UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K

 

 

 

 

 

 

BLACK HILLS CORPORATION

 

 

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

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

 

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

 

 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.

 

 

Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.

 

 

Documents Incorporated by Reference

TABLE OF CONTENTS

 

 

 

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GLOSSARY OF TERMS

 

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

 

 

 

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Website Access to Reports

 

Through our Internet website, www.blackhillscorp.com, we make available free of charge our annual report on Form

10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

 

Safe Harbor for Forward-Looking Information

 

This Annual Report on Form 10-K includes “forward-looking statements” as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in Item IA. of this Form 10-K and in other reports that we file with the SEC from time to time, and the following:

 

 

 

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

 

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PART I

 

 

Overview

 

Black Hills Corporation, a South Dakota corporation, is a diversified energy company. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941 and began selling and marketing various forms of energy on an unregulated basis in 1956. We operate principally in the United States with two major business groups: Utilities and Non-regulated energy (previously referred to as Retail Services and Wholesale Energy, respectively).

 

Utilities Group

 

Our Utilities group conducts business in two segments:

 

Electric Utility. Through Black Hills Power, our electric utility segment, we engage in the generation, transmission and distribution of electricity to approximately 65,100 customers in South Dakota, Wyoming and Montana, and the sale of electric energy and capacity on a wholesale, or “off-system,” basis.

 

Combination Electric and Gas Utility. Through Cheyenne Light, our combination electric and gas utility segment, we engage in the distribution of electric and natural gas service and serve approximately 39,400 electric and 33,000 natural gas customers in Cheyenne, Wyoming and vicinity. We acquired Cheyenne Light on January 21, 2005.

 

Non-regulated Energy Group

 

Our non-regulated energy group, which operates through Black Hills Energy and its subsidiaries, conducts business in four segments:

 

Oil and Gas. BHEP and its subsidiaries acquire, develop and produce natural gas and crude oil primarily in the Rocky Mountain region of the United States.

 

Power Generation. Black Hills Generation and its subsidiaries and Black Hills Wyoming engage in the production and sale of electric capacity and energy through a diversified portfolio of generating plants in the Rocky Mountain and Western regions of the United States.

 

 

Energy Marketing. Enserco is engaged in the marketing of natural gas and crude oil primarily in the Western and Mid-continent regions of the United States and in Canada.

 

Recent Events

 

On February 7, 2007, we announced that we have entered into definitive agreements to acquire the assets of Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa along with the associated assets and liabilities for a total of $940 million in cash, subject to closing adjustments. This acquisition would significantly broaden our regional presence and retail utility base. The transaction would add a total of approximately 612,000 new utility customers (92,000 electric customers and 520,000 gas customers) to the 137,500 utility customers (104,500 electric customers and 33,000 gas customers) we currently serve. Other assets in the transaction include a customer service center and centralized natural gas operations in Nebraska.

 

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The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the assets of the regulated utilities to us. During October 2007, Great Plains and Aquila shareholders approved of the merger. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Utilities Commission, the Nebraska Public Service Commission, the Iowa Utilities Board and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions. We have filed all necessary applications for the state and federal regulatory reviews and approvals required for the proposed transaction. Thus far, we have obtained state regulatory approval for the transfer of ownership in Iowa, Nebraska and Colorado. In addition, during February 2008 settlements were reached with all parties to the proceedings in Kansas and are pending approval by the Kansas regulators. At the federal level, the FERC has approved our acquisition of the Colorado Electric operation, and antitrust clearance has been obtained from the Federal Trade Commission.

 

Segment Financial Information

 

Discussion of our business strategy as well as prospective information is included in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations. Financial information regarding the segments of Black Hills Corporation’s business is incorporated herein by reference to Item 8 – Financial Statements and Supplementary Data, Note 20 to the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

 

Utilities Group

 

Our Utilities group consists of two business segments – our regulated electric utility, Black Hills Power, and our regulated electric and gas utility, Cheyenne Light.

 

Properties and Agreements

 

Electric Utility Segment

 

Our regulated electric utility, Black Hills Power, is engaged in the generation, transmission and distribution of electricity. It provides us with a solid foundation of revenues, earnings and operating cash flows.

 

Distribution and Transmission. Black Hills Power’s distribution and transmission system serves approximately 65,100 electric customers, with an electric transmission system of 447 miles of high voltage transmission lines (greater than 69 KV) and 420 miles of lower voltage lines. In addition, Black Hills Power jointly owns 47 miles of high voltage lines with Basin Electric Cooperative. Black Hills Power’s service territory covers a 9,300 square mile area of western South Dakota, northeastern Wyoming and southeastern Montana with a strong and stable economic base. Approximately 90 percent of Black Hills Power’s retail electric revenues in 2007 were generated in South Dakota.

 

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The following are characteristics of Black Hills Power’s distribution and transmission businesses:

 

 

 

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Power Sales Agreements. A portion of Black Hills Power’s current load is sold under long term contracts. Key contracts include:

 

 

We integrate these consumers into Black Hills Power’s control area and consider them as part of our firm native load. Black Hills Power also provides 20 MW of energy and capacity to MEAN under a contract that expires in 2013. This contract is unit-contingent based on the availability of our Neil Simpson II plant.

 

Regulated Power Plants and Purchased Power. Black Hills Power’s electric load is primarily served by its generating facilities in South Dakota and Wyoming, which provide 435 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. Approximately 50 percent of Black Hills Power’s capacity is coal-fired, 39 percent is oil- or gas-fired, and 11 percent is supplied under the following purchased power and reserve capacity contracts with PacifiCorp:

 

 

The following table describes Black Hills Power’s portfolio of power plants:

 

 

 

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Ben French. Ben French is a wholly-owned coal-fired plant located in Rapid City, South Dakota, with a capacity of 25 MW. This plant began service in 1960 and operates as a baseload plant. The plant purchases coal delivered by truck from our WRDC coal mine.

 

Ben French Diesel Units 1-5. The Ben French Diesel Units 1-5 are wholly-owned diesel-fired plants located in Rapid City, South Dakota, with an aggregate capacity of 10 MW. These plants began service in 1965 and operate as peaking plants.

 

Ben French CTs 1-4. The Ben French CTs 1-4 are wholly-owned gas- and/or oil-fired units with an aggregate capacity of 100 MW located in Rapid City, South Dakota. These facilities began service from 1977 to 1979 and operate as peaking units.

 

Lange CT. The Lange CT is a wholly-owned 40 MW gas-fired plant located near Rapid City, South Dakota. The plant began service in 2002 and provides peaking capacity and voltage support for the area.

 

Neil Simpson I and II. Neil Simpson I and II are wholly-owned, air-cooled, coal-fired facilities located near Gillette, Wyoming. Neil Simpson I has a capacity of 21.8 MW and began service in 1969. Neil Simpson II has a capacity of 91 MW and began service in 1995. These mine-mouth plants receive their coal directly from our WRDC coal mine via conveyor and operate as baseload facilities.

 

Neil Simpson CT. The Neil Simpson CT is a wholly-owned gas-fired plant located near Gillette, Wyoming with a capacity of 40 MW. This plant began service in 2000 and supplies peaking capabilities.

 

Osage. The Osage plant is a wholly-owned coal-fired plant in Osage, Wyoming with a total capacity of 34.5 MW. This plant began service from 1948 to 1952. It has three turbine generating units and operates as a baseload plant. The plant purchases coal delivered by truck from our WRDC coal mine.

 

Wyodak. Wyodak is a 362 MW mine-mouth coal-fired plant owned 80 percent by PacifiCorp and 20 percent (or 72.4 net MW) by Black Hills Power. The WRDC coal mine furnishes all the coal fuel supply for the Wyodak plant. The plant, which is operated by PacifiCorp, began service in 1978 and operates as a baseload plant.

 

Rate Regulation. Rates for Black Hills Power’s retail electric service are subject to regulation by the SDPUC for customers in South Dakota, the WPSC for customers in Wyoming and the MTPSC for customers in Montana. Any changes in retail rates are subject to approval by the respective regulatory body. Black Hills Power has rate adjustment mechanisms in Montana and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. Black Hills Power is also subject to the jurisdiction of the FERC with respect to accounting practices and wholesale electricity sales. Black Hills Power has been granted market-based rate authority by the FERC and is not required to file cost-based tariffs for wholesale electric rates. Rates charged by Black Hills Power for use of its transmission system are subject to regulation by the FERC.

 

Combination Electric and Gas Utility Segment

 

Electric System. Cheyenne Light’s electric system serves approximately 39,400 customers in Cheyenne, Wyoming and vicinity, with a peak load of 171 MW and an average load of 114 MW. Power was supplied to Cheyenne Light under an all-requirements contract with PSCo, which expired at the end of 2007. For power needs subsequent to 2007, Cheyenne Light has a contract for 40 MW of energy and capacity from our Gillette CT, until August 2011, and 60 MW of energy and capacity from our Wygen I plant until the first quarter of 2013. Cheyenne Light also constructed a 95 MW coal-fired plant (Wygen II) adjacent to the WRDC coal mine near Gillette, Wyoming, which was placed into commercial service on January 1, 2008. In November 2006, Cheyenne Light entered into a 20-year agreement to purchase power provided by a new wind generation facility to be located near the City of Cheyenne, Wyoming. The agreement is anticipated to provide up to 30 MW of renewable power to Cheyenne Light beginning in September 2008. A portion of this renewable power may be contracted to Black Hills Power.

 

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Cheyenne Light and Black Hills Power are parties to an affiliate agreement whereby Cheyenne Light has the ability to sell excess energy from its generating resources to Black Hills Power. The transfer price under the agreement through the first quarter of 2013 is set at the variable cost of energy under Cheyenne Light’s wholesale contract with our Wygen I plant. The agreement became effective on January 1, 2008.

 

Natural Gas System. Cheyenne Light’s natural gas distribution system serves approximately 33,000 natural gas customers in the City of Cheyenne and other portions of Laramie County, Wyoming. Cheyenne Light purchases natural gas from independent suppliers for delivery to its retail customers. The natural gas supplies arrive at our delivery systems through a combination of transportation agreements with interstate pipelines and deliveries by suppliers directly to certain transportation customers. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at Cheyenne Light’s city gate meter station, and a small amount is received directly from wellhead sources.

 

Rate Regulation. Cheyenne Light is subject to the jurisdiction of the WPSC with respect to its facilities, rates, accounts, services and issuance of securities. Cheyenne Light is subject to the jurisdiction of FERC with respect to accounting practices and wholesale electricity sales. All electric demand, purchased power and transmission costs are recoverable through an ECA clause subject to WPSC jurisdiction. All purchased gas and transportation costs are recoverable through a GCA clause, also subject to WPSC jurisdiction. Differences between actual costs incurred and costs recovered in rates are deferred and recovered or refunded through prospective adjustments to rates. These ECA filings are made at least annually and GCA filings at least quarterly. We continually monitor these cost recovery levels and are allowed to file more frequently if there is a significant over or under-recovery of these costs. Rate changes for cost recovery require WPSC approval before going into effect.

 

In November 2007, the WPSC approved general rate increases of $6.7 million for electric rates and $4.4 million for natural gas rates to provide for increased costs of providing service. The allowed rate of return on equity is 10.9 percent based on a capital structure that is 54 percent equity and 46 percent debt. In addition, the electric rate increase includes placing the 95 megawatt, coal-fired Wygen II power plant into rate base. The WPSC also approved a new pass-through mechanism for Cheyenne Light’s electric business. For calendar years beginning in 2008, the annual increase or decrease for transmission, fuel, and purchased power costs is passed on to customers, subject to a $1.0 million threshold. Under its tariff, Cheyenne Light collects or refunds 95 percent of the increase or decrease that is in excess of the $1.0 million threshold. For changes in these costs that are less than the $1.0 million annual threshold, Cheyenne Light absorbs the increase and likewise retains the savings. The new rates and tariffs were effective January 1, 2008.

 

Business Characteristics

 

The following business characteristics are common within our Utilities Group:

 

Competition. Historically, electric and gas utilities were established as natural monopolies operating in highly regulated environments where they were obligated to provide electric and gas services to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return. Recently, the structure of the utility industry has been subject to change as a result of increased merger and acquisition activity, resulting in blended utilities with objectives to capture economies of scale or establish a strategic niche in preparing for the future.

 

Competition exists in varying degrees for our Utilities group. Established service territories still define our electric service area, but as the communities we serve continue to grow and expand, we encroach upon areas served by rural electric cooperatives. Our electric and gas utility faces some competition as certain industrial and large customers have the ability to own or operate facilities to generate their own electricity, and under some circumstances, choose their electricity provider. In addition, our electric utility competes with alternative forms of energy, such as natural gas. The primary factors we face in competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power.

 

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Legislative and regulatory activity could affect our operations in the future, although we cannot predict the substance or timing of these initiatives. The efforts by state and federal governing bodies to restructure the electric utility industry have moderated. There have been no recent legislative actions regarding electric retail choice in any of the states in which we operate, and the Company does not expect retail competition in the foreseeable future.

 

Our electric utility, like the electric industry generally, faces competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services. As a result, more generators may now participate in this market. The principal factors affecting competition for wholesale sales are price (including fuel costs), availability of capacity and energy, and reliability of service.

 

Regulation. We are subject to a broad range of federal, state and local energy and environmental laws and regulations, which significantly impact our business operations, including the following:

 

Energy Policy Act of 2005. EPA 2005 was signed into law on August 8, 2005. EPA 2005 repealed PUHCA effective February 8, 2006 and transferred oversight of public utility holding companies to FERC. The rules under EPA 2005 require us to register with FERC as a public utility holding company and impose record keeping requirements and provide for oversight of affiliate transactions and service company allocations. EPA 2005 also amended portions of the Federal Power Act and PURPA.

 

PURPA. The enactment of PURPA in 1978 provided incentives for the development of qualifying cogeneration facilities and small power production facilities that utilized certain alternative or renewable fuels, referred to as qualifying facilities, or QFs. With the enactment of EPA 2005, state regulators must consider standards for regulated utilities related to net metering, fuel diversity, fossil fuel generation efficiency, smart metering and interconnection for distributed resources.

 

Federal Power Act. The Federal Power Act gives FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must file tariffs and rate schedules with FERC prior to commencement of wholesale sales or interstate transmission of electricity. Public utilities are also subject to accounting, record-keeping and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their affiliates.

 

Environmental Regulation. We are subject to federal, state and local laws and regulations with regard to air and water quality, solid waste disposal, federal health and safety regulations, and other environmental matters. Environmental laws, regulations and issues affecting the Utilities group include, but are not limited to:

 

Clean Air Act. The Clean Air Act as well as state laws and regulations impacting air emissions affect all our generating units. Title IV of the Clean Air Act requires certain fossil-fuel-fired combustion devices to hold SO₂ “allowances” for each ton of sulfur dioxide emitted. Title IV applies to our Neil Simpson II, Neil Simpson CT, Lange CT, Wyodak and Wygen II plants. We currently hold sufficient allowances credited to us as a result of sulfur removal equipment previously installed at the Wyodak plant to apply to the operation of all units subject to Title IV through 2036, without requiring the purchase of any additional allowances. For future plants, we plan to comply with the need for holding the appropriate number of allowances by reducing SO₂ emissions through the use of low sulfur fuels, installation of “back end” control technology, use of banked allowances left over from our unused portion of Wyodak allowances, and if necessary, the purchase of allowances on the open market. We expect to integrate the cost of obtaining the required number of allowances needed for future projects into our overall financial analysis of such projects.

 

Title V of the federal Clean Air Act requires that all of our generation facilities obtain operating permits. All of our existing facilities subject to this requirement have received Title V permits.

 

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Clean Air Mercury Rule. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit overturned the EPA’s CAMR. CAMR established limits for mercury emissions from coal-fired power plants subject to Title IV of the Clean Air Act and created a market-based cap-and-trade program. The EPA is evaluating whether to appeal the decision or propose new rules. The effects of any new rules regarding mercury reduction cannot be determined at this time and may require us to make significant investments at our power generating facilities. The Wygen II plant, placed into commercial operation in January 2008, utilizes emissions control technology which reduces mercury emissions and is required under Title IV of the Clean Air Act to monitor mercury emissions.

 

Clean Water Act. Our facilities are subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through NPDES permits. All of our facilities required to have NPDES permits have those permits in place and are in compliance with discharge limitations. We are aware of no proposed regulations that will have a significant impact on our operations. Additionally, the EPA regulates surface water oil pollution prevention through its oil pollution prevention regulations. All of our facilities under this program have their required plans in place.

 

Toxic Substance Control Act. Under the federal Toxic Substance Control Act, the EPA has issued regulations that specify procedures for use, handling and disposal of PCBs. PCBs were widely used as insulating fluids in many electric utility transformers and capacitors manufactured before the Toxic Substance Control Act prohibited any further manufacture of PCB equipment. We remove and dispose of PCB-contaminated equipment in compliance with law as it is discovered.

 

Solid Waste Disposal. Under appropriate state permits, we dispose of all solid wastes collected as a result of burning coal at our power plants in approved solid waste disposal sites. Ash and wastes from flue gas and sulfur removal from the Wyodak, Neil Simpson I, Wygen II, Ben French and Neil Simpson II plants are deposited in mined areas at the WRDC coal mine. These disposal areas are located below some shallow water aquifers in the mine. The State of Wyoming is currently re-evaluating this practice and may, in the future, limit ash disposal to mined areas that are above future groundwater aquifers. This would increase costs, which cannot be quantified until the exact requirements are known. None of the solid wastes from the burning of coal are classified as hazardous material, but the wastes do contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. Investigations concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. Agreements in place require PacifiCorp to be responsible for any such costs related to the solid waste from its 80 percent interest in the Wyodak plant.

 

Additional unexpected material costs could also result in the future if any regulator determines that solid waste from the burning of coal contains some hazardous material that requires special treatment, including previously disposed solid waste. In that event, the government regulator could hold those entities that disposed of such waste responsible for such treatment.

 

U.S. Department of Homeland Security. Under regulations promulgated in November 2007, our facilities were required to review chemical inventories for comparison to certain reporting triggering thresholds, with a reporting due date of January 22, 2008. This exercise and required reporting has been completed. In 2008, the USDHS will contact us regarding a determination of any required security measures to be implemented.

 

Electric and Magnetic Fields. Research on potential adverse health effects from exposure to EMF continues. To date, no definite relationship between EMF and health risks has been clearly demonstrated. EMF remains the subject of ongoing studies and evaluations and the implications of any new reports have not yet been determined. These reports may raise the profile of the EMF issue for electric companies. We are monitoring the research but cannot predict the impact, if any, the EMF issue may have on the Company in the future.

 

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Global Climate Change and Renewable Energy Mandates. Many states have enacted, and others are considering, some form of mandatory renewable energy standard requiring utilities to meet certain thresholds for the production or use of renewable energy. Many states have also either enacted or are considering legislation setting greenhouse gas emissions reduction targets. Additionally, federal legislation for both renewable energy standards and greenhouse gas emission reductions are also under consideration. While currently there are no regulations controlling greenhouse gas emissions from our Black Hills Power and Cheyenne Light generation units and no renewable energy mandates for the regulatory jurisdictions in which our utilities operate, we believe that it is possible that such programs may be developed in the near future. We anticipate significant additional costs to comply with any federally or state mandated greenhouse gas reductions or limits on CO₂ emissions. In addition to legislative activity, climate change issues are the subject of a number of lawsuits whose outcomes could impact the utility industry.

 

Other requirements. We have incurred, and expect to continue to incur, substantial capital and operating and maintenance costs to comply with evolving environmental requirements primarily associated with the operations of our coal-fired generating units. While these evolving requirements will impact the operation of existing and new coal-fired and other fossil-fuel generating units, it is virtually certain that environmental requirements placed on the operations of these generating units will continue to become more restrictive.

 

Seasonality. Our electric utility and electric and gas utility business segments are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity is often greater in the summer and winter months for cooling and heating, respectively. Because our electric utility has a diverse customer and revenue base and we have historically optimized the utilization of our electric power supply resources, the impact on our operations may not be as significant when weather conditions are warmer in the winter and cooler in the summer in comparison to other investor-owned utilities. Conversely, natural gas is used primarily for residential and commercial heating, so the demand for this product depends heavily upon weather patterns throughout our service territories, and as a result, a significant amount of natural gas revenues are normally recognized in the heating season of the first and fourth quarters.

 

Risk Management. Our business operations require effective management of price, counterparty performance and operational risks. Price risk arises from the volatility of energy prices. Counterparty performance risk is the risk that a counterparty will fail to satisfy its contractual obligations to us and includes credit risk. Operational risk is the risk that we will be unable to perform on our contractual obligations to our counterparties. We have implemented controls to mitigate each of these risks.

 

A potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. Short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risks, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities exceed our anticipated load requirements plus a required reserve margin.

 

Non-regulated Energy Group

 

Our Non-regulated energy group, which operates through Black Hills Energy and its subsidiaries, produces and sells electric capacity and energy through ownership of a diversified portfolio of generating plants; produces coal, natural gas and crude oil primarily in the Rocky Mountain region; and markets and stores natural gas and crude oil. The Non-regulated energy group consists of four business segments for reporting purposes:

 

 

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Oil and Gas Segment

 

Our oil and gas segment, which operates through BHEP and its subsidiaries, acquires, explores for, develops and produces natural gas and crude oil which are then sold into the commodity markets. As of December 31, 2007, we held operating interests in oil and gas properties including approximately 628 gross and 572 net wells located in the San Juan Basin of New Mexico and Colorado, the Powder River and Big Horn Basins of Wyoming, the Piceance Basin of Colorado, and the Nebraska section of the Denver Julesberg Basin. In our San Juan and Piceance Basin operations, we also own and operate natural gas gathering pipeline systems along with associated gas compression and treating facilities. We hold non-operated interests in oil and natural gas properties including approximately 608 gross and 78 net wells located in California, Colorado, Louisiana, Montana, North Dakota, Oklahoma, Texas and Wyoming.

 

We own a 44.7 percent non-operated interest in the Newcastle gas processing plant and associated gathering system located in Weston County, Wyoming. The plant is adjacent to our producing properties in that area, where BHEP production accounts for the majority of the facility throughput. The plant is operated by Anadarko, Inc.

 

At December 31, 2007, we had total reserves of approximately 208 Bcfe, of which natural gas comprised 83 percent and oil comprised 17 percent of total reserves. The majority of our reserves are located in select oil and natural gas producing basins in the Rocky Mountain region. Approximately 37 percent of our reserves are located in the San Juan Basin of northwestern New Mexico, primarily in the East Blanco Field of Rio Arriba County, 22 percent are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field of Weston and Niobrara counties and 31 percent are located in the Piceance Basin of western Colorado.

 

Summary Oil and Gas Reserve Data

 

The following tables set forth summary information concerning our estimated proved developed and undeveloped oil and gas reserves and the 10 percent discounted present value of estimated future net revenues as of December 31, 2007 and 2006. The 2007 information is based on reports prepared by Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm located in Fort Worth, Texas. This is the first year Cawley, Gillespie & Associates, Inc. has served as the reserve auditor for BHEP. Ralph E. Davis Associates, Inc. prepared the reserve audit reports for the information presented as of December 31, 2006. Reserves were determined consistent with SEC requirements using year-end product prices, held constant for the life of the properties. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results.

 

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*Oil Bbls are multiplied by six to convert to Mcfe.

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The following table reflects average wellhead pricing used in the determination of the present value of estimated future net revenues, before tax:

 

 

 

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Drilling Activity

 

The following tables reflect the wells completed through our drilling activities for the last three years. In 2007, we participated in drilling 115 gross (37.84 net) development and exploratory wells, with a success rate of approximately 93 percent. A development well is a well drilled within a proved area of a reservoir known to be productive. An exploratory well is a well drilled to find and/or produce oil or gas in an unproved area, to find a new reservoir in a previously productive field or to extend a known reservoir. Gross wells represent the total wells we participated in, regardless of ownership interest, with net wells representing our fractional ownership interests within those wells.

 

 

 

 

As of December 31, 2007, we were participating in the drilling of 19 gross (3.4 net) wells, which had been commenced but not yet completed.

 

Recompletion Activity

 

Recompletion activities for the year ended December 31, 2007 were not material to the overall operations of this segment.

 

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Production

 

The following table presents certain information with respect to our net share of production attributable to our properties for the years ended December 31, as follows:

 

 

Productive Wells

 

The following table summarizes our gross and net productive wells at December 31, 2007:

 

 

Acreage

 

The following table summarizes our undeveloped, developed and total acreage by state as of December 31, 2007 (in thousands):

 

 

 

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Competition. The oil and gas industry is highly competitive. We compete with a substantial number of companies ranging from those that have greater financial resources, personnel, facilities and in some cases, technical expertise to the multitude of smaller, aggressive new start-up companies. Many of these companies explore for, produce and market oil and natural gas. The primary areas in which we encounter considerable competition are in recruiting and maintaining high quality staff, locating and acquiring leasehold acreage for drilling and development activity, locating and acquiring producing oil and gas properties, locating and obtaining sufficient drilling rig and contractor services and securing purchasers and transportation for the oil and natural gas we produce.

 

Seasonality of Business. Weather conditions affect the demand for, and prices of, natural gas and can also temporarily reduce production and delay drilling activities, which in turn impacts our overall business plan. The demand for natural gas is typically higher in the fourth and first quarters of our fiscal year, resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations on a quarterly basis may not reflect results which may be realized on an annual basis.

 

Regulation. We are subject to federal, state, tribal and local environmental, health and safety laws and regulations. Crude oil and natural gas development and production activities are subject to various laws and regulations governing a wide variety of matters, including, among others, prevention of waste, pollution standards and protection of the environment and wildlife resources, protection of historical artifacts and protection of public health, safety and welfare. Environmental laws and regulations are frequently changed and subject to interpretation and tend to become more onerous over time. Many governmental bodies have issued rules and regulations that can be difficult and costly to comply with, that create areas of overlap and ambiguity and that carry substantial penalties for non-compliance. The Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time, but that now require remedial work to meet ever-changing regulatory standards.

 

These regulations often require multiple permits and bonds to drill or operate wells, and establish rules regarding the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the timing of when drilling and construction activities can be conducted relative to various wildlife stipulations and the plugging and abandoning of wells. Our operations are also subject to various mineral conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration, when voluntary pooling of lands and leases cannot be accomplished. The effect of these regulations may limit the number of wells or the locations where we can drill.

 

We must comply with numerous and complex regulations governing activities on federal and state lands, notably the National Environmental Policy Act, the Endangered Species Act, the Resource Conservation and Recovery Act, the National Historic Preservation Act, the Clean Water Act and the Clean Air Act. In addition to these federal laws and associated regulations, each state we operate in has numerous laws in place with which we must also comply. The state of Colorado passed new laws in 2007 applicable to oil and natural gas development. These new laws included a complete restructuring of the Colorado Oil and Gas Conservation Commission and have charged the new commission with developing new oil and gas well permitting processes in 2008.

 

Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. Each Native American tribe is a sovereign nation possessing the power to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on tribal lands. One or more of these factors may increase the Company’s costs of doing business on tribal lands and impact the viability of its gas, oil and gathering operations on such lands.

 

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Environmental. Our operations are subject to various federal, state and local laws and regulations relating to the discharge of materials into, and the protection of the environment. We must account for the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures (such as spill prevention, control and countermeasure plans, storm water pollution prevention plans, state and federal air quality permits, underground injection control disposal permits), chemical storage and use and the remediation of petroleum-product contamination. Certain states, such as Colorado, have chosen to impose storm water requirements more strict than EPA’s and are taking a high profile in implementing and enforcing their requirements. We take a proactive role in working with these agencies to ensure compliance.

 

Under state and federal laws, we could also be required to remove or remediate previously disposed waste, including waste disposed of or released by us, or prior owners or operators, in accordance with current laws, or to otherwise suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. We generate waste that is already subject to the RCRA and comparable state statutes. The EPA and various state agencies limit the disposal options for those wastes. It is possible that certain oil and gas wastes which are currently exempt from treatment as RCRA wastes may in the future be designated as wastes under RCRA or other applicable statutes.

 

For additional information on our oil and natural gas operations, see Note 22 to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

Power Generation Segment

 

Our power generation segment, which operates through Black Hills Generation and subsidiaries and Black Hills Wyoming, acquires, develops and operates unregulated power plants. We currently hold varying interests in independent power plants in Colorado, Nevada, Wyoming, California and Idaho with a total net ownership of 978 MW as of December 31, 2007. We also hold minority interests in several power-related funds with a net ownership interest of 5.0 MW.

 

During 2007, we began construction of the Valencia generation facility. Valencia is a 149 MW simple-cycle gas turbine generating facility located near Albuquerque, New Mexico. The facility is expected to cost approximately $101.0 million to construct and is on schedule to commence commercial operations during the summer of 2008. If we fail to meet the required in-service date, significant penalties could be incurred under the “delay damage” provisions that are customary within agreements of this nature. We will provide the capacity and energy of the facility to Public Service Company of New Mexico under a 20-year power purchase agreement. The agreement is a customary tolling arrangement, where we receive variable and fixed fees for the plant’s availability and operation, and Public Service Company of New Mexico is responsible for providing fuel for the operation. The agreement also allows Public Service Company of New Mexico the option to acquire an equity interest of up to 50 percent in the facility.

 

We have recently initiated a review of strategic alternatives for our non-regulated power plants located in Colorado, Nevada, New Mexico and California. We may sell all, none or a combination of these assets and expect to make a decision on any possible sale during the second quarter of 2008. Separately, we are also considering selling a 20 MW undivided interest in the Wygen I plant. If we elect to sell this undivided interest, we intend to retain the remaining interest and continue operating control of the plant.

 

Portfolio Management. We maintain a geographically diverse portfolio of power plants in our Non-regulated energy group, with a focus on the western region of the United States. The fuel mix of our unregulated generation portfolio is approximately 91 percent natural gas-fired and 9 percent coal-fired. We sell capacity and energy under a combination of mid- to long-term contracts, which helps mitigate the impact of a potential downturn in power prices in the future. Currently, we sell approximately 99 percent of our unregulated generating capacity under contracts having terms greater than one year. We sell additional power into the wholesale power markets from our generating capacity when it is available and when it is economic to do so. We also mitigate our financial exposure in the power generation segment by selling a majority of our unregulated capacity and energy under “tolling” agreements, or agreements under

 

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which the power purchaser is responsible for supplying fuel for the facility, thus assuming fuel price risk. The contracted purchasers of capacity and energy from our facilities are load-serving utility companies.

 

Rocky Mountain and West Coast Facilities. As of December 31, 2007, we had approximately 978 net MW of name plate generating capacity in the WECC states of Colorado, Nevada, Wyoming, California and Idaho, as follows:

 

________________________

 

Fountain Valley, Arapahoe and Valmont Facilities. Our Fountain Valley, Arapahoe and Valmont plants are wholly-owned gas-fired peaking facilities in the Front Range of Colorado, with a total capacity of 450 MW. The Fountain Valley and Valmont facilities operate in simple cycle. The Arapahoe facility operates in combined cycle. We sell all of the output from these plants to PSCo under tolling contracts expiring in 2012.

 

Las Vegas Cogeneration Facilities. Our Las Vegas I facility is a 53 MW, combined-cycle, gas-fired plant northeast of Las Vegas, Nevada, and is a QF under PURPA. We sell 45 MW of power from this plant to NPC under a long-term contract that expires in 2024. Under the terms of the NPC contract, we assume the fuel price risk associated with the energy generation. The project also sells steam production to Windset Greenhouses (Nevada), Inc., under a one-year agreement that contains annual renewal provisions and currently expires on July 31, 2008. We have recently negotiated a long-term tolling agreement with NPC that, if approved by the PUCN, would replace our existing contract with NPC. The agreement is part of a stipulation currently scheduled to be reviewed by the PUCN during March 2008. Our Las Vegas II facility is a wholly-owned, 224 MW, combined-cycle, gas-fired plant that became operational early in 2003. The capacity and power from this plant is sold to NPC under a long-term tolling agreement, which expires December 31, 2013.

 

Gillette CT. The Gillette CT is a wholly-owned, simple-cycle, gas-fired combustion turbine located near Gillette, Wyoming at our power plant and coal mine complex. The Gillette CT has a total capacity of 40 MW and became operational in May 2001. Prior to our ownership of Cheyenne Light, we entered into a 10-year power purchase agreement with Cheyenne Light, which expires in August 2011, for the sale of energy and capacity from this facility. In connection with PSCo’s execution of an all-requirements power purchase agreement with Cheyenne Light, the Gillette CT power purchase agreement was temporarily assigned by Cheyenne Light to PSCo for the term of the all-requirements agreement, which expired December 31, 2007. Upon expiration of PSCo’s all-requirements power purchase agreement with Cheyenne Light, the Gillette CT power purchase agreement reverted back to Cheyenne Light.

 

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Wygen I Plant. The Wygen I plant is a mine-mouth, coal-fired plant with a total capacity of 90 MW, which commenced operations in 2003 and is located at our Gillette energy complex. Prior to ownership of Cheyenne Light, we entered into agreements to sell 60 MW of unit contingent capacity and energy from this plant to Cheyenne Light with a term of 10 years, expiring in the first quarter of 2013, and 20 MW of unit contingent capacity and energy to MEAN for a term of 10 years, expiring in the first quarter of 2013. As with the Gillette CT power purchase agreement, Cheyenne Light temporarily assigned the Wygen I power purchase agreement to PSCo for the term of its all-requirements power purchase agreement. The PSCo contract expired on December 31, 2007, and the output then reverted back to Cheyenne Light. We are the lessee of the Wygen I plant under a synthetic lease arrangement, but under accounting principles generally accepted in the United States, we consolidate the plant and its operating activity in our financial statements.

 

Harbor Cogeneration Facility. Harbor Cogeneration is a 98 MW, combined-cycle, gas-fired plant located at the Port of Long Beach, California. All of the capacity and energy of the facility is sold to SCE under a tolling agreement, which expires May 31, 2008. Subsequent to the expiration of this tolling agreement, we will sell energy from the facility on a merchant basis while we attempt to arrange a new long-term power sales agreement. Under a termination agreement with SCE pertaining to a long-term contract that was previously terminated, Harbor Cogeneration also receives payments pursuant to a schedule that ends on October 1, 2008. Termination payments are received on a quarterly basis and are expected to total $8.4 million in 2008.

 

Ontario Cogeneration Facility. Our Ontario facility, a QF, is a 12 MW, “Cheng-cycle,” gas-fired power plant in Ontario, California, which we currently operate as a baseload plant. Electrical output from the plant is sold under a 25-year power purchase agreement with SCE, which expires in May 2010. The project also sells steam production to Sunkist Growers, Inc. under a five-year agreement, which terminated in December 2007. In order to maintain QF status and the underlying power purchase agreement, the project must maintain a thermal energy host or obtain the required QF waivers. We are currently evaluating our options for maintaining QF status. We are also considering selling the plant’s allocated nitrous oxide RECLAIM Trading Credits for the period subsequent to the 2010 expiration of the SCE power purchase agreement. A sale of these emissions credits would increase the likelihood of retiring the plant by 2010.

 

Idaho Cogeneration Facilities. Through partnership investments, we own a 50 percent interest in two QFs in Rupert and Glenns Ferry, Idaho. Rupert and Glenns Ferry are both 11 MW, combined-cycle, gas-fired plants. We account for our investment in the partnerships under the equity method of accounting. Electrical output from the facilities is sold to Idaho Power Company under 20-year Energy Sales Agreements, which expire in late 2016. The facilities also sell steam production to Idaho Fresh-Pak, Inc. under Thermal Energy Service Agreements, which also expire in late 2016. Idaho Fresh-Pak, Inc. has recently provided notice to the facilities of their intent to cease operations and discontinue steam purchases. Such an action would likely have a material adverse effect on the facilities’ operations, including an inability to meet QF requirements and terms of related energy sales agreements.

 

Power Funds. In addition to our ownership of the power plants described above, we hold various indirect interests in power plants through our investment in energy and energy-related funds, both domestic and international, with a total net capacity of approximately 5.0 MW. We account for our investment in the funds under the equity method of accounting and as of December 31, 2007, we had a $3.0 million investment balance in the funds. The funds have been liquidating their investments in recent years. Accordingly, we expect our returns from these investment funds to diminish in the future.

 

 

 

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Project Development Program. We continue to pursue the acquisition or development of additional unregulated generation projects, ranging from the expansion of existing generating capacity, or “brownfield development,” to the acquisition or development of new generating facilities. Our primary geographic focus has been, and is likely to remain, in the North American Electric Reliability Council region known as the WECC. Among the factors we consider important in evaluating new or expanded generation opportunities are the following:

 

 

Our goal is to sell the capacity and energy from a substantial portion of the independent power generation portfolio under long-term contracts, while reserving the balance for merchant or spot sales. To mitigate fuel price risk, we prefer long-term contracts that are tolling agreements where our counterparty provides the required fuel. We seek long-term contracts with either utilities serving native customer loads under state utility commission-approved contracts, or other investment-grade counterparties.

 

Competition. The independent power industry is replete with strong and capable competitors, some of which may have more extensive operating experience, larger staffs or greater financial resources than we possess.

 

The FERC has implemented and continues to favor regulatory initiatives to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity and to enhance competition in wholesale electricity markets. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses. The pace of restructuring slowed significantly following public and governmental reactions to issues associated with deregulation efforts in California and the collapse of its wholesale electric energy market in 2001. In some instances, states are reevaluating their steps taken towards deregulation and have begun allowing utilities to reinvest in power generation assets.

 

EPA 2005 repealed PUHCA and transferred oversight of holding companies to FERC effective February 8, 2006. On December 8, 2005, FERC issued final rules under the Public Utility Holding Company Act of 2005, which were effective February 8, 2006. We cannot predict the long-term effect of such regulation or how FERC will interpret the new rules. As a result of these regulatory changes, significant additional competitors could become active in the utility, generation and power marketing segments of our industry.

 

Risk Management. Our business operations require effective management of price, counterparty performance and operational risks. Price risk arises from the volatility of energy prices. Counterparty performance risk is the risk that a counterparty will fail to satisfy its contractual obligations to us, and includes credit risk. Operational risk is the risk that we will be unable to perform on our contractual obligations to our counterparties. We have implemented controls to mitigate each of these risks.

 

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Regulation. We are subject to a broad range of federal, state and local energy and environmental laws and regulations which generally require that a wide variety of permits and other approvals be obtained before construction or operation of a project commences and that, after completion, the facility operates in compliance with such requirements, including the following:

 

Energy Policy Act of 2005. EPA 2005 repealed PUHCA effective February 8, 2006 and transferred oversight of public utility holding companies to FERC. The rules under EPA 2005 require us to register with FERC as a public utility holding company and impose record keeping requirements and provide for oversight of affiliate transactions and service company allocations. EPA 2005 amended portions of the Federal Power Act and also amended portions of the PURPA relating to QFs, including the elimination of ownership restrictions and a prospective repeal of the mandatory purchase and sale requirements for a QF if FERC finds that the QF has nondiscriminatory access to other markets.

 

The Energy Policy Act of 1992. The passage of the Energy Policy Act of 1992 encouraged independent power production by providing certain exemptions from regulation for EWGs. An EWG is an entity that is directly or indirectly, and exclusively, in the business of owning or operating, or both owning and operating, eligible facilities and selling electric energy at wholesale. An EWG is subject to FERC regulation, including rate regulation. All of our EWGs have been granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates. However, FERC customarily reserves the right to suspend, upon complaint, market-based rate authority on a prospective basis if it is subsequently determined that any of our EWGs exercised market power. If FERC were to suspend market-based rate authority for any of our EWGs, those EWGs most likely would be required to file, and obtain FERC acceptance of, cost-based power sales rate schedules. Also, the loss of market-based rate authority would subject the EWGs to the accounting, record keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules.

 

In addition, if a “material change” occurs that might affect any of our subsidiaries’ eligibility for EWG status, within 60 days of the material change, the relevant EWG must (1) file a written explanation of why the material change does not affect its EWG status, (2) file a new application for EWG status, or (3) notify FERC that it no longer wishes to maintain EWG status.

 

PURPA. The enactment of PURPA in 1978 provided incentives for the development of qualifying cogeneration facilities and small power production facilities that utilized certain alternative or renewable fuels. Prior to the enactment of EPA 2005, FERC’s regulations under PURPA required that (1) electric utilities purchase electricity generated by QFs at a price based on the purchasing utility’s full avoided cost of producing power, (2) the electric utilities must sell back-up, interruptible, maintenance and supplemental power to the QF on a non-discriminatory basis, and (3) the electric utilities must interconnect with any QF in its service territory, and, if required, transmit power if they do not purchase it. We operate our Las Vegas I, Glenns Ferry, Rupert and Ontario facilities as QFs. The enactment of EPA 2005 did not affect the existing contracts for these facilities.

 

State Energy Regulation. In areas outside of wholesale rate regulation (such as financial or organizational regulation), some state utility laws may give their public utility commissions broad jurisdiction over steam sales or EWGs that sell power in their service territories. The actual scope of the jurisdiction over steam or independent power projects depends on state law and varies significantly from state to state.

 

Environmental Regulation. We are subject to a broad range of federal, state and local laws and regulations with regard to air and water quality, solid waste disposal and other environmental matters. Environmental laws, regulations and issues affecting our Power generation segment are substantially the same as those affecting our Utilities group. In addition, the Power generation segment is impacted by the following:

 

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Clean Air Act. The Clean Air Act impacts the Power generation segment in a similar manner to the impact disclosed for our Utilities group. Title IV of the Clean Air Act applies to our Gillette CT, Wygen I, Arapahoe, Valmont, Fountain Valley, Las Vegas II and Valencia plants. We currently hold sufficient allowances credited to us as a result of sulfur removal equipment previously installed at our electric utility’s Wyodak plant to apply to the operation of all of our units subject to Title IV through 2036 without requiring the purchase of any additional allowances from non-affiliated third parties. The allowances credited for the Wyodak plant are purchased from Black Hills Power at current market prices.

 

Title V of the federal Clean Air Act requires that all of our facilities obtain operating permits. All of our existing facilities subject to this requirement have received Title V permits.

 

Clean Water Act. The Clean Water Act impacts our Power generation segment in a similar manner to the impact disclosed for our Utilities group. All of our facilities required to have NPDES permits have those permits in place and are in compliance with discharge limitations. There are no proposed regulations that we are aware of that will have a significant impact on our operations. Additionally, the EPA regulates surface water oil pollution prevention through its oil pollution prevention regulations. All of our facilities regulated under this program have their required plans in place.

 

Solid Waste Disposal. We dispose of all solid wastes collected as a result of burning coal at our power plants in approved solid waste disposal sites. Each disposal site has been permitted by the state of its location. Ash and wastes from flue gas and sulfur removal from the Wygen I plant are deposited in mined areas at our WRDC coal mine. This disposal area is located below some shallow water aquifers in the mine. The State of Wyoming is currently reevaluating this practice and may, in the future, limit ash disposal to mined areas that are above future groundwater aquifers. This would result in increased costs, although those costs cannot be quantified until the exact requirements are known. None of the solid wastes from the burning of coal are classified as hazardous material, but the wastes do contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. Investigations have concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could experience material costs to mitigate any resulting damages.

 

Global Climate Change. In addition to the factors discussed under this caption for the Utilities group, our Non-regulated group is impacted by regulation from several western states.

 

California passed the Global Warming Solutions Act of 2006. This law sets enforceable state-wide greenhouse gas emissions caps from major industries and includes penalties for non-compliance. It requires that by 2020 the state’s CO₂ emissions be reduced to 1990 levels. The CARB is the state agency charged with monitoring and regulating sources of emissions of greenhouse gases. The CARB is working with the California PUC to establish emissions performance standards for power generation. At this time, individual reduction targets have not been issued for each plant and we are unable to determine the impact of this law until these targets are established.

 

New Mexico and Nevada have passed legislation requiring the tracking and reporting of greenhouse gas emissions, beginning with calendar year 2008. To date there are no associated emission limitations, although we anticipate these and other states may implement such programs in the future.

 

Other requirements. We may incur substantial capital and operating and maintenance costs to comply with evolving environmental requirements. While these evolving requirements will impact the operation of existing and new coal-fired and other fossil-fuel generating units, it is virtually certain that environmental requirements placed on the operations of these generating units will continue to become more restrictive. Many of the long-term power sales agreements in place at our power generation facilities contain government imposition clauses that allow us to pass certain of these costs on to the power purchaser.

 

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Coal Mining Segment

 

Our coal mining segment operates through our WRDC subsidiary. We mine and process low-sulfur coal at our coal mine near Gillette, Wyoming. The WRDC coal mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin, one of the largest coal reserves in the United States. We produced approximately 5.0 million tons of coal in 2007. In a basin characterized by thick coal seams, our overburden ratio, a comparison of the amount of dirt removed to a ton of coal uncovered, has historically approximated a 1:1 ratio. In recent years this has trended towards a 2:1 ratio, where it is expected to remain for the next several years.

 

Mining rights to the coal are based on four federal leases and one state lease. We pay royalties of 12.5 percent and 9.0 percent, respectively, of the selling price on all federal and state coal. As of December 31, 2007, we had coal reserves of approximately 280 million tons, based on internal engineering studies. The reserve life is equal to approximately 43 years at expected production levels.

 

Substantially all of our coal production is currently sold under long-term contracts to:

 

 

We also expect to increase our coal production to supply:

 

 

Our coal mining segment sells coal to Black Hills Power and Cheyenne Light for all of their requirements under agreements that limit earnings from the related coal sales to a specified return on our coal mine’s cost-depreciated investment base. The return is 4 percent (400 basis points) above A-rated utility bonds, to be applied to our coal mining investment base as determined each year. Black Hills Power made a commitment to the SDPUC, the WPSC and the City of Gillette, Wyoming that coal for Black Hills Power’s operating plants would be furnished and priced as provided by that agreement for the life of the Neil Simpson II plant, which was placed into service in 1995. The agreement with Cheyenne Light provides coal for the life of the Wygen II plant, which was placed in service January 1, 2008.

 

The price for unprocessed coal sold to PacifiCorp for its 80 percent interest in the Wyodak plant is determined by a coal supply agreement which was executed in 2001 and terminates in 2022.

 

Competition. Our primary strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically our off-site sales have been to consumers within a close proximity to our mine. Due to the economic limitations on transporting our lower-heat content coal, we do not actively promote the sale of our coal in distant markets.

 

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Environmental Regulation. The construction and operation of coal mines are subject to extensive environmental protection and land use regulation in the United States. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies.

 

Mine Reclamation. Under federal and state laws and regulations, we must submit applications to, and receive approval from, the WDEQ for a mining and reclamation plan which provides for orderly mining, reclamation and restoration of our entire WRDC coal mine. We have an approved mining permit and are in compliance with other permitting programs administered by various regulatory agencies.

 

Based on extensive reclamation studies, we currently have approximately $14.8 million accrued on our accompanying Consolidated Balance Sheets for reclamation costs. Additional requirements in the future could be imposed that would cause an unexpected material or significant increase in reclamation costs.

 

One situation that could result in substantial unexpected increases in costs relating to our reclamation permit concerns three depressions – the “South” depression, the “Peerless” depression and the “Clovis” depression – that have or will result from our mining activities at the WRDC coal mine. Because of the thick coal seam and relatively shallow overburden, the current restoration plan would leave these depressions having limited reclamation potential, with interior drainage only. Although the WDEQ has accepted the current plan to limit reclamation of these depressions, it reserved the right to review and evaluate future reclamation plans or to re-evaluate the existing reclamation plan. If, as a result of our mining activities, surplus overburden becomes available, the WDEQ could require us to conduct additional reclamation of the depressions, particularly if the WDEQ finds that the current limited reclamation and drainage results in exceedances of the WDEQ’s water quality standards.

 

Another situation that could result in unexpected increases in costs is the current State of Wyoming reexamination of ash disposal practices. The WRDC coal mine is currently allowed to dispose of ash below the future groundwater table, as state-approved studies have shown no future offsite impacts to groundwater due to this practice. If the state alters this approval at some point in the future, increased costs could be incurred for specialized placement of ash at alternate approved sites within the mine due to loss of mine backfill.

 

Energy Marketing Segment

 

Through our subsidiary, Enserco, we market natural gas and crude oil in specific regions of the United States and Canada. Our marketing operations are headquartered in Golden, Colorado, with a satellite sales office in Calgary, Alberta, Canada. Our gas and oil marketing efforts are concentrated in the Rocky Mountain, Western and Mid-continent regions of the United States and in Canada. The customers of our energy marketing segment include:

 

 

Our average daily marketing physical volumes for the year ended December 31, 2007 were approximately 1.7 million MMBtu of gas and approximately 8,600 Bbls of oil.

 

Our energy marketing operations focus primarily on producer services and wholesale natural gas marketing. The business scope is comprised of the purchase, sale, storage and transportation of natural gas and crude oil, as well as a variety of services including asset optimization, price risk management and customized offerings to producer and end-use clients.

 

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This segment previously included the Houston, Texas based operations of our subsidiary, BHER, which is now reported as discontinued operations. On March 1, 2006, we sold all of the operating assets to Sunoco Logistics Partners L.P. The sale included the crude oil marketing business, the 200-mile Millennium Pipeline system and the 190-mile Kilgore Pipeline system and related facilities.

 

Competition. The energy marketing industry is characterized by numerous large, strong and capable competitors, some of which may have more extensive operating experience, larger staffs or greater financial resources than we possess.

 

Seasonality. Weather conditions affect the demand for natural gas and can be a source of volatility in natural gas prices. Both are typically higher in the fourth and first quarters of our fiscal year, resulting in higher margins. Due to these seasonal fluctuations, results of operations on a quarterly basis may not reflect results which may be realized on an annual basis.

 

Working Capital Practices. The natural gas storage part of the business requires significant working capital investment in the form of inventory. Those investment levels are typically highest in the second and third quarters of our fiscal year.

 

Risk Management. Our business operations require effective management of price, counterparty performance and operational risks. Price risk arises from the volatility of energy prices. Counterparty performance risk is the risk that a counterparty will fail to satisfy its contractual obligations to us and includes credit risk. Operational risk is the risk that we will be unable to perform on our contractual obligations to our counterparties. We have implemented controls to mitigate each of these risks.

 

Our energy marketing operations are conducted in accordance with guidelines established through separate risk management policies and procedures for the marketing company and through our credit policies and procedures. These policies and procedures limit speculative positions and specify various maximum risk exposure levels within which the marketing company must operate. These policies are established and approved by our Executive Risk Committee and Executive Credit Committee and reviewed by our Board of Directors. These committees, which include senior executives, meet on a regular basis to review the Company’s risk and credit activities and to monitor compliance with the adopted policies. The policies are reviewed and monitored on a regular basis.

 

We further limit the exposure of our parent holding company, Black Hills Corporation, to energy marketing risks by maintaining a separate credit facility for our energy marketing company. This credit facility provides security interests limited to the assets of the marketing company. In addition, we limit the number and amount of any parent company guarantees for energy marketing; as of December 31, 2007, we had $7.0 million of parent guarantees for our energy marketing company.

 

Other Properties

 

We own an eight-story, 47,000 square foot office building in Rapid City, South Dakota, where our corporate headquarters is located. Also in Rapid City, we own one additional office building consisting of approximately 19,900 square feet, a warehouse building and shop with approximately 25,200 square feet and lease 18,000 square feet of office space and 8,800 square feet for a customer call center. In Cheyenne, Wyoming, we own a business office with approximately 13,400 square feet, and a service center and garage with an aggregate of approximately 28,300 square feet. We lease an aggregate of 36,200 square feet of office space in Golden, Colorado and in Bellevue, Nebraska, we lease space for a data center.

 

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Employees

 

At January 31, 2008, we had 998 full-time employees. We have experienced no labor stoppages or significant labor disputes in recent years. The following table sets forth the number of employees by business:

 

 

 

 

 

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The following specific risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company. These important factors and other matters discussed herein could cause our actual results or outcomes to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

 

We have entered into a definitive agreement to acquire utility assets from Aquila. There are many risks associated with our ability to complete the transaction and subsequently achieve the anticipated benefits of our acquisition.

 

We may not be able to obtain the approvals required to complete the acquisition or, in order to do so, we may be required to comply with material restrictions or conditions.

 

Our acquisition of the utility assets is subject to approvals from the FERC and various utility regulatory, antitrust and other authorities in the United States. Several approvals were received during 2007. As we proceed to obtain the remaining approvals, these governmental authorities may impose conditions on the completion, or require changes to the terms of the acquisition, including restrictions or conditions on the business, operations, or financial performance of the gas utilities and electric utility that we would acquire from Aquila, following completion of the acquisition. These conditions or changes could impose additional costs on us or limit our revenues following the acquisition, or may impose unacceptable conditions on our operation of the gas utilities and electric utility assets, which could delay the completion of or cause us to abandon our acquisition.

 

In addition, the participating financial institution commitments to fund our $1.0 billion acquisition facility expire on August 5, 2008, and the facility terminates on February 5, 2009. Delays that prevent the closing of the acquisition prior to August 5, 2008 could require us to find replacement financing, for which we may incur a substantial amount of additional financing-related costs. If we were unable to find acceptable replacement financing, it could cause us to abandon our acquisition.

 

If we do not complete the acquisition, we will still incur and remain liable for significant transaction costs, including legal, accounting, financial advisory, filing, printing and other related costs.

 

If completed, we may not be able to effectively integrate the utility operations we acquire into our existing businesses and operations, or achieve the intended results.

 

We expect that the acquisition will result in various benefits. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties. We cannot provide assurance that the gas utilities and the electric utility businesses we would acquire from Aquila can be integrated in an efficient and effective manner, or that once integrated; they will prove to be profitable.

 

We will be subject to business uncertainties while the acquisition is pending that could adversely affect our financial results.

 

Uncertainty about the effect of the acquisition on employees and customers may have an adverse effect on us. Although we have taken steps designed to eliminate or at least reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the acquisition is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to change existing business relationships.

 

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Employee retention and recruitment may be particularly challenging prior to the completion of the acquisition, as employees and prospective employees may experience uncertainty about their future roles with the addition of the gas utilities and electric utility we would acquire from Aquila. If, despite our retention and recruitment efforts, key employees depart or fail to accept employment with us because of issues relating to uncertainty and difficulty of integration or a desire not to remain with us, our financial results could be negatively affected.

 

Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, our cost of capital and our other operating costs, which could adversely affect our ability to complete the acquisition.

 

Our issuer credit rating is Baa3, with a negative outlook by Moody’s and BBB-, with a stable outlook by S&P. While we do not expect any negative effect on our credit rating from our proposed acquisition of the utility assets, we cannot provide assurance that our credit ratings will not be lowered as a result of the proposed acquisition or for any other reason, including the failure to consummate the acquisition of the utility assets. Any reduction in our ratings by Moody’s or S&P would reduce our credit rating with that agency to non-investment grade status, and could adversely affect our ability to complete the Aquila transaction, to refinance or repay our existing debt and to complete new financings on acceptable terms or at all.

 

Our utilities may not raise their retail rates without prior approval of the SDPUC, the WPSC and the MTPSC. If either utility seeks rate relief, it could experience delays, reduced or partial rate recovery, or disallowances in rate proceedings.

 

Because our utilities are generally unable to increase their base rates without prior approval from the SDPUC, the WPSC, and the MTPSC, our returns could be threatened by plant outages, machinery failure, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which our utilities have no control that could cause operating costs to increase and operating margins to decline. While we have cost pass-through mechanisms in place that allow recovery of increased costs related to fuel, purchased power, transmission and natural gas, there is no guarantee that all increases in these costs will be recovered. Additionally, our utilities’ general operating costs and investments are subject to the review of the SDPUC, the WPSC and the MTPSC. These commissions could find certain costs or investments are not prudent and not recoverable in our rates, thus negatively affecting our revenues.

 

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 interpretation of available technical data and various assumptions, including assumptions relating to economic factors. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of reserve estimates 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, future capital expenditures 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. These variances may be significant. Any significant variance from the assumptions used could cause the actual quantity of our reserves, and future net cash flow to be materially different from our estimates. In addition, results of drilling, testing and production, changes in future capital expenditures and fluctuations in oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.

 

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Our current or future development, expansion and acquisition activities may not be successful, which could impair our ability to execute our growth strategy.

 

Execution of our future growth plan is dependent on successful ongoing and future acquisition, development and expansion activities. We can provide no assurance that we will be able to complete acquisitions or development projects we undertake or continue to develop attractive opportunities for growth. Factors that could cause our activities to be unsuccessful include:

 

 

We can provide no assurance that results from any acquisition will conform to our expectations. There may be additional risks associated with the operation of any newly acquired assets.

 

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 expected results include:

 

 

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, with a negative outlook by Moody’s, and BBB-, with a stable outlook by S&P. Any reduction in our ratings by Moody’s or S&P would reduce our credit rating with that agency to non-investment grade status, which could adversely affect our ability to refinance or repay our existing debt or complete new financings on acceptable terms, or at all.

 

In addition, a downgrade in our credit rating would increase our interest expense under some of our existing debt obligations, including borrowings made under our credit agreements and the $1.0 billion acquisition facility.

 

A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under existing or new transactions.

 

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Construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve significant risks which could reduce revenues or increase expenses.

 

The construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve many risks, including:

 

 

The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses, or cause us to incur higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses or liquidated damage payments.

 

Because prices for our products and services and operating costs for our business are volatile, our revenues and expenses may fluctuate.

 

A substantial portion of our net income in recent years was attributable to sales of wholesale electricity and natural gas into a robust market. Energy prices are influenced by many factors outside our control, including:

 

 

Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant, unpredictable price fluctuations over relatively short periods of time.

 

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The success of our oil and gas operations is affected by the prevailing market prices of oil and natural gas. Oil and natural gas prices and markets historically have also been, and are likely to continue to be, volatile. A decrease in oil or natural gas prices would not only reduce revenues and profits, but would also reduce the quantities of reserves that are commercially recoverable, and may result in charges to earnings for impairment of the net capitalized cost 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.

 

Our mining operation requires a reliable supply of replacement parts, explosives, fuel, tires and steel-related products. If the cost of any of these increase significantly, or if a source of these supplies or mining equipment was unavailable to meet our replacement demands, our profitability could be lower than our current expectations. In recent years, industry-wide demand growth has exceeded supply growth for certain surface mining equipment and off-the-road tires. As a result, lead times for some items have generally increased to several months.

 

Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results and our stock price could be adversely affected as a result.

 

We use various contracts and derivatives, including futures, forwards, options and swaps, to manage commodity price and financial market risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the items being hedged. The difference in accounting can result in volatility in reported results, even though the expected profit margin is essentially unchanged from the dates the transactions were consummated.

 

Our energy marketing subsidiary relies on storage and transportation assets that we do not own or control to deliver natural gas and crude oil.

 

The commodity, storage and transportation portfolios at our energy marketing operations consist of contracts to buy and sell natural gas and crude oil commodities, many of which are settled by physical delivery.

 

We depend on pipelines and other storage and transportation facilities owned and operated by third parties to deliver these commodities to satisfy contractual commitments. If transportation is disrupted, or if storage capacity is inadequate, including for reasons of force majeure, our ability to fulfill our commitments may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates.

 

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, tribal and local authorities. We generally must obtain and comply with a variety of licenses, permits and other approvals in order to operate. 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, which could have a detrimental effect on our business.

 

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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, whether known or unknown, and in some cases agreed to indemnify the former owners of those facilities for on-site environmental liabilities. We strive to comply with all applicable environmental laws and regulations. Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect our results of operation and financial condition. We expect our environmental expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the assets we operate.

 

Federal and/or State requirements imposing further emission reduction mandates, including limitations on CO₂ emissions, could make some of our electric generating units uneconomical to maintain and operate.

 

Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil-fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses. The issue of global climate change is receiving increased attention with a strong focus on CO₂ emissions from power generation facilities and their potential role in climate change. There is considerable debate regarding the public policy approach that the United States should follow to address this issue. Although several bills have been introduced in Congress that would compel CO₂ emission reductions, none have been enacted into law. Future changes in environmental regulations governing these pollutants could make some of our electric generating units more expensive or uneconomical to maintain and operate. In addition, any legal obligation that would require us to substantially reduce our emissions below present levels could require extensive mitigation efforts and, in the case of CO₂ legislation, may raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.

 

Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations.

 

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against others within industries in which we operate, highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities in particular.

 

Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.

 

Inherent in our natural gas distribution activities are a variety of hazards and operating risks, such as leaks, explosions and mechanical problems that could cause substantial adverse financial impacts. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse affect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks could be greater. If we are able to complete the pending Aquila acquisition, our natural gas distribution activities will expand greatly.

 

Increased risks of regulatory penalties could negatively impact our business.

 

EPA 2005 increased FERC’s civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1.0 million per violation, per day. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations. If a serious violation did occur, and penalties were imposed by FERC, it could have a material adverse effect on our operations or financial results of operations.

 

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Our agreements with counterparties 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 business 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 occasionally serve as our counterparties. In addition, we have project level financing arrangements 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 attempt to sell the plant’s power at prevailing market prices.

 

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. Significant inaccuracies in interpretation or modeling could materially affect the quantity and quality of our reserves. The accuracy of reserve estimates is a function of engineering and geological interpretation 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 require reserve revisions either upward or downward from prior reserve estimates.

 

Ongoing changes in the United States utility industry, including state and federal regulatory changes, a potential increase in the number or geographic scale of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.

 

The United States electric utility industry is experiencing increasing competitive pressures as a result of:

 

 

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 led to the disaggregation of vertically integrated utilities into separate generation, transmission and distribution businesses. Deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry, which could 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 price limitations and other mechanisms may adversely affect the profitability of generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets, and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

 

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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, so investments in our subsidiaries are our primary assets. Our operating cash flow and 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 applicable contractual or regulatory restrictions that 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. 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 for the states in which we operate 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 or pay dividends to our shareholders.

 

Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.

 

We have multiple defined benefit pension and non-pension postretirement plans that cover a substantial portion of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements may change and additional contributions could be required in the future.

 

Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity.

 

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

 

An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.

 

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. Our independent registered public accounting firm also attests to the effectiveness of these controls. During their assessment of these controls, management or our independent auditors may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists.

 

 

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None.

 

 

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub caption within Item 8, Note 18, “Commitments and Contingencies”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

 

No matter was submitted to a vote of security holders during the fourth quarter of 2007.

 

 

David R. Emery, age 45, was elected Chairman in April 2005 and has been President and Chief Executive Officer and a member of the Board of Directors since 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 18 years of experience with us.

 

Thomas M. Ohlmacher, age 56, has been the President and Chief Operating Officer of our Non-regulated 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. Mr. Ohlmacher has 33 years of experience with us.

 

Linden R. Evans, age 45, has been President and Chief Operating Officer – Utilities since 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. Mr. Evans has 6 years of experience with us.

 

Steven J. Helmers, age 51, 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. Mr. Helmers has 7 years of experience with us.

 

Maurice T. Klefeker, age 51, has been Senior Vice President – Strategic Planning and Development since 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. Mr. Klefeker has 8 years of experience with us.

 

James M. Mattern, age 53, 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 20 years of experience with us.

 

Roxann R. Basham, age 46, has been Vice President – Governance and Corporate Secretary since February 2004. Prior to that, she was our Vice President – Controller from March 2000 to January 2004. Ms. Basham has a total of 24 years of experience with us.

 

Kyle D. White, age 48, has been Vice President – Corporate Affairs since January 30, 2001 and Vice President – Marketing and Regulatory Affairs since July 1998. Mr. White has 25 years of experience with us.

 

Garner M. Anderson, age 45, has been Vice President, Treasurer and Chief Risk Officer since October 2006. He had served as Vice President and Treasurer since July 2003. Mr. Anderson has 19 years of experience with us, including positions as Director – Treasury Services and Risk Manager.

 

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Perry S. Krush, age 48, has been Vice President – Controller since December 2004. Mr. Krush has 19 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

 

 

Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of February 1, 2008, we had 4,911 common shareholders of record and approximately 15,100 beneficial owners, representing all 50 states, the District of Columbia and 10 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 November 2007 meeting, our Board of Directors declared a quarterly dividend of $0.35 per share, equivalent to an annual dividend of $1.40 per share, marking 2008 as the 38^th consecutive annual dividend increase for the Company.

 

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, 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 interest expense coverage ratio, as calculated in our credit agreements, is less than 2.5 to 1.0, our recourse leverage ratio exceeds 0.65 to 1.00 (or 0.70 to 1.00 for the first year after the Aquila acquisition) 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. As of December 31, 2007, we were in compliance with all covenants, and accordingly, are not currently restricted from paying any dividends.

 

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:

 

 

 

 

 

 

 

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UNREGISTERED SECURITIES ISSUED DURING 2007

 

No unregistered securities were sold during 2007, except as has been previously reported in our periodic and current reports to the SEC.

 

ISSUER PURCHASES OF EQUITY SECURITIES

 

_________________________

 

 

 

 

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____________________________________

Certain items related to 2003 through 2005 have been restated from prior year presentations to reflect the classification of the oil marketing and transportation business as discontinued operations in 2006 (see Notes 1 and 16 of Item 8. Financial Statements and Supplementary Data).

 

(2) Impairment charges to reduce the carrying value of long-lived assets to fair value and record related costs were approximately $2.2 million after-tax in 2007, $33.9 million after-tax in 2005, and $76.2 million after-tax in 2003.

 

For additional information on our business segments see – ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK AND NOTE 20 TO THE NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS IN THIS ANNUAL REPORT ON FORM 10-K.

 

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We are an integrated energy company operating principally in the United States with two major business groups – Utilities and Non-regulated energy (previously Retail services and Wholesale energy, respectively). We report for our business groups in the following financial segments:

 

 

Our Utilities business group currently consists of our electric utility, Black Hills Power, and our electric and gas utility, Cheyenne Light, which was acquired January 21, 2005. Black Hills Power generates, transmits and distributes electricity to approximately 65,100 customers in South Dakota, Wyoming and Montana. Cheyenne Light serves approximately 39,400 electric customers and 33,000 natural gas customers in Cheyenne, Wyoming and vicinity. Our Non-regulated energy group, which operates through Black Hills Energy and its subsidiaries, engages in the production of natural gas, crude oil and coal primarily in the Rocky Mountain region; the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term “tolling” contracts; and the marketing of natural gas and crude oil.

 

Industry Overview

 

The U.S. energy industry experienced another year of strong economic performance in 2007. Energy commodity prices continued to be high and volatile. Domestic energy prices continue to be influenced by global factors, including foreign economic growth, especially in China and Asia, domestic economic growth, the policies of OPEC and other large foreign oil producers, and political tensions and conflict in many regions. Mild weather dominated the U.S. during most of the year, reducing demand for fuel used for power generation and heating. Minimal hurricane activity allowed for normal Gulf of Mexico oil and gas production. At year-end 2007, domestic supplies of natural gas in storage were above historical averages.

 

While the major economic factors affecting energy remained positive in 2007, the political environment changed significantly. Environmental issues took “center stage” in the U.S. Congress in 2007. Among the topics of emphasis were federally-mandated renewable portfolio standards, carbon taxes, carbon “cap-and-trade” arrangements, and mandated reductions of greenhouse gas emissions. Although the Congress has not yet enacted any major legislation relative to these environmental issues, it appears increasingly likely in the future. All of these potential legislative actions could have significant macroeconomic consequences. The associated cost increase would cause a dramatic increase in consumers’ rates for electricity and other energy in the mid- to long-term. State Legislatures, too, were very active on the environmental front, with a total of approximately 31 states now having adopted some form of renewable standard, including some where we operate.

 

The federal and state regulatory climate in 2007, in a general sense, remained relatively constructive among government, industry and consumer representatives. In the multi-state region surrounding our utility operations, regulators were willing to establish rates based on multi-year considerations, including fuel and other reasonable cost adjustments, justifiable capital expenditures for maintenance and expansion of energy systems, and a response to environmental considerations through demand management and efficiency programs.

 

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Progress in the domestic energy industry in 2007 included continued oil and gas exploration and production activity in the Rocky Mountains, continued planning and construction of liquefied natural gas port facilities, proposals for additional coal-fired and nuclear power plants, planning for additional transmission capacity, and the advancement of renewable energy resources and utilization. Of particular note was the regional expansion of natural gas transportation out of Colorado, with the completion of the second phase of the Rockies Express Pipeline.

 

The energy industry continues to adjust to change, including the trends of consolidation in the electric and gas utility sectors, along with asset divestitures to restrict or redefine business strategies. The energy market place continues to adjust to increased oversight of the FERC and increased environmental and emissions reviews and mandates. In recent years, several state regulatory agencies allowed electric utilities to construct and operate power plants in vertically integrated structures after years of discouraging or prohibiting such activity.

 

Over the last several years, the corporate structure of many energy companies underwent evaluation and change, in large part due to efforts to create additional shareholder value. A number of companies are contemplating or implementing a realignment of business lines, reflecting a shift in long-term strategies. Some are divesting certain energy properties to focus on core businesses, such as exiting unregulated power production or oil and gas production in favor of more stable utility operations. Others have engaged in mergers and acquisitions with a goal to improve economies of scale and returns to investors. Private equity investors continued to play a role in the changing composition of energy ownership, but to a lesser extent than previous years.

 

Many industry analysts have identified the need for expanded energy capacity and delivery systems. They foresee an increase in capital investments across a wide spectrum of energy companies. Many electric and gas utilities must replace aging plants and equipment, and regulators appear to be willing to provide acceptable rate treatment for additional utility investment. Oil and gas producers are expected to continue to increase capital spending in response to relatively high prices, particularly for oil. Historically high field service costs, however, have begun to curtail projects as companies more closely examine their economic considerations. In addition, the process for obtaining drilling permits, particularly on public and Native American lands, is getting increasingly more difficult.

 

In 2007, the domestic coal industry benefited from a positive price environment, in large part due to high and volatile natural gas prices. Coal prices have moderated recently in response to a trend of lower overall natural gas prices, compared to a year ago. Fossil fuel combustion continues to be a contentious domestic and international public policy issue, as many nations, including U.S. allies, advocate reductions in CO₂ and other emissions. Many states now encourage the energy industry to invest in renewable energy resources, such as wind or solar power, or the use of bio-mass as a fuel. In many instances, renewable energy use is mandated by state regulators. Furthermore, in the case of California, rules have established a requirement that future imports of power must come from power plants with lower emission levels than currently associated with conventional coal-fired plants. Such restrictions may alter transmission flow of power in western states, as a large percentage of current power generation in the western grid comes from coal sources.

 

Despite these longer-term challenges, the power generation industry continues to make improvements in emissions control in response to regulatory mandates. Emissions from new coal-fired plants are a small fraction of those produced by power plants built a generation ago. Along with similar technological progress, coal can and likely will remain an important, domestically available, and economical national energy resource that is vital to meet growing energy demand. To that point, the U.S. Department of Energy is beginning to take positive steps toward ensuring the future of coal through research funding for “clean coal” technologies and methods of carbon capture/sequestration.

 

Like other U.S. industries, the energy industry is faced with uncertainties looming on the economic horizon. A global credit problem emerged from a proliferation of sub-prime lending. As that issue attracted attention, other credit quality concerns surfaced, creating an international-scale financial crisis, which could likely take years to resolve. Access to debt markets and capital availability are crucial for a robust and capital-intensive energy industry. Another issue facing the U.S. economy is inflation. As energy companies expand, inflation can impair the ability to manage the costs of lengthy construction projects and other factors. Still another uncertainty is a growing probability of a domestic recession. Utility companies generally are less impacted by economic downturns, but a prolonged or severe recession can affect the demand for energy services and the ability of companies to execute capital expansion plans.

 

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Energy providers, government authorities and private interests continue to address longer term issues concerning electric transmission, power generation capacity, the use of renewable and other diversified sources of energy, oil and natural gas pipelines and storage, and other infrastructure-related matters. Despite public and private efforts to promote conservation and efficiency, the demand for energy is expected to increase steadily over time. To meet that growing demand, the industry is ready to provide capital, resources and innovation to serve customers in cost-effective ways and to achieve returns on investment.

 

The Company believes that it is well-positioned in this industry setting and able to proceed with its strategic agenda. We also believe that we, along with industry counterparts, are ready to address the challenges discussed in this overview, such as new environmental mandates, renewable portfolio standards, carbon-related taxes or trading systems, credit market conditions, inflation, or other factors that can affect energy demand and supply. In particular, we are sensitive to additional costs that can negatively affect our customers or our profitability. To that end, we intend to work closely with regulators and industry leaders to assure that cost-conscious proposals and solutions are prominent in public policy proceedings.

 

Business Strategy

 

We are a customer-focused integrated energy company. Our business is comprised of utility operations, including electric and gas distribution systems; fuel assets and services, including oil, natural gas and coal production and marketing operations; and electric generation operations. Our focus on customers – whether utility customers or non-regulated generation, fuel or marketing customers – provides opportunities to expand our businesses. Our balanced, integrated approach to the energy business is supported by disciplined risk management practices.

 

The diversity of our operations reduces reliance on any single business to achieve our strategic objectives. Our diversification is expected to provide a measure of stability to our business and financial performance during volatile or cyclical periods. It helps us reduce our total corporate risk, and allows us to achieve potentially stronger returns over the long term. We have a strong and stable balance sheet, which is essential given the demands of the market. We possess access to capital, sufficient liquidity, and solid cash flows and earnings. Consequently, we believe our financial foundation is sound and capable of supporting an expansion of operations in both the near and long term.

 

Related to our long-term strategy, our current emphasis is to expand our core utility operations and their power generation assets, while we provide sufficient growth capital for our non-regulated fuel, generation and energy marketing operations. We currently are evaluating the strategic merits of certain of our non-regulated power generation assets. As a result of that evaluation, we may elect to sell some or all of such assets.

 

Our long-term strategy focuses on increasing our customer base and providing superior economic and performance value to both utility and non-regulated energy customers. In our utility operations, we seek to grow our existing asset base through construction of new rate-based generation facilities, and by adding new customers through the acquisition of additional utility properties. We intend to maintain our high customer service and reliability standards. In our fuel production operations, we will continue to economically grow and develop our existing inventory of oil and gas reserves, while we strive to maintain our positive relationships with mineral owners, landowners and regulatory authorities. We seek to develop additional markets for our coal production, including the development of additional power plants at our mine site. Our non-regulated power generation business will continue to focus on long-term contractual relationships with key wholesale customers, as well as new customers that will allow us to selectively grow our power generation business, while evaluating the strategic merits of certain of our existing facilities. The expertise of our energy marketing business should allow us to continue to provide profitability through a risk-managed and disciplined approach to producer service, origination, storage, transportation and proprietary marketing strategies.

 

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The following are key elements of our business strategy:

 

 

Operate our lines of business as utility and non-regulated energy components. The utility component consists of electric and natural gas products and services. The non-regulated energy component consists of fuel production, mid-stream assets, power production facilities and energy marketing. We partition operations into utility and non-regulated energy business groups to achieve operating efficiencies. In the Utilities group, the integration of customer service, marketing and promotional efforts streamline operating processes and improve productivity. In the non-regulated energy group, the fuel production, generation and marketing segments integrate balanced, yet diverse strategic operations.

 

Expand utility operations through selective acquisitions of electric and gas utilities consistent with our regional focus and strategic advantages. For 125 years, we and our predecessor companies have provided strong utility services, based on delivering quality and value to our customers. Our tradition of accomplishment is expected to support efforts to expand our utility operations into other markets, most likely in the Midwest, West and possibly other regions that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation, system reliability, superior customer service and a relationship-based approach to regulatory matters. The 2005 acquisition of Cheyenne Light and the pending acquisition of certain electric and gas utility assets of Aquila are examples of such expansion efforts. Utility operations also enhance other important business development, including gas transmission pipelines and storage infrastructure, which could promote other non-regulated energy operations. Utility operations can contribute substantially to the stability of our long-term cash flows, earnings and dividend policy.

 

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Complete our proposed acquisition of certain Aquila-owned utility assets and successfully integrate and profitably operate our expanded utility operations. Our pending acquisition of Aquila’s five utility properties in four states will significantly expand our regional presence and the size and scope of our utility operations. We believe that the expanded utility operations will enhance our ability to serve customers and communities and build long-term value for our shareholders. In addition to other customary conditions, the completion of the transaction requires us to obtain state and federal regulatory approvals, and pass federal antitrust review. As of February 29, 2008, we received approvals from regulators in the states of Iowa, Nebraska and Colorado, obtained federal antitrust clearance, and received FERC approval of the Colorado electric property acquisition. On February 12, 2008, a hearing was held by the Kansas Corporation Commission on our joint application with Aquila. All the parties to the Kansas proceeding entered into a settlement which was presented at that hearing. A decision by the Kansas regulators is pending. In addition, another party to the transaction, Great Plains Energy, must obtain approval from regulators in the states of Missouri and Kansas, which are pending.

 

We will require access to the capital markets to secure capital sufficient to fund our acquisition. We have obtained a $1.0 billion temporary financing arrangement with a termination date of February 5, 2009. In the interim, we intend to obtain permanent financing for the transaction from a variety of sources, including equity, mandatory convertible securities, corporate-level debt or cash from operations or the potential divestiture of certain non-regulated power plant assets. Access to capital markets could be impacted by our ability to maintain our investment grade issuer credit rating. We expect that the acquisition will result in multiple benefits after a period of transition and integration costs. We will strive to integrate our current and acquired utility operations to achieve these anticipated benefits.

 

Plan, invest in, construct and expand our rate-base generation to serve our electric utilities. Our Company’s original business was a vertically integrated electric utility. This business model remains a core strength and strategy today, where we invest in and operate efficient power generation resources to transmit and distribute electricity to our customers. We provide power at reasonable and stable rates to our customers and earn solid returns for our investors. Rate-based generation assets offer several advantages for consumers, regulators and investors. First, the assets assure consumers that rates have been reviewed and approved by government authorities who safeguard the public interest. Second, regulators participate in a planning process where long-term investments are designed to match long-term energy demand. Third, investors are assured that a long-term, reasonable, stable rate of return may be earned on their investment. A lower risk profile may also improve credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

 

Examples of our progress include the recent start-up of commercial operations at Wygen II, and the ongoing permitting and development of Wygen III. In 2007, we submitted to regulators an Integrated Resource Plan and applied for an Industrial Siting Permit and a Certificate of Public Convenience and Necessity for Wygen III. The Industrial Siting Permit was obtained in January 2008. The Certificate is pending with hearings scheduled to begin during March 2008. Once the Certificate is obtained, we expect to commence construction of Wygen III in the spring of 2008.

 

Proactively integrate alternative and renewable energy into our utility energy supply while remaining mindful of potential customer rate impacts. The energy and utility industries are faced with a tremendous amount of uncertainty related to the potential impact of legislation intended to decrease greenhouse gas emissions and increase the use of renewable and other alternative energy sources. To date, many states have enacted and others are considering some form of mandatory renewable energy standard requiring utilities to meet certain thresholds for the use of renewable energy. Additionally, many states have either enacted or are considering legislation setting greenhouse gas emissions reduction targets. Federal legislation for both renewable energy standards and greenhouse gas emission reductions are also under consideration. Any significant mandate for renewable energy supplies or greenhouse gas emission reductions would likely increase prices for electricity and natural gas considerably.

 

The Company’s strategy related to renewable energy standards and greenhouse gas emission reductions is customer-centered and attempts to balance our customers’ rate concerns with environmental considerations. As a regulated public utility, we are responsible for providing safe, reasonably priced, reliable sources of energy to our customers. Absent any specific renewable energy standard in South Dakota and Wyoming, our current strategy is to prudently incorporate renewable energy into our resource supply, while seeking to minimize rate increases for our utility customers. We have executed a 20-year purchase power agreement commencing in September 2008 for 30 MW of wind energy resources to be located in Cheyenne, Wyoming. We are exploring other potential biomass and wind energy projects, and are evaluating other potential wind generator sites, including sites located near our utility service territories.

 

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Using reasonable assumptions, we have carefully evaluated our coal-fired generating facilities and the potential future economic impact of a carbon tax or cap and trade regime intended to reduce CO₂ emissions. Based on current assumptions, we believe it is in our utility customers’ long-term interest to construct new mine-mouth, coal-fired generating facilities, such as our recently completed Wygen II generation facility and our proposed Wygen III generation facility. We are also evaluating alternative coal-fired generation technologies, including IGCC and carbon capture and sequestration, though both appear cost prohibitive in the near term.

 

Selectively grow our power generation segment by developing assets in targeted Western markets, while evaluating the strategic merits of certain of our existing assets. We aim to continue developing and operating power plants in regional markets based on prevailing supply and demand fundamentals in a manner that complements our existing fuel assets and fuel and energy marketing capabilities. This approach seeks to capitalize on market growth while managing our fuel procurement needs. We intend to grow through a combination of disciplined acquisitions and development of new power generation facilities primarily in the western regions where we believe we have the detailed knowledge of market fundamentals and competitive advantage to achieve attractive returns. Our emphasis is to pursue small-scale build-outs to serve incremental growth, and improve the likelihood of receiving approvals for permitting and siting. In 2007, we began construction of another independent power plant to provide capacity and energy to Public Service Company of New Mexico under a 20-year tolling arrangement. That plant is expected to be in commercial service in June 2008.

 

We believe that existing sites with opportunities for brownfield expansion generally offer the potential for greater returns than development of new sites through a “greenfield” strategy. Brownfield sites typically offer several competitive advantages over greenfield development, including:

 

 

We expanded our capacity with brownfield development at our Valmont and Wyodak sites in 2001, Arapahoe and Las Vegas sites in 2002 and our Wyodak site in 2003. We believe that our Wyodak, Fountain Valley and Harbor sites in particular provide further opportunities for significant expansion of our gas- and coal-fired generating capacity over the next several years.

 

In 2007, we initiated an evaluation of the merits of divesting certain power generation assets. That strategic review is ongoing as of February 29, 2008. While much of our recent power plant development has been for regulated utilities, we may continue to expand our non-regulated power generation business with select projects that are consistent with our overall strategies.

 

Sell a large percentage of our capacity and energy production from our non-regulated power generation projects through mid- and long-term contracts primarily to load-serving utilities in order to secure a stable revenue stream and attractive returns. The majority of our energy and capacity is provided under mid- and long-term contracts. By doing so, we believe that we can satisfy the requirements of our customers while earning more stable revenues and greater returns over the long term than we could by selling our energy into the more volatile spot markets. When possible, we structure long-term contracts as tolling arrangements, whereby the contract counterparty assumes the fuel risk. Our goal is to sell a majority of our unregulated power generation under long-term, utility commission-reviewed or -approved contracts primarily to load-serving utilities.

 

The first of our long-term power contracts expires in 2008, and nearly all expire before 2014. These contract arrangements are presently under evaluation for renewal or extension, with or without potential revisions to the basic terms of the existing agreements. Most of the existing contracts have been reviewed by regulatory agencies. Our power plants, particularly in Wyoming, the front range of Colorado, Las Vegas, Nevada and Long Beach, California are sited in regions of moderate to rapid population and load growth. They are also located to provide advantageous, convenient access to both fuel supply and power transmission. In anticipation of renewal or extension, a contract review process generally begins about two years in advance of expiration, and we would expect to proceed accordingly.

 

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Exploit our fuel cost advantages and our operating and marketing expertise to produce and sell power at attractive margins. We expect to selectively expand our portfolio of power plants having relatively low marginal costs of producing energy and related products and services. We intend to utilize a competitive power production strategy, together with access to coal and natural gas reserves, to protect our revenue stream. Competitive production costs can result from a variety of factors, including low fuel costs, efficiency in converting fuel into energy, and low per unit operation and maintenance costs. In addition, we typically operate our plants with high levels of availability, as compared to national standards. We aggressively manage each of these factors with the goal of achieving low production costs.

 

A primary competitive advantage is our coal mine, which is located in close proximity to our retail service territories. We are exploiting the competitive advantage of this native fuel source by building additional mine-mouth coal-fired generating capacity. This strengthens our position as a low-cost producer since transportation costs often represent the largest component of the delivered cost of coal for many other utilities.

 

Build and maintain strong relationships with wholesale power customers. We strive to build strong relationships with utilities, municipalities and other wholesale customers and believe we will continue to be a primary provider of electricity to wholesale utility customers. We further believe that these entities will need products, such as capacity, in order to serve their customers reliably. By providing these products under long-term contracts, we are able to meet our customers’ energy needs. Through this approach, we also believe we can earn more stable revenues and greater returns over the long term than we could by selling energy into more volatile spot markets.

 

Efficiently utilize our coal resources through expansion of mine-mouth generation and increased third-party coal sales. Our primary strategy is to expand our coal production through the construction of mine-mouth coal-fired generation plants at our WRDC coal mine location. Our objective is to develop coal production operations to serve our mine-mouth coal-fired generation plants directly. We also plan to pursue future sales of coal to additional regional rail-served and truck-served customers. Recently, we renegotiated a contract to provide coal for the Dave Johnston power plant in Wyoming and extended the term through 2011.

 

Grow our reserves and increase our production of natural gas and crude oil. Our strategy is to increase both reserves and production through a combination of drilling and acquisitions. Primary emphasis will be placed on developing our existing core properties located in the San Juan, Piceance and Powder River Basins. Specifically, we plan to:

 

 

Geographically expand our energy marketing operations including producer and end-use origination services and, as warranted by market conditions, natural gas and crude oil storage and transportation opportunities. Our energy marketing business seeks to provide services to producers and end-users of natural gas and crude oil and to capitalize on market volatility by employing storage, transportation and proprietary trading strategies. The service provider focus of our energy marketing activities largely differentiates us from other energy marketers. Through our producer services group, we assist mostly small- to medium-sized producers throughout the Western U.S. with marketing and transporting their natural gas. Through our origination services, we work with utilities, municipalities and industrial users of natural gas to provide customized delivery services, as well as to support their efforts to optimize their transportation and storage positions.

 

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Diligently manage the risks inherent in energy marketing. Our energy marketing operations require effective management of price and operational risks related to adverse changes in commodity prices and the volatility and liquidity of the commodity markets. To mitigate these risks, we have implemented risk management policies and procedures for our marketing operations. We have oversight committees that monitor compliance with our policies. We also limit exposure to energy marketing risks by maintaining credit facilities separate from our corporate facility.

 

Conduct business with a diversified group of creditworthy or sufficiently collateralized counterparties. All our operations require effective management of counterparty credit risk. We mitigate this risk by conducting business with a diversified group of creditworthy counterparties. In certain cases where creditworthiness merits security, we require prepayment, secured letters of credit or other forms of financial collateral. We establish counterparty credit limits and employ continuous credit monitoring with regular review of compliance under our credit policy by our executive credit committee.

 

Prospective Information

 

We expect long-term growth through the expansion of integrated, balanced and diverse energy operations. We recognize that sustained growth requires continual capital deployment. We are strategically positioned to take advantage of opportunities to acquire and develop energy assets consistent with our investment criteria and a prudent capital structure.

 

Utilities

 

Electric Utility

 

Business at our electric utility, Black Hills Power, remained strong in 2007. We believe that Black Hills Power will produce modest growth in revenue, and absent unplanned plant outages, continue to produce stable earnings for the next several years. We forecast firm energy sales in our retail service territory to increase over the next 10 years at an annual compound growth rate of approximately one to two percent, with the system demand forecasted to increase at a rate of one to two percent. These forecasts are derived from studies we conducted, whereby we examined and analyzed our service territory to estimate changes in the needs for electrical energy and demand over a 20-year period. These forecasts are only estimates, and the actual changes in electric sales may be substantially different. Weather deviations can also affect energy sales significantly when compared to forecasts based on normal weather. The portion of the utility’s future earnings that will result from wholesale off-system sales will depend on many factors, including regulatory requirements, native load growth, plant availability and electricity demand and commodity prices in not only our service territory, but in the surrounding power markets as well.

 

In 2008, we plan to begin construction of Wygen III, a 100 MW coal-fired power plant to be located at our Neil Simpson Complex. We have received the required air permit and industrial siting permit, with the last regulatory step, obtaining a Certificate of Public Convenience and Necessity from the State of Wyoming, set for hearing on March 8, 2008. Upon obtaining this permit, we would commence construction. We anticipate that Black Hills Power will have 55 MW of the facilities’ capacity and are considering third-party investors to own the remaining 45 MW.

 

Electric and Gas Utility

 

We acquired Cheyenne Light in January 2005. On January 1, 2008, Wygen II, a 95 MW baseload coal-fired power plant commenced commercial service as a rate base asset to serve Cheyenne Light. The plant cost approximately $182 million, including interim financing costs during construction. Effective January 1, 2008, a regulatory approved agreement between the affiliates gives Cheyenne Light the ability to sell its surplus energy to Black Hills Power. In addition, we entered into a 20 year contract to purchase up to 30 MW of renewable wind power, beginning in September 2008. The energy from this contract can be utilized by both Cheyenne Light and Black Hills Power. We expect system demand in the Cheyenne, Wyoming vicinity over the next 10 years to increase at an annual compound rate of approximately two percent.

 

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Pending Acquisition

 

On February 7, 2007, we announced an agreement with Aquila to purchase utility assets. If completed, the acquisition will dramatically increase the size and scope of our Utilities group. Through the transaction, we will acquire the assets of Aquila’s regulated electric utility in Colorado and their regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The transaction would add approximately 612,000 new utility customers (92,000 electric customers and 520,000 gas customers) to our current customer base. The regulatory approval process is progressing. As of February 29, 2008, approvals have been received from the states of Iowa, Nebraska and Colorado; federal antitrust clearance was obtained under the Hart-Scott-Rodino Act; and FERC has approved of the Colorado Electric acquisition. On February 12, 2008, a hearing was held by the Kansas Corporation Commission on our joint application with Aquila. All the parties to the Kansas proceeding entered into a settlement which was presented at that hearing. A decision by the Kansas regulators is pending. In addition, our purchase of these utility assets is cross-contingent with the merger of Great Plains Energy and Aquila, whose remaining assets would be in the state of Missouri. Great Plains Energy must obtain regulatory approvals in the states of Missouri and Kansas, which are pending.

 

To prepare for the acquisition, we have been expensing certain temporary transition and integration costs as they have occurred, amounting to approximately $4.8 million after tax, for the year ended December 31, 2007. In addition, we have capitalized certain costs relating to the acquisition, amounting to approximately $19.1 million, as of December 31, 2007. The transaction is expected to close in the second quarter of 2008. The Company expects the acquisition to be dilutive to earnings in the first full year of operations. The purchase price of $940 million is expected to be financed through a combination of equity, corporate level debt, mandatory convertible securities, and internally generated cash, which could include cash proceeds from the potential divestiture of certain non-regulated power plant assets.

 

Non-regulated Energy Group

 

Power Generation

 

Earnings from our Power Generation segment in 2008 will benefit from commercial operation of the Valencia plant beginning in the summer of 2008. This will be partially offset by a decrease in earnings and cash flows associated with our receipt from SCE of contract termination payments for the Harbor facility, which will be completed in October 2008.

 

We are conducting a strategic review of our assets within this segment, which may result in the divestiture of certain of our non-regulated power generation assets. Such divestiture would, of course, result in a reduction of future earnings and cash flows, offset initially by any potential gain on sale and ultimately by alternative use of the sale proceeds.

 

Coal Mining

 

Production from the coal mining segment is expected to primarily serve mine-mouth generation plants and select regional customers with long-term fuel needs. Increased demand will come from additional mine-mouth generation either currently being constructed or in various stages of development. A contract to provide coal to PacifiCorp’s Dave Johnston power plant was renegotiated in late 2007. Beginning in 2008, it provides for the sale of up to 1.8 million tons of coal annually through 2011. Previous coal sales to the plant ranged from 0.3 million tons to 1.3 million tons during previous contract years 2001 through 2007. Deliveries to the Wygen II power plant began in late 2007. The demand from the new Dave Johnston and Wygen II contracts is expected to result in a production increase of approximately 1.0 million tons annually. Total annual production is estimated to be approximately 6.0 million tons in 2008, compared to 5.0 million tons in 2007 and 4.7 million tons in 2006 and 2005.

 

We expect lower earnings from this segment in 2008, as higher revenues from production and coal price increases is offset by higher operating expenses. Operating cost increases will be driven by higher labor and equipment costs as overburden ratios and production levels increase. Non-operating income will also decrease as a result of recapitalizing our coal mining subsidiary.

 

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Oil and Gas

 

We expect that earnings from this segment over the next few years will be driven primarily by increased oil and gas production. Our long-term compounded annual production growth target is 2 to 4 percent. Recent results, which have not attained expected performance, reflected weakened economic conditions caused by rapidly increasing capital costs and operating expenses. Consequently, we elected to reduce our drilling program in 2007.

 

As economic conditions merit, we may elect to increase our drilling and production activity. Near term growth is expected to come from development of our 2006 acquisitions in the Piceance Basin and the ongoing development of the San Juan, Powder River and Williston Basins. We expect to deploy approximately $94.2 million of capital in 2008 developing our current properties. We will continue our focus on optimal deployment of capital as drilling and completion costs are expected to continue to rise due to persistent shortages in the industry. Our drilling program is focused on both proved reserves and the further delineation of existing fields, including development of additional locations in the San Juan, Piceance and Powder River Basins. In addition, we may invest in mid-stream assets, such as gathering, compression and treating systems.

 

Energy Marketing

 

We expect lower earnings from this segment in 2008, as 2007 earnings were strong due to unusually favorable natural gas market conditions. A new natural gas pipeline providing expanded transportation services out of the Rocky Mountain region may affect market conditions and the opportunity to effectively exploit certain regional price basis differentials. Continued market volatility will enable us to extract economic value as we look to expand our business. We will continue to focus on producer, end-use origination, and gas storage and transportation services and a regional wholesale marketing strategy. This will be done while maintaining our conservative credit management and lower-risk profile that emphasizes short-term physical transactions.

 

Results of Operations

 

Executive Summary

 

Results for the year 2007 reflect solid utility performance, strong energy marketing results and improved power generation and coal mining performance, while the oil and gas segment results were similar to 2006.

 

Earnings for the utilities increased 31 percent over the prior year. A rate increase for Black Hills Power’s South Dakota service territory went into effect January 1, 2007. Results for Cheyenne Light were impacted by increased AFUDC income attributable to the 95 MW coal-fired Wygen II plant which was placed in commercial service January 1, 2008. In November 2007, the WPSC approved a new rate structure for Cheyenne Light and included the Wygen II plant in the rate base effective January 1, 2008.

 

Strong earnings from energy marketing are primarily attributable to a $30.7 million increase in realized gas marketing margins. Earnings benefited from favorable natural gas market conditions that prevailed throughout 2007. Daily average physical gas volumes marketed increased 9 percent over 2006. This segment also reflects oil marketing operations in the Rocky Mountain region for the full year in 2007.

 

Power generation improved earnings for 2007 as the Las Vegas plants were returned to normal operations after extensive repairs and maintenance in 2006 for scheduled and unscheduled outages. Earnings were also impacted by a $1.8 million after-tax impairment charge for the Ontario plant and $0.4 million after-tax for a goodwill impairment. Lower investment partnership earnings were primarily a result of a partnership impairment charge for the Glenns Ferry and Rupert power plants in which we hold a 50 percent interest. The impairments reduced our equity in earnings of unconsolidated subsidiaries by approximately $2.7 million after-tax.

 

Oil and gas segment earnings were similar to the previous year. A 7 percent increase in revenues was offset by increased operating, depletion and interest costs.

 

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Coal mining earnings increased due to higher average prices received and increased tons of coal sold partially offset by increased overburden expense and higher mineral taxes and royalties due to increased revenues and tons sold.

 

Overview

 

Revenue and Income (loss) from continuing operations provided by each business group were as follows (in thousands):

 

 

 

The Corporate results represent unallocated costs for administrative activities that support the business segments. Corporate also includes business development activities that do not fall under the two business groups.

 

On January 21, 2005, we completed the acquisition of Cheyenne Light, an electric and natural gas utility serving customers in Cheyenne, Wyoming and vicinity. The results of operations of Cheyenne Light have been included in the accompanying Consolidated Financial Statements from the date of acquisition.

 

Discontinued operations in 2007, 2006 and 2005 represents the operations and gain on sale of our crude oil marketing and transportation business, sold in March 2006. In addition to the Houston, Texas based crude oil marketing and transportation operations, the 2005 discontinued operations also include our Communications segment, Black Hills FiberSystems, Inc., which was sold in June 2005; and our 40 MW Pepperell power plant, which was sold in April 2005. Results of operations for 2005 have been restated to reflect the operations discontinued.

 

2007 Compared to 2006

 

Consolidated income from continuing operations for 2007 was $100.1 million, compared to $74.0 million in 2006, or $2.68 per share in 2007, compared to $2.21 per share in 2006. Loss from discontinued operations was $1.4 million, or $0.04 per share, compared to income of $7.0 million, or $0.21 per share in 2006. Results for 2006 include the $8.9 million gain on the sale of the operating assets of the crude oil marketing and transportation business. Return on average common stock equity in 2007 and 2006 was 11.2 percent and 10.6 percent, respectively.

 

The Utilities group income from continuing operations increased $7.4 million in 2007 compared to 2006. Earnings from continuing operations from the electric utility increased $6.2 million primarily due to an increase in retail rates. Earnings from continuing operations from the electric and gas utility increased $1.2 million primarily due to AFUDC and associated tax benefits related to the construction of Wygen II.

 

The Non-regulated energy group’s income from continuing operations increased $19.0 million in 2007, compared to 2006, primarily due to increased earnings from energy marketing of $16.9 million and power generation of $1.5 million.

 

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Unallocated corporate costs for 2007 increased $0.4 million after-tax, compared to 2006. The increase is primarily due to increased acquisition and integration costs for the Aquila acquisition offset by lower interest expense which was allocated down to the subsidiary level in 2007.

 

Consolidated revenues for 2007 were $39.0 million higher than 2006 due to increased revenues from all operating segments, other than the electric and gas utility which had lower revenues primarily due to lower ECA and GCA pass-through cost recovery rate adjustments. We consider gross margin to be a more useful performance measure for the electric and gas utility as fluctuations in cost of electricity and gas flow through to revenues through cost recovery rate adjustments.

 

Consolidated operating expenses for 2007 increased $12.2 million compared to 2006. Increased operating expenses reflect a $3.3 million impairment charge at our power generation segment, increased compensation costs at the energy marketing segment, a $5.6 million increase in depreciation, depletion and amortization expense, primarily due to increased depletion at the oil and gas segment, and a $5.1 million increase in operations and maintenance expense. The increased expenses were partially offset by a $27.6 million decrease in fuel and purchased power primarily due to cost recovery adjustments at the electric and gas utility. The increase in operations and maintenance expense was partially offset by the 2007 receipt of $2.5 million of insurance proceeds as a reimbursement for repair costs incurred in 2006 on the Las Vegas II plant.

 

Income from continuing operations was also impacted by a $10.1 million decrease in interest expense primarily due to the reduction of debt, using in part, proceeds from the issuance and sale of common stock, and the effect of interest capitalization during ongoing construction and development.

 

2006 Compared to 2005

 

Consolidated income from continuing operations for 2006 was $74.0 million, compared to $32.8 million in 2005, or $2.21 per share in 2006, compared to $0.98 per share in 2005. Income from discontinued operations, including the $8.9 million gain on the sale of the operating assets of the crude oil marketing and transportation business, was $7.0 million or $0.21 per share in 2006, compared to income of $0.6 million or $0.02 per share in 2005. Return on average common stock equity in 2006 and 2005 was 10.6 percent and 4.5 percent, respectively.

 

Income from continuing operations for our Utilities group increased $4.1 million in 2006 compared to 2005. Earnings from continuing operations from the electric utility increased $0.7 million and earnings from continuing operations from the electric and gas utility, acquired January 21, 2005, increased $3.4 million primarily due to lower write-offs for bad debt and, AFUDC and related tax effects, related to the Wygen II plant.

 

The Non-regulated energy group’s income from continuing operations increased $29.2 million in 2006 compared to 2005. Increased earnings from power generation of $32.4 million and from energy marketing of $3.5 million were offset by decreased earnings of $5.2 million at our oil and gas operations and $1.1 million from coal mining operations. Earnings at the power generation segment increased due primarily to a $52.2 million impairment charge in 2005.

 

Unallocated corporate costs for the year ended December 31, 2006 decreased $8.0 million after-tax, compared to 2005. The decrease is primarily due to increased allocations of corporate costs and interest expense down to the subsidiary level and the 2005 write-off of approximately $6.4 million after-tax of certain capitalized project development costs and the expensing of other development costs, which are included in Administrative and general operating expenses on the accompanying Consolidated Statements of Income.

 

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Consolidated operating expenses for 2006 decreased $27.5 million compared to 2005. Decreased operating expenses reflect the $52.2 million impairment charge at our power generation segment in 2005 offset by a $13.7 million increase in fuel and purchased power, a $6.0 million increase in depreciation expense and a $3.0 million increase in operations and maintenance. Higher fuel and purchased power costs were primarily the result of the increased cost of sales of electricity and gas at Cheyenne Light, which was acquired during 2005, partially offset by lower purchased power costs at Black Hills Power. The increase in depreciation, depletion and amortization expense is primarily due to higher depletion at the oil and gas segment. Increased operations and maintenance expense is primarily related to scheduled and unscheduled plant outages, partially offset by the receipt of $3.9 million of insurance proceeds for repairs on the Las Vegas II plant in 2006.

 

A discussion of operating results from our business segments follows.

 

The following business group and segment information does not include discontinued operations or intercompany eliminations. Accordingly, 2005 information has been revised to remove information related to operations that were discontinued.

 

Utilities

 

Electric Utility

 

 

The following tables provide certain electric utility operating statistics:

 

 

 

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We established a new summer peak load of 430 MW in July 2007 and a new winter peak load of 361 MW in February 2007. We own 435 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.