ITEM 1A.
Risk Factors
The following specific risk factors and other risk factors that we discuss in our periodic reports filed from time to time 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 must rely on cash distributions from our subsidiaries to make and maintain dividends and debt payments. There may be changes in the regulatory environment that restrict future dividends from our subsidiaries.
We are a holding company and thus our investments in our subsidiaries are our primary assets. Consequently, our operating cash flow and our ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any contractual or regulatory restrictions that may be applicable to it, which may include requirements to maintain minimum levels of cash, working capital or debt service funds.
Our utility operations are regulated by utility commissions in the States of South Dakota, Wyoming and Montana. These commissions generally possess broad powers to ensure that the needs of the utility customers are being met and that we maintain a reasonable capital structure. As a result of the energy crisis in California and the financial troubles at a number of energy companies, some state utility commissions have imposed restrictions on the ability of the utilities they regulate to pay dividends or make advances to their parent holding companies. If the utility commissions in South Dakota or Wyoming choose to adopt similar restrictions, our utilities’ ability to pay dividends or advance funds to us would be limited, which could materially and adversely affect our ability to meet our financial obligations.
We cannot assure you that our results from any acquisition will conform to our expectations. There may be additional risks associated with the operation of any new acquisition.
Successful acquisitions require an assessment of a number of factors, many of which are beyond our control and are inherently uncertain. Factors which may cause our actual results to differ materially from our expected results include:
• delay in any required governmental or regulatory approvals;
• the loss of management or key personnel;
• the diversion of our management’s attention from other business segments; and
• integration and operational issues.
Our agreements with counterparties that have experienced downgrades in their credit ratings expose us to the risk of counterparty default, which could adversely affect our cash flow and profitability.
We are exposed to credit risks in our power generation, distribution and energy marketing operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. In the past several years, a substantial number of energy companies have experienced downgrades in their credit ratings, some of which serve as our counterparties from time to time. In addition, we have project level financing arrangements in place that provide for the potential acceleration of payment obligations in the event of nonperformance by a counterparty under related power purchase agreements. If these or other counterparties fail to perform their obligations under their respective power purchase agreements, our financial condition and results of operations may be adversely affected. We may not be able to enter into replacement power purchase agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement power purchase agreements, we would sell the plant’s power at market prices.
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 issuer credit rating is Baa3 by Moody’s Investor Services, Inc., or Moody’s, and BBB- by Standard & Poor’s Rating Service. Any reduction in our ratings by Moody’s or Standard & Poor’s would reduce our credit rating with that agency to non-investment grade status, and such reduction could adversely affect our ability to refinance or repay our existing debt and to complete new financings on acceptable terms or at all.
In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations, including borrowings made under our revolving credit facility, our $128.3 million Wygen I plant project financing, and our $26.2 million General Electric Capital Corp. secured financings.
A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under existing or new transactions.
Geopolitical tensions may impair our ability to raise capital and limit our growth.
Continuing conflict in Iraq and tensions between the United States and other governments could disrupt capital markets and make it more costly or temporarily impossible for us to raise capital, thus hampering the implementation of our stated strategy. In the past, geopolitical events, including the uncertainty associated with the Gulf War in 1991 and the terrorist attacks of September 11, 2001, have been associated with general economic slowdowns. Geopolitical tensions or other factors could retard economic growth and reduce demand for the power and fuel products that we produce or market, which could adversely affect our earnings.
Our utilities may not raise their retail rates without prior approval of the South Dakota Public Utilities Commission or the Wyoming Public Services Commission. If either utility seeks rate relief, it could experience delays in obtaining approvals and could have rate recovery disallowed in rate proceedings.
Our rate freeze agreement with the SDPUC for our Black Hills Power electric utility expired on January 1, 2005. Until such time as we petition the SDPUC or the WPSC for rate relief, or either commission requires that we do so, neither Black Hills Power nor Cheyenne Light may increase its retail rates. Additionally, Black Hills Power may not invoke any fuel and purchased power adjustment tariff that would take effect prior to the completion of a rate proceeding, absent extraordinary circumstances. As part of the process for obtaining approval to acquire Cheyenne Light, we agreed with the WPSC that Cheyenne Light would not raise retail rates for its customers prior to January 1, 2006. Because our utilities are generally unable to increase their base rates without prior approval from the SDPUC and the WPSC, our returns could be threatened by plant outages, machinery failure, increases in purchased power costs over which our utilities have no control, acts of nature, acts of terrorism or other unexpected events that could cause operating costs to increase and operating margins to decline. Moreover, in the event of unexpected plant outages or machinery failures, Black Hills Power may be required to purchase replacement power in wholesale power markets at prices that exceed the rates it is permitted to charge its retail customers. Finally, our utilities’ costs would be subject to the review of the SDPUC or the WPSC, and the commissions could find certain costs not to be recoverable, thus negatively affecting our revenues.
Because prices for our products and services and other operating costs for our business are volatile, our revenues and expenses may fluctuate.
A substantial portion of our net income in recent years has been attributable to sales of wholesale electricity and natural gas into a robust market. The prices of electricity in the wholesale power markets have stabilized at lower levels after the price volatility experienced in the second half of 2000 and the first half of 2001. Power prices are influenced by many factors outside our control, including:
• fuel prices;
• transmission constraints;
• supply and demand;
• weather;
• 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 price fluctuations over relatively short periods of time and can be unpredictable.
The success of our oil and gas operations will depend somewhat upon the prevailing market prices of oil and natural gas. Historically, oil and natural gas prices and markets have also been volatile, and they are likely to continue to be volatile in the future. A decrease in oil or natural gas prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. A decline in fuel price volatility could also affect our revenues and returns from energy marketing, which historically tend to increase when markets are volatile.
Construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve significant risks which could lead to lost revenues or increased expenses.
The construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve many risks, including:
• the inability to obtain required governmental permits and approvals;
• the unavailability of equipment;
• supply interruptions;
• work stoppages;
• labor disputes;
• social unrest;
• weather interferences;
• unforeseen 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 result in lost revenues, increased expenses, 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 adequate to cover lost revenues, increased expenses or liquidated damage payments.
Our power project development, expansion and acquisition activities may not be successful, which would impair our ability to execute our growth strategy.
The growth of our independent power business through development, expansion and acquisition activities is important to our future growth. We may not be able to continue to develop attractive opportunities or to complete acquisitions or development projects we undertake. Factors that could cause our activities to be unsuccessful include:
• competition;
• the trend of utilities building their own generation or looking for developers to develop and build projects for sale to utilities under turnkey arrangements;
• lower than anticipated increases in the demand for power in our target markets;
• fuel prices or fuel supply constraints;
• transmission constraints;
• changes in federal or state laws and regulations;
• our inability to negotiate acceptable acquisition, construction, fuel supply, power sales or other material agreements;
• our inability to obtain financing on acceptable terms, or at all;
• our inability to obtain required governmental permits and approvals;
• capital market conditions; and
• our inability to successfully integrate any businesses we acquire.
Estimates of the quantity and value of our proved oil and gas reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves.
There are many uncertainties inherent in estimating quantities of proved reserves and their values. The process of estimating oil and natural gas reserves requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretations and judgment, and the assumptions used regarding quantities of recoverable oil and gas reserves and prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and these variances may be significant. Any significant variance from the assumptions used could result in the actual quantity of our reserves and future net cash flow being materially different from our estimates. In addition, results of drilling, testing and production and changes in oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.
Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three dimensional structural modeling.
There are many uncertainties inherent in estimating quantities of coal reserves. The process of coal volume estimation requires interpretations of drill hole log data and subsequent computer modeling of the intersected deposit. Any significant inaccuracies in these interpretations or modeling could materially affect the quantity and quality of our reserves. The accuracy of reserve estimates is a function of engineering and geological interpretations and judgment of known data, assumptions used regarding structural limits and mining extents, conditions encountered during actual reserve recovery, and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that can result in reserve revisions either upward or downward from prior reserve estimates.
Our business is subject to substantial governmental regulation and permitting requirements as well as on-site environmental liabilities we assumed when we acquired some of our facilities. We may be adversely affected by any future inability to comply with existing or future regulations or requirements or the potentially high cost of complying with such requirements.
Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. In the course of complying with these requirements, we may incur significant additional 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. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulation may have a detrimental effect on our business.
In acquiring some of our facilities, we assumed on-site liabilities associated with the environmental condition of those facilities, regardless of when such liabilities arose and whether known or unknown, and in some cases agreed to indemnify the former owners of those facilities for on-site environmental liabilities. We strive at all times to be in compliance with all applicable environmental laws and regulations. However, steps to bring our facilities into compliance, if necessary, could be expensive, and thus could adversely affect our results of operation and financial condition. Furthermore, with the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the assets we operate, we expect our environmental expenditures to be substantial in the future.
Ongoing changes in the United States utility industry, such as state and federal regulatory changes, a potential increase in the number 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;
• consumer demands;
• 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, and 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 negatively affect our ability to expand our asset base.
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 those 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.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” subcaption within Item 8, Note 20, “Commitments and Contingencies”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter of 2005.
ITEM 4A.
EXECUTIVE OFFICERS OF THE REGISTRANT
David R. Emery, age 43, was elected Chairman in April 2005 and President and Chief Executive Officer and a member of the Board of Directors in January 2004. Prior to that, he was our President and Chief Operating Officer - Retail Business Segment from April 2003 to January 2004 and Vice President-Fuel Resources from January 1997 to April 2003. Mr. Emery has 16 years of experience with us.
Thomas M. Ohlmacher, age 54, has been the President and Chief Operating Officer of our Wholesale Energy Group since November 2001. He served as Senior Vice President-Power Supply and Power Marketing from January 2001 to November 2001 and Vice President - Power Supply from 1994 to 2001. Prior to that, he held several positions with our company since 1974.
Linden R. Evans, age 43, was appointed President and Chief Operating Officer - Retail Business Segment in October 2004. Mr. Evans had been serving as the Vice President and General Manager of our former communication subsidiary, since December 2003 and served as our Associate Counsel from May 2001 to December 2003. Prior to joining Black Hills, Mr. Evans was an attorney and member with the Rapid City, South Dakota law firm of Truhe, Beardsley, Jensen, Helmers and VonWald from February 1997 to May 2001.
Mark T. Thies, age 42, has been our Executive Vice President and Chief Financial Officer since March 2000. From May 1997 to March 2000, he was our Controller. Mr. Thies has 8 years of experience with us.
Steven J. Helmers, age 49, has been our Senior Vice President, General Counsel since January 2004. He served as our Senior Vice President, General Counsel and Corporate Secretary from January 2001 to January 2004. Prior to joining us, Mr. Helmers was an attorney and a shareholder with the Rapid City, South Dakota law firm of Truhe, Beardsley, Jensen, Helmers & VonWald, from 1997 to January 2001.
Russell L. Cohen, age 45, has been Senior Vice President and Chief Risk Officer since May 2002. Prior to joining Black Hills, Mr. Cohen was General Partner and Chief Financial Officer at Regenesis Group, LLC from December 2000 to April 2002.
Maurice T. Klefeker, age 49, was elected Senior Vice President - Strategic Planning and Development in March 2004. Prior to that he served as Senior Vice President of our subsidiary, Black Hills Generation, Inc. from September 2002 to March 2004 and as Vice President of Corporate Development from July 2000 to September 2002.
James M. Mattern, age 51, has been the Senior Vice President - Corporate Administration and Compliance since April 2003 and Senior Vice President-Corporate Administration from September 1999 to April 2003. Mr. Mattern has 18 years of experience with us.
Roxann R. Basham, age 44, was elected Vice President - Governance and Corporate Secretary in February 2004. Prior to that, she was our Vice President-Controller from March 2000 to January 2004. Ms. Basham has a total of 22 years of experience with us.
Kyle D. White, age 46, has been Vice President - Corporate Affairs since January 30, 2001 and Vice President - Marketing and Regulatory Affairs since July 1998. Mr. White has 23 years of experience with us.
Garner M. Anderson, age 43, has been our Vice President and Treasurer since July 2003. Mr. Anderson has 17 years of experience with us, including positions as Director - Treasury Services and Risk Manager.
Perry S. Krush, age 47, was appointed Vice President - Controller in December 2004. Mr. Krush has over 16 years of experience with us, including positions as Controller - Retail Operations from 2003 to 2004, Director of Accounting for our subsidiary, Black Hills Energy Inc. and Accounting Manager - Fuel Resources from 1997 to 2003.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on The New York Stock Exchange under the symbol BKH. As of March 1, 2006, we had 5,367 common shareholders of record and approximately 17,200 beneficial owners, representing all 50 states, the District of Columbia and 12 foreign countries.
We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 2006 meeting, our board of directors raised the quarterly dividend to $0.33 per share, equivalent to an annual dividend of $1.32 per share.
The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities, any regulatory restrictions and our future business prospects. Our credit facilities contain restrictions on the payment of cash dividends, the most restrictive of which prohibit the payment of cash dividends if our fixed charge coverage ratio, as calculated in our credit agreements, is less than 2.5:1.0, our recourse leverage ratio exceeds 0.65:1.00 or our consolidated net worth does not exceed the sum of $625 million and 50 percent of our aggregate consolidated net income since January 1, 2005.
Quarterly dividends paid and the high and low common stock prices, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:
UNREGISTERED SECURITIES ISSUED DURING THE FOURTH QUARTER OF 2005
No unregistered securities were issued during the fourth quarter of 2005.
ISSUER PURCHASES OF EQUITY SECURITIES
_________________________
(1)
Shares acquired by forfeiture of Restricted Stock.
(2)
Includes 253 shares acquired by a Rabbi Trust for the Outside Directors Stock Based Compensation Plan, and 4,783 shares acquired from certain key employees under the share withholding provisions of the Restricted Stock Plan for payment of taxes associated with the vesting of shares of Restricted Stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
____________________________________
We have experienced significant change over the last five years, primarily as a result of the expansion of our wholesale energy business, commodity price volatility and volatility in wholesale electric sales and the related margins at our electric utility, Black Hills Power. Unusual conditions in the Western energy markets during the first half of 2001 accounted for approximately $1.40 per share of our earnings in 2001. Impairment charges recorded to reduce the carrying value of long-lived assets to fair value were approximately $33.9 million after-tax in 2005, and approximately $76.2 million after-tax in 2003.
During 2005 we acquired Cheyenne Light, which is referred to as our Electric and gas utility segment. In addition, certain items related to 2001 through 2004 have been restated from prior year presentations to reflect the classification of Black Hills FiberSystems, Inc. as discontinued operations in 2005 (see Notes 1 and 18 of Item 8. Financial Statements and Supplementary Data).
(1)
Includes $114.0 million of contract termination revenue.
(2)
In May 2003 and May 2001, we issued 4.6 million and 3.4 million common stock shares, respectively, which dilutes our earnings per share in subsequent periods.
(3)
Includes 40 MWs in 2004 and 2003, respectively, 82 MWs in 2002 and 68 MWs in 2001, which have been reported as “Discontinued operations.”
(4)
Includes the 224 megawatt expansion at the Las Vegas cogeneration power plant that was placed in service on January 3, 2003., which have been reported as “Discontinued operations.”
For additional information on our business segments see - ITEM 7.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
81 - 82
Consolidated Statements of Income for the three years ended December 31, 2005
Consolidated Balance Sheets as of December 31, 2005 and 2004
Consolidated Statements of Cash Flows for the three years ended December 31, 2005
Consolidated Statements of Common Stockholders’ Equity and
Comprehensive Income for the three years ended December 31, 2005
Notes to Consolidated Financial Statements
87 - 147
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, 2005, 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, 2005.
Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Black Hills Corporation
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Black Hills Corporation
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Black Hills Corporation and subsidiaries (the “Corporation”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Corporation’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Corporation maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005, of the Corporation, and our report dated March 13, 2006, expressed an unqualified opinion on those financial statements and included an explanatory paragraph relating to the adoption of Emerging Issues Task Force Issue 02-3, Accounting for Contracts Involving Energy Trading and Risk Management Activities, effective January 1, 2003 and Financial Accounting Standards Board Interpretation No. 46 (Revised), Consolidation of Variable Interest Entities, effective December 31, 2003.
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 13, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Black Hills Corporation
We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the “Corporation”) as of December 31, 2005 and 2004, and the related consolidated statements of income, common stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these consolidated financial statements 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial statements present fairly, in all material respects, the financial position of Black Hills Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 13, 2006, expressed an unqualified opinion on management’s assessment of the effectiveness of the Corporation’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Corporation’s internal control over financial reporting.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2003, the Corporation adopted Emerging Issues Task Force Issue 02-3, Accounting for Contracts Involving Energy Trading and Risk Management Activities. Also, as discussed in Note 6 to the consolidated financial statements, effective December 31, 2003, the Corporation adopted Financial Accounting Standards Board Interpretation No. 46 (Revised), Consolidation of Variable Interest Entities.
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 13, 2006
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
______________________
*Includes approximately $2.3 million of cash included in the assets of discontinued operations
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2005, 2004 and 2003
(1)
BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation is a diversified energy company and with its subsidiaries operates in two primary operating groups: retail services and wholesale energy. Retail services include public utility electric operations through its subsidiary, Black Hills Power, Inc., and public utility electric and gas operations through its subsidiary, Cheyenne Light, Fuel and Power (Cheyenne Light), which was acquired on January 21, 2005 (see Note 23). The Company operates its wholesale energy businesses through its direct and indirect subsidiaries: Wyodak Resources related to coal, Black Hills Exploration and Production related to oil and natural gas production, Enserco Energy related to natural gas marketing and Black Hills Energy Resources related to crude oil marketing and transportation, and Black Hills Generation and its subsidiaries and Black Hills Wyoming related to independent power activities, all aggregated for reporting purposes as Black Hills Energy. For further descriptions of the Company’s business segments, see Note 22.
In June 2005, the Company sold its subsidiary, Black Hills FiberSystems, Inc., the Company’s communications segment and in April 2005 sold the Pepperell power plant, the last remaining power plant in the eastern region. In 2004, the Company sold its subsidiary, Landrica Development Corp., which held land and coal enhancement facilities. In 2003, the Company sold its hydroelectric power plants located in Upstate New York. Amounts related to Black Hills FiberSystems, Landrica and the hydroelectric power plants are included in Discontinued operations on the accompanying Consolidated Financial Statements. See Note 18 for further details.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. The most significant estimates relate to allowance for uncollectible accounts receivable, realization of market value of derivatives due to commodity risk, intangible asset valuations and useful lives, long-lived asset values and useful lives, proved oil and gas reserve volumes, employee benefit plans and contingency accruals. Actual results could differ from those estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills Corporation and its wholly owned and majority-owned subsidiaries. In addition, the Company consolidates Wygen Funding, Limited Partnership, a variable interest entity in which the Company is the primary beneficiary as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities Revised” (FIN 46-R). Generally, the Company uses the equity method of accounting for investments of which it owns between 20 and 50 percent and investments in partnerships under 20 percent if the Company exercises significant influence.
All significant intercompany balances and transactions have been eliminated in consolidation except for revenues and expenses associated with intercompany fuel sales in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Total intercompany fuel sales not eliminated were $10.1 million, $9.6 million and $10.3 million in 2005, 2004 and 2003, respectively.
The Company’s consolidated statements of income include operating activity of acquired companies beginning with their acquisition date.
The Company uses the proportionate consolidation method to account for its working interests in oil and gas properties and for its ownership in the jointly owned Black Hills Power transmission tie, the Wyodak power plant and the Black Hills Exploration and Production gas processing plant as discussed in Note 5.
Reclassifications
Certain 2004 and 2003 amounts in the consolidated financial statements have been reclassified to conform to the 2005 presentation. These reclassifications had no effect on the Company’s stockholders’ equity or results of operations, as previously reported. The reclassifications primarily related to planned or completed divestitures and the related reclassification to discontinued operations.
Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Materials, Supplies and Fuel
As of December 31, 2005, the following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets:
________________________
*
As of December 31, 2005 and 2004, market adjustments related to gas and oil held by energy marketing and recorded in inventory, were $6.6 million and $(9.0) million, respectively. As of December 31, 2005, market adjustments related to fuel held by the electric utility were $(0.2) million. (See Note 2 for further discussion of natural gas marketing trading activities.)
“Materials and supplies” and “Fuel” are stated at the lower of cost or market. Generally, cost for these classifications is determined on a weighted-average cost methodology.
“Gas and oil held by energy marketing” primarily consists of gas held in storage and gas imbalances held on account with pipelines. Gas imbalances represent the differences that arise between volumes of gas received into the pipeline versus gas delivered off of the pipeline. Generally, natural gas and oil inventory is stated at the lower of cost or market on a weighted-average cost basis. To the extent that fuel and gas and oil held by energy marketing have been designated as the underlying hedged item in a “fair value” hedge transaction, those volumes are stated at market value using published industry quotations.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is an allowance for funds used during construction (AFUDC) which represents the approximate composite cost of borrowed funds and a return on capital used to finance the project. In addition, the Company capitalizes interest, when applicable, on certain non-regulated construction projects. The amount of AFUDC and interest capitalized was $0.7 million, $0.2 million and $0.4 million in 2005, 2004 and 2003, respectively. 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. Retirement or disposal of all other assets, except for oil and gas properties as described below, result in gains or losses recognized as a component of income. Ordinary repairs and maintenance of property are charged to operations as incurred. Costs of major renewals and replacements are capitalized as property, plant and equipment.
Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method on volumes produced and estimated reserves. For certain non-utility power plant components, a unit-of-production methodology based on plant hours run is used.
Oil and Gas Operations
The Company accounts for its oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and development drilling activities are capitalized. These costs are amortized using a units-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized.
Under the full cost method, net capitalized costs are subject to a “ceiling test” which limits these costs to the present value of future net cash flows discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the net capitalized costs. Future net cash flows are estimated based on end-of-period spot market prices adjusted for contracted price changes. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period unless subsequent market price changes eliminate or reduce the indicated write-down. Given the volatility of oil and gas prices, the Company’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that a write-down of oil and gas properties could occur in the future. No “ceiling test” write-downs were recorded during 2005, 2004 or 2003.
Goodwill and Intangible Assets
The Company accounts for goodwill and intangible assets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). Under SFAS 142, goodwill and intangible assets with indefinite lives are not amortized but the carrying values are reviewed annually (or more frequently if impairment indicators arise) for impairment. Intangible assets with a defined life continue to be amortized over their useful lives (but with no maximum life).
The substantial majority of the Company’s goodwill and intangible assets are contained within the Power Generation segment. Changes to goodwill and intangible assets during the years ended December 31, 2005 and 2004 are as follows (in thousands):
Amortized Other
Goodwill
Intangible Assets
Balance at December 31, 2003, net of accumulated amortization
$
30,144
$
40,070
Amortization expense
-
(3,320)
Reclassification to discontinued operations
-
(62)
Balance at December 31, 2004, net of accumulated amortization
30,144
36,688
Additions
3,915
Impairment losses
(1,897)
(5,567)
Acquisition-related tax adjustment
(626)
-
Amortization expense
-
(3,298)
Balance at December 31, 2005, net of accumulated amortization
$
31,536
$
27,826
Intangible assets primarily relate to site development fees and acquired above-market long-term contracts within the Power Generation segment and are amortized using a straight-line method using estimated useful lives ranging from 5 to 40 years. Intangible assets totaled $51.3 million, with accumulated amortization of $23.5 million at December 31, 2005 and $58.4 million, with accumulated amortization of $21.7 million at December 31, 2004. Amortization expense for intangible assets was $3.3 million, $3.3 million and $4.0 million in 2005, 2004 and 2003, respectively. Amortization expense for existing intangible assets is expected to be approximately $3.1 million a year through 2009 and $2.3 million in 2010.
Additions to goodwill relate to the acquisition of Cheyenne Light and represent the cost of the investment over the estimated fair value of the underlying net assets on the date of acquisition (see Note 23).
During the fourth quarter of 2005, the Company wrote off goodwill of approximately $1.9 million, net of accumulated amortization of $0.3 million related to partnership “equity flips” at certain power fund investments. Upon the triggering of the “equity flips,” the Company recognized earnings for the value of its additional partnership equity and impaired the related goodwill.
During the third quarter of 2005, the Company wrote off intangible assets of $5.6 million, net of accumulated amortization of $1.5 million, related to the impairment of the Las Vegas I gas-fired plant, due to uneconomic operations as a result of significant increases in forecasted natural gas prices (see Note 13).
During the third quarter of 2003, the Company wrote off intangible assets of $34.1 million, net of accumulated amortization of $1.1 million, related to the impairment of the Las Vegas II plant. The impairment charge is a result of a contract termination and subsequent impairment of the Las Vegas II plant (see Notes 12 and 13).
Impairment of Long-Lived Assets
The Company periodically evaluates whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of its long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, the Company 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, the Company would recognize an impairment loss. In 2005, a $50.3 million pre-tax impairment charge was recorded to reduce the carrying value of the Las Vegas I plant and related intangibles, and a $1.9 million, pre-tax impairment charge was recorded to reduce goodwill relating to the recognition of additional earnings in certain power fund investments. In 2004, a $1.1 million pre-tax impairment was recorded to reduce the carrying value of the Company’s Pepperell power plant. This charge is reported in discontinued operations. In 2003, a $117.2 million pre-tax impairment was recorded to reduce the carrying value of the Las Vegas II facility and related intangibles (see Note 13).
Derivatives and Hedging Activities
The Company accounts for its derivative and hedging activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). SFAS 133 requires that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
SFAS 133 allows hedge accounting for qualifying fair value and cash flow hedges. SFAS 133 provides that the 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 be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income 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.
Currency Adjustments
The Company’s functional currency for all operations is the U.S. dollar. The Company’s natural gas marketing subsidiary, Enserco, engages in business transactions in Canada and accordingly, has various transactions that have been denominated in Canadian dollars. These Canadian denominated transactions/balances are adjusted to United States dollars for financial reporting purposes using the year-end exchange rate for balance sheet items and an average exchange rate during the period for income statement items. Currency transaction gains or losses on transactions executed in Canadian dollars are recorded in Operating revenues on the accompanying Consolidated Statements of Income as incurred.
Deferred Financing Costs
Deferred financing costs are amortized using the effective interest method over the term of the related debt.
Development Costs
The Company generally expenses, when incurred, development and acquisition costs associated with corporate development activities prior to the Company acquiring or beginning construction of a project. Certain incremental direct costs for projects deemed by management to be probable of completion are capitalized as deferred assets. Expensed development costs are included in Administrative and general operating expenses on the accompanying consolidated financial statements. Capitalized development costs at December 31, 2005 and 2004 were $0 and $7.6 million, respectively, and are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets.
Legal Costs
Litigation settlements are recorded when it is probable the Company is liable for the costs and the liability can be reasonably estimated. Litigation settlement accruals are recorded net of expected insurance recovery. Legal costs related to settlements are not accrued, but expensed as incurred.
Minority Interest in Subsidiaries
Minority interest in the accompanying Consolidated Statements of Income and Balance Sheets represents the non-affiliated equity investors’ interest in Wygen Funding, L.P., a variable interest entity as defined by Interpretation No. 46 “Consolidation of Variable Interest Entities” (FIN 46) (see Note 6).
Earnings attributable to minority ownership are generally shown on the accompanying Consolidated Statement of Income on a pre-tax basis as the minority investor is a limited partnership which pays no tax at the corporate level.
Regulatory Accounting
The Company’s subsidiaries, Black Hills Power and Cheyenne Light, are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company’s non-regulated businesses.
The regulated utilities follow the provisions of SFAS 71, and their financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating the utilities. If rate recovery becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to Black Hills Power’s generation operations. In the event Black Hills Power determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company could be an extraordinary non-cash charge to operations of an amount that could be material.
Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that could restrict the utilities’ ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure that the continuing application of SFAS 71 is appropriate.
At December 31, 2005 and 2004, the Company had regulatory assets of $17.3 million and $7.2 million and regulatory liabilities of $18.4 million and $6.0 million, respectively. Regulatory assets are primarily recorded for the probable future revenue to recover future income taxes related to the deferred tax liability for the equity component of allowance for funds used during construction of utility assets, unamortized losses on reacquired debt and deferred purchased power, transmission and natural gas costs from Cheyenne Light customers through an electric cost adjustment (ECA) and gas cost adjustment (GCA) mechanism. Each year Cheyenne Light files with the Wyoming Public Service Commission (WPSC) an ECA, effective January 1, and a GCA, effective October 1, to be included in tariff rates for the following year. The ECA and GCA are based on forecasts of the upcoming year’s energy costs and recovery of prior year unrecovered costs. To the extent that energy costs are under recovered or over recovered during the year, they are recorded as a regulatory deferred asset or liability, respectively. These deferred energy balances are interest bearing. As of December 31, 2005, the Company had a deferred energy asset balance. 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 and also the cost of removal for utility plant, recovered through the Company’s electric utility rates. The increase in regulatory liabilities in 2005 is primarily due to the cost of removal for Cheyenne Light, which was acquired in January 2005. The regulatory assets are included in Other assets and the regulatory liabilities are included in Other deferred credits and other liabilities on the Consolidated Balance Sheets.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Income taxes for consolidated subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss.
The Company uses 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. 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. The Company classifies deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.
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. In addition, energy marketing businesses have historically used the mark-to-market method of accounting. Under that method, certain energy marketing activities are recorded at fair value as of the balance sheet date and net gains or losses resulting from the revaluation of these contracts to fair value are recognized currently in the results of operations. In accordance with Emerging Issues Task Force (EITF) Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3), all energy marketing contracts entered into after October 25, 2002 that do not meet the definition of derivatives as defined by SFAS 133, have been accounted for under the accrual method of accounting. For long-term non-utility power sales agreements revenue is recognized either in accordance with EITF No. 91-6, “Revenue Recognition of Long-Term Power Sales Contracts” (EITF 91-6), or in accordance with SFAS No. 13, “Accounting for Leases,” (SFAS 13) as appropriate. Under EITF 91-6, revenue is generally recognized as the lower of the amount billed or the average rate expected over the life of the agreement. Under SFAS 13, revenue is generally levelized over the life of the agreement. For its Investment in Associated Companies (see Note 3), which are involved in power generation, the Company uses the equity method to recognize as earnings its pro rata share of the net income or loss of the associated company.
The Company presents its operating revenues from energy marketing operations in accordance with the guidance provided in EITF 02-3 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19). Accordingly, gains and losses (realized and unrealized) on transactions at our natural gas marketing operations are presented on a net basis in operating revenues, whether or not settled physically. Settled amounts on contracts at our crude oil marketing operations are reported on a gross basis as they are not held for “trading purposes” as defined by EITF 02-3 and EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not “held for trading purposes” as defined by Issue No. 02-3.”
Earnings per Share of Common Stock
Basic earnings per share from continuing operations is computed by dividing “Income from continuing operations before changes in accounting principles” less preferred dividends, by the weighted average number of common shares outstanding during each year. Diluted earnings per share gives effect to all dilutive potential common shares outstanding during a period. A reconciliation of income from continuing operations and basic and diluted share amounts is as follows (in thousands):
The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
Options to purchase common stock
Restricted stock
-
-
Stock-based Compensation
At December 31, 2005, the Company has three stock-based employee compensation plans under which it can issue stock options to its employees, which are described more fully in Note 10. The Company accounts for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related Interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123), to stock-based employee compensation as of December 31 (in thousands, except per share amounts):
Recently Issued Accounting Pronouncements
SFAS No. 123 (Revised 2004)
On December 16, 2004, the Financial Accounting Standards Board, or FASB, issued FASB Statement No. 123 (Revised 2004) “Share-Based Payment,” or SFAS 123(R), which is a revision of SFAS Statement No. 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.
The Company currently accounts for its employee equity compensation stock option plans under the provisions of APB No. 25 and no stock-based employee compensation cost is reflected in net income (see Note 1, Stock-based Compensation) for stock options. Had the Company applied the fair value recognition provisions of SFAS 123-R during those periods, total stock-based employee compensation expense, net of related tax effects, would have been $0.7 million, $0.9 million and $0.9 million for the years ended December 31, 2005, 2004 and 2003, respectively.
As of the required effective date, the Company will apply SFAS 123-R using the modified prospective method, recognizing compensation expense for all awards granted after the date of adoption and for the unvested portion of previously granted awards that remain outstanding at the date of adoption. The Company estimates the adoption of SFAS 123-R will result in less than $0.3 million (after-tax) in additional stock-based compensation expense for the year ending December 31, 2006.
SAB 106
In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106, (SAB No. 106) to be effective October 1, 2004. SAB No 106 provides interpretive guidance on how full cost companies should reflect asset retirement obligations, or ARO, in their full cost ceiling and depreciation, depletion and amortization expense calculations. SAB No. 106 requires future cash outflows associated with settling ARO’s that have accrued on the balance sheet to be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. SAB No. 106 also requires the inclusion of the estimated amount of ARO that will be incurred as a future development activity on proved reserves in the costs to be amortized. Since we were already applying the provisions of SAB No. 106, there was no impact on us after adoption.
FIN 47
In March 2005 the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” (SFAS 143) refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred - generally upon acquisition, construction, or development and (or) through the normal operation of the asset. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.
The Company has identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in its Oil and gas segment, reclamation of its coal mining sites in its Coal mining segment, and removal of fuel tanks and transformers containing polychlorinated biphenyls (PCBs) at the Electric and gas utility segment. The Company adopted FIN 47 effective December 31, 2005, which did not have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
EITF Issue No. 04-6
On March 17, 2005, the Emerging Issues Task Force (EITF) issued EITF Issue No. 04-6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” (EITF 04-6). EITF 04-6 provides that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. The Company currently has a deferred asset recorded, representing costs of removing overburden from coal deposits, and amortizes the deferred asset on a units-of-production basis in proportion of coal tonnage mined and sold to estimated coal tonnage uncovered. EITF 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005. Upon adoption of EITF 04-6 on January 1, 2006, the Company recorded a $3.1 million cumulative effect adjustment to write-off previously recorded deferred charges, with the offset decreasing retained earnings. Additionally, future stripping costs will be expensed as a cost of inventory produced at the time incurred.
EITF Issue No. 04-13
On September 28, 2005 the FASB ratified the consensus reached under EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” (EITF 04-13) which determines if such transactions should be reported on a gross basis or a net basis. EITF 04-13 is effective for new arrangements entered into, and modifications or renewals of existing arrangements, in reporting periods beginning after March 16, 2006. The adoption will not have a significant effect on the Company’s consolidated financial position, results of operations or cash flows.
(2)
RISK MANAGEMENT ACTIVITIES
The Company’s activities in the regulated and unregulated energy sector expose it to a number of risks in the normal operations of its businesses. Depending on the activity, the Company is exposed to varying degrees of market risk and counterparty risk. The Company has developed policies, processes, systems, and controls to manage and mitigate these risks.
Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. The Company is exposed to the following market risks:
• commodity price risk associated with its marketing businesses, its natural long position with crude oil and natural gas reserves and production, and fuel procurement for its gas fired generation assets;
• interest rate risk associated with variable rate credit facilities and project financing floating rate debt as described in Notes 7 and 8; and
• foreign currency exchange risk associated with natural gas marketing business transacted in Canadian dollars.
The Company’s exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates, currency exchange rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.
Trading Activities
Natural Gas Marketing
To effectively manage our marketing portfolios, the Company enters into forward physical commodity contracts, financial instruments including over-the-counter swaps and options, transportation agreements and forward foreign exchange contracts.
Gas marketing business activities are conducted within the parameters as defined and allowed by the Company’s risk policies and procedures. As a general policy, only limited market risk positions are permitted, as clearly defined in these policies and procedures. Therefore, a significant majority of the Company’s gas marketing positions are fully hedged. The Company attempts to balance its portfolio in terms of volume and timing of performance and delivery obligations.
For the years ended December 31, 2005, 2004 and 2003, contracts and other activities at the Company’s natural gas marketing operations are accounted for under the provisions of EITF 02-3 and SFAS No. 133. As such, all of the contracts and other activities at the Company’s natural gas marketing operations that meet the definition of a derivative under SFAS 133 are accounted for at fair value. The fair values are recorded as either Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The net gains or losses are recorded as Operating revenues in the accompanying Consolidated Statements of Income. EITF 02-3, precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to SFAS 133. The prior authoritative accounting guidance applied was EITF Issue 98-10 “Accounting for Contracts Involving Energy Trading and Risk Management Activities” (EITF 98-10), which allowed a broad interpretation of what constituted “trading activity” and hence what would be marked-to-market. EITF 02-3 took a much narrower view of what “trading activity” should be marked-to-market, limiting mark-to-market treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. At the Company’s natural gas marketing operations, management often employs strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of the Company’s producer services, end-use origination and wholesale marketing groups. Except in limited circumstances when the Company is able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow the Company to mark inventory, transportation or storage positions to market. The result is that while a significant majority of the Company’s natural gas marketing positions are economically hedged, the Company is required to mark some parts of its overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of its economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.
Upon adoption of EITF 02-3 on January 1, 2003, the Company recorded a charge for a cumulative effect of an accounting change totaling approximately $2.9 million, net of tax. This cumulative effect of an accounting change was the result of certain energy contracts in our Energy marketing and transportation segment, previously marked to fair value under EITF 98-10, being restated to reflect historical cost. The amount of the cumulative effect represents the unrealized gain or loss recorded on these contracts as of January 1, 2003.
The contract or notional amounts and terms of our natural gas marketing and derivative commodity instruments at December 31, are set forth below:
Derivatives and certain natural gas marketing activities were marked to fair value on December 31, 2005 and 2004, and the gains and/or losses recognized in earnings. The amounts related to the accompanying Consolidated Balance Sheets and Consolidated Statements of Income as of December 31, 2005 and 2004 are as follows (in thousands):
In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published industry quotations. Market adjustments are recorded in inventory on the Balance Sheet and unrealized gain/loss on the Statement of Income. As of December 31, 2005 and 2004, the market adjustments recorded in inventory were $6.6 million and $(9.0) million, respectively.
Activities Other than Trading
Crude Oil Marketing
The Company’s crude oil marketing operations sold effective March 1, 2006, executed physical crude oil purchase contracts with producers and resold into various crude oil markets. Through these transactions, the Company effectively locked in a marketing fee equal to the difference between the sales price and the purchase price, less transportation costs. The crude oil marketing portfolio was essentially hedged whereby market risk, basis risk and quality differentials are mitigated or eliminated. The Company did not speculate with the crude oil marketing portfolio with the intent to generate profits from short-term market differences. Any accepted risk was from small differences in contract terms, index risk, or credit risk. Any risk that the Company identified was managed and mitigated within the guidelines stipulated in the Company’s risk policies.
With the adoption of EITF 02-3, the contracts entered into at the Company’s crude oil marketing operations either do not meet the definition of derivatives under SFAS 133 or have been exempted from mark-to-market accounting as normal purchase or normal sales contracts as allowed by SFAS 133. Accordingly, none of the contracts entered into in our crude oil marketing operations are marked-to-market.
The contract or notional amounts and terms of our crude oil contracts at December 31, are set forth below:
As of December 31, 2005 and 2004, all of the Company’s crude oil marketing contracts are accounted for under the accrual method of accounting.
Oil and Gas Exploration and Production
The Company produces natural gas and crude oil through its exploration and production activities. These natural “long” positions, or unhedged open positions, introduce commodity price risk and variability in its cash flows. The Company employs risk management methods to mitigate this commodity price risk and preserve cash flows. The Company has adopted guidelines covering hedging for its natural gas and crude oil production. These guidelines have been approved by the Company’s Executive Risk Committee, and are routinely reviewed by our Board of Directors.
To mitigate commodity price risk and preserve cash flows, over-the-counter swaps and options are used. These derivative instruments fall under the purview of SFAS 133 and the Company elects to utilize hedge accounting as allowed under this Statement.
At December 31, 2005 and 2004, the Company had a portfolio of swaps to hedge portions of its crude oil and natural gas production. These transactions were previously identified as cash flow hedges, properly documented and initially met prospective effectiveness testing. At year-end, these transactions met retrospective effectiveness testing criteria and retained their cash flow hedge status.
At December 31, 2005 and 2004, the derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives was reported in other comprehensive income and the ineffective portion was reported in earnings.
On December 31, 2005 and 2004 the Company had the following swaps and related balances (in thousands):
__________________________
*Crude in bbls, gas in MMBtu
Most of the Company’s crude oil and natural gas hedges are highly effective, resulting in very little earnings impact prior to realization. The Company estimates a portion of the unrealized earnings gains or losses currently recorded in accumulated other comprehensive income will be realized in earnings during 2006. Based on December 31, 2005 market prices, a $5.1 million loss will be realized and reported in earnings during 2006. These estimated realized losses for 2006 were calculated using December 31, 2005 market prices. Estimated and actual realized losses will likely change during 2006 as market prices change.
Electric Utility
On December 31, 2005, the Company had the following swaps and related balances (in thousands):
________________________
*gas in MMbtu
Based on December 31, 2005 market prices, a $0.2 million loss would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. These estimated realized losses for the next twelve months were calculated using December 31, 2005 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.
In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Consolidated Balance Sheet and the related unrealized gain/loss on the Consolidated Statement of Income. As of December 31, 2005, the market adjustments recorded in inventory were $(0.2) million.
Power Generation
The Company has a portfolio of natural gas fueled generation assets located throughout several western states. Most of these generation assets are locked into long-term tolling contracts with third parties whereby any commodity price risk is assumed by the third party. However, we do have some natural gas fueled generation assets under long-term contracts and a few merchant plants that do possess market risk for fuel purchases.
It is the Company’s policy that fuel risk, to the extent possible, be hedged. Since the Company is “long” natural gas in its exploration and production company, the Company looks at its enterprise wide natural gas market risk when hedging at the subsidiary level. Therefore, the Company attempts to hedge only enterprise wide “long” or “short” positions.
A potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. These short positions can arise from unplanned plant outages or from unanticipated load demands. To control such risk, the Company restricts wholesale off-system sales to amounts by which the Company’s anticipated generating capabilities exceed its anticipated load requirements plus a required reserve margin.
Financing Activities
The Company engages in activities to manage risks associated with changes in interest rates. The Company has entered into floating-to-fixed interest rate swap agreements to reduce its exposure to interest rate fluctuations associated with its floating rate debt obligations. At December 31, 2005, these hedges met effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2005, the Company had $163.0 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of 10 years and a fair value of $(0.3) million. These hedges are substantially effective and any ineffectiveness was immaterial. Of the $163.0 million of swaps, $88.0 million expired in January 2006.
On December 31, 2005 and 2004 the Company’s interest rate swaps and related balances were as follows (in thousands):
The Company anticipates a portion of unrealized losses recorded in accumulated other comprehensive income will be realized as increased interest expense in 2006. Based on December 31, 2005 market interest rates, less than $0.1 million will be realized as additional interest expense during 2006. Estimated and realized amounts will likely change during 2006 as market interest rates change.
At December 31, 2005, the Company had $292.5 million of outstanding, floating-rate debt of which $179.5 million was not offset with interest rate swap transactions that effectively convert a portion of the debt to a fixed rate. A 100 basis point increase in interest rates would cause annual interest expense to increase $2.2 million in 2006.
In June 2005, the Company repaid approximately $81.5 million of project level financing on its Fountain Valley power facility. The Company has an interest rate swap with a $25.0 million notional amount maturing in September 2006, that was previously designated as a cash flow hedge of the variable rate interest payments on this project level debt. In accordance with FAS 133, upon repayment of the debt the Company de-designated the interest rate swap as a cash flow hedge and reclassified approximately $0.3 million from Accumulated Other Comprehensive Loss into earnings as additional interest expense. Without hedge designation, future variability in the fair value of this derivative will be recorded as a gain or loss in earnings.
Foreign Exchange Contracts
The Company’s gas marketing subsidiary conducts its business in the United States as well as western Canada. Transactions in Canada are generally transacted in Canadian dollars and create exchange rate risk for the Company. To mitigate this risk, the Company enters into forward currency exchange contracts to offset earning volatility from changes in exchange rates between the Canadian and United States dollars. At December 31, 2005 and 2004, the Company had outstanding forward exchange contracts to sell approximately $29.0 million and $38.0 million Canadian dollars, respectively. At December 31, 2005 and 2004, the Company also had outstanding forward exchange contracts to purchase approximately $88.0 million and $10.8 million Canadian dollars, respectively. These contracts had a fair value of $(1.0) million at December 31, 2005 and 2004, and have been recorded as Derivative Assets/Liabilities on the accompanying Consolidated Balance Sheets. The Company recognized foreign exchange losses of $1.0 million and $1.4 million and foreign exchange income of $0.7 million for the years ended December 31, 2005, 2004 and 2003, respectively. All forward exchange contracts outstanding at December 31, 2005 settle by May 2006.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. The Company adopted the Black Hills Corporation Credit Policy (BHCCP) that establishes guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. In addition, the Company has a credit committee composed of senior executives that meets on a regular basis to review the Company’s credit activities and monitor compliance with the policies adopted by the Company.
For energy marketing, production, and generation activities, the Company attempts to mitigate its credit exposure by conducting its business primarily with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements, and securing credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.
The Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. The Company maintains a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.
At the end of the year, the Company’s credit exposure (exclusive of retail customers of our regulated utilities) was concentrated with investment grade companies. Approximately 82 percent of the credit exposure was with investment grade companies. For the 18 percent credit exposure with non-investment grade rated counterparties, approximately 79 percent of this exposure was supported through letters of credit, prepayments, parental guarantees or asset liens.
(3) INVESTMENTS IN ASSOCIATED COMPANIES
Included in Investments on the Consolidated Balance Sheets are the following investments that have been recorded on the equity method of accounting:
• A 12.6 percent, 6.9 percent 5.3 percent and 3.7 percent interest in Energy Investors Fund, L.P., Energy Investors Fund II, L.P., Project Finance Fund III, L.P., and Caribbean Basin Power Fund, Ltd., respectively, which in turn have investments in numerous electric generating facilities in the United States and elsewhere. During the fourth quarter of 2005, the Company wrote off goodwill of approximately $1.9 million, net of accumulated amortization of $0.3 million, related to increased partnership interest earned through fund performance triggered by “equity flips.” The Company recognized earnings for the value of its additional partnership equity and impaired the related goodwill. The Company’s carrying amount of its investment in the funds is $10.8 million and $10.5 million, as of December 31, 2005 and 2004, respectively. As of, and for the year ended December 31, 2005, the funds had assets of $124.2 million, liabilities of $1.4 million and net income of $34.4 million. As of, and for the year ended December 31, 2004, the funds had assets of $178.4 million, liabilities of $0.5 million and net income of $2.9 million.
The power funds in which the Company invests apply the provisions of the AICPA Audit and Accounting Guide, “Audits of Investment Companies.” This guidance among other things requires investments held by investment companies to be stated at fair value.
• 50 percent interest in two natural gas-fired cogeneration facilities located in Rupert and Glenns Ferry, Idaho. The Company’s carrying amount in the investment is $4.3 million and $3.6 million as of December 31, 2005 and 2004, respectively, which includes $0.6 million that represents the cost of the investment over the value of the underlying net assets of the projects. As of, and for the year ended December 31, 2005, these projects had assets of $19.4 million, liabilities of $11.4 million and net income of $1.1 million. As of, and for the year ended December 31, 2004, these projects had assets of $19.8 million, liabilities of $12.3 million and net income of $0.3 million.
(4)
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31, consisted of the following (in thousands):
_________________________
*
As part of the Common Use Transmission Open-Access Transmission Tariff FERC filing that was originally made in 2003, the majority of 69KV lines and substation costs have been reclassified from Transmission to Distribution assets.
(5)
JOINTLY OWNED FACILITIES
The Company’s subsidiary, Black Hills Power (BHP), owns a 20 percent interest and PacifiCorp owns an 80 percent interest in the Wyodak Plant (Plant), a 362 megawatt coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. BHP receives 20 percent of the Plant’s capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 2005, BHP’s investment in the Plant included $73.8 million in electric plant and $38.8 million in accumulated depreciation, and is included in the corresponding captions in the accompanying Consolidated Balance Sheets. BHP’s share of direct expenses of the Plant was $6.1 million, $6.0 million and $5.8 million for the years ended December 31, 2005, 2004 and 2003, respectively, and is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income. As discussed in Note 20, the Company’s coal mining subsidiary, Wyodak Resources, supplies PacifiCorp’s share of the coal to the Plant under an agreement expiring in 2022. This coal supply agreement is collateralized by a mortgage on and a security interest in some of Wyodak Resources’ coal reserves. Under the coal supply agreement, PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustment for planned outages. Wyodak Resources’ sales to PacifiCorp for the Plant were $18.1 million, $16.2 million and $18.7 million for the years ended December 31, 2005, 2004 and 2003, respectively.
BHP also owns a 35 percent interest and Basin Electric Power Cooperative owns a 65 percent interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie placed into service in the fourth quarter of 2003. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides the Company with access to both the Western Electricity Coordinating Council (WECC) region and the Mid-Continent Area Power Pool, or “MAPP” region. The total transfer capacity of the tie is 400 megawatts - 200 megawatts West to East and 200 megawatts from East to West. BHP is committed to pay 35 percent of the additions, replacements and operating and maintenance expenses. For the twelve months ended December 31, 2005 and 2004, BHP’s share of direct expenses was $0.2 million and $0.1 million, respectively. As of December 31, 2005, BHP’s investment in the transmission tie was $19.7 million, with $0.9 million of accumulated depreciation and is included in the corresponding captions in the accompanying Consolidated Balance Sheets.
The Company, through its subsidiary Black Hills Exploration and Production (BHEP), owns a 44.7 percent non-operating interest in the Newcastle Gas Plant (Gas Plant); a gas processing facility that gathers and processes approximately 3,000 MCF/day of gas, primarily from the Finn-Shurley Field in Wyoming. The Company receives its proportionate share of the Gas Plant’s net revenues and is committed to pay its proportionate share of additions, replacements and operating and maintenance expenses. As of December 31, 2005, the Company’s investment in the Gas Plant included $4.1 million in plant and equipment and $3.5 million in accumulated depreciation, and is included in the corresponding captions in the accompanying Consolidated Balance Sheets. The Company’s share of revenues of the Gas Plant was $3.1 million, $2.5 million and $1.7 million for the years ended December 31, 2005, 2004 and 2003, respectively. The Company’s share of direct expenses for the Gas Plant were $0.3 million, $0.3 million and $0.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. These items are included in the corresponding categories of operating revenues and expenses in the accompanying Consolidated Statements of Income.
(6)
VARIABLE INTEREST ENTITY
In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). In December 2003, the FASB issued FIN No. 46 (Revised) (FIN 46-R) to address certain FIN 46 implementation issues. The Company’s subsidiary, Black Hills Wyoming, has an agreement with Wygen Funding, Limited Partnership, an unrelated variable interest entity (VIE) to lease the Wygen I plant. Under the accounting interpretation, as amended, the Company consolidated the VIE effective December 31, 2003.
Prior to the December 31, 2003 consolidation, the Company recorded lease expense on the Wygen I plant. Lease payments began upon completion of the plant in February 2003. During the twelve month period ended December 31, 2003, lease payments were $2.7 million and are included in Operations and maintenance on the accompanying 2003 Consolidated Statement of Income. The net effect of consolidating the income statement of the VIE on December 31, 2003, was to recognize a cumulative effect charge for $2.5 million (net of $1.4 million of income taxes), which represents the depreciation and interest expense which would have been recorded had the VIE been consolidated at inception. The net effect on current results is to recognize depreciation and interest expense in place of recognizing lease expense. During the twelve month period ended December 31, 2005 and 2004, depreciation expense was $3.7 million and $3.4 million, respectively; and interest expense was $6.0 million and $3.6 million, respectively.
(7) LONG-TERM DEBT
Long-term debt outstanding at December 31 is as follows (in thousands):
_______________
(a)
In the fourth quarter of 2004, the Company’s electric utility called and refinanced $18.7 million of pollution control revenue bonds.
(b)
Floating rate debt, 86 percent secured by Gillette combustion turbine and 14 percent secured by a spare LM6000 turbine.
(c)
Interest rates are presented as of December 31, 2005.
(d)
The Company intends to exercise an available two-year extension in June 2006.
At December 31, 2005, approximately 39 percent, or $113.0 million, of the Company’s $292.5 million variable rate debt balance has been hedged with interest rate swaps converting floating rates to fixed rates with a weighted average interest rate of 4.43 percent (see Note 2).
Substantially all of the Company’s utility property is subject to the lien of the indentures securing its first mortgage bonds. First mortgage bonds of the utilities may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.
Project financing debt is debt collateralized by a mortgage on each respective project’s land and facilities, leases and rights, including rights to receive payments under long-term purchase power contracts. The Valmont and Arapahoe project debt is non-recourse debt. The Wygen I project debt is additionally guaranteed by the Company (see Note 21).
Certain debt instruments of the Company and its subsidiaries contain restrictions and covenants, all of which the Company and its subsidiaries were in compliance with, or issued waivers for, at December 31, 2005. Also, certain of the subsidiaries’ debt agreements provide that approximately $8.5 million of the subsidiaries’ cash balance at December 31, 2005 may not be distributed to the parent company.
Scheduled maturities of long-term debt for the next five years are: $11.8 million in 2006, $115.7 million in 2007, $132.5 million in 2008, $4.3 million in 2009 and $50.5 million in 2010.
(8)
NOTES PAYABLE
The Company has committed lines of credit with various banks totaling $400.0 million at December 31, 2005 and $350.0 million at December 31, 2004. The $400.0 million line of credit outstanding at December 31, 2005 is a revolving credit facility, which terminates May 4, 2010. The Company had $55.0 million of borrowings and $60.7 million of letters of credit and $24.0 million of borrowings and $44.6 million of letters of credit issued on the lines at December 31, 2005 and 2004, respectively. The Company has no compensating balance requirements associated with these lines of credit.
On May 5, 2005, we entered into a new $400.0 million revolving bank facility with ABN AMRO as Administrative Agent, Union Bank of California and US Bank as Co-Syndication Agents, Bank of America and Harris Nesbitt as Co-Documentation Agents, and other syndication participants. The new facility has a five year term, expiring May 4, 2010. The facility contains a provision which allows the facility size to be increased by up to an additional $100.0 million through the addition of new lenders, or through increased commitments from existing lenders, but only with the consent of such lenders. The cost of borrowings or letters of credit issued under the new facility is determined based on our credit ratings; at our current ratings levels, the facility has an annual facility fee of 17.5 basis points, and has a borrowing spread of 70.0 basis points over the LIBOR (which equates to a 5.09 percent one-month borrowing rate as of December 31, 2005). In conjunction with entering into the new revolving bank facility, we terminated our $125.0 million revolving bank facility due May 12, 2005 and our $225.0 million facility due August 20, 2006.
In addition to the above lines of credit, at December 31, 2005, Enserco Energy (Enserco) has a $200.0 million uncommitted, discretionary line of credit to provide support for the purchases of natural gas. The line of credit is secured by all of Enserco’s assets and expires on November 30, 2006. The Company has made a $3.0 million guarantee to the lender associated with the line of credit. At December 31, 2005 and 2004, there were outstanding letters of credit issued under the facility of $165.1 million and $91.7 million, respectively, with no borrowing balances on the facility.
Similarly, Black Hills Energy Resources, Inc. (BHER), our oil marketing unit, has maintained an uncommitted, discretionary credit facility. The facility allowed BHER to elect from $25.0 million up to $60.0 million of available credit via notification to the bank at the beginning of each calendar quarter. The line of credit provided credit support for the purchase of crude oil by BHER. At December 31, 2005, BHER had elected to have $50.0 million of available credit and had letters of credit outstanding of $48.5 million. On March 1, 2006, in conjunction with the sale of assets of BHER, the facility was terminated.
The credit facility and notes payable contain certain restrictive covenants including, among others, the maintenance of a fixed charge coverage ratio, a recourse debt-to-capitalization ratio and a total level of equity. At December 31, 2005, the Company and its subsidiaries were in compliance with, or issued waivers for, the debt covenants. These facilities do not contain default provisions pertaining to credit rating status.
(9) ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and was effective January 1, 2003. SFAS 143 requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. The Company has identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in our Oil and Gas segment, reclamation of our coal mining sites in our Coal mining segment and removal of fuel tanks and transformers containing PCB’s at the electric and gas utility segment. Cumulative accretion and accumulated depreciation has been recognized for the time period from the date the liability would have been recognized had the provisions of SFAS 143 been in effect, to the date of its adoption. Upon adoption, the Company recorded a $2.9 million transition adjustment to properly reflect its asset retirement obligations in accordance with the provisions of SFAS 143. The transition adjustment represents the current estimated fair value of the Company’s obligation to plug its oil and gas wells at the time of abandonment and an adjustment to its liability for reclaiming its coal mining sites following completion of mining activity.
The cumulative effect on earnings of adopting SFAS 143 in 2003 was a benefit of approximately $0.2 million representing the cumulative amounts of depreciation and changes in the asset retirement obligation due to the passage of time for historical accounting periods. The cumulative effect of initially applying SFAS 143 was recognized as a change in accounting principle.
The following table presents the details of the Company’s asset retirement obligations which are included on the accompanying Consolidated Balance Sheets in “Other” under “Deferred credits and other liabilities” (in thousands):
(10)
COMMON AND PREFERRED STOCK
Equity Compensation Plans
The Company has several employee equity compensation plans, which allow for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. The Company has 1,168,873 shares available to grant at December 31, 2005. The Company accounts for such plans under APB No. 25, and has adopted the disclosure-only provisions of SFAS 123. For a discussion of the effect on earnings and earnings per common share for the years ended December 31, 2005, 2004 and 2003, if the Company had applied SFAS 123 and recognized compensation expense for all outstanding and unvested stock options based on the fair value at the date of grant, see Note 1.
The Company has granted options with an option exercise price equal to the fair market value of the stock on the day of the grant. The options granted vest one-third each year for three years and expire after ten years from the grant date.
A summary of the status of the stock option plans at December 31, 2005, 2004 and 2003, and changes during the years then ended are as follows:
Details of outstanding options at December 31, 2005 are as follows:
The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model. The weighted average fair value of the options granted and the assumptions used to estimate the fair value of options are as follows:
In recent years, the Company maintained an Employee Stock Purchase Plan (ESPP) under which it sold shares to employees at 90 percent of the stock’s market price on the offering date. The Company issued 15,644 and 24,963 shares of common stock under the ESPP in 2004 and 2003, respectively. The Company discontinued the ESPP Plan in 2005.
The Company issued 2,594, 16,019 and 45,123 restricted stock units in 2005, 2004 and 2003, respectively, and 58,461, 34,828 and 24,643 restricted common shares, in 2005, 2004 and 2003, respectively. The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest one-third per year over three years, contingent on continued employment. Compensation cost related to the awards is recognized over the vesting period. The Company recognized pre-tax compensation cost related to the awards of $1.5 million in 2005, $1.7 million in 2004 and $0.9 million in 2003. The Company also issued 13,326 and 11,215 shares of common stock for the conversion of restricted stock units in 2005 and 2004.
Certain officers of the Company and its subsidiaries are participants in a performance share award plan. Performance shares are awarded based on the Company’s total shareholder return over designated performance periods as measured against a selected peer group. In addition, the Company’s stock price must also increase during the performance periods.
Target grants of performance shares were made for the following performance periods:
Grant Date
Performance Period
Target Grant of Shares
March 1, 2004
March 1, 2004 - December 31, 2005
15,548
March 1, 2004
March 1, 2004 - December 31, 2006
31,384
January 1, 2005
January 1, 2005 - December 31, 2007
41,499
Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50th percentile of the selected peer group. The final value of the performance shares may vary according to the number of shares of common stock that are ultimately granted based upon the performance criteria. Compensation expense recognized for the performance share awards was $1.5 million and $0.5 million for the years ended December 31, 2005 and 2004, respectively. The performance awards are paid in 50 percent cash and 50 percent common stock.
The Company issued 3,266, 10,310 and 3,075 shares of common stock in 2005, 2004 and 2003, respectively to certain key employees under the Short-term Annual Incentive Plan. The weighted average grant date fair value of the stock awards was $31.17, $31.10 and $23.10, respectively.
Dividend Reinvestment and Stock Purchase Plan
The Company has a Dividend Reinvestment and Stock Purchase Plan under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent of the recent average market price. The Company has the option of issuing new shares or purchasing the shares on the open market. The Company has been funding the Plan by the purchase of shares of common stock on the open market since June 2004. The Company issued 22,934 new shares in 2004 at a weighted average price of $30.41 and 94,346 new shares in 2003 at a weighted average price of $28.90. At December 31, 2005, 166,820 shares of unissued common stock were available for future offering under the Plan.
Other Common Stock Transactions
During 2003, the Company completed a public offering of its common stock through which 4.6 million shares were sold at $27 per share. Net proceeds were approximately $118.0 million after commissions and expenses. The proceeds were used to pay off a $50 million credit facility and to repay $68.0 million under the Company’s 364-day revolving credit facility, which expired on August 26, 2003. In addition, in 2003 the Company issued 481,509 shares and 45,000 warrants to purchase common stock in the acquisition of Mallon Resources Corporation (see Note 23).
During 2003, the Company issued a total of 12,575 common shares, as a stock bonus award to its non-officer employees. The bonuses were grossed up to cover related employee taxes. The total pre-tax compensation charge recognized by the Company was $0.3 million in 2003, which was based on the market value of the stock on the grant date.
Dividend Restrictions
The Company’s credit facility contains restrictions on the payment of cash dividends under a circumstance of default or event default. An event of default would be deemed to have occurred if the Company did not meet the financial covenant requirements for the facility. The most restrictive financial covenants include the following: fixed charge coverage ratio of not less than 2.5 to 1.0; a recourse leverage ratio not to exceed 0.65 to 1.00; and a minimum consolidated net worth of $625 million plus 50 percent of our aggregate consolidated net income since January 1, 2005. As of December 31, 2005, we were in compliance with the above covenants.
Treasury Shares Acquired
The Company acquired 2,771, 4,005 and 4,400 shares of treasury stock related to forfeitures of unvested restricted stock in 2005, 2004 and 2003, respectively, and 16,872, 7,508 and 3,119 shares related to the share withholding provisions of the restricted stock plan for the payment of taxes associated with the vesting of restricted shares in 2005, 2004 and 2003, respectively.
Preferred Stock
On July 7, 2005, the 6,839 outstanding shares of the company’s Preferred Stock Series 2000-A were automatically converted into 195,599 shares of the Company’s common stock. The preferred shares valued at $1,000 per share plus the accrued and unpaid dividends were converted into common shares based upon a $35.00 per share conversion price. No shares of preferred stock remain outstanding after this transaction.
(11)
FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company’s financial instruments are as follows (in thousands):
The following methods and assumptions were used to estimate the fair value of each class of the Company’s financial instruments.
Cash and Cash Equivalents and Restricted Cash
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 various instruments the Company uses and the valuation method employed are available in Note 2.
Notes Payable
The carrying amount approximates fair value due to their variable interest rates with short reset periods.
Long-Term Debt
The fair value of the Company’s long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. The Company’s outstanding first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for the Company to call and refinance the bonds.
(12)
CONTRACT TERMINATION REVENUE
During the third quarter of 2003, the Company completed a transaction terminating a fifteen year contract with Allegheny Energy Supply Company, LLC, a subsidiary of Allegheny Energy, Inc., for capacity and energy at the Company’s Las Vegas II power plant. The Company received a cash payment of $114.0 million, which is recorded as “Contract termination revenue” in the accompanying Consolidated Statements of Income. Operating results from the Las Vegas II power plant are included in the Power Generation segment.
(13) IMPAIRMENT OF LONG - LIVED ASSETS AND CAPITALIZED DEVELOPMENT COSTS
Due to a significant increase in the long-term forecasts for natural gas prices during the third quarter of 2005, the operation of the Company’s Las Vegas I gas-fired power plant (Las Vegas I) became uneconomic. Accordingly, the Company assessed the recoverability of the carrying value of Las Vegas I in accordance with the provisions of SFAS No. 144 “Accounting for the Impairment of Long-lived Assets” (SFAS 144).
Las Vegas I is a 53 megawatt, natural gas-fired, combined-cycle turbine operating under a contract as a qualifying facility as defined by the Public Utility Regulatory Policies Act of 1978. Under the contract, which extends through 2024, the Company sells capacity and energy to Nevada Power Company. Fuel requirements for the plant are not externally hedged and have been provided at market index prices under a long-term supply arrangement. While the Company’s oil and gas exploration and production operation produces gas sufficient to cover the plant’s fuel requirements thus providing an internal hedge, SFAS 144 requires the determination of asset impairment at each asset group which has separately identifiable cash flows.
The carrying value of the assets tested for impairment was $60.3 million. The assessment resulted in an impairment charge of $50.3 million to write down the related Property, plant and equipment by $44.7 million, net of accumulated depreciation of $11.1 million, and intangible assets by $5.6 million, net of accumulated amortization of $1.5 million. This charge reflects the amount by which the carrying value of the facility exceeded its estimated fair value determined by its estimated future discounted cash flows. This charge is included as a component of “Operating expenses” on the accompanying Consolidated Statements of Income. Operating results from Las Vegas I are included in the Power Generation segment.
During the fourth quarter of 2005, the Company wrote off goodwill of approximately $1.9 million, net of accumulated amortization of $0.3 million related to partnership “equity flips” at certain power fund investments. Upon the triggering of the “equity flips,” the Company recognized earnings for the value of its additional partnership equity and impaired the related goodwill.
In addition, during 2005, the Company recorded a $9.9 million pre-tax charge for the write-off and expensing of certain capitalized costs for various energy development projects determined less likely to advance, and costs related to unsuccessfully bid projects during the third quarter of 2005. These charges are included in Administrative and general on the accompanying 2005 Consolidated Statement of Income. The Company determined these projects were less likely to advance, due to reduced economic feasibility of gas-fired power generation in the expected sustained high-priced natural gas environment, increased expectations of reliance on renewable or coal-fired generation, and a perceived preference of utilities in certain regions to acquire existing merchant generation at significant discounts as an alternative to entering into contracts for capacity and energy from new generation. These costs had previously been capitalized as management believed it was probable that such costs would ultimately result in acquisition or construction of the projects. This charge is included as a component of Administrative and general costs in “Operating expenses” on the accompanying Consolidated Statements of Income. For segment reporting the development costs are included in Corporate results.
As a result of the 2003 contract termination discussed in Note 12, the Company assessed the recoverability of the carrying value of the Las Vegas II facility. The carrying value of the assets tested for impairment was $237.2 million. This assessment resulted in an impairment charge of $117.2 million to write down the related Property, plant and equipment by $83.1 million, net of accumulated depreciation of $5.1 million, and intangible assets by $34.1 million, net of accumulated amortization of $1.1 million. This charge reflects the amount by which the carrying value of the facility exceeded its estimated fair value determined by its estimated future discounted cash flows. This charge is included as a component of “Operating expenses” on the accompanying Consolidated Statements of Income. Operating results from the Las Vegas II power plant are included in the Power Generation segment.
(14)
GAIN ON SALE OF ASSETS
On March 1, 2004, the Company’s subsidiary, Daksoft, Inc., sold assets used in its campground reservation system. The Company recorded a pre-tax gain on the sale of the assets of $1.0 million, which is included as an offset to Operating expenses, Administrative and general on the accompanying Consolidated Statement of Income. Prior to this sale, for segment reporting (see Note 22) results of operations for Daksoft were included in the Communications segment. As Daksoft now primarily provides information technology support to the Company, its results are included in “Corporate” for segment reporting.
(15)
OPERATING LEASES
The Company has entered into lease agreements relating to certain power plant land leases, office facility leases and storage agreements. Rental expense incurred under these operating leases was $0.9 million, $0.8 million and $0.8 million for the years ended December 31, 2005, 2004 and 2003, respectively.
The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):
$
1,810
1,456
1,429
1,324
Thereafter
10,774
$
17,496
(16) INCOME TAXES
Income tax expense from continuing operations for the years indicated was:
Foreign taxes represent Canadian income taxes incurred through the Company’s Canadian operations.
The temporary differences, which gave rise to the net deferred tax liability, were as follows:
The following table reconciles the change in the net deferred income tax liability from December 31, 2004 to December 31, 2005 to deferred income tax benefit:
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
At December 31, 2005, the Company had the following remaining net operating loss carryforwards which were acquired as part of the Mallon and Pepperell acquisitions (in thousands):
As of December 31, 2005, the Company had a valuation allowance of $1.5 million against these NOL carryforwards. Ultimate usage of these NOL’s depends upon the Company’s future tax planning and filings. If the valuation allowance is reduced due to higher than anticipated utilization of the NOL’s, the offsetting amount would reduce the Company’s financial reporting basis in its Mallon property.
In 2005, Canadian income tax returns were filed and accepted by Canada for the years of 1999 - 2003. Excess foreign tax credits were generated and are available to offset U.S. federal income taxes. At December 31, 2005, the Company had the following remaining foreign tax credit carryforwards (in thousands):
(17)
OTHER COMPREHENSIVE INCOME (LOSS)
The following table displays the related tax effects allocated to each component of Other Comprehensive Income (Loss) for the years ended December 31 (in thousands):
(18)
DISCONTINUED OPERATIONS
The Company accounts for its discontinued operations under the provisions of Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (SFAS 144). Accordingly, results of operations and the related charges for discontinued operations have been classified as “(Loss) income from discontinued operations, net of income taxes” in the accompanying Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis.
Sale of Black Hills FiberSystems
On April 20, 2005, the Company entered into an agreement to sell its Communications business, Black Hills FiberSystems, Inc. to PrairieWave Communications, Inc. and completed the sale on June 30, 2005. Under the purchase and sale agreement, the Company received a cash payment of approximately $103 million.
Revenues and net income (loss) from the discontinued operations at December 31 are as follows (in thousands):
Assets and liabilities of the discontinued operations are as follows (in thousands):
Sale of Pepperell Plant
During the third quarter of 2003, the Company adopted a plan to sell the 40 megawatt gas-fired Pepperell plant. On April 8, 2005, the Company sold the Pepperell plant to an unrelated party for a nominal amount plus the assumption of certain obligations. The sale of this facility was considered an asset sale and the Company retained the deferred tax asset, which was originally classified into Discontinued operations. For business segment reporting purposes, the Pepperell plant results were previously included in the Power generation segment.
Revenues and net income from the discontinued operations during the years ended December 31, are as follows:
Assets and liabilities of the discontinued operations at December 31 are as follows (in thousands):
Sale of Landrica Development Corp.
On May 21, 2004, the Company sold its subsidiary, Landrica Development Corp. Landrica’s primary assets consisted of a coal enhancement plant and land. The purchaser made a $0.5 million cash payment to the Company and assumed a $2.9 million reclamation liability. The sale resulted in a $2.1 million after-tax gain. For segment reporting purposes, Landrica was previously included in the Coal mining segment.
Net income from the discontinued operations at December 31, is as follows (in thousands):
Sale of Hydroelectric Assets
On September 30, 2003 the Company sold its seven hydroelectric power plants located in Upstate New York. For business segment reporting purposes, the hydroelectric power plants results were previously included in the Power generation segment.
Revenues and net income from the discontinued operations at December 31 are as follows (in thousands):
Sale of Coal Marketing Subsidiary
In July 2002, the Company disposed of its coal marketing subsidiary, Black Hills Coal Network.
Net income from the discontinued operation at December 31, is as follows (in thousands):
(19) EMPLOYEE BENEFIT PLANS
Defined Contribution Plans
The Company sponsors two 401(k) savings plans. The Black Hills Corporation Retirement Savings Plan is for eligible employees of the Company and its subsidiaries, but excluding the employees of Cheyenne Light. The Cheyenne Light, Fuel and Power Company Retirement Savings Plan is for eligible employees of Cheyenne Light. For both plans, participants may elect to invest up to 20 percent of their eligible compensation on a pre-tax basis up to maximum amounts established by the Internal Revenue Service. The Black Hills Corporation plan provides a matching contribution of 100 percent of the employee’s annual tax-deferred contribution up to a maximum of 3 percent of eligible compensation. Matching contributions vest at 20 percent per year and are fully vested when the participant has 5 years of service with the Company. The Cheyenne Light plan provides for two matching formulas depending on status as a bargaining unit employee or as a non-bargaining unit employee. Bargaining unit employees receive a maximum match of 5 percent of eligible compensation based upon the following formula: 100 percent of the employee’s tax-deferred contribution on the first 3 percent of eligible compensation, plus 50 percent of the next 4 percent of eligible compensation. Non-bargaining unit employees receive a maximum match of 4 percent of eligible compensation based upon the following formula: 100 percent of the employee’s tax-deferred contribution on the first 3 percent of eligible compensation, plus 50 percent of the next 2 percent of eligible compensation. Matching contributions under both formulas are immediately 100 percent vested. In addition, the Cheyenne Light plan provides for a profit sharing contribution for certain eligible Cheyenne Light employees equal to 3.5 percent to 10 percent of eligible compensation, depending on age and years of service. Profit sharing contributions become 100 percent vested after completion of 5 years of service. The Black Hills Corporation Retirement Savings Plan matching contributions were $1.5 million for 2005, $1.4 million for 2004 and $1.4 million for 2003. The Cheyenne Light Retirement Savings Plan matching contributions were $0.2 million for the initial plan year of 2005. The Cheyenne Light plan profit sharing contribution was $0.2 million for the initial plan year of 2005.
Defined Benefit Pension Plan
The Company has two noncontributory defined benefit pension plans (the Pension Plans). The Pension Plan of Black Hills Corporation (BHC Pension Plan) covers the employees of the Company and the employees of the subsidiaries Black Hills Power, Wyodak Resources Development Corp., and Black Hills Exploration and Production 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. The Cheyenne Light, Fuel and Power Company Pension Plan (Cheyenne Light Pension Plan) covers the employees of the Company’s subsidiary, Cheyenne Light, who meet certain eligibility requirements. The benefits for the bargaining unit employees of Cheyenne Light are based on years of service and compensation levels during the highest three consecutive 12-month periods of service, reduced by the vested New Century Accrued Pension Benefits, if any. The benefits for non-bargaining unit employees of Cheyenne Light are based on annual credits for each year of service plus investment credits. The Company’s funding policy is in accordance with the federal government’s funding requirements. The BHC Pension Plans’ assets are held in trust and consist primarily of equity securities and cash equivalents. At December 31, 2005, the Cheyenne Light Pension Plan had no assets. The Company uses a September 30 measurement date for the Pension Plans.
The BHC 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 Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from long-term historical returns for the asset class, with adjustments if it is anticipated that long-term future returns will not achieve historical results.
The expected long-term rate of return for equity investments was 9.5 percent and 10.0 percent for the 2005 and 2004 plan years, respectively. For determining the expected long-term rate of return for equity assets, the Company reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2005, 11.8 percent, 12.5 percent, 10.1 percent and 10.3 percent, respectively. Fund management fees were estimated to be 0.18 percent for S&P 500 Index assets and 0.45 percent for other assets. The expected long-term rate of return on fixed income investments was 6.0 percent; the return was based upon historical returns on 10-year treasury bonds of 7.0 percent from 1962 to 2005, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 4.0 percent; expected cash returns were estimated to be 2.0 percent below long-term returns on intermediate-term bonds.
Plan Assets
Percentage of fair value of BHC Pension Plan assets at September 30:
Domestic equity
52.9%
59.7%
Foreign equity
40.6
34.5
Fixed income
3.4
2.6
Cash
3.1
3.2
Total
100.0%
100.0%
The BHC Pension Plan’s investment policy includes a target asset allocation as follows:
Asset Class
Target Allocation*
US Stocks
60% (with a variance of no more or less than 10% of target)
Foreign Stocks
30% (with a variance of no more or less than 10% of target)
Fixed Income
5% (with a variance of no more than 10% or no less than 5% of target)
Cash
5% (with a variance of no more than 10% or no less than 5% of target)
_________________________
*
The BHC Pension Plan’s investment policy has been modified for 2006 to target an allocation of 50 percent U.S. stocks, 25 percent foreign stocks and 25 percent fixed income.
The BHC Pension Plan’s investment policy includes the investment objective that the achieved long-term rate of return meet or exceed the assumed actuarial rate. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity-based assets. The policy provides that the BHC Pension Plan will maintain a passive core U.S. Stock portfolio based on a broad market index. Complementing this core will be investments in U.S. and foreign equities through actively managed mutual funds.
The policy contains certain prohibitions on transactions in separately managed portfolios in which the BHC Plan may invest, including prohibitions on short sales and the use of options or futures contracts. With regard to pooled funds, the policy requires the evaluation of the appropriateness of such funds for managing BHC Pension Plan assets if a fund engages in such transactions. The BHC Pension Plan has historically not invested in funds engaging in such transactions.
Cash Flows
The Company has made a $1.2 million contribution to the Cheyenne Light Pension Plan in the first quarter of 2006; no additional contributions are anticipated to be made to the BHC Pension Plan or to the Cheyenne Light Pension Plan during the 2006 fiscal year.
Supplemental Nonqualified Defined Benefit Retirement Plans
The Company has various supplemental retirement plans for key executives of the Company. The Plans are nonqualified defined benefit plans. The Company uses a September 30 measurement date for the Plans.
Plan Assets
The Plans have no assets. The Company funds on a cash basis as benefits are paid.
Estimated Cash Flows
The estimated employer contribution is expected to be $0.7 million in 2006. Contributions are expected to be made in the form of benefit payments.
Non-pension Defined Benefit Postretirement Plan
The Company sponsors two retiree healthcare plans (collectively, the Plans): the Black Hills Corporation Postretirement Healthcare Plan and the Healthcare Plan for Retirees of Cheyenne Light, Fuel and Power Company. Employees who are participants in the Black Hills Corporation Postretirement Healthcare Plan and who retire from the Company on or after attaining age 55 after completing at least five years of service with the Company are entitled to postretirement healthcare benefits. Employees who are participants in the Healthcare Plan for Retirees of Cheyenne Light, Fuel and Power Company and who retire from Cheyenne Light on or after attaining age 55 and after completion of a number of consecutive years of service, which when added to the employee’s age totals 90, are entitled to postretirement healthcare benefits. The benefits for both plans are subject to premiums, deductibles, co-payment provisions and other limitations. The Company may amend or change either plan periodically. The Company is not pre-funding either retiree healthcare plan. The Company uses a September 30 measurement date for both Plans.
It has been determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The effect of the Medicare Part D subsidy on the accumulated postretirement benefit obligation for the 2005 fiscal year, was an actuarial gain of approximately $2.0 million. The effect on 2006 net periodic postretirement benefit cost will be a decrease of approximately $0.3 million.
Plan Assets
The Plans have no assets. The Company funds on a cash basis as benefits are paid.
Estimated Cash Flows
The estimated employer contribution is expected to be $0.2 million in 2006. Contributions are expected to be made in the form of benefit payments.
The following tables provide a reconciliation of the Employee Benefit Plan’s obligations and fair value of assets for 2005 and 2004, a statement of funded status for 2005 and 2004 and components of the net periodic expense for the years ended 2005, 2004 and 2003.
Benefit Obligations
A reconciliation of the fair value of Plan assets (as of the September 30 measurement date) is as follows:
Funded Status
Amounts recognized in statement of financial position consist of:
___________________________
(a)
The provisions of SFAS 87 “Employers’ Accounting for Pensions” (SFAS 87) required the Company to record a net pension asset of $4.7 million and $10.1 million at December 31, 2005 and 2004, respectively. This amount is included in Other assets, Other on the accompanying Consolidated Balance Sheets.
(b)
The provisions of SFAS 87 required the Company to record a net pension liability of $13.8 million and $10.9 million at December 31, 2005 and 2004, respectively. This amount is included in Deferred credits and other liabilities, Other on the accompanying Consolidated Balance Sheets.
Components of Net Periodic Expense
Additional Information
Assumptions
_____________________________
*The expected rate of return on plan assets was changed from 9.0 percent in 2005 to 8.5 percent for the calculation of the 2006 net periodic pension cost. This change is expected to increase pension expense in 2006 by approximately $0.3 million.
The healthcare trend rate assumption for 2005 fiscal year benefit obligation determination and 2006 fiscal year expense is 11 percent for 2005 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2011. The healthcare cost trend rate assumption for the 2004 fiscal year benefit obligation determination and 2005 fiscal year expense was 12 percent for 2004 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2011.
The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1 percent increase in the healthcare cost trend assumption would increase the service and interest cost $0.4 million or 26 percent and the accumulated periodic postretirement benefit obligation $3.0 million or 21 percent. A 1 percent decrease would reduce the service and interest cost by $0.3 million or 20 percent and the accumulated periodic postretirement benefit obligation $2.3 million or 16 percent.
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
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COMMITMENTS AND CONTINGENCIES
Variable Interest Entity
The Company’s subsidiary, Black Hills Wyoming, has an Agreement for Lease and Lease with Wygen Funding, Limited Partnership (the variable interest entity) for the Wygen I plant. The Company is considered the “primary beneficiary” and therefore the variable interest entity has been consolidated by the Company into the accompanying consolidated financial statements (see Note 6). The initial term of the lease is five years, with two five-year renewal options, and includes a purchase option equal to the adjusted acquisition cost. The adjusted acquisition cost is essentially equal to the cost of the plant. At the end of each lease term, the Company may renew the lease, purchase the plant, or sell the plant on behalf of the variable interest entity, to an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the investors, the Company will be required to make a payment to the variable interest entity of the shortfall up to 83.5 percent of the adjusted acquisition cost, or approximately $111.1 million. The Company has guaranteed the obligations of Black Hills Wyoming to the variable interest entity. As discussed in Note 6, the Company has recorded the debt of the Variable Interest Entity on the Consolidated Balance Sheet, which was $128.3 million at December 31, 2005.
Power Purchase and Transmission Services Agreements - Pacific Power
In 1983, the Company entered into a 40 year power purchase agreement with PacifiCorp providing for the purchase by the Company of 75 megawatts of electric capacity and energy from PacifiCorp’s system. An amended agreement signed in October 1997 reduces the contract capacity by 25 megawatts (5 megawatts per year starting in 2000). The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants. Costs incurred under this agreement were $10.1 million in 2005, $10.0 million in 2004 and $10.8 million in 2003.
In addition, the Company has a firm network transmission agreement for 36 megawatts of capacity with PacifiCorp that expires on December 31, 2006. Annual costs are approximately $0.9 million per year. The Company uses this agreement to serve the Sheridan, Wyoming electric service territory under our contract with Montana-Dakota Utilities Company.
The Company also has a firm point-to-point transmission service agreement with PacifiCorp that expires on December 31, 2023. The agreement provides that the following amounts of capacity and energy be transmitted: 32 megawatts in 2001, 27 megawatts in 2002, 22 megawatts in 2003, 17 megawatts in 2004-2006 and 50 megawatts in 2007-2023. Costs incurred under this agreement were $0.4 million in 2005, $0.4 million in 2004 and $0.5 million in 2003.
Long-Term Power Sales Agreements
The Company, through its subsidiaries, has the following significant long-term power sales contracts:
• The Company has long-term power sales contracts with Public Service Company of Colorado (PSCo) for the output of several of its plants. All of the output of the Company’s Fountain Valley, Arapahoe and Valmont gas-fired facilities, totaling 450 megawatts, is included under the contracts which expire in 2012. The contracts are treated as leases under accounting principles generally accepted in the United States and establish capacity and availability payments over the lives of the contracts. The contracts are tolling arrangements in which the Company assumes no fuel price risk.
• The Company has a ten-year power sales contract with Cheyenne Light for the output of the 40 megawatt gas-fired Gillette CT, which expires August 2011. The Company assumes a portion of the fuel price risk under this agreement since the fuel price is fixed at the outset of each month and Cheyenne Light has the right to dispatch the facility on a day-ahead basis. The Company is permitted to remarket the energy that is not prescheduled by Cheyenne Light. This agreement has been temporarily assigned from Cheyenne Light to its former affiliate, PSCo, for the four-year term of Cheyenne Light’s all requirements power purchase agreement with PSCo, which expires December 31, 2007. The Company acquired Cheyenne Light on January 21, 2005 (see Note 23).
• The Company has a ten-year contract with Cheyenne Light for 60 megawatts of contingent capacity from the 90 megawatt Wygen I plant, which expires the first quarter of 2013. As with the Gillette CT contract, this agreement has been temporarily assigned to PSCo.
• The Company has a ten-year power sales contract with the Municipal Energy Agency of Nebraska (MEAN) for 20 megawatts of contingent capacity from the Neil Simpson Unit #2 plant. The contract expires in February 2013.
• The Company has a long-term contract for 45 megawatts of the output of the 53 megawatt Las Vegas I plant with Nevada Power Company (NPC) through 2024.
• The Company has a long-term contract to provide capacity and energy from the Las Vegas II plant to NPC. The contract became effective April 1, 2004 and expires December 31, 2013. The contract is a tolling arrangement whereby NPC is responsible for supplying natural gas. The Las Vegas II power plant, comprised of combined-cycle gas turbines, is rated at 224 megawatts. The power plant’s capacity and energy will be fully dispatchable by NPC to serve its retail load.
• The Company has entered into a tolling agreement with Southern California Edison for all of the capacity and energy from the Company’s gas-fired Harbor Cogeneration plant. The agreement commenced April 1, 2005 and expires May 31, 2008. Through October 2004, the facility sold capacity and energy under a seasonal agreement that ran from June through October of each year.
• The Company has a contract with Montana-Dakota Utilities Company, expiring January 1, 2007, for the sale of up to 55 megawatts of energy and capacity to service the Sheridan, Wyoming electric service territory. We entered into a new power purchase agreement with MDU for the supply of up to 74 megawatts of capacity and energy for Sheridan, Wyoming from 2007 through 2016, which is subject to regulatory approval by the WPSC. The Company also has a contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city’s first 23 megawatts of capacity and energy. The agreement renews automatically and requires a seven-year notice of termination. Both contracts are served by BHP and are integrated into its control area and are treated as part of the utility’s firm native load.
Transmission Services Agreement
The Company has a Firm Point-To-Point Transmission Service Agreement (TSA) with NPC related to the Las Vegas II power plant that expires April 30, 2008. The TSA provided transmission service in support of a Capacity and Ancillary Services Sale and Tolling Services Agreement with Allegheny Energy Supply Company, LLC (Allegheny), which was terminated in September 2003. On April 1, 2004, the Company’s new long-term tolling contract to provide capacity and energy from the Las Vegas II plant to NPC became effective. The Las Vegas II plant is interconnected with NPC’s transmission system through a step-up transformer owned by Las Vegas Cogeneration II, LLC, pursuant to an interconnection agreement on file with FERC. To the extent that transmission rights established under the TSA cannot be remarketed, costs under the agreement may not be recoverable. Payments under the TSA are approximately $3.9 million per year based on current tariffs. In its consideration and approval of the NPC tolling contract, the Nevada Public Utilities Commission established a linkage between the TSA and the tolling contract that results in the Company recognizing the costs of the TSA over the term of the tolling contract (10 years, $1.6 million per year) rather than the remaining term of the TSA (3.5 years, $3.9 million per year).
Reclamation Liability
Under its mining permit, Wyodak Resources is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land with an equivalent amount added to the asset costs. The asset is depreciated over the appropriate time period and the liability is accreted over time using an interest method of allocation. Approximately $0.6 million, $0.7 million and $0.6 million was charged to accretion expense for the years ended December 31, 2005, 2004 and 2003, respectively. Approximately $0.4 million, $0.5 million and $0.3 million was charged to depreciation expense for the years ended December 31, 2005, 2004 and 2003, respectively. Accrued reclamation costs included in Other in Deferred credits and other liabilities on the accompanying Consolidated Balance Sheets were approximately $16.0 million and $15.9 million at December 31, 2005 and 2004, respectively.
Legal Proceedings
Forest Fire Claims
In September 2001, a fire occurred in the southwestern Black Hills, now known as the “Hell Canyon Fire.” It is alleged that the fire occurred when a high voltage electrical span maintained by the Company’s electric utility, BHP, broke, and electrical arcing from the severed line ignited dry grass. The fire burned approximately 10,000 acres of land owned by the Black Hills National Forest, the Oglala Sioux Tribe, and other private landowners. The State of South Dakota initiated litigation against BHP, in the Seventh Judicial Circuit Court, Fall River County, South Dakota, on or about January 31, 2003. The Complaint seeks recovery of damages for alleged fire suppression and rehabilitation costs. A claim for treble damages is asserted with respect to the claim for injury to timber. A substantially similar suit was filed against BHP by the United States Forest Service, on June 30, 2003, in the United States District Court for the District of South Dakota, Western Division. The State subsequently joined its claim in the federal action. The State claims damages in the amount of approximately $0.8 million for fire suppression and rehabilitation costs. The United States Government’s claim for fire suppression and related costs has been submitted at approximately $1.3 million. A trial date has been set for late 2006. The Company has denied all claims and will vigorously defend this matter, the timing or outcome of which is uncertain.
On June 29, 2002, a forest fire began near Deadwood, South Dakota, now known as the “Grizzly Gulch Fire.” Before being contained more than eight days later, the fire consumed over 10,000 acres of public and private land, mostly consisting of rugged forested areas. The fire destroyed approximately 7 homes and 15 outbuildings. There were no reported personal injuries. In addition, the fire burned to the edge of the City of Deadwood, forcing the evacuation of the City of Deadwood, and the adjacent City of Lead, South Dakota. These communities are active in the tourist and gaming industries. Individuals were ordered to leave their homes, and businesses were closed for a short period of time. On July 16, 2002, the State of South Dakota announced the results of its investigation of the cause and origin of the fire. The State asserted that the fire was caused by tree encroachment into and contact with a transmission line owned and maintained by BHP.
On September 6, 2002, the State of South Dakota commenced litigation against BHP, in the Seventh Judicial Circuit Court, Pennington County, South Dakota. The Complaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages was asserted with respect to the claim for injury to timber.
On March 3, 2003, the United States of America filed a similar suit against BHP, in the United States District Court, District of South Dakota, Western Division. The federal government’s Complaint likewise seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A similar claim for treble damages is asserted with respect to the claim for injury to timber. In April 2003, the State of South Dakota intervened in the federal action. Accordingly, the state court litigation has been stayed, and all governmental claims will be tried in U.S. District Court.
The state and federal government claim approximately $5.3 million for suppression costs, $1.2 million for rehabilitation costs, and $0.6 million for timber loss. Additional claims could be asserted for alleged loss of habitat and aesthetics or for assistance to private landowners.
BHP completed its own investigation of the fire cause and origin and based upon information currently available, BHP filed its Answer to the Complaints of both the State and the United States government, denying all claims, and asserting that the fire was caused by an independent intervening cause, or an act of God. A trial date has been set for August 2006. The Company expects to vigorously defend all claims brought by governmental or private parties.
During the period of April 2003 through June 2005, various private civil actions were filed against BHP, asserting that the Grizzly Gulch Fire caused damage to the parties’ real property. These actions were filed in the Fourth Judicial Circuit Court, Lawrence County, South Dakota. The Complaints seek recovery on the same theories asserted in the governmental Complaints, but most of the Complaints specify no amount for damage claims. The Company will vigorously defend these matters as well.
Additional claims could be made for individual and business losses relating to injury to personal and real property, and lost income, all arising from the Grizzly Gulch Fire. A trial date has been set for August 2006.
Although we cannot predict the outcome or the viability of potential claims with respect to either fire, based on the information available, management believes that any such claims, if determined adversely to the Company, will not have a material adverse effect on the Company’s financial condition or results of operations.
PPM Energy, Inc. Demand for Arbitration
On January 2, 2004, PPM Energy, Inc. delivered a Demand for Arbitration to BHP. The demand alleges claims for breach of contract and requests a declaration of the parties’ rights and responsibilities under an Exchange Agreement executed on or about April 3, 2001. Specifically, PPM Energy asserts that the Exchange Agreement obligates BHP to accept receipt and cause corresponding delivery of electric energy, and to grant access to transmission rights allegedly covered by the Agreement. PPM Energy requests an award of damages in an amount not less than $20.0 million. BHP filed its Response to Demand, including a counterclaim that seeks recovery of sums PPM has refused to pay pursuant to the Exchange Agreement. The Company denies all claims. The dispute was presented to the arbitrator in August 2005. The Company cannot predict the outcome of the decision.
Price Reporting Class Actions
A.
Cornerstone Propane Partners, L.P.
On August 18, 2003, Cornerstone Propane Partners, L.P. commenced a putative class action lawsuit against over thirty energy companies. Cornerstone Propane Partners, L.P. v. Reliant Energy Services, Inc., et. al., Civ. No. 03-CV-6168 (U.S. District Court, Southern District of New York) (“Cornerstone Propane Litigation”). The Complaint, which names Black Hills Corporation and Enserco Energy Inc. as defendants, asserts claims for an unspecified amount of damages, based upon alleged violations of the Commodity Exchange Act. General allegations in the Complaint assert that defendants manipulated natural gas futures contracts through false reporting of prices and volumes. Similar specific allegations are made against Black Hills Corporation and Enserco, based upon claims that former traders at Enserco reported false price and volume information to trade publications. Other defendants are alleged to have manipulated spot market gas prices by engaging in “wash trades” and/or by “churning” natural gas trades. Initially, the plaintiff seeks an order certifying the proceeding as a class action according to applicable rules.
B.
Roberto E. Calle Gracey
On October 1, 2003, Roberto E. Calle Gracey commenced a putative class action lawsuit against a group of defendants that sets forth claims and demands similar to those described above with respect to the Cornerstone Propane Litigation. Black Hills Corporation and Enserco Energy, Inc. are named as defendants in this action as well. Gracey v. American Electric Power Company, Inc., et. al., Civ. No., 03-CV-7750 (U.S. District Court, Southern District of New York).
C.
In re Natural Gas Commodity Litigation
On December 5, 2003, the actions cited in paragraphs A and B were consolidated, with other actions involving similar claims against other parties, in a civil action captioned In re Natural Gas Commodity Litigation, 03 CV 6186(VM), United States District Court, Southern District of New York. All further proceedings relative to these matters will be conducted in the consolidated action. The consolidated class action now includes claims against a number of companies, based upon a variety of alleged misconduct. The claims against Enserco comprise a relatively small part of only one category of the total claims included in this lawsuit. Enserco denied all claims for damages, and joined in motions to dismiss, which were unsuccessful.
Notwithstanding the Company’s continued belief that the Class Plaintiffs present a flawed theory to recover actual damages as a result of the alleged conduct of former Enserco traders, in the third quarter of 2005 Enserco made a business decision to seek a settlement of claims made against it, due to mounting defense costs, and settlements by other defendant companies, which further increase the Company’s ongoing share of joint-defense expenses. In early October 2005, motions to certify the action to proceed as a class action were granted. On October 28, 2005, the Company reached a tentative settlement with Plaintiffs, pursuant to which the Company would pay $2.6 million in full and final settlement of all claims. The parties await approval of the final settlement documents. The accompanying 2005 consolidated financial statements include a $2.6 million accrual for the settlement.
Acquisition Earn-Out Agreement Lawsuit
On August 13, 2004, the former shareholders of Indeck Capital, Inc. (Indeck) commenced litigation against the Company in United States District Court, Northeastern District of Illinois, Eastern Division. The lawsuit concerns the Company’s performance of its obligation under the “Earn-out” provisions of the Agreement and Plan of Merger dated July 7, 2000, related to the Company’s acquisition of Indeck. Under the “Earn-out” provisions, the former shareholders of Indeck were entitled to receive “contingent merger consideration” for a four year period beginning in 2000. The “contingent merger consideration” was not to exceed $35.0 million and was based on the acquired company’s earnings over the four year period. As of December 31, 2004, $11.3 million has been either paid or offered for payment under the “Earn-out” provisions.
The lawsuit alleges that the Company failed to meet its obligation to produce documentation for its calculation of the contingent merger consideration, and in addition, failed to issue stock compensation in the full amount due to them. The Company denies these allegations and believes that it has fully and in good faith performed all of its obligations under the Agreement and Plan of Merger. In addition, the Company contends that the Agreement and Plan of Merger provides for mandatory arbitration as a medium for resolution of all disputes relating to the payment of contingent merger consideration. The federal court agreed, in part, with the Company’s views concerning arbitration, and ordered that certain issues be determined in that forum. Accordingly, the parties will select an arbitrator and will resolve the disputes on a dual track, with certain issues remaining with the federal court to resolve. The outcome of this matter is uncertain, as is the amount of contingent merger consideration that could be awarded following arbitration or litigation.
Ongoing Proceedings
The Company is subject to various other 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 the consolidated financial position or results of operations of the Company.
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GUARANTEES
The Company has entered into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees of debt obligations, contractual performance obligations and indemnification for reclamation and surety bonds.
As prescribed in FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45), the Company records a liability for the fair value of the obligation it has undertaken for guarantees issued after December 31, 2002.
As of December 31, 2005, the Company had the following guarantees in place (in thousands):
The Company has guaranteed up to $10.0 million of payments of its power generation subsidiary, Las Vegas Cogeneration Limited Partnership, to Sempra Energy Solutions which may arise from transactions entered into by the two parties under a Master Power Purchase and Sale Agreement. To the extent liabilities exist under this power and purchase sale agreement subject to this guarantee, such liabilities are included in the Consolidated Balance Sheets. The guarantee may be terminated by the Company for future transactions upon five days written notice.
The Company has guaranteed up to $3.0 million of Enserco Energy Inc.’s obligations to Fortis Capital Corp. and other lenders under its credit facility. There are no liabilities on the Company’s Consolidated Balance Sheets associated with this guarantee.
The Company has guaranteed up to $0.8 million of the obligations of Las Vegas Cogeneration II, LLC under an interconnection and operations agreement for the LV II unit. To the extent liabilities exist under the interconnection and operations agreement, such liabilities are included in the Consolidated Balance Sheets. The obligation is due November 20, 2006.
The Company has guaranteed up to $0.9 million of the obligations of its power generation subsidiary, Black Hills Colorado, to Union Bank of California related to the obligations of an interest rate swap transaction with a notional amount of $25.0 million and a fixed interest rate of 4.96 percent. The swap expires September 29, 2006. At December 31, 2005 we had a liability included on the Consolidated Balance Sheet of less than $0.1 million associated with this swap.
The Company has guaranteed up to $0.3 million of the obligations of its electric utility subsidiary, BHP, under various transactions with Idaho Power Company. To the extent liabilities exist under these transactions and subject to this guarantee, such liabilities are included in the Consolidated Balance Sheets. In February 2006, the expiration date of the guarantee was extended to March 1, 2007.
The Company has guaranteed the obligations of Black Hills Wyoming under the Agreement for Lease and Lease for the Wygen I plant. The Company consolidates the Variable Interest Entity that owns the plant into its financial statements; therefore the obligations associated with this guarantee are included in the Consolidated Balance Sheets. If the lease was terminated and sold, the Company’s obligation is the amount of deficiency in the proceeds from the sale to repay the investors up to a maximum of 83.5 percent of the cost of the project. At December 31, 2005, the Company’s maximum obligation under the guarantee is $111.0 million (83.5 percent of $133.0 million, the cost incurred for the Wygen I plant). The initial term of the lease expires in 2008, with two five-year renewal options.
The Company has guaranteed the payment of $22.5 million of debt of Black Hills Wyoming and $3.7 million of debt for another of the Company’s wholly-owned subsidiaries, Black Hills Generation. The debt is recorded on the Company’s Consolidated Balance Sheets and is due December 18, 2010.
The Company has guaranteed up to $5.0 million of payments of its power generation subsidiary, Las Vegas Cogeneration II, LLC under the Western Systems Power Pool Confirmation Agreement with Nevada Power Company. To the extent liabilities exist under the agreements subject to this guarantee, such liabilities are included in the Consolidated Balance Sheets. The guarantee expires upon payment in full of all the obligations under the contract, which expires in 2013.
In addition, at December 31, 2005, the Company had guarantees in place totaling approximately $5.4 million for reclamation and surety bonds for its subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in the Company’s Consolidated Balance Sheets.
(22)
BUSINESS SEGMENTS
The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of December 31, 2005, substantially all of the Company’s operations and assets are located within the United States. The Company’s operations are conducted through six business segments that include: Wholesale Energy consisting of: Coal mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region, Texas, California and other states; Energy marketing and transportation, which markets natural gas, oil and related services to customers in the Midwest, Southwest, Rocky Mountain, West Coast and Northwest regional markets; Power generation, which produces and sells power and capacity to wholesale customers primarily in the western United States; and Retail Services consisting of: Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana and Electric and gas utility, acquired January 21, 2005, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity.
On June 30, 2005, the Company completed the sale of its subsidiary, Black Hills FiberSystems, Inc., which operated as the Company’s Communication segment (see Note 18). The financial information of Black Hills FiberSystems, Inc. has been reclassified into Discontinued operations on the accompanying consolidated financial statements.
Prior to 2004, the Company’s communications segment also marketed campground reservation services and software development services to external parties through Daksoft, Inc. With the sale of certain assets and a change in its business strategy, Daksoft now primarily provides information technology support to the Company. With its focus now on corporate support, beginning with the first quarter 2004, Daksoft’s results of operations are included with corporate results.
(23)
ACQUISITIONS
Cheyenne Light, Fuel and Power
On January 13, 2004, the Company entered into a Stock Purchase Agreement to acquire from Xcel Energy, Inc. all of the outstanding capital stock of its subsidiary, Cheyenne Light. On January 21, 2005, the Company completed this acquisition. The Company purchased all the common stock of Cheyenne Light, including the assumption of outstanding debt of approximately $24.6 million, for approximately $90.7 million. The purchase price has been reduced to reflect final revisions to the estimated working capital included in the purchase payment on the date of the transaction closing.
This acquisition has been accounted for under the purchase method of accounting, and accordingly, the purchase price has been allocated to the acquired assets and liabilities based on estimates of the fair values of the assets purchased and liabilities assumed as of the date of acquisition. Allocation of the purchase price (as revised for the working capital adjustment described above) is as follows (in thousands):
Current assets
$
18,036
Property, plant and equipment
94,506
Deferred assets and goodwill
20,139
$
132,681
Current liabilities
$
12,546
Long-term debt
26,388
Deferred tax liabilities
7,408
Long-term liabilities
20,195
$
66,537
Net assets
$
66,144
The results of operations of Cheyenne Light have been included in the accompanying Consolidated Financial Statements since the acquisition date.
The following pro-forma consolidated results of operations have been prepared as if the Cheyenne Light acquisition had occurred on January 1, 2003 (in thousands):
The above pro-forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that would have been achieved had the acquisition been consummated at that time; nor is it intended to be a projection of future results.
Power Plant Ownership Interests
On December 31, 2005, the Company purchased the following power plant ownership interests:
• an additional 50 percent ownership interest in the Company’s Las Vegas I facility;
• an additional 50 percent ownership interest in the Company’s Ontario facility;
• a 50 percent interest in two 11 megawatt, gas-fired plants located in Rupert and Glenns Ferry, Idaho (the Idaho Cogeneration Facilities).
The Company previously held demand promissory notes and related purchase options for these ownership interests. On December 31, 2005, the Company exercised its purchase option on the ownership interests with cancellation of the related promissory notes as full consideration paid.
The transactions had no impact on the Company’s financial statements as prior to the transactions, under accounting principles generally accepted in the United States, the Company consolidated these ownership interests into our financial statements.
Mallon Resources Corporation
On October 1, 2002, the Company entered into a definitive merger agreement to acquire the Denver-based Mallon Resources Corporation. On March 10, 2003, the Company completed this acquisition.
The results of operations of the above acquired company have been included in the accompanying consolidated financial statements since the acquisition date.
The following pro forma consolidated results of operations for the year ended December 31, 2003 has been prepared as if the Mallon acquisition had occurred on January 1, 2003 (in thousands):
The above pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results.
(24) SUBSEQUENT EVENTS
Sale of Crude Oil Marketing and Transportation Assets
On January 5, 2006, the Company entered into a definitive agreement to sell the operating assets of its crude oil marketing and transportation business. The sale was completed on March 1, 2006. The Company received approximately $41.0 million of cash proceeds, which will be used for debt reduction or other corporate purposes. As a result of the transaction, the Company expects to record a gain on the sale. For business segment reporting purposes, Black Hills Energy Resources is included in the Energy marketing and transportation segment.
Revenues and net assets of the crude oil marketing and transportation business at December 31 are as follows (in thousands):
In conjunction with the sale of the operating assets of BHER, the $60.0 million uncommitted discretionary credit facility was terminated on March 1, 2006.
Acquisition
On March 6, 2006, the Company entered into a definitive agreement to acquire certain oil and gas assets of Koch Exploration Company, LLC. The assets include approximately 40 Bcfe of proved reserves, which are substantially all natural gas, and associated midstream and gathering assets. The acquisition is subject to further due diligence and is expected to close in the first quarter of 2006.
(25) OIL AND GAS RESERVES AND RELATED FINANCIAL DATA (Unaudited)
Black Hills Exploration and Production has operating and non-operating interests in 1,022 oil and gas properties in eleven states and holds leases on approximately 323,000 net acres.
Costs Incurred
Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the year ended December 31, (in thousands):
Reserves
The following table summarizes Black Hills Exploration and Production’s quantities of proved developed and undeveloped oil and natural gas reserves, estimated using constant year-end product prices, as of December 31, 2005, 2004 and 2003, and a reconciliation of the changes between these dates. These estimates are based on reserve reports by Ralph E. Davis Associates, Inc., an independent engineering company selected by the Company. Such reserve estimates are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
The 2005 reserve reconciliation reflected a 21.6 Bcfe downward revision to previous estimates. These downward revisions are primarily associated with the drilling and completion activities in the East Blanco Field, New Mexico. Approximately 60 percent of the downward revisions were primarily attributed to lower than expected production results from drilling activities conducted to further delineate the boundaries of the field. The lower reserves from the delineation wells, in turn, prompted revisions to previous reserve estimates (proved undeveloped and proved non-producing) for properties offsetting the delineation wells drilled in 2005.
Capitalized Costs
Following is information concerning capitalized costs for the years ended December 31, (in thousands):
Results of Operations
Following is a summary of results of operations for producing activities for the years ended December 31, (in thousands):
Standardized Measure of Discounted Future Net Cash Flows
Following is a summary of the standardized measure as prescribed in SFAS 69, of discounted future net cash flows and related changes relating to proved oil and gas reserves for the years ended December 31, (in thousands):
The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31, (in thousands):
(26) QUARTERLY HISTORICAL DATA (Unaudited)
The Company operates on a calendar year basis. The following table sets forth selected unaudited historical operating results and market data for each quarter of 2005 and 2004.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
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, 2005. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.
Internal control over financial reporting
Management’s Report on Internal Control over Financial Reporting is presented on page 80 of this Annual Report.
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.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding our directors and information required by Items 401 and 405 of Regulation S-K is incorporated herein by reference to the Proxy Statement for the Annual Shareholders’ Meeting to be held May 24, 2006.
Our Board of Directors has adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Corporate Controller, and certain other persons performing similar functions. In addition, we have adopted Corporate Governance Guidelines for the Board of Directors, a Code of Business Conduct for our employees and Charters for the Executive, Audit, Compensation and Governance Committees of the Board of Directors. The current version of these Corporate Governance Documents can be found on our Corporate Governance section of our Web site, http://www.blackhillscorp.com/corpgov.htm or a copy may be obtained without charge by contacting our Corporate Secretary. We intend to disclose any amendments to, or waivers of the Code of Ethics on behalf of our Chief Executive Officer, Chief Financial Officer, Corporate Controller, and persons performing similar functions, on our Internet website.
Information required by Item 401(b) of Regulation S-K is presented as Item 4A herein as permitted by General Instruction G(3) to Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Information regarding management remuneration and transactions is incorporated herein by reference to our Proxy Statement for the Annual Shareholders’ Meeting to be held May 24, 2006.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Information regarding the security ownership of certain beneficial owners and management and securities authorized for issuance under equity compensation plans is incorporated herein by reference to our Proxy Statement for the Annual Shareholders’ Meeting to be held May 24, 2006.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions is incorporated herein by reference to our Proxy Statement for the Annual Shareholders’ Meeting to be held May 24, 2006.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accounting fees and services is incorporated herein by reference to our Proxy Statement for the Annual Shareholder’s Meeting to be held May 24, 2006.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Black Hills Corporation
We have audited the consolidated financial statements of Black Hills Corporation and subsidiaries (the “Corporation”) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, management’s assessment of the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2005, and the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2005, and have issued our reports thereon dated March 13, 2006; such consolidated financial statements and reports are included in your 2005 Annual Report on Form 10-K and included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Corporation listed in Item 15(a)(2). The consolidated financial statement schedule is the responsibility of the Corporation’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 13, 2006
(a)
1.
Consolidated Financial Statements
Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.
2.
Schedules
Schedule II - Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2005, 2004 and 2003.
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 in our consolidated financial statements and notes thereto.
(a)
Recoveries
(b)
Uncollectible accounts written off
3.
Exhibits
Exhibit
Number
Description
2.1*
Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as Exhibit 2 to the Registrant’s Registration Statement on Form S-4 (No. 333-52664)).
3.1*
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3.1 to the Registrant’s Form 10-K for 2004).
3.2*
Amended and Restated Bylaws of the Registrant dated December 20, 2002 (filed as Exhibit 3.3 to the Registrant’s Form 10-K for 2002).
3.3*
Statement of Designations, Preferences and Relative Rights and Limitations of No Par Preferred Stock, Series 2000-A of the Registrant (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on December 26, 2000).
4.1*
Indenture dated as of May 21, 2003 between the Registrant and LaSalle Bank National Association, as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
4.2*
First Supplemental Indenture dated as of May 21, 2003 between the Registrant and LaSalle Bank National Association, as Trustee (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
4.3*
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 an exhibit to the Registrant’s Registration Statement on Form S-4 (No. 333-52664)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002).
4.4*
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
10.1*
Coal Leases between Wyodak Resources Development Corp. and the Federal Government
-Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10-K for 1989)
-Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10-K for 1989)
-Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10-K for 1989).
10.2*
Assignment of Mining Leases and Related Agreement effective May 27, 1997, between Wyodak Resources Development Corp. and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).
10.3*
Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant’s Form 10-K for 1999).
10.4*
Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002).
10.5*
Black Hills Corporation Nonqualified Deferred Compensation Plan dated June 1, 1999 (filed as Exhibit 10.13 to the Registrant’s Form 10-K for 2000). First Amendment to the Black Hills Corporation Nonqualified Deferred Compensation Plan dated April 29, 2003 (filed as Exhibit 10.6 to the Registrant’s Form 10-K for 2003).
10.6*
Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant’s Form 10-K for 1997).
10.7*
Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to the Registrant’s Form 10-K for 2000).
10.8*
Black Hills Corporation Omnibus Incentive Compensation Plan dated May 30, 2001 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2001).
10.9*
Black Hills Corporation 2005 Omnibus Incentive Plan (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005).
10.10*
Form of Stock Option Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 11, 2005).
10.11*
Form of Restricted Stock Award Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 11, 2005).
10.12*
Form of Restricted Stock Unit Award Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on July 11, 2005).
10.13*
Form of Performance Share Award Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on July 11, 2005).
10.14*
Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).
10.15*
Change in Control Agreement dated June 30, 2005 between Black Hills Corporation and David R. Emery (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 1, 2005).
10.16*
Form of Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 1, 2005).
10.17*
Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant’s Form 10-K for 1997). First Amendment to the Outside Directors Stock Based Compensation Plan (filed as Exhibit 10.13 to the Registrant’s Form 10-K for 2003). Second Amendment to the Outside Directors Stock Based Compensation Plan (filed as Exhibit 10.14 to the Registrant’s Form 10-K for 2003). Third Amendment to the Outside Directors Stock Based Compensation Plan (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on June 2, 2005).
10.18*
Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant’s Form 10-K for 1999).
10.19*
Employment Agreement dated December 20, 2002, by and between Black Hills Corporation, as employer, and Daniel P. Landguth as employee (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on December 23, 2002).
10.20*
Registration Rights Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 7 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.21*
Shareholders Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 8 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.22*
Credit Agreement, dated as of May 5, 2005 among Black Hills Corporation, as Borrower, the financial institutions from time to time party thereto as Banks, U.S. Bank, National Association, as Co-Syndication Agent, Union Bank of California, N.A., as Co-Syndication Agent, BANK OF AMERICA, N.A., as Co-Documentation Agent, BANK OF MONTREAL dba HARRIS NESBITT, as Co-Documentation Agent, and ABN AMRO Bank N.V. as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for March 31, 2005).
10.23*
Amended and Restated Credit Agreement dated as of May 14, 2004 among Enserco Energy, Inc., as Borrower, and Fortis Capital Corp., as administrative agent, collateral agent, documentation agent and arranger, and BNP Paribas, and U.S. Bank National Association and Societe Generale, and each other financial institution which may become a party hereto (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 6, 2004).
10.24*
First Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2004, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 6, 2004).
10.25*
Second Amendment to the Amended and Restated Credit Agreement made as of the 5th day of April, 2005, among Enserco Energy Inc. the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party thereto (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for September 30, 2005).
10.26*
Third Amendment to the Amended and Restated Credit Agreement made as of the 20th day of July 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party thereto (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for September 30, 2005).
10.27*
Fourth Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party thereto (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for September 30, 2005).
10.28
Fifth Amendment to the Amended and Restated Credit Agreement made as of the 30th day of November, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, U.S. Bank National Association, Societe Generale and UFJ Bank Limited.
10.29*
Stock Purchase Agreement between Xcel Energy, Inc., as “Seller” and Black Hills Corporation, as “Buyer,” dated January 13, 2004 (filed as Exhibit 2.1 to the Registrant’s Form 10-Q for March 31, 2004).
10.30*
Agreement for Lease between Wygen Funding, Limited Partnership and Black Hills Generation, Inc. dated as of July 20, 2001 (filed as Exhibit 10.31 to the Registrant’s Form 10-K for 2001).
10.31*
Amendment No. 1 dated as of December 20, 2001 to Agreement for Lease dated as of July 20, 2001 between Wygen Funding, Limited Partnership as Owner and Black Hills Generation, Inc., as Agent (filed as Exhibit 10.32 to the Registrant’s Form 10-K for 2001).
10.32*
Lease Agreement dated as of July 20, 2001 between Wygen Funding, Limited Partnership as Lessor and Black Hills Generation, Inc. as Lessee (filed as Exhibit 10.33 to the Registrant’s Form 10-K for 2001).
List of Subsidiaries of Black Hills Corporation.
23.1
Independent Auditors’ Consent.
23.2
Consent of Petroleum Engineer and Geologist.
31.1
Certification pursuant to Rule 13a - 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 pursuant to Rule 13a - 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification 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.

Indicates a board of director or management compensatory plan.
(b)
See (a) 3. Exhibits above.
(c)
See (a) 2. Schedules above.
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 CORPORATION
By/S/ DAVID R. EMERY
David R. Emery, Chairman, President and
Chief Executive Officer
Dated: March 16, 2006
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.
Chief Executive Officer
Chief Financial Officer
/S/ DAVID C. EBERTZ
Director
March 16, 2006
David C. Ebertz
/S/ JACK W. EUGSTER
Director
March 16, 2006
Jack W. Eugster
/S/ KAY S. JORGENSEN
Director
March 16, 2006
Kay S. Jorgensen
/S/ RICHARD KORPAN
Director
March 16, 2006
Richard Korpan
/S/ STEPHEN D. NEWLIN
Director
March 16, 2006
Stephen D. Newlin
/S/ WILLIAM G. VAN DYKE
Director
March 16, 2006
William G. Van Dyke
/S/ JOHN B. VERING
Director
March 16, 2006
John B. Vering
/S/ THOMAS J. ZELLER
Director
March 16, 2006
Thomas J. Zeller
INDEX TO EXHIBITS
Exhibit
Number
Description
2.1*
Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as Exhibit 2 to the Registrant’s Registration Statement on Form S-4 (No. 333-52664)).
3.1*
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3.1 to the Registrant’s Form 10-K for 2004).
3.2*
Amended and Restated Bylaws of the Registrant dated December 20, 2002 (filed as Exhibit 3.3 to the Registrant’s Form 10-K for 2002).
3.3*
Statement of Designations, Preferences and Relative Rights and Limitations of No Par Preferred Stock, Series 2000-A of the Registrant (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on December 26, 2000).
4.1*
Indenture dated as of May 21, 2003 between the Registrant and LaSalle Bank National Association, as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
4.2*
First Supplemental Indenture dated as of May 21, 2003 between the Registrant and LaSalle Bank National Association, as Trustee (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
4.3*
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 an exhibit to the Registrant’s Registration Statement on Form S-4 (No. 333-52664)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002).
4.4*
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
10.1*
Coal Leases between Wyodak Resources Development Corp. and the Federal Government
-Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10-K for 1989)
-Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10-K for 1989)
-Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10-K for 1989).
10.2*
Assignment of Mining Leases and Related Agreement effective May 27, 1997, between Wyodak Resources Development Corp. and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).
10.3*
Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant’s Form 10-K for 1999).
10. 4*
Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002).
10.5*
Black Hills Corporation Nonqualified Deferred Compensation Plan dated
June 1, 1999 (filed as Exhibit 10.13 to the Registrant’s Form 10-K for 2000). First Amendment to the Black Hills Corporation Nonqualified Deferred Compensation Plan dated April 29, 2003 (filed as Exhibit 10.6 to the Registrant’s Form 10-K for 2003).
10.6*
Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant’s Form 10-K for 1997).
10.7*
Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to the Registrant’s Form 10-K for 2000).
10.8*
Black Hills Corporation Omnibus Incentive Compensation Plan dated May 30, 2001 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2001).
10.9*
Black Hills Corporation 2005 Omnibus Incentive Plan (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005).
10.10*
Form of Stock Option Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 11, 2005).
10.11*
Form of Restricted Stock Award Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 11, 2005).
10.12*
Form of Restricted Stock Unit Award Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on July 11, 2005).
10.13*
Form of Performance Share Award Agreement for 2005 Omnibus Incentive Plan (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on July 11, 2005).
10.14*
Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).
10.15*
Change in Control Agreement dated June 30, 2005 between Black Hills Corporation and David R. Emery (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 1, 2005).
10.16*
Form of Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 1, 2005).
10.17*
Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant’s Form 10-K for 1997). First Amendment to the Outside Directors Stock Based Compensation Plan (filed as Exhibit 10.13 to the Registrant’s Form 10-K for 2003). Second Amendment to the Outside Directors Stock Based Compensation Plan (filed as Exhibit 10.14 to the Registrant’s Form 10-K for 2003). Third Amendment to the Outside Directors Stock Based Compensation Plan (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on June 2, 2005).
10.18*
Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant’s Form 10-K for 1999).
10.19*
Employment Agreement dated December 20, 2002, by and between Black Hills Corporation, as employer, and Daniel P. Landguth as employee (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on December 23, 2002).
10.20*
Registration Rights Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 7 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.21*
Shareholders Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 8 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.22*
Credit Agreement, dated as of May 5, 2005 among Black Hills Corporation, as Borrower, the financial institutions from time to time party thereto as Banks, U.S. Bank, National Association, as Co-Syndication Agent, Union Bank of California, N.A., as Co-Syndication Agent, BANK OF AMERICA, N.A., as Co-Documentation Agent, BANK OF MONTREAL dba HARRIS NESBITT, as Co-Documentation Agent, and ABN AMRO Bank N.V. as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for March 31, 2005).
10.23*
Amended and Restated Credit Agreement dated as of May 14, 2004 among Enserco Energy, Inc., as Borrower, and Fortis Capital Corp., as administrative agent, collateral agent, documentation agent and arranger, and BNP Paribas, and U.S. Bank National Association and Societe Generale, and each other financial institution which may become a party hereto (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 6, 2004).
10.24*
First Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2004, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 6, 2004).
10.25*
Second Amendment to the Amended and Restated Credit Agreement made as of the 5th day of April, 2005, among Enserco Energy Inc. the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party thereto (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for September 30, 2005).
10.26*
Third Amendment to the Amended and Restated Credit Agreement made as of the 20th day of July 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party thereto (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for September 30, 2005).
10.27*
Fourth Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party thereto (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for September 30, 2005).
10.28
Fifth Amendment to the Amended and Restated Credit Agreement made as of the 30th day of November, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, U.S. Bank National Association, Societe Generale and UFJ Bank Limited.
10.29*
Stock Purchase Agreement between Xcel Energy, Inc., as “Seller” and Black Hills Corporation, as “Buyer,” dated January 13, 2004 (filed as Exhibit 2.1 to the Registrant’s Form 10-Q for March 31, 2004).
10.30*
Agreement for Lease between Wygen Funding, Limited Partnership and Black Hills Generation, Inc. dated as of July 20, 2001 (filed as Exhibit 10.31 to the Registrant’s Form 10-K for 2001).
10.31*
Amendment No. 1 dated as of December 20, 2001 to Agreement for Leasedated as of July 20, 2001 between Wygen Funding, Limited Partnership asOwner and Black Hills Generation, Inc., as Agent (filed as Exhibit 10.32 tothe Registrant’s Form 10-K for 2001).
10.32*
Lease Agreement dated as of July 20, 2001 between Wygen Funding, Limited Partnership as Lessor and Black Hills Generation, Inc. as Lessee (filed as Exhibit 10.33 to the Registrant’s Form 10-K for 2001).
List of Subsidiaries of Black Hills Corporation.
23.1
Independent Auditors’ Consent.
23.2
Consent of Petroleum Engineer and Geologist.
31.1
Certification pursuant to Rule 13a - 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 pursuant to Rule 13a - 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification 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.

Indicates a board of director or management compensatory plan.