 
When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are made based on currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position and results of operations.
 

22

 

ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX TO FINANCIAL STATEMENTS
 
 
 
 
Page
 
 
Management's Report on Internal Control over Financial Reporting
 
 
Report of Independent Registered Public Accounting Firm
 
 
Statements of Income for the three years ended December 31, 2010
 
 
Balance Sheets as of December 31, 2010 and 2009
 
 
Statements of Cash Flows for the three years ended December 31, 2010
 
 
Statements of Common Stockholder's Equity and Comprehensive Income for the three years ended December 31, 2010
 
 
Notes to Financial Statements
 

23

 

Management's Report on Internal Control over Financial Reporting
 
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
 
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2010, based on the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation we have concluded that our internal control over financial reporting was effective as of December 31, 2010.
 
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting because this requirement is inapplicable to companies such as ours which are known as "non-accelerated filers."
 
Black Hills Power
 
 

24

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Stockholder of
Black Hills Power, Inc.
Rapid City, South Dakota
 
We have audited the accompanying balance sheets of Black Hills Power, Inc. (the "Company") as of December 31, 2010 and 2009, and the related statements of income, common stockholder's equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
 
/s/ DELOITTE & TOUCHE LLP
 
Minneapolis, Minnesota
March 7, 2011
 

25

 

BLACK HILLS POWER, INC.
STATEMENTS OF INCOME
 
Years ended December 31,
2010
2009
2008
 
(in thousands)
 
 
 
 
Operating revenues
$
229,763
 
$
207,079
 
$
232,674
 
 
 
 
 
Operating expenses:
 
 
 
Fuel and purchased power
87,757
 
91,349
 
113,672
 
Operations and maintenance
68,884
 
57,116
 
55,125
 
Gain on sale of operating assets
(6,238
)
 
 
Depreciation and amortization
22,030
 
19,465
 
20,930
 
Taxes - property
2,062
 
4,344
 
4,311
 
Total operating expenses
174,495
 
172,274
 
194,038
 
 
 
 
 
Operating income
55,268
 
34,805
 
38,636
 
 
 
 
 
Other (expense) income:
 
 
 
Interest expense
(18,737
)
(15,779
)
(13,392
)
AFUDC - borrowed
2,224
 
4,357
 
2,556
 
Interest income
318
 
258
 
725
 
AFUDC - equity
2,748
 
5,831
 
3,605
 
Other expense
(35
)
 
(47
)
Other income
223
 
1,971
 
227
 
Total other expense
(13,259
)
(3,362
)
(6,326
)
 
 
 
 
Income from continuing operations before income taxes
42,009
 
31,443
 
32,310
 
Income tax expense
(10,741
)
(8,304
)
(9,551
)
 
 
 
 
Net income
$
31,268
 
$
23,139
 
$
22,759
 
 
 
The accompanying notes to financial statements are an integral part of these financial statements.
 

26

 

BLACK HILLS POWER, INC.
BALANCE SHEETS
 
At December 31,
2010
2009
 
(in thousands, except share amounts)
ASSETS
 
 
Current assets:
 
 
Cash and cash equivalents
$
2,045
 
$
1,709
 
Receivables - customers, net
28,716
 
19,991
 
Receivables - affiliates
6,891
 
4,146
 
Other receivables, net
2,077
 
5,293
 
Money pool notes receivable
39,862
 
57,737
 
Materials, supplies and fuel
21,259
 
18,825
 
Regulatory assets, current
3,584
 
7,467
 
Other current assets
3,712
 
1,639
 
Total current assets
108,146
 
116,807
 
 
 
 
Investments
4,396
 
4,197
 
 
 
 
Property, plant and equipment
962,640
 
950,577
 
Less accumulated depreciation and amortization
(304,800
)
(293,823
)
Total property, plant and equipment, net
657,840
 
656,754
 
 
 
 
Other assets:
 
 
Regulatory assets, non-current
37,740
 
31,305
 
Other, non-current assets
3,610
 
3,730
 
Total other assets
41,350
 
35,035
 
TOTAL ASSETS
$
811,732
 
$
812,793
 
 
 
 
LIABILITIES AND STOCKHOLDER'S EQUITY
 
 
Current liabilities:
 
 
Current maturities of long-term debt
$
81
 
$
32,025
 
Accounts payable
14,828
 
24,175
 
Accounts payable - affiliate
12,562
 
10,030
 
Accrued liabilities
15,541
 
17,892
 
Regulatory liability, current
1,932
 
1,238
 
Deferred income tax liability - current
859
 
1,853
 
Total current liabilities
45,803
 
87,213
 
 
 
 
Long-term debt, net of current maturities
276,422
 
297,044
 
 
 
 
Deferred credits and other liabilities:
 
 
Deferred income tax liability - non-current
122,319
 
96,207
 
Regulatory liabilities, non-current
28,276
 
14,955
 
Benefit plan liabilities
19,581
 
28,224
 
Other, non-current liabilities
9,914
 
10,952
 
Total deferred credits and other liabilities
180,090
 
150,338
 
 
 
 
Commitments and contingencies (Notes 6, 10, 11 and 13)
 
 
 
 
 
Stockholder's equity:
 
 
Common stock $1 par value; 50,000,000 shares authorized; Issued: 23,416,396 shares in 2010 and 2009
23,416
 
23,416
 
Additional paid-in capital
39,575
 
39,575
 
Retained earnings
247,688
 
216,420
 
Accumulated other comprehensive loss
(1,262
)
(1,213
)
Total stockholder's equity
309,417
 
278,198
 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY
$
811,732
 
$
812,793
 
 
The accompanying notes to financial statements are an integral part of these financial statements.
 

27

 

BLACK HILLS POWER, INC.
STATEMENTS OF CASH FLOWS
 
Years ended December 31,
2010
2009
2008
 
(in thousands)
Operating activities:
 
 
 
Net income
$
31,268
 
$
23,139
 
$
22,759
 
Adjustments to reconcile net income to net cash provided by operating activities -
 
 
 
Depreciation and amortization
22,030
 
19,465
 
20,930
 
Deferred income taxes
25,626
 
11,600
 
16,072
 
AFUDC - equity
(2,748
)
(5,831
)
(3,605
)
Gain on sale of operating assets
(6,238
)
 
 
Employee benefits
4,030
 
4,234
 
730
 
Other adjustments
(4,335
)
240
 
416
 
Change in operating assets and liabilities -
 
 
 
Accounts receivable and other current assets
(14,541
)
13,233
 
(11,909
)
Accounts payable and other current liabilities
(5,525
)
2,556
 
7,821
 
Regulatory assets
3,883
 
(2,205
)
(738
)
Regulatory liabilities
3,562
 
586
 
(518
)
Contributions to defined benefit pension plan
(8,798
)
 
 
Other operating activities
2,389
 
(859
)
6
 
Net cash provided by operating activities
50,603
 
66,158
 
51,964
 
 
 
 
 
Investing activities:
 
 
 
Property, plant and equipment additions
(78,602
)
(146,148
)
(132,247
)
Proceeds from sale of ownership interest in plant
62,000
 
32,783
 
 
Notes receivable from affiliate companies, net
17,875
 
(82,737
)
10,304
 
Other investing activities
2,202
 
1,067
 
(225
)
Net cash (used in) provided by investing activities
3,475
 
(195,035
)
(122,168
)
 
 
 
 
Financing activities:
 
 
 
Note payable to affiliate companies, net
 
(45,184
)
70,184
 
Long-term debt issuance
 
180,000
 
 
Long-term debt - repayments
(52,566
)
(2,140
)
(2,009
)
Other financing activities
(1,176
)
(2,094
)
 
Net cash (used in) provided by financing activities
(53,742
)
130,582
 
68,175
 
 
 
 
 
Increase (decrease) in cash and cash equivalents
336
 
1,705
 
(2,029
)
 
 
 
 
Cash and cash equivalents:
 
 
 
Beginning of year
1,709
 
4
 
2,033
 
End of year
$
2,045
 
$
1,709
 
$
4
 
 
See Note 12 for Supplemental Cash Flows information
The accompanying notes to financial statements are an integral part of these financial statements.
 
 

28

 

BLACK HILLS POWER, INC.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
AND COMPREHENSIVE INCOME
 
 
2010
2009
2008
 
(in thousands)
Common stock shares:
 
 
 
Balance beginning of year
23,416
 
23,416
 
23,416
 
Issuance of common stock
 
 
 
Balance end of year
23,416
 
23,416
 
23,416
 
 
 
 
 
Common stock amounts:
 
 
 
Balance beginning of year
$
23,416
 
$
23,416
 
$
23,416
 
Issuance of common stock
 
 
 
Balance end of year
$
23,416
 
$
23,416
 
$
23,416
 
 
 
 
 
Additional paid-in capital:
 
 
 
Balance beginning of year
$
39,575
 
$
39,575
 
$
39,575
 
Issuance of common stock
 
 
 
Balance end of year
$
39,575
 
$
39,575
 
$
39,575
 
 
 
 
 
Retained earnings:
 
 
 
Balance beginning of year
$
216,420
 
$
193,281
 
$
170,706
 
Net income available for common stock
31,268
 
23,139
 
22,759
 
Adoption of accounting pronouncement
 
 
(184
)
Balance end of year
$
247,688
 
$
216,420
 
$
193,281
 
 
 
 
 
Accumulated other comprehensive loss:
 
 
 
Balance beginning of year
$
(1,213
)
$
(1,349
)
$
(1,277
)
Other comprehensive (loss) income, net of tax
(49
)
136
 
(72
)
Balance end of year
$
(1,262
)
$
(1,213
)
$
(1,349
)
 
 
 
 
Total stockholder's equity
$
309,417
 
$
278,198
 
$
254,923
 
 
 
 
 
Comprehensive income:
 
 
 
Net income
$
31,268
 
$
23,139
 
$
22,759
 
Other comprehensive income (loss) , net of tax (see Note 9)
(49
)
136
 
(72
)
Comprehensive income
$
31,219
 
$
23,275
 
$
22,687
 
 
The accompanying notes to financial statements are an integral part of these financial statements.
 
 

29

 

NOTES TO FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
 
 
 
(1)     BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Business Description
 
Black Hills Power, Inc. (the Company, "we," "us" or "our") is an electric utility serving customers in South Dakota, Wyoming and Montana. We are a wholly-owned subsidiary of BHC or the Parent, a public registrant listed on the New York Stock Exchange.
 
Basis of Presentation
 
The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3). Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. The statements of income for the prior periods have been modified to reflect the retrospective application of a change in the presentation of the statement of income. This change was made to enhance our statement of income presentation. The Statement of Cash Flows was modified to reflect Employee benefit expense as a specific adjustment to reconcile net income to net cash provided by operating activities. It was previously included in Other adjustments.
 
Use of Estimates
 
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Regulatory Accounting
 
Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC.
 
Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating our electric operations. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply to our regulated operations. In the event we determine that we no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.
 

30

 

Our regulatory assets and liabilities for which we recover the costs, but we do not earn a return were as follows as of December 31 (in thousands):
 
Recovery Period
2010
2009
 
 
 
 
Regulatory assets:
 
 
 
Unamortized loss on reacquired debt
14 years
$
3,016
 
$
2,207
 
AFUDC
Up to 45 years
9,489
 
7,579
 
Defined benefit postretirement plans
Up to 13 years
18,049
 
21,024
 
Deferred energy costs
Less than one year
3,584
 
7,467
 
Flow through accounting
Up to 35 years
4,772
 
 
Other
 
2,414
 
495
 
Total regulatory assets
 
$
41,324
 
$
38,772
 
 
 
 
 
Regulatory liabilities:
 
 
 
Cost of removal for utility plant
Up to 53 years
$
15,429
 
$
13,678
 
Defined benefit postretirement plans
Up to 13 years
10,204
 
 
Other
 
4,575
 
2,515
 
Total regulatory liabilities
 
$
30,208
 
$
16,193
 
 
Regulatory assets are primarily recorded for the probable future revenue to recover the costs associated with defined benefit postretirement plans, future income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt. To the extent that energy costs are under-recovered or over-recovered during the year, they are recorded as a regulatory asset or liability, respectively. Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates, gains associated with regulated utilities' defined benefit postretirement plans and the cost of removal for utility plant, recovered through our electric utility rates. Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheets.
 
Allowance for Funds Used During Construction
 
AFUDC represents the approximate composite cost of borrowed funds and a return on capital used to finance a project. Our AFUDC for the years ended December 31 was as follows (in thousands):
 
 
2010
2009
2008
 
 
 
 
AFUDC - borrowed
$
2,224
 
$
4,357
 
2,556
 
AFUDC - equity
2,748
 
5,831
 
3,605
 
Total AFUDC
$
4,972
 
$
10,188
 
$
6,161
 
 
Cash Equivalents
 
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
 

31

 

Allowance for Doubtful Accounts
 
We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect the ability to pay.
 
Accounts receivable consist of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivables are stated at billed amounts net of write-offs or payment received. Approximately 26% of the accounts receivable balance consists of unbilled revenue.
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollected. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management's best estimate of future collection success given the existing collections environment.
Following is a summary of accounts receivables at December 31 (in thousands):
 
 
2010
2009
 
 
 
Accounts receivable trade
$
21,365
 
$
14,703
 
Unbilled revenues
7,581
 
5,547
 
Total accounts receivable - customers
28,946
 
20,250
 
Allowance for doubtful accounts
(230
)
(259
)
Net accounts receivable
$
28,716
 
$
19,991
 
 
Materials, Supplies and Fuel
 
Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis. To the extent fuel has been designated as the underlying hedged item in a "fair value" hedge transaction, those volumes are stated at market value using published industry quotations.
 
Deferred Financing Costs
 
Deferred financing costs are amortized using the effective interest method over the term of the related debt.
 
Property, Plant and Equipment
 
Additions to property, plant and equipment are recorded at cost when placed in service. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property are charged to operations as incurred.
 
Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.2% in 2010, 2.8% in 2009 and 3.2% in 2008.
 

32

 

Derivatives and Hedging Activities
 
From time to time we utilize risk management contracts including forward purchases and sales and fixed-for-float swaps to hedge the price of fuel for our combustion turbines, maximize the value of our natural gas storage or fix the interest on our variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
 
Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. Gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income, net of tax, and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.
 
Impairment of Long-Lived Assets
 
We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, we would recognize an impairment loss. No impairment loss was recorded during 2010, 2009 or 2008.
 
Income Taxes
 
We use the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.
 
We file a federal income tax return with other affiliates. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.
 
Revenue Recognition
 
Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured.
 
 
 
(2)     RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS
 
Recently Adopted Accounting Standards
 
Disclosures About the Credit Quality of Financing Receivables and the Allowance for Credit Losses, ASC 310-10-50
 
In July 2010, the FASB issued an amendment to ASC 310-10-50, Receivables - Disclosures. The guidance requires additional disclosures that will facilitate financial statement user's evaluation of the nature of credit risk inherent in financing receivables, how that risk is analyzed in arriving at the allowance for credit losses, and the reason for any changes in the allowance for credit losses. These disclosures should be provided on a disaggregated basis but exempts trade receivables that have a contractual maturity of one year or less, receivables measured at lower of cost or fair value, and receivables measured at fair value with the changes in fair value reported in earnings. (See Note 1) It is effective for interim and annual reporting periods ending on or after December 15, 2010.
 

33

 

Consolidation of Variable Interest Entities, ASC 810-10-15
 
In June 2009, the FASB issued a revision regarding consolidations. The amendment requires a company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It requires additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard is effective for annual periods that begin after November 15, 2009 with ongoing re-evaluation. The adoption of this standard in January 2010 did not have any impact on our financial statements, results of operations, and cash flows.
 
Recently Issued Accounting Standards and Legislation
 
Patient Protection and Affordable Care Act
 
In March 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the PPACA as amended by the Healthcare and Education Reconciliation Act. The potential impact on the Company, if any, cannot be determined until regulations are promulgated under the PPACA.  Included among the provisions of the PPACA is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which affects our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The impact of this change in the tax treatment of the subsidy had an immaterial effect on our financial position, results of operations and cash flows. The Company will continue to assess the accounting implications of the PPACA as related regulations and interpretations become available. 
 
(3)     PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment consisted of the following (in thousands):
 
 
 
December 31, 2010
 
December 31, 2009
 
 
December 31, 2010
Weighted Average Useful Life
December 31, 2009
Weighted Average Useful Life
Lives
(in years)
Electric plant:
 
 
 
 
 
Production
$
475,762
 
50
$
336,534
 
53
30-62
 
Transmission
116,056
 
43
86,841
 
44
35-55
 
Distribution
271,470
 
37
264,847
 
37
15-65
 
Plant acquisition adjustment
4,870
 
32
4,870
 
32
32
 
General
58,777
 
22
55,701
 
22
10-50
 
Total electric plant
926,935
 
 
748,793
 
 
 
Less accumulated depreciation and amortization
304,800
 
 
293,823
 
 
 
Electric plant net of accumulated depreciation and amortization
622,135
 
 
454,970
 
 
 
Construction work in progress
35,705
 
 
201,784
 
 
 
Net electric plant
$
657,840
 
 
$
656,754
 
 
 
 
 

34

 

(4)     JOINTLY OWNED FACILITIES
 
We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following facilities:
 
•    
We own a 20% interest and PacifiCorp owns an 80% interest in the Wyodak Plant (the "Plant"), a 362 MW coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. We receive 20% of the Plant's capacity and are committed to pay 20% of its additions, replacements and operating and maintenance expenses. Our investment in the Plant and accumulated depreciation is included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plant is included in the corresponding categories of operating expenses in the accompanying Statements of Income.
 
•    
We own a 35% interest and Basin Electric owns a 65% interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW - 200 MW West to East and 200 MW from East to West. We are committed to pay 35% of the additions, replacements and operating and maintenance expenses. Our investment in the transmission tie and accumulated depreciation is included in the corresponding captions in the accompanying Balance Sheets.
 
•    
We own a 52% interest in the Wygen III power plant. MDU owns 25% which was purchased in April 2009. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility and subsequently reimbursed us for 25% of the total costs paid to complete the project. Our share of direct expenses of the jointly-owned facility are included in Operating expenses in the Statements of Income. Our share of property, plant and equipment in Wygen III and associated accumulated depreciation is included in the corresponding captions in the accompanying Balance Sheets.
 
•    
The City of Gillette owns a 23% interest in the Wygen III power plant which was purchased in July 2010 for $62.0 million. Wygen III was placed into commercial operations on April 1, 2010. Our share of direct expenses of the jointly-owned facility are included in Operating expenses in the Statements of Income. Our share of property, plant and equipment in Wygen III and associated accumulated depreciation is included in the corresponding captions in the accompanying Balance Sheets.
 
Our share of direct expenses related to our jointly owned plants for the years ended December 31 was as follows (dollars in thousands):
Share of Direct Expenses
Ownership Percentage
2010
2009
2008
Wyodak Plant
20.0
%
$
8,546
 
$
8,021
 
$
8,000
 
Transmission Tie
35.0
%
$
154
 
$
100
 
$
123
 
Wygen III (a)
52.0
%
$
7,618
 
$
 
$
 
___________
(a)    The Wygen III plant commenced commercial operations on April 1, 2010.
 
As of December 31, 2010, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (dollars in thousands):
Share of Direct Expenses
Ownership Percentage
Plant in Service
Construction Work in Progress
Accumulated Depreciation
Wyodak Plant
20.0
%
$
82,466
 
$
21,687
 
$
54,108
 
Transmission Tie
35.0
%
$
19,644
 
$
 
$
4,111
 
Wygen III (a)
52.0
%
$
129,340
 
$
194
 
$
2,282
 
___________
(a)    The Wygen III plant commenced commercial operations on April 1, 2010.
 

35

 

(5)    RISK MANAGEMENT
 
We hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we utilize various derivative instruments in managing these risks. As of December 31, 2010, there were no derivative contracts outstanding. As of December 31, 2009, we had the following derivatives and related balances included in Accrued liabilities on the accompanying Balance Sheet (dollars, in thousands):
 
 
December 31, 2009
 
 
Notional*
232,500
 
Maximum terms in months
10
 
Current derivative liabilities
$
5
 
Pre-tax accumulated other comprehensive loss
$
(5
)
_________________
*    Gas in MMbtus
.
(6)     LONG-TERM DEBT
 
Long-term debt outstanding was as follows (in thousands):
 
 
December 31, 2010
December 31, 2009
First mortgage bonds:
 
 
8.06% due 2010
$
 
$
30,000
 
9.49% due 2018
 
2,520
 
9.35% due 2021
 
19,980
 
7.23% due 2032
75,000
 
75,000
 
6.125% due 2039
180,000
 
180,000
 
Unamortized discount on 6.125% bonds
(119
)
(124
)
 
254,881
 
307,376
 
Other long-term debt:
 
 
Pollution control revenue bonds at 4.8% due 2014
6,450
 
6,450
 
Pollution control revenue bonds at 5.35% due 2024
12,200
 
12,200
 
Other
2,972
 
3,043
 
 
21,622
 
21,693
 
 
 
 
Total long-term debt
276,503
 
329,069
 
Less current maturities
(81
)
(32,025
)
Net long-term debt
$
276,422
 
$
297,044
 
 

36

 

Bond Issuance
 
On October 27, 2009, we completed a $180 million first mortgage bond issuance. The bonds were priced at 99.931% of par and a reoffer yield of 6.13%. The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which is paid semi-annually. We received proceeds net of underwriting fees of $178.3 million which were used to repay intercompany borrowings from BHC, primarily incurred to fund the construction of Wygen III, and to redeem the Series AC mortgage bonds. Deferred finance costs of approximately $2.2 million were capitalized and are being amortized over the term of the bonds. Amortization of deferred financing costs is included in Interest expense.
 
Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.
 
Series AC Bonds
 
In February 2010, the Series 8.06% AC bonds matured. These were paid in full for $30.0 million of principal plus accrued interest of $1.2 million.
 
Series Y Bonds
 
In March 2010, we completed redemption of our Series Y 9.49% bonds in full. The bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which includes the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Balance Sheet and is being amortized over the remaining term of the original bonds.
 
Series Z Bonds
 
In June 2010, we completed redemption of our Series Z 9.35% bonds in full. The bonds were originally due in 2021. A total of $21.8 million was paid on June 1, 2010, which included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Balance Sheet and is being amortized over the remaining term of the original bonds.
 
Long-term Debt Maturities
 
Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts) are as follows (in thousands):
2011
$
81
 
2012
$
36
 
2013
$
 
2014
$
6,450
 
2015
$
 
Thereafter
$
270,055
 
 
 

37

 

(7)     FAIR VALUE OF FINANCIAL INSTRUMENTS
 
The estimated fair values of our financial instruments were as follows (in thousands):
 
 
December 31, 2010
December 31, 2009
 
Carrying Value
Fair Value
Carrying Value
Fair Value
 
 
 
 
 
Cash and cash equivalents
$
2,045
 
$
2,045
 
$
1,709
 
$
1,709
 
Derivative financial instruments - Accrued liabilities
$
 
$
 
$
5
 
$
5
 
Long-term debt, including current maturities
$
276,503
 
$
301,964
 
$
329,069
 
$
344,942
 
 
The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.
 
Cash and Cash Equivalents
 
The carrying amount approximates fair value due to the short maturity of these instruments.
 
Derivative Financial Instruments
 
These instruments are carried at fair value. Descriptions of the instruments we use are included in Note 5.
 
Long-Term Debt
 
The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. Our outstanding first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for us to call and refinance the first mortgage bonds.
 
(8)     INCOME TAXES
 
Income tax expense (benefit) from continuing operations for the years ended was (in thousands):
 
December 31, 2010
December 31, 2009
December 31, 2008
 
 
 
 
Current
$
(14,885
)
$
(3,296
)
$
(6,521
)
Deferred
25,626
 
11,600
 
16,072
 
Total income tax expense
$
10,741
 
$
8,304
 
$
9,551
 
 

38

 

The temporary differences which gave rise to the net deferred tax liability were as follows (in thousands):
 
December 31, 2010
December 31, 2009
 
 
 
Deferred tax assets, current:
 
 
Asset valuation reserve
$
217
 
$
90
 
Employee benefits
803
 
946
 
Rate refund
428
 
 
Other
 
2
 
Total deferred tax assets, current
1,448
 
1,038
 
 
 
 
Deferred tax liabilities, current:
 
 
Prepaid expenses
(251
)
(214
)
Deferred costs
(2,056
)
(2,677
)
Total deferred tax liabilities, current
(2,307
)
(2,891
)
 
 
 
Net deferred tax assets (liabilities), current
$
(859
)
$
(1,853
)
 
 
 
Deferred tax assets, non-current:
 
 
Plant related differences
$
909
 
$
1,151
 
Regulatory liabilities
10,074
 
7,847
 
Employee benefits
3,547
 
3,468
 
Net operating loss
9,147
 
 
Items of other comprehensive income
225
 
175
 
Research and development credit
1,613
 
1,038
 
Other
 
128
 
Total deferred tax assets, non-current
25,515
 
13,807
 
 
 
 
Deferred tax liabilities, non-current:
 
 
Accelerated depreciation and other plant related differences
(132,338
)
(93,253
)
AFUDC
(6,168
)
(4,926
)
Regulatory assets
(5,557
)
(10,011
)
Employee benefits
(2,983
)
(1,052
)
Other
(788
)
(772
)
Total deferred tax liabilities, non-current
(147,834
)
(110,014
)
 
 
 
Net deferred tax assets (liabilities), non-current
$
(122,319
)
$
(96,207
)
 
 
 
Net deferred tax assets (liabilities)
$
(123,178
)
$
(98,060
)
 
 

39

 

The following table reconciles the change in the net deferred income tax assets (liabilities) from December 31, 2009 to December 31, 2010 and from December 31, 2008 to December 31, 2009 to deferred income tax expense (benefit) (in thousands):
 
 
2010
2009
 
 
 
Change in deferred income tax assets (liabilities)
$
25,118
 
$
11,824
 
Deferred taxes related to regulatory assets and liabilities
9,272
 
(1,323
)
Deferred taxes associated with other comprehensive income
(2,141
)
(73
)
Deferred taxes related to property basis differences
(4,713
)
2,851
 
Deferred taxes related to AFUDC
(1,910
)
(1,679
)
Other
 
 
Deferred income tax expense (benefit) for the period
$
25,626
 
$
11,600
 
 
The effective tax rate differs from the federal statutory rate for the years ended, as follows:
 
 
December 31, 2010
December 31, 2009
December 31, 2008
 
 
 
 
Federal statutory rate
35.0
 %
35.0
 %
35.0
 %
Amortization of excess deferred and investment tax credits
(0.6
)
(0.9
)
(0.7
)
Equity AFUDC
(2.0
)
(6.2
)
(3.6
)
Flow through adjustments *
(7.4
)
 
 
Other
0.6
 
(1.5
)
(1.1
)
 
25.6
 %
26.4
 %
29.6
 %
            
*    The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. Due to this regulatory treatment, we recorded an income tax benefit that was attributable to the 2008 through 2010 tax years. For years prior to 2008, we did not record a regulatory asset for the repairs deduction as the tax benefit was not flowed through to customers.
    
The accounting standards for uncertain tax positions clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with accounting standards for income taxes. The accounting standards prescribe a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken. The impact of this implementation had no effect on our financial statements.
 
The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the period (in thousands):
 
 
2010
2009
 
 
 
Unrecognized tax benefits at January 1
$
3,877
 
$
767
 
Additions for prior year tax positions
130
 
3,110
 
Reductions for prior year tax positions
(913
)
 
 
 
 
Unrecognized tax benefits at December 31
$
3,094
 
$
3,877
 
 

40

 

The reduction for prior year tax positions relate to the reversal through otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $1.1 million.
 
It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2010 and 2009, the interest expense recognized related to income tax matters was not material to our financial results.
 
The Company files income tax returns in the United States federal jurisdiction as a member of the BHC consolidated group. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations prior to December 31, 2011.
 
At December 31, 2010, we have federal NOL carry forward of $26.1 million which will expire in 2030. Ultimate usage of this NOL depends upon our future taxable income.
 
(9)     COMPREHENSIVE INCOME
 
The following tables display each component of Other Comprehensive Income (Loss), after-tax, and the related tax effects for the years ended (in thousands):
 
 
December 31, 2010
 
Pre-tax Amount
Tax (Expense)
Benefit
Net-of-tax Amount
 
 
 
 
Minimum pension liability adjustment
$
(145
)
$
51
 
$
(94
)
Reclassification adjustments of cash flow hedges settled and included in net income
64
 
(23
)
41
 
Net change in fair value of derivatives designated as cash flow hedges
6
 
(2
)
4
 
Other comprehensive loss
$
(75
)
$
26
 
$
(49
)
 
 
December 31, 2009
 
Pre-tax Amount
Tax (Expense)
Benefit
Net-of-tax Amount
 
 
 
 
Minimum pension liability adjustment
$
150
 
$
(52
)
$
98
 
Reclassification adjustments of cash flow hedges settled and included in net income
64
 
(24
)
40
 
Net change in fair value of derivatives designated as cash flow hedges
(5
)
3
 
(2
)
Other comprehensive income
$
209
 
$
(73
)
$
136
 
 
 
December 31, 2008
 
Pre-tax Amount
Tax
Benefit
Net-of-tax Amount
 
 
 
 
Minimum pension liability adjustment
$
(4
)
$
1
 
$
(3
)
Reclassification adjustments of cash flow hedges settled and included in net income
(107
)
38
 
(69
)
Other comprehensive loss
$
(111
)
$
39
 
$
(72
)
 

41

 

Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):
 
 
December 31, 2010
December 31, 2009
 
 
 
Derivatives designated as cash flow hedges
$
(848
)
$
(893
)
Employee benefit plans
(414
)
(320
)
Total accumulated other comprehensive loss
$
(1,262
)
$
(1,213
)
 
(10)     EMPLOYEE BENEFIT PLANS
 
Funded Status of Benefit Plans
 
The funded status of postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for pension plan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation.
 
We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.
 
The measurement date of plans should be the date of our year-end balance sheet. We had used a September 30 measurement date. During 2008, we changed the measurement date to December 31. Therefore, $0.2 million, net of tax, was recognized as an adjustment to retained earnings.
 
Defined Benefit Pension Plan
 
We have a noncontributory defined benefit pension plan ("Pension Plan") covering employees who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. Our funding policy is in accordance with the federal government's funding requirements. The Pension Plan's assets are held in trust and consist primarily of equity and fixed income investments. We use a December 31 measurement date for the Pension Plan.
 
In July 2009, the Board of Directors approved a partial freeze to the Pension Plan for all participants with the exception of bargaining unit participants. The freeze eliminated new non-bargaining unit employees from participation in the Pension Plan and froze the benefits of current non-bargaining unit participants except for the following group: those non-bargaining unit participants who are both 1) age 45 or older as of December 31, 2009 and have 10 years or more of credited service as of January 1, 2010; and 2) elect to continue to accrue additional benefits under the Pension Plan and consequently forego the additional age and points-based employer contribution under the Company's 401(k) retirement savings plan. As a result of this action, we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009.
 
In September of 2010, our bargaining unit employees voted to freeze participation in the Pension Plan and to freeze the benefits of current bargaining unit participants except for the following group: those bargaining unit participants who are both 1) age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the Pension Plan and consequently forego the additional age and points-based employer contribution under the Company's 401(k) retirement savings plan. The change is effective January 1, 2011. As a result of this action, we recognized a pre-tax curtailment expense of less than $0.1 million that was recognized in the fourth quarter of 2010.
 
The Pension Plan's expected long-term rate of return on assets assumption is based upon the weighted average expected long-term rate of returns for each individual asset class. The asset class weighting is determined using the target allocation for each asset class in the Pension Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from adjusted long-term historical returns for the asset class. It is anticipated that long-term future returns will not achieve historical results.
 

42

 

The expected long-term rate of return for equity investments was 9.25% and 9.50% for the 2010 and 2009 plan years, respectively. For determining the expected long-term rate of return for equity assets, we reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2010, 9.1%, 10.8%, 10.1% and 9.7%, respectively. Fund management fees were estimated to be 0.18% for S&P 500 Index assets and 0.45% for other assets. The expected long-term rate of return on fixed income investments was 5.75%; the return was based upon historical returns on 10-year treasury bonds of 6.9% from 1962 to 2009, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 1.0%, which was based upon current one-year LIBOR rates.
 
Pension Plan Assets
 
Percentage of fair value of Pension Plan assets at December 31:
 
 
2010
2009
 
 
 
Equity
68
%
72
%
Fixed income
29
 
25
 
Cash
3
 
3
 
Total
100
%
100
%
 
The Investment Policy for the Pension Plans is to seek to achieve the following long-term objectives: 1) a rate of return in excess of the annualized inflation rate based on a five-year moving average; 2) a rate of return that meets or exceeds the assumed actuarial rate of return as stated in the Plan's actuarial report; 3) a rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates on a moving three-year average, and 4) maintenance of sufficient income and liquidity to pay monthly retirement benefits. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets.
 
The policy contains certain prohibitions on transactions in separately managed portfolios in which the Pension Plan may invest, including prohibitions on short sales.
 
Supplemental Non-qualified Defined Benefit Retirement Plans
 
We have various supplemental retirement plans ("Supplemental Plans") for key executives. The Supplemental Plans are non-qualified defined benefit plans. We use a December 31 measurement date for the Supplemental Plans. Effective January 1, 2010, we eliminated a non-qualified pension plan in which some of our officers participated due to the partial freeze of our qualified pension plan. We also amended the NQDC, which was adopted in 1999. The NQDC is a non-qualified deferred compensation plan that provides executives with an opportunity to elect to defer compensation and receive benefits without reference to the limitations on contributions in the Plan or those imposed by the IRS. The amended NQDC provides for non-elective non-qualified restoration benefits to certain officers who are not eligible to continue accruing benefits under the Defined Benefit Pension Plans and associated non-qualified pension restoration plans. All contributions to the non-qualified plans are subject to a graded vesting schedule of 20% per year over five years with vesting credit beginning with service in the Plan on and after January 1, 2010.
 
Supplemental Plan Assets
 
The Supplemental Plans have no assets. We fund on a cash basis as benefits are paid.
 

43

 

Non-pension Defined Benefit Postretirement Plan
 
Employees who are participants in our Non-Pension Postretirement Healthcare Plan ("Healthcare Plan") and who retire on or after attaining age 55 after completing at least five years of service are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We use a December 31 measurement date for the Healthcare Plan. In July 2009, the Board of Directors approved an amendment to the Healthcare Plan which changed the structure of the Healthcare Plan for non-union employees to a RMSA structure. This change was effective January 1, 2010. In September 2010, the bargaining unit employees voted to change the structure of their benefits to an RMSA. This change is effective January 1, 2011. It has been determined that the Healthcare Plan's post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.
 
Plan Assets
 
The Healthcare Plan has no assets. We fund on a cash basis as benefits are paid.
 
Plan Contributions and Estimated Cash Flows
 
Contributions made to the Supplemental Non-qualified Defined Benefit Retirement Plans and the Non-pension Defined Benefit Postretirement Plan are expected to be made in the form of benefit payments. Contributions to each of the plans were as follows (in thousands):
 
 
2010
2009
Defined Benefit Plans
 
 
Defined Benefit Pension Plan
$
8,798
 
$
 
Non-pension Defined Benefit Postretirement Healthcare Plan
$
657
 
$
578
 
Supplemental Non-Qualified Defined Benefit Plan
$
108
 
$
89
 
 
 
 
Defined Contribution Plans
 
 
Company Retirement Contribution
$
171
 
$
 
Matching contributions
$
1,029
 
$
712
 
 
Contributions to our employee benefit plans to be made in 2011 are as follows (in thousands):
 
2011
Defined Benefit Plans
 
Defined Benefit Pension Plan
$
 
Non-Pension Defined Benefit Postretirement Healthcare Plan
$
503
 
Supplemental Non-Qualified Defined Benefit Plan
$
108
 
 
Fair Value Measurements
 
Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The pension plan is able to classify fair value balances based on the observability of inputs.
 

44

 

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:
 
Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.
 
Level 2 - Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
 
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources.
 
As required by accounting standards for fair value measurements, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31 (in thousands):
 
Defined Benefit Pension Plan
December 31, 2010
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total Fair Value
 
 
 
 
 
Registered Investment Companies
$
28,042
 
$
 
$
 
$
28,042
 
Common Collective Trust
 
19,104
 
 
19,104
 
Insurance contracts
 
1,082
 
 
1,082
 
Total investments measured at fair value
$
28,042
 
$
20,186
 
$
 
$
48,228
 
 
 
Defined Benefit Pension Plan
December 31, 2009
Recurring Fair Value Measures
Level 1
Level 2
Level 3
Total Fair Value
 
 
 
 
 
Registered Investment Companies
$
22,632
 
$
 
$
 
$
22,632
 
Common Collective Trust
 
16,408
 
 
16,408
 
Total investments measured at fair value
$
22,632
 
$
16,408
 
$
 
$
39,040
 
 

45

 

Plan Reconciliations
 
The following tables provide a reconciliation of the Employee Benefit Plan's obligations and fair value of assets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):
 
Benefit Obligations
 
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
2010
2009
2010
2009
2010
2009
Change in benefit obligation:
 
 
 
 
 
 
 
 
 
 
 
 
 
Projected benefit obligation at beginning of year
$
55,615
 
$
51,965
 
$
1,690
 
$
1,672
 
$
9,432
 
$
7,393
 
Service cost
1,215
 
1,155
 
 
 
340
 
216
 
Interest cost
3,280
 
3,143
 
100
 
100
 
547
 
444
 
Actuarial loss (gain)
4,129
 
1,686
 
54
 
7
 
(88
)
3,474
 
Amendments
260
 
100
 
 
 
(2,270
)
(1,960
)
Discount rate change
 
1,047
 
 
 
 
 
Benefits paid
(2,472
)
(2,312
)
(109
)
(89
)
(658
)
(579
)
Asset transfer (to) from affiliate
(3,300
)
(121
)
417
 
 
(328
)
(23
)
Plan curtailment reduction
(974
)
(1,048
)
 
 
 
 
Medicare Part D adjustment
 
 
 
 
88
 
46
 
Plan participants' contributions
 
 
 
 
454
 
421
 
Net increase (decrease)
2,138
 
3,650
 
462
 
18
 
(1,915
)
2,039
 
Projected benefit obligation at end of year
$
57,753
 
$
55,615
 
$
2,152
 
$
1,690
 
$
7,517
 
$
9,432
 
 
A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows (in thousands):
 
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
2010
2009
2010
2009
2010
2009
 
 
 
 
 
 
 
Beginning market value of plan assets
$
39,040
 
$
32,100
 
$
 
$
 
$
 
$
 
Investment income
5,361
 
9,337
 
 
 
 
 
Benefits paid
(2,472
)
(2,312
)
 
 
 
 
Employer contributions
8,798
 
 
 
 
 
 
Asset transfer to affiliate
(2,499
)
(85
)
 
 
 
 
Ending market value of plan assets
$
48,228
 
$
39,040
 
$
 
$
 
$
 
$
 
 

46

 

Amounts recognized in the statement of financial position consist of (in thousands):
 
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
2010
2009
2010
2009
2010
2009
 
 
 
 
 
 
 
Regulatory asset (liability)
$
18,049
 
$
19,580
 
$
 
$
 
$
(1,050
)
$
1,443
 
Current (liability)
$
 
$
 
$
(141
)
$
(98
)
$
(428
)
$
(325
)
Non-current (liability)
$
(9,525
)
$
(16,576
)
$
(2,011
)
$
(1,592
)
$
(7,096
)
$
(9,110
)
 
Accumulated Benefit Obligation
 
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
2010
2009
2010
2009
2010
2009
 
 
 
 
 
 
 
Accumulated benefit obligation
$
52,250
 
$
47,745
 
$
2,058
 
$
1,645
 
$
7,517
 
$
9,432
 
 
Components of Net Periodic Expense
 
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
2010
2009
2008
2010
2009
2008
2010
2009
2008
 
 
 
 
 
 
 
 
 
 
Service cost
$
1,214
 
$
1,155
 
$
1,117
 
$
 
$
 
$
 
$
340
 
$
216
 
$
211
 
Interest cost
3,280
 
3,143
 
3,032
 
100
 
100
 
120
 
547
 
444
 
417
 
Expected return on assets
(3,008
)
(2,780
)
(4,374
)
 
 
 
 
 
 
Amortization of prior service cost
62
 
87
 
112
 
 
 
1
 
(141
)
 
 
Amortization of transition obligation
 
 
 
 
 
 
171
 
51
 
51
 
Recognized net actuarial loss (gain)
1,378
 
1,586
 
 
30
 
43
 
44
 
 
 
(1
)
Curtailment expense
57
 
189
 
 
 
 
 
 
 
 
Net periodic expense
$
2,983
 
$
3,380
 
$
(113
)
$
130
 
$
143
 
$
165
 
$
917
 
$
711
 
$
678
 
 

47

 

Accumulated Other Comprehensive Income (Loss)
 
Amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
 
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
2010
2009
2010
2009
2010
2009
 
 
Net loss
$
 
$
 
$
(418
)
$
(324
)
$
 
$
 
Prior service cost
 
 
 
 
 
 
Transition obligation
 
 
 
 
 
 
 
$
 
$
 
$
(418
)
$
(324
)
$
 
$
 
 
The amounts in AOCI, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2011 were as follows (in thousands):
 
 
Defined Benefits Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
 
 
 
Net loss
$
966
 
$
31
 
$
106
 
Prior service cost
40
 
 
(204
)
Transition obligation
 
 
 
Total net periodic benefit cost expected to be recognized during calendar year 2011
$
1,006
 
$
31
 
$
(98
)
 
Assumptions
 
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Plans
 
2010
2009
2008
2010
2009
2008
2010
2009
2008
Weighted-average assumptions used to determine benefit obligations:
 
 
 
 
 
 
 
 
 
Discount rate
5.50
%
6.05
%
6.20
%
5.50
%
6.10
%
6.20
%
5.00
%
5.90
%
6.10
%
Rate of increase in compensation levels
3.70
%
4.25
%
4.25
%
5.00
%
5.00
%
5.00
%
N/A
N/A
N/A
 
 
 
 
 
 
 
 
 
 
Weighted-average assumptions used to determine net periodic benefit cost for plan year:
 
 
 
 
 
 
 
 
 
Discount rate
6.05
%
6.25
%
6.35
%
6.10
%
6.20
%
6.35
%
5.90
%
6.10
%
6.35
%
Expected long-term rate of return on assets*
8.00
%
8.50
%
8.50
%
N/A
N/A
N/A
N/A
N/A
N/A
Rate of increase in compensation levels
4.25
%
4.25
%
4.34
%
5.00
%
5.00
%
N/A
N/A
N/A
N/A
_____________________________
*    The expected rate of return on plan assets changed to 7.75% for the calculation of the 2011 net periodic pension cost.
 

48

 

The healthcare benefit obligation was determined at December 31, 2010, using an initial healthcare trend rate of 9.5% grading down to an ultimate rate of 4.5% in 2027, and at December 31, 2009, using an initial healthcare trend rate of 10.0% trending down to an ultimate rate of 4.5% in 2027.
 
The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1% increase or 1% decrease in the healthcare cost trend assumptions would affect the service and interest costs and the accumulated periodic postretirement benefit obligation as follows (dollars in thousands):
 
 
Service and Interest Costs
Accumulated Periodic Postretirement Benefit Obligation
 
Dollars
Percent
Dollars
Percent
1% increase
$
147
 
17
 %
$
426
 
6
 %
1% (decrease)
$
(114
)
(13
)%
$
(375
)
(5
)%
 
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
 
 
 
 
Non-pension Defined Benefit Postretirement Plans
 
Defined Benefit Pension Plans
Supplemental Nonqualified Defined Benefit Retirement Plan
Expected Gross Benefit Payments
Expected Medicare Part D Drug Benefit Subsidy
Expected Net Benefit Payments
 
 
 
 
 
 
2011
$
2,817
 
$
141
 
$
503
 
$
(75
)
$
428
 
2012
$
2,907
 
$
122
 
$
600
 
$
(82
)
$
518
 
2013
$
3,016
 
$
102
 
$
652
 
$
(87
)
$
565
 
2014
$
3,148
 
$
103
 
$
699
 
$
(91
)
$
608
 
2015
$
3,224
 
$
91
 
$
723
 
$
(95
)
$
628
 
2016-2020
$
18,167
 
$
583
 
$
4,266
 
$
(500
)
$
3,766
 
 
Defined Contribution Plan
 
The Parent sponsors a 401(k) retirement savings plan in which employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis, up to a maximum amount established by the Internal Revenue Service. The plan provides for company matching contributions and company retirement contributions. Employer contributions vest at 20% per year and are fully vested when the participant has 5 years of service.
(11)     RELATED-PARTY TRANSACTIONS
 
Receivables and Payables
 
We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31, were as follows (in thousands):
 
 
2010
2009
Related party receivables
$
6,891
 
$
4,146
 
Related party payables
$
12,562
 
$
10,030
 
 
Money Pool Notes Receivable and Notes Payable
 
We have a Utility Money Pool Agreement with the Parent, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from the Parent. The Agreement restricts us from loaning funds to the Parent or to any of the Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to the Parent. Borrowings under the agreement bear interest at the daily cost of external funds as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 100 basis points.

49

 

 
Advances under this note bear interest at 2.75% above the daily LIBOR rate (3.01% at December 31, 2010). We had the following balances with the Utility Money Pool as of and for the years ended December 31 (in thousands):
 
 
2010
2009
2008
 
 
 
 
Notes receivable (payable) with Utility Money Pool, net
$
39,862
 
$
57,737
 
$
(70,184
)
 
 
 
 
Net interest revenue (expense)
$
467
 
$
(1,123
)
$
(865
)
 
Other Balances and Transactions
 
We had the following related party transactions for the years ended December 31, 2010 and 2009 included in the corresponding captions in the accompanying Statements of Income:
 
•    
We received revenues from Black Hills Wyoming, Inc. for the transmission of electricity.
 
•    
We received revenues from Cheyenne Light for the sale of electricity and dispatch services.
 
•    
We recorded revenues relating to payments received pursuant to a natural gas swap entered into with Enserco.
 
•    
We purchase coal from WRDC. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.
 
•    
We purchase excess power generated by Cheyenne Light.
 
•    
In order to fuel our combustion turbine, we purchase natural gas from Enserco. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.
 
•    
In addition, we also pay the Parent for allocated corporate support service costs incurred on our behalf.
 
•    
We have two contracts with Cheyenne Light under which Cheyenne Light sells up to 40 MW of wind-generated, renewable energy to us.
 
 
2010
2009
2008
 
(in thousands)
Revenues:
 
 
 
Black Hills Wyoming for transmission of electricity
$
1,378
 
$
873
 
$
1,245
 
Cheyenne Light for electricity and dispatch services
$
1,200
 
$
1,823
 
$
2,778
 
Natural gas swaps from Enserco
$
 
$
 
$
200
 
 
 
 
 
Purchases:
 
 
 
Coal purchases from WRDC
$
13,569
 
$
16,284
 
$
15,469
 
Excess power purchased from Cheyenne Light
$
8,664
 
$
8,580
 
$
6,387
 
Natural gas from Enserco
$
1,652
 
$
2,250
 
$
8,049
 
Corporate support services from Parent
$
17,145
 
$
15,014
 
$
12,391
 
Renewable wind energy from Cheyenne Light
$
4,538
 
$
2,791
 
$
628
 
 
We have funds on deposit from Black Hills Wyoming for transmission system reserve which are included in Other, non-current liabilities on the accompanying Balance Sheets. We have transmission system reserve balances as follows as of December 31 (in thousands):
 

50

 

 
2010
2009
Deferred credits and other liabilities
$
2,044
 
$
1,978
 
 
Interest on the transmission system reserve deposit accrues quarterly at an average prime rate (3.25% at December 31, 2010). We paid interest for the years ended December 31 as follows (in thousands):
 
 
2010
2009
2008
Interest expense
$
65
 
$
70
 
$
114
 
 
(12)    SUPPLEMENTAL CASH FLOW INFORMATION
 
Years ended December 31,
2010
2009
2008
 
(in thousands)
Non-cash investing activities -
 
 
 
Property, plant and equipment financed with accrued liabilities
$
7,188
 
$
10,191
 
$
13,294
 
Money pool activity - net repayment of funds loaned
$
 
$
25,000
 
$
 
Non-cash financing activities -
 
 
 
Money pool activity - net repayment of funds borrowed
$
 
$
(25,000
)
$
 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash (paid) refunded during the period for -
 
 
 
Interest (net of amounts capitalized)
$
(19,554
)
$
(14,252
)
$
(11,578
)
Income taxes
$
15,805
 
$
3,700
 
$
5,877
 
 
(13)     COMMITMENTS AND CONTINGENCIES
 
Partial Sale of Wygen III
 
On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received of which $30.2 million was used to pay down a portion of the Acquisition Facility. MDU continued to reimburse us for its 25% of the total costs paid to complete the project. The Wygen III generation facility began commercial operations on April 1, 2010. In conjunction with the sales transaction, we also modified a 2004 PPA between us and MDU.
 
On July 14, 2010, we sold a 23% ownership interest in Wygen III to the City of Gillette for $62.0 million. The purchase terminates the current PPA with the City of Gillette, and the Wygen III Participation Agreement has been amended to include the City of Gillette. The Participation Agreement provides that the City of Gillette will pay us for administrative services and share in the costs of operating the plant for the life of the facility. The estimated amount of net fixed assets sold totaled $55.8 million. We recognized a gain on the sale of $6.2 million.
 
Power Purchase and Transmission Services Agreements
 
We have the following power purchase and transmission agreements as of December 31, 2010:
 
•    
A PPA with PacifiCorp expiring in 2023, which provides for the purchase by us of 50 MW of electric capacity and energy. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants;
 
•    
A firm point-to-point transmission access agreement to deliver up to 50 MW of power on PacifiCorp's transmission system to wholesale customers in the western region through 2023;

51

 

 
•    
Cheyenne Light entered into a 20-year PPA with Happy Jack for 29.4 MW of energy. Under a separate inter-company agreement expiring in 2028, Cheyenne Light has agreed to sell 50% of the facility output from Happy Jack to us;
 
•    
Cheyenne Light entered into a 20-year PPA with Silver Sage for 30 MW of energy. Under a separate inter-company agreement expiring in 2029, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to us; and
 
•    
A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light's excess energy.
 
Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):
 
Contract
Contract Type
Expiring
2010
2009
2008
 
 
 
 
 
 
PacifiCorp
Electric capacity and energy
2023
$
12,936
 
$
11,862
 
$
11,571
 
PacifiCorp
Transmission access
2023
$
1,215
 
$
1,215
 
$
1,215
 
Cheyenne Light
Happy Jack Wind Farm
2028
$
2,815
 
$
2,078
 
$
628
 
Cheyenne Light
Silver Sage Wind Farm
2029
$
1,723
 
$
713
 
$
 
 
Long-Term Power Sales Agreements
 
We have the following power sales agreements as of December 31, 2010:
 
•    
In March 2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette effective April 2010 that replaces a previous agreement. This PPA provided the City of Gillette, with an option to purchase a 23% ownership interest in our Wygen III facility which commenced commercial operations on April 1, 2010. The City of Gillette exercised its option to purchase the 23% ownership interest in Wygen III and the transaction closed in July 2010. The PPA terminated upon the closing of the transaction. We retain responsibility for operations of the facility with a life-of-plant lease and agreement for operations and coal supply. We entered into a five year agreement with the City of Gillette to dispatch the City of Gillette's first 23% of net generating capacity. MWs from the Wygen III unit are deemed to supply a portion of the City of Gillette's capacity and energy annually. 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% from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, we will also provide the City of Gillette their operating component of spinning reserves;
 
•    
An agreement with MDU to provide 25% of Wygen III's net generating capacity for the life of the plant. In conjunction with MDU's April 2009 purchase of 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 our 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 its 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;
 
•    
An agreement under which we 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; and
 

52

 

•    
A five-year PPA with MEAN which commenced on April 1, 2010. Under this contract, MEAN purchases 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.
 
Legal Proceedings
 
Ongoing Litigation
 
We are subject to various legal proceedings, claims and litigation which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect our financial position, results of operations or cash flows.
 
(14)     QUARTERLY HISTORICAL DATA (Unaudited)
 
We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter (in thousands):
 
 
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
2010
 
 
 
 
Operating revenues
$
54,489
 
$
56,438
 
$
59,051
 
$
59,785
 
Operating income
$
9,361
 
$
10,510
 
$
21,092
 
$
14,305
 
Net income
$
5,934
 
$
4,102
 
$
14,078
 
$
7,154
 
 
 
 
 
 
2009
 
 
 
 
Operating revenues
$
54,458
 
$
46,836
 
$
53,086
 
$
52,699
 
Operating income
$
10,705
 
$
5,006
 
$
8,920
 
$
10,174
 
Net income
$
6,964
 
$
3,105
 
$
7,166
 
$
5,904
 
 
 
 
 
 

53

 

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
 
None.
 
ITEM 9A.    CONTROLS AND PROCEDURES
 
Evaluation of disclosure controls and procedures
 
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2010. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
 
Internal control over financial reporting
Management's Report on Internal Control over Financial Reporting is presented on Page 24 of this Annual Report on Form 10-K.
 
During our fourth fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
 
ITEM 9B.    OTHER INFORMATION
 
None.
 
 

54

 

 
ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES
 
The following table sets forth the aggregate fees for services provided to us for the fiscal years ended December 31, 2010 and 2009 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):
 
Deloitte & Touche LLP
2010
2009
Audit Fees
$
335
 
$
552
 
Tax Fees
157
 
116
 
Audit-related fees
48
 
190
 
Total
$
540
 
$
858
 
 
Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission.
 
Tax Fees. Fees for services related to tax compliance, and tax planning and advice including tax assistance with tax audits. These services include assistance regarding federal and state tax compliance and advice, review of tax returns, and federal and state tax planning.
 
Audit-Related Fees. Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under "Audit Fees." These may services include internal control reviews; attest services that are not required by statute or regulation; employee benefit plan audits; due diligence, consultations and audits related to mergers and acquisitions; and consultations concerning financial accounting and reporting standards.
 
The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Black Hills Corporation Audit Committee's pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee annually reviews the services expected to be provided by the independent auditors and establish pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.
 
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
(a)
1.
Financial Statements
 
 
 
 
 
Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.
 
 
 
 
2.
Schedules
 
Valuation and Qualifying Accounts for the years ended December 31, 2010, 2009 and 2008 
 
 
 
All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in this Form 10-K.
 

55

 

BLACK HILLS POWER, INC.
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
 
Description
Balance at beginning of year
Additions Charged to costs and expenses
Deductions
Balance at end of year
 
(in thousands)
Allowance for doubtful accounts:
 
 
 
 
2010
$
259
 
$
499
 
$
(528
)
$
230
 
2009
$
370
 
$
316
 
$
(427
)
$
259
 
2008
$
388
 
$
637
 
$
(655
)
$
370
 
 
 

56

 

3.    Exhibits
Exhibit Number
Description
 
 
3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)).
 
 
3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000).
 
 
3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999).
 
 
4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
10.1*
Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
10.2*
Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
10.3*
Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
23
Independent Auditors' Consent
 
 
31.1
Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
31.2
Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
_________________________
*    Previously filed as part of the filing indicated and incorporated by reference herein.
 
(a)    
See (a) 3. Exhibits above.
(b)    
See (a) 2. Schedules above.
 

57

 

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.
 
The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.
 

58

 

 
SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
BLACK HILLS POWER, INC.
 
 
 
 
 
By
/s/ DAVID R. EMERY
 
 
David R. Emery, Chairman and
 
 
Chief Executive Officer
 
 
 
Dated:
March 7, 2011
 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
 
/s/ DAVID R. EMERY
Director and
March 7, 2011
David R. Emery, Chairman and
Principal Executive Officer
 
Chief Executive Officer
 
 
 
 
 
/s/ ANTHONY S. CLEBERG
Principal Financial and
March 7, 2011
Anthony S. Cleberg, Executive Vice President
Accounting Officer
 
and Chief Financial Officer
 
 
 
 
 
/s/ DAVID C. EBERTZ
Director
March 7, 2011
David C. Ebertz
 
 
 
 
 
/s/ JACK W. EUGSTER
Director
March 7, 2011
Jack W. Eugster
 
 
 
 
 
/s/ JOHN R. HOWARD
Director
March 7, 2011
John R. Howard
 
 
 
 
 
/s/ KAY S. JORGENSEN
Director
March 7, 2011
Kay S. Jorgensen
 
 
 
 
 
/s/ STEPHEN D. NEWLIN
Director
March 7, 2011
Stephen D. Newlin
 
 
 
 
 
/s/ GARY L. PECHOTA
Director
March 7, 2011
Gary L. Pechota
 
 
 
 
 
/s/ WARREN L. ROBINSON
Director
March 7, 2011
Warren L. Robinson
 
 
 
 
 
/s/ JOHN B. VERING
Director
March 7, 2011
John B. Vering
 
 
 
 
 
/s/ THOMAS J. ZELLER
Director
March 7, 2011
Thomas J. Zeller
 
 
 

59

 

INDEX TO EXHIBITS
 
Exhibit Number
Description
 
 
3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)).
 
 
3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000).
 
 
3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999).
 
 
4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
10.1*
Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
10.2*
Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
10.3*
Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).
 
 
23
Independent Auditors' Consent
 
 
31.1
Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
31.2
Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
32.1
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
32.2
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
_________________________
*    Previously filed as part of the filing indicated and incorporated by reference herein.
 

60