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.               x

 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (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 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: retail services and wholesale energy.

 

Retail Services Group

 

Our retail services 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 64,200 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 38,900 electric and 32,600 natural gas customers in Cheyenne, Wyoming and vicinity. We acquired Cheyenne Light on January 21, 2005.

 

Wholesale Energy Group

 

Our wholesale 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.

 

Coal Mining. WRDC mines and sells coal at our coal mine located near Gillette, Wyoming.

 

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 Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa along with the associated 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 616,000 new utility customers (93,000 electric customers and 523,000 gas customers) to the 137,000 utility customers (104,000 electric customers and 33,000 gas customers) we currently serve. Other assets included in the transaction include a customer service center and centralized natural gas operation in Nebraska.

 

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At the same time we entered into our agreements with Aquila, Aquila also entered into an agreement with Great Plains for the merger of Gregory Acquisition Corp., a subsidiary of Great Plains, with and into Aquila. Each transaction is contingent on the completion of the other transaction, meaning that one transaction will not be completed unless the other transaction is completed. Completion of the transactions is subject to various conditions, including: (i) approval of the FERC; (ii) approval of the Colorado Public Utilities Commission, Iowa Utilities Board, Kansas Corporation Commission, and Nebraska Public Service Commission; (iii) the expiration or early termination of any waiting period under the Hart-Scott-Rodino Antitrust Act of 1976, as amended; (iv) the absence of a material adverse effect on the utility businesses being sold to us; and (v) the ability and readiness of Aquila, Great Plains and Gregory Acquisition Corp. to complete the merger immediately after the completion of the asset sale transactions.

 

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.

 

Retail Services Group

 

Our retail services 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 businesses serve approximately 64,200 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 91 percent of Black Hills Power’s retail electric revenues in 2006 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. We sell a portion of Black Hills Power’s current load under long term contracts. Our 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:

 

 

Since 1995, Black Hills Power has been a net producer of energy. Black Hills Power reached its peak system load of 415 MW in July 2006, with an average system load of 249 MW for the year ended December 31, 2006. None of Black Hills Power’s generation is restricted by hours of operation, thereby providing the ability to generate power to meet demand whenever necessary and economically feasible.

 

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 from our WRDC coal mine, which is delivered by truck.

 

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 from our WRDC coal mine, which is delivered by truck.

 

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. Two consecutive rate freezes granted by the SDPUC, which were in effect for Black Hills Power since 1995, expired on January 1, 2005. During this ten-year term, Black Hills Power was prohibited, subject to certain limited exceptions, from filing for any increase in its rates or invoking any fuel and purchased power adjustment tariff which would take effect during the freeze period. On June 30, 2006, Black Hills Power filed an application with the SDPUC for an increase in its electric rates for South Dakota customers and to provide automatic adjustment of rates for changes in energy, fuel and transmission costs. On December 28, 2006, the SDPUC approved a rate increase of 7.8 percent along with the addition of tariff provisions which provide for the automatic adjustment of rates. The rates and new tariff provisions are effective beginning January 1, 2007. Terms of the settlement agreement with the SDPUC include the following:

 

 

 

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Combination Electric and Gas Utility Segment

 

Electric System. Cheyenne Light’s electric system serves approximately 38,900 customers in Cheyenne, Wyoming and vicinity, with a peak load of 163 MW and an average load of 112 MW. Power is supplied to Cheyenne Light under an all-requirements contract with PSCo, which expires at the end of 2007. For power needs after 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 is also constructing a 90 MW coal-fired plant (Wygen II) adjacent to the WRDC coal mine near Gillette, Wyoming, which is expected to be in service by the end of 2007. On November 22, 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 pending regulatory and other approvals and is anticipated to provide up to 30 MW of renewable power to Cheyenne Light beginning in early 2008.

 

Natural Gas System. Cheyenne Light’s natural gas distribution system serves approximately 32,600 natural gas customers in the City of Cheyenne and other portions of Laramie County, Wyoming. Cheyenne Light’s annual natural gas sales to commercial and residential customers for 2006 were approximately 4.4 million Dth. 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. 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 and GCA filings are made at least annually and 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 October 2005, the WPSC approved a 3.65 percent and 5.11 percent increase in Cheyenne Light’s base rates for gas and electric service, respectively, effective on January 1, 2006.

 

Business Characteristics

 

The following business characteristics are common within our Retail Services 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 in varying degrees exists for our retail services 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 some industrial and large customers have the ability to own or operate facilities to generate their own electricity. 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 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 power 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 amended portions of the Federal Power Act and also amended portions of the PURPA.

 

Public Utility Holding Company Act of 1935. On December 28, 2004, we became a registered holding company under PUHCA. As a registered holding company, we were subject to regulatory oversight by the SEC. The rules and regulations imposed a number of restrictions on the operations of registered holding company systems. These restrictions included, subject to certain exceptions, a requirement that the SEC approve securities issuances, payments of dividends out of capital or unearned surplus, sales and acquisitions of utility assets or of securities of utility companies, and acquisitions of other businesses. In connection with our registration, we formed a service company, Black Hills Service Company, L.L.C., to provide common services to affiliates such as accounting, administrative, human resources, information systems, engineering, financial, legal, maintenance and other services. With the passage of EPA 2005, PUHCA was repealed and the oversight of public utility holding companies was transferred to FERC effective February 8, 2006.

 

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 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.

 

PCBs. Under the federal Toxic Substances Control Act, the EPA has issued regulations that control the use and disposal of PCBs. PCBs were widely used as insulating fluids in many electric utility transformers and capacitors manufactured before the Toxic Substances 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.

 

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Air Quality. Our Neil Simpson II, Neil Simpson CT, Lange CT, Wyodak and Wygen II plants are all subject to Title IV of the Clean Air Act, which requires certain fossil-fuel-fired combustion devices to hold SO2 “allowances” for each ton of sulfur dioxide emitted. 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 2035, 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 dictates that all of our fossil-fuel-fired generation facilities must obtain operating permits. All of our existing facilities subject to this requirement have submitted Title V permit applications and have received permits.

 

In March 2005, the EPA issued mercury emission requirements for fossil-fuel-fired steam electric power plants. Neil Simpson II and Wyodak will be subject to the monitoring, cap and trade requirements beginning in 2010. Our air permit for Wygen II requires mercury removal and therefore Wygen II is one of the first coal-fired plants to incorporate mercury reduction technology. Wygen II will be subject to “cap and trade” requirements beginning in 2010. There are several pending legal actions involving other parties, challenging various aspects of the mercury rule. Until these legal actions and emission control system evaluation efforts are finalized, we cannot fully evaluate the impact of mercury regulations on the operation of our facilities.

 

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, 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.

 

Clean Water Act. Our existing facilities are also 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 authority of the Clean Water Act and govern overall water/wastewater discharges through NPDES permits. Under current provisions of the Clean Water Act, existing NPDES permits must be renewed every five years, at which time permit limits are extensively reviewed and can be modified to account for changes in regulations or program initiatives. Some of our existing facilities have been operating under NPDES permits for many years and have gone through one or more NPDES permit renewal cycles. 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 regulated under this program have their required plans in place.

 

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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 milder 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.

 

Wholesale Energy Group

 

Our wholesale 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; we produce coal, natural gas and crude oil primarily in the Rocky Mountain region; and market and store natural gas and crude oil. The wholesale energy group consists of four business segments for reporting purposes:

 

 

Oil and Gas Segment

 

Our oil and gas segment, which operates through BHEP and its subsidiaries, acquires, explores, develops and produces natural gas and crude oil. As of December 31, 2006, we held operated interests in oil and gas properties totaling approximately 625 gross and 571 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 Denver Julesberg Basin of Colorado and Nebraska. 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 also hold non-operated interests in oil and natural gas properties totaling approximately 511 gross and 71 net wells located in California, Colorado, Louisiana, Montana, North Dakota, Oklahoma, Texas and Wyoming.

 

We also own a 44.7 percent 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, 2006, we had total reserves of approximately 199 Bcfe, of which natural gas comprised 83 percent of total reserves 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 36 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, and 23 percent are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field of Weston and Niobrara counties.

 

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An expanding area of operated interests is in multiple fields of the Piceance Basin of Colorado, which now represents 35 percent of our total reserves, of which approximately 67 percent are undeveloped. In December 2005, the Company completed the acquisition of certain Piceance Basin gas assets from Red Oak Capital Management, LLC, Plateau Creek Partners, LP and other working interests in the Plateau Field, Mesa County, Colorado. The Company acquired approximately 13,000 net acres of oil and gas leasehold, and interests in a number of producing and shut-in wells. The acreage is mostly undeveloped. On March 17, 2006, effective as of January 1, 2006, we acquired certain oil and gas assets of Koch Exploration Company, LLC, including approximately 40.0 Bcf of proved reserves, which are almost entirely natural gas, and associated midstream and gathering assets. The associated acreage position is in the Piceance Basin in Colorado adjacent to the properties acquired from Red Oak in 2005, and is comprised of leases covering more than 31,000 gross and 18,000 net acres, of which more than 48 percent are presently undeveloped. The acquisition included 63 wells, of which 58 were operated by Koch Exploration Company. Finally, on August 17, 2006, effective as of April 1, 2006, we completed the acquisition from a third party of most of the remaining working interests associated with the property acquired from Koch Exploration Company. The acquisition included approximately 22.4 Bcf of proved reserves together with an interest in associated midstream and gathering assets. The acquisition included interests in leases covering more than 15,000 net acres.

 

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 based on reports prepared by Ralph E. Davis Associates, Inc., an independent consulting and engineering firm. Reserves were determined 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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The following table reflects average wellhead pricing used in the determination of the present value of estimated future net revenues, before tax:

 

 

Drilling Activity

 

The following tables reflect the wells completed through our drilling activities for the last three years. In 2006, we participated in drilling 106 gross (60.01 net) development and exploratory wells, with a success rate of approximately 95 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.

 

 

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As of December 31, 2006, we were participating in the drilling of 34 gross (9.75 net) wells, which had been commenced but not yet completed.

 

Recompletion Activity

 

The following table reflects our recompletion activities for the year ended December 31, 2006:

 

 

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:

 

 

 

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Productive Wells

 

The following table summarizes our gross and net productive wells at December 31, 2006:

 

 

Acreage

 

The following table summarizes our undeveloped, developed and total acreage by state as of December 31, 2006 (in thousands):

 

 

        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.

 

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        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 and pollution and protection of the environment. 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, 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 changing regulatory standards.

 

These regulations require permits to drill wells, bonding requirements to drill or operate wells, and regulations regarding the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various 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, while other states rely on voluntary pooling of lands and leases. The effect of these regulations can 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.

 

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 transportation operations on such lands.

 

        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, and underground injection control disposal permits), and the remediation of petroleum-product contamination.

 

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 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 23 to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

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Power Generation Segment

 

Our power generation segment 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, 2006. We also hold minority interests in several power-related funds with a net ownership interest of 11 MW.

 

Portfolio Management. We maintain a geographically diverse portfolio of power plants in our wholesale 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 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 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, 2006, 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.

 

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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 initially expires on July 31, 2007. 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 the same site as our Wygen I plant and WRDC coal mine. 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 expires December 31, 2007. Upon expiration of PSCo’s all-requirements power purchase agreement with Cheyenne Light, the Gillette CT power purchase agreement reverts back to Cheyenne Light. During the remaining term of the temporary assignment, we assume intra-month fuel price risk since the fuel price is fixed at the outset of each month and PSCo has the right to dispatch the facility on a day-ahead basis. We can remarket the energy that is not prescheduled by PSCo.

 

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 the first quarter of 2003. 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 February 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. After the PSCo contract expires on December 31, 2007, the output will then revert 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.

 

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 terminates in November 2007. In order to maintain QF status and the underlying power purchase agreement, the project must maintain a thermal energy host.

 

Harbor Cogeneration Facility. Harbor Cogeneration is a 98 MW, combined-cycle, gas-fired plant located at the Port of Long Beach, California. We sell all of the capacity and energy of the facility to SCE under a tolling agreement, which expires May 31, 2008. 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 $12.0 million in 2007 and $8.4 million in 2008.

 

Idaho Cogeneration Facilities. We own a 50 percent interest in two QF facilities in Rupert and Glenns Ferry, Idaho. Rupert and Glenns Ferry are both 11 MW, combined-cycle, gas-fired plants. Electrical output from the facilities is sold to Idaho Power Company under 20-year Energy Sales Agreements, which expires in late 2016. The projects also sell steam production to Idaho Fresh-Pak, Inc. under Thermal Energy Service Agreements, which also expire in late 2016.

 

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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 11 MW. We account for our investment in the funds under the equity method of accounting and as of December 31, 2006, we had a $5.5 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.

 

 

Project Development Program. Through our project development program, we 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 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 implementing the enactment of 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.

 

 

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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.

 

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 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 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, Idaho and Ontario facilities as QFs. The enactment of EPA 2005 does 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.

 

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Environmental Regulation.

 

Air Quality. Our Gillette CT, Wygen I, Arapahoe, Valmont, Fountain Valley and Las Vegas II plants are all subject to Title IV of the Clean Air Act, which requires certain fossil-fuel-fired combustion devices to hold SO2 “allowances” for each ton of sulfur dioxide emitted. We currently hold sufficient allowances credited to us as a result of sulfur removal equipment previously installed at the electric utility’s Wyodak plant to apply to the operation of all units subject to Title IV through 2035 without requiring the purchase of any additional allowances. With respect to any future plants, we plan to comply with allowance requirements by reducing sulfur dioxide 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 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 fossil-fuel-fired generation facilities must obtain operating permits. All of our existing facilities subject to this requirement have submitted Title V permit applications and have received permits.

 

In March 2005, the EPA issued mercury emission requirements for fossil-fuel-fired steam electric power plants. Wygen I will be subject to the monitoring, cap and trade requirements beginning in 2010. Testing at Wygen I was conducted during 2006, to gain understanding and knowledge of the mercury control and monitoring technology, which in turn will enable us to determine the best approach to managing compliance with Wyoming mercury emission caps. There are several pending legal actions involving other parties, challenging various aspects of the mercury rule. Until these legal efforts and emission control system evaluation efforts are finalized, we cannot fully evaluate the impact of mercury regulations on the operation of our facilities.

 

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 re-evaluating 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.

 

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 of solid waste. In that event, the government regulator could consequently hold those entities that disposed of such waste responsible for such treatment.

 

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Clean Water Act. Our existing facilities are also 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 authority of the Clean Water Act and govern overall water/wastewater discharges through NPDES permits. Under current provisions of the Clean Water Act, existing NPDES permits must be renewed every five years, at which time permit limits are extensively reviewed and can be modified to account for changes in regulations or program initiatives. In addition, the permits have reopener clauses which allow the permitting authority (which may be the United States or an authorized state) to attempt to modify a permit to conform to changes in applicable laws and regulations. Some of our existing facilities have been operating under NPDES permits for many years and have gone through one or more NPDES permit renewal cycles. 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.

 

Coal Mining Segment

 

Our coal mining segment operates through our WRDC subsidiary. We mine and process low-sulfur, sub-bituminous 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 4.7 million tons of coal in 2006. 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, 2006, we had coal reserves of approximately 285 million tons, based on internal engineering studies. The reserve life is equal to approximately 55 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 for all of its requirements under an agreement that limits earnings from all coal sales to Black Hills Power, including the 20 percent share on the Wyodak plant and all sales to Black Hills Power’s other plants, 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 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.

 

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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.

 

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 otherwise in compliance with other permitting programs administered by various regulatory agencies.

 

Based on extensive reclamation studies, we currently have approximately $16.0 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 reevaluate 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 in the WDEQ’s water quality standards.

 

Another situation that could result in unexpected increases in costs is the current State of Wyoming re-examination 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 due to loss of mine backfill and for specialized placement of ash at alternate approved sites within the mine.

 

Energy Marketing Segment

 

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. We engage in physical and financial wholesale energy marketing and offer storage and transportation services as well as price risk management products and services to a variety of customers. The customers of our energy marketing segment include:

 

 

 

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Our average daily marketing physical volumes for the year ended December 31, 2006 were approximately 1.6 million MMBtu of gas, and for the period May 1, 2006 to December 31, 2006 were approximately 8,800 barrels of oil.

 

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.

 

Our energy marketing operations focus primarily on producer services, origination and wholesale marketing services. Our producer services include purchases of wellhead gas and crude oil and risk transfer and hedging products for gas producers. Our gas and oil marketing efforts are concentrated in the Rocky Mountain, Western and Mid-continent regions of the United States and in Canada. We hold, under contract, both long- and short-term natural gas storage and transportation capacity on several major pipelines in the western and mid-continent regions of the United States and in Canada.

 

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.

 

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 policy 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 guarantees for energy marketing; as of December 31, 2006, we had no 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 and a warehouse building and shop with approximately 25,200 square feet and lease an additional 12,180 square feet of office space. 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.

 

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Employees

 

At January 31, 2007, we had 819 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:

 

 

 

 

 

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.

 

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 or the WPSC. 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 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 and changes 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 would impair our ability to execute our growth strategy.

 

Execution of our future growth plan is dependent on successful completion of 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 new acquisition.

 

Successful acquisitions require an assessment of a number of factors, many of which are beyond our control and are inherently uncertain. Factors which may cause our actual results to differ materially from 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 costs of borrowing under some of our existing debt obligations, including borrowings made under our revolving credit facility, our $128.3 million Wygen I plant project financing, our $86.8 million Black Hills Colorado project financing and our $24.2 million General Electric Capital Corp. secured financings.

 

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

 

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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.

 

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.

 

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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 the past year, 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 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.

 

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.

 

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 power generation, distribution and energy marketing operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. In the past several years, a substantial number of energy companies have experienced downgrades in their credit ratings, some of which 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 sell the plant’s power at 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.

 

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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.

 

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 in South Dakota or Wyoming 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.

 

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We have recently 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 various approvals from the FERC and various utility regulatory, antitrust and other authorities in the United States. 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.

 

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 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 our acquisition of those assets is subject to a number of uncertainties and we cannot assure you 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 intend to take 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.

 

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 affected.

 

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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 assure you 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.

 

We can provide no assurance that we will be able to close our proposed new acquisition credi facility, or any necessary backstop revolving credit facility. Inability to close on these facilities could adversely impact our ability to complete the Aquila transaction.

 

We have obtained a commitment letter with respect to a new $1.0 billion senior unsecured credit facility to, among other things, fund our acquisition of the utility assets. We have also obtained a commitment letter with respect to a $500.0 million, 364 day backstop revolving credit facility. Should we be unable to obtain sufficient lender consent to amend our existing revolving credit facility to allow for the proposed Aquila transaction, the backstop revolving credit facility would refinancing our existing facility. Our ability to borrow amounts under our proposed new acquisition credit facility or a backstop revolving credit facility will be subject to the execution of customary documentation, including security documents, satisfaction of certain customary conditions precedent and compliance with terms and conditions included in the loan documents. Prior to each drawdown under either the acquisition facility or a backstop facility, we will be required, among other things, to meet specified financial ratios and other requirements. To the extent that we are not able to satisfy these requirements, we may not be able to draw down the full amount of the facilities which could adversely impact our ability to complete the Aquila transaction.

 

Restrictive covenants in our proposed new acquisition credit facility will impose financial and other restrictions on us, including our ability to pay dividends.

 

Our proposed new acquisition facility will impose operating and financial restrictions on us and will require us to comply with certain financial covenants. These restrictions and covenants may limit our ability to, among other things:

 

 

 

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Therefore, we may need to seek permission from the lenders under our acquisition facility in order to engage in some corporate actions. Our lenders’ interests may be different from ours and we cannot guarantee that we will be able to obtain our lenders’ consent when needed. If we do not comply with the restrictions and covenants in our proposed acquisition facility, we will not be able to pay dividends, finance our future operations, make acquisitions or pursue business opportunities.

 

Geopolitical tensions may impair our ability to raise capital and limit our growth.

 

Continuing conflict in Iraq and tensions between the United States and other governments could disrupt capital markets and make it more costly or temporarily impossible for us to raise capital, thus hampering the implementation of our stated strategy. In the past, geopolitical events, including the uncertainty associated with the Gulf War in 1991 and the terrorist attacks of September 11, 2001, were associated with general economic slowdowns. Geopolitical tensions or other factors could retard economic growth and reduce demand for the power and fuel products that we produce or market, both of which could adversely affect our earnings.

 

 

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 2006.

 

 

David R. Emery, age 44, was elected Chairman in April 2005 and President and Chief Executive Officer and a member of the Board of Directors in January 2004. Prior to that, he was our President and Chief Operating Officer – Retail Business Segment from April 2003 to January 2004 and Vice President – Fuel Resources from January 1997 to April 2003. Mr. Emery has 17 years of experience with us.

 

Thomas M. Ohlmacher, age 55, has been the President and Chief Operating Officer of our Wholesale Energy Group since November 2001. He served as Senior Vice President – Power Supply and Power Marketing from January 2001 to November 2001 and Vice President – Power Supply from 1994 to 2001. Prior to that, he held several positions with our company since 1974. Mr. Ohlmacher has 32 years of experience with us.

 

Linden R. Evans, age 44, was appointed President and Chief Operating Officer – Retail Business Segment in October 2004. Mr. Evans had been serving as the Vice President and General Manager of our former communication subsidiary since December 2003, and served as our Associate Counsel from May 2001 to December 2003. Mr. Evans has 5 years of experience with us.

 

Mark T. Thies, age 43, has been our Executive Vice President and Chief Financial Officer since March 2000. From May 1997 to March 2000, he was our Controller. Mr. Thies has 9 years of experience with us.

 

Steven J. Helmers, age 50, 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 6 years of experience with us.

 

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Maurice T. Klefeker, age 50, was appointed Senior Vice President – Strategic Planning and Development in March 2004. Prior to that, he served as Senior Vice President of our subsidiary, Black Hills Generation, Inc. from September 2002 to March 2004 and as Vice President of Corporate Development from July 2000 to September 2002. Mr. Klefeker has 7 years of experience with us.

 

James M. Mattern, age 52, 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 19 years of experience with us.

 

Roxann R. Basham, age 45, was appointed Vice President – Governance and Corporate Secretary in February 2004. Prior to that, she was our Vice President–Controller from March 2000 to January 2004. Ms. Basham has a total of 23 years of experience with us.

 

Kyle D. White, age 47, has been Vice President – Corporate Affairs since January 30, 2001 and Vice President – Marketing and Regulatory Affairs since July 1998. Mr. White has 24 years of experience with us.

 

Garner M. Anderson, age 44, was appointed Vice President, Treasurer and Chief Risk Officer in October 2006. He had served as Vice President and Treasurer since July 2003. Mr. Anderson has 18 years of experience with us, including positions as Director – Treasury Services and Risk Manager.

 

Perry S. Krush, age 47, was appointed Vice President – Controller in December 2004. Mr. Krush has 18 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.

 

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PART II

 

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of February 1, 2007, we had 5,129 common shareholders of record and approximately 15,400 beneficial owners, representing all 50 states, the District of Columbia and 11 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 February 2007 meeting, our board of directors raised the quarterly dividend to $0.34 per share, equivalent to an annual dividend of $1.36 per share, marking the 37^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 2.5:1.0, our recourse leverage ratio exceeds 0.65:1.00 or our consolidated net worth does not exceed the sum of $625 million and 50 percent of our aggregate consolidated net income since January 1, 2005. As of December 31, 2006, we are in compliance with all covenants and accordingly are not restricted from paying any currently declared 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 THE FOURTH QUARTER OF 2006

 

No unregistered securities were issued during the fourth quarter of 2006.

 

ISSUER PURCHASES OF EQUITY SECURITIES

 

_________________________

 

 

 

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ITEM 6.  SELECTED FINANCIAL DATA

 

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____________________________________

Certain items related to 2002 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 recorded to reduce the carrying value of long-lived assets to fair value were approximately $33.9 million after-tax in 2005, and approximately $76.2 million after-tax in 2003.

 

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 – retail services and wholesale energy. We report for our business groups in the following financial segments:

 

 

Our retail services 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 64,200 customers in South Dakota, Wyoming and Montana. Cheyenne Light serves approximately 38,900 electric customers and 32,600 natural gas customers in Cheyenne, Wyoming and vicinity. Our wholesale 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.

 

 

 

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Industry Overview

 

The U.S. energy industry experienced another year of strong economic performance in 2006. 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 the summer of 2006 and through early winter, reducing demand for fuel used for power generation and heating. At year-end 2006, domestic supplies of natural gas in storage were well above historical averages.

 

Progress in the energy industry in 2006 included the discovery of substantial oil and gas reserves in the Gulf of Mexico, increased exploration and production of oil and natural gas in the lower 48 states, continued planning and construction of liquefied natural gas port facilities, the proposal of additional coal-fired and nuclear power plants, the advancement of renewable energy resources and utilization. The industry has also experienced better cooperation between regulators and energy providers in many states seeking cooperative, constructive solutions to ongoing issues and rate cases.

 

The energy industry continues to adjust to change, including the trends of consolidation in the electric and gas utility sectors, increased private equity investment, and asset divestitures to narrow business strategies. The energy market place is still adjusting to the repeal of PUHCA, effective in early 2006; 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. As a result, the independent and merchant power industry was challenged in its ability to increase its market presence.

 

In the past year, the corporate structure of many energy companies underwent evaluation and change, largely from efforts to create additional shareholder value. Some companies are contemplating or implementing a realignment of assets, reflecting shifts in longer-term business strategies. Others are divesting certain energy properties to focus on core businesses, such as exiting unregulated power production or oil and gas production in favor of utility operations. Others continue to engage in mergers and acquisitions in a quest to improve economies of scale and returns to investors.

 

Many industry analysts expect an increase in capital investments across a wide spectrum of energy companies. A number of electric and gas utilities need to replace aging plants and equipment, and regulators are providing favorable recognition in rates for additional investment. Oil and gas producers are expected to continue to increase capital spending in response to relatively high prices. In response to relatively high seasonal supplies of natural gas and widening regional price differentials capital spending in certain producing areas may moderate or even be curtailed.

 

In 2006, the domestic coal industry benefited from a stronger 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. Some deliveries of Powder River Basin coal in Wyoming were hampered by transportation disruptions, causing temporary difficulties for utilities in the West and Midwest. Fossil fuel combustion continues to be a contentious domestic and international public policy issue, as many nations, including U.S. allies, advocate reductions in carbon dioxide emission. Many states now encourage the industry to invest in renewable energy resources, such as wind power or the use of bio-mass as a fuel. In some instances, renewable energy use is mandated by state regulators. In the case of California, a new adopted interim standard requires that future imports of power must come from power plants with lower emission levels than currently associated with conventional coal-fired plants. Such restrictions could 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 fraction of those produced by power plants built a generation ago. As a result, coal remains an important, domestically available, and economical national energy resource that is vital to meet growing energy demand.

 

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, the demand for energy is expected to increase steadily over time.

 

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Business Strategy

 

We are a customer-focused integrated energy company. Our business is comprised of retail utility assets, including electric and gas distribution systems, fuel assets and electric generation assets. To optimize the value of our assets, we utilize our energy marketing and transportation expertise. Our focus on customers, whether retail utility customers, wholesale generation or marketing customers, provides opportunities to expand our businesses. Our balanced, integrated approach to retail utility operations, fuel production, power generation and energy marketing is supported by disciplined risk management practices. The diversity of our operations reduces reliance on any single business to achieve our strategic objectives. Our diversity 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 stronger returns over the long term. The strength and stability of our balance sheet is critical in today’s market. Access to capital, sufficient liquidity and quality of earnings are our key drivers.

 

Our long-term strategy is to continue expanding our core retail utility, fuel asset and generation businesses, supplemented by our energy marketing operations. We will do this primarily by focusing on providing superior economic and performance value to customers, and by increasing our customer base. In the retail area, we seek to grow our existing utility asset base through construction of new rate-based generation facilities, and by adding new customers through the acquisition of additional retail utility properties, while maintaining our high customer service and reliability standards. In the fuel production area, we will continue to develop our existing inventory of oil and gas reserves while striving to maintain our positive relationships with mineral owners and regulatory authorities and working to develop additional markets for our coal production, including the development of additional power plants at our mine site. Our power generation business will focus on long-term contractual relationships with key wholesale customers, as well as new customers that will allow us to expand existing generation sites, or to construct or acquire new generation facilities. The expertise of our energy marketing business will continue to enable us to optimize the value of our asset-based businesses.

 

The following are key elements of our business strategy:

 

 

 

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

 

Expand retail operations through selective acquisitions of electric and gas utilities consistent with our regional focus and strategic advantages. For more than 65 years, we have provided strong retail utility services, based on delivering quality and value to our customers. Our tradition of accomplishment is expected to support efforts to expand our retail operations in other markets, most likely in the Midwest, West and in regions that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation, system reliability, superior customer service and relationship-based approach to regulatory matters. The January 2005 acquisition of Cheyenne Light and the February 2007 announcement of the proposed acquisition of certain electric and gas utility assets of Aquila are examples of such expansion efforts. Retail operations also enhance other important business development, including gas transmission pipelines and storage infrastructure, which could promote other wholesale operations. Regulated retail utility operations can contribute substantially to the stability of our long-term cash flows, earnings and dividend policy.

 

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 today, where we are investing in and operating 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, they 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.

 

We continue to advance our strategy as evidenced by the construction of Wygen II and the development and permitting of Wygen III. Construction of the 90 MW, coal-fired Wygen II plant is currently on schedule. Cost of the plant is currently expected to be approximately $182 million, including interim financing costs during construction. We expect to file a rate case in the first quarter of 2007 to recover the cost of Wygen II. In early 2007, we received a regulatory issued air permit for the Wygen III power plant. This enables us to move forward with other regulatory processes with the goal of commencing construction in late 2007 or early 2008.

 

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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 recently announced definitive agreement to acquire Aquila’s utility properties in five states will significantly increase 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 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. We will also need to access the capital markets to secure capital sufficient to fund our acquisition. This could be impacted by our ability to maintain our investment grade issuer credit rating. We expect that the acquisition will result in multiple benefits. We will strive to integrate our current and acquired utility operations to achieve these anticipated benefits.

 

Grow our reserves and increase 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:

 

 

Grow our energy marketing operations primarily through the expansion of producer and end-use origination services and, as warranted by the market, 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 to capitalize on market volatility by utilizing storage, transportation and proprietary trading positions. 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 wholesale marketing division 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. We have also added oil marketing within the Rocky Mountain region to our business portfolio and in the future may seek to construct and/or acquire mid-stream assets, such as regional pipelines, to facilitate and augment our marketing services.

 

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Selectively grow our power generation segment by developing and acquiring power generating assets in targeted western markets and, in particular, by expanding generating capacity of our existing sites through a strategy known as “brownfield development.” We aim to develop 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 on small-scale buildouts to serve incremental growth and improve likelihood of permitting and siting.

 

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 and Harbor sites in particular provide further opportunities for significant expansion of our gas- and coal-fired generating capacity over the next several years.

 

Increase earnings from our coal production through an expansion of mine-mouth generation and increased 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.

 

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. As an increasing number of gas-fired power plants are brought into operation, we intend to utilize a low-cost power production strategy, together with access to coal and natural gas reserves, to protect our revenue stream. Low marginal 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. We aggressively manage each of these factors with the goal of achieving very low production costs.

 

Our 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.

 

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.

 

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Conduct business with a diversified group of creditworthy or sufficiently collateralized counterparties. 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 that reports to our board of directors.

 

Sell a large percentage of our capacity and energy production from our independent power projects through mid- and long-term contracts primarily to load-serving utilities in order to secure a stable revenue stream and attractive returns. By selling the majority of our energy and capacity under mid- and long-term contracts, 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-approved contracts primarily to load serving utilities.

 

The first of our long-term power contracts expires in 2010, and nearly all expire before 2014. Such 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 state 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, and in advantageous locations with 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 with preliminary planning accordingly.

 

Build and maintain strong relationships with wholesale power customers. We strive to build strong relationships with utilities, municipalities and other wholesale customers, who we believe will continue to be the primary providers of electricity to retail customers in a deregulated environment. 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.

 

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.

 

Retail Services Group

 

Electric Utility

 

Business at our electric utility, Black Hills Power, remained strong in 2006. We believe that Black Hills Power will produce modest growth in revenue, and absent unplanned plant outages, it will 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 percent, with the system demand forecasted to increase at a rate of 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.

 

49

On June 30, 2006, Black Hills Power filed an application with the SDPUC for an electric rate increase to be effective January 1, 2007. On December 28, 2006, the SDPUC approved a rate increase of 7.8 percent along with the addition of tariff provisions which provide for the automatic adjustment of rates, effective January 1, 2007. The cost adjustments would require the electric utility to absorb a portion of power cost increases, depending in part on earnings from certain short-term wholesale sales of electricity. Absent certain conditions, the order also restricts Black Hills Power from requesting an increase in base rates that would go into effect prior to January 1, 2010. The previous rate structure, in place since 1995, did not contain fuel or purchased power adjustment clauses and only provided the ability to request rate relief from energy costs in certain defined situations. South Dakota retail customers account for approximately 91 percent of the electric utility’s total retail revenues.

 

Electric and Gas Utility

 

We acquired Cheyenne Light on January 21, 2005. We requested and received approval from the WPSC for a rate increase that went into effect on January 1, 2006. We are on schedule with construction of Wygen II, a 90-MW baseload coal-fired power plant. The plant will be a regulated asset of Cheyenne Light. The facility is currently expected to cost approximately $182 million, including interim financing costs during construction. This power plant is expected to be in commercial operation by the end of 2007 and will require a rate review with the WPSC in order to recover capital and provide a return on invested capital. Presently, power is provided by PSCo under an all-requirements contract, which expires December 31, 2007. In addition, Cheyenne Light entered into a 20-year contract to purchase supplemental power of up to 30 MW of renewable wind power, beginning in 2008, pending regulatory and other approvals. 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.

 

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 Retail services group. Through the transaction, we will acquire Aquila’s one regulated electric utility in Colorado and their regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The transaction would add approximately 616,000 new utility customers (93,000 electric customers and 523,000 gas customers) to our current customer base.

 

Wholesale Energy Group

 

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 10 percent. Near term growth will come from development of our 2006 acquisitions in the Piceance Basin and the ongoing development of the San Juan and Piceance Basins.

 

We expect to deploy approximately $72.0 million of capital in 2007 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 Basin resulting from an approved increased density order received on January 30, 2007. We are also encouraged by recent approvals on our non-operated properties in Montana and Oklahoma. These approvals provide high confidence drilling opportunities in areas of well developed gathering infrastructure.

 

Energy Marketing

 

We expect lower earnings from this segment in 2007, as 2006 earnings were stronge due to advantageous market conditions. 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.

 

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Power Generation

 

We expect higher earnings from our Power Generation segment in 2007 primarily as a result of satisfactorily resolving maintenance issues in 2006 at our Las Vegas facility. In January 2006, the Las Vegas II plant was taken off line for diagnosis and initiation of repairs of both of its heat recovery steam turbine generators. We restored this plant’s capacity and energy availability as of July 2006. At the Las Vegas I power plant, an extensive maintenance program initiated in the fourth quarter of 2005 was completed in April 2006. There were no major maintenance issues in the last six months of 2006 and contracted fleet plant availability was 97.9 percent during this period.

 

Coal Mining

 

Production from the coal mining segment is expected to primarily serve mine-mouth plant generation and select regional customers with long-term fuel needs. Assuming no significant coal-fired plant outages, we expect increased earnings from higher production rates, even though operating costs will increase due to higher equipment and labor costs, resulting from higher overburden ratios and increased production. Increased demand will come from additional mine-mouth generation either currently being constructed or in the permitting stages of development. A contract to provide coal to the Dave Johnston power plant expires in 2007. We currently have a put option to sell additional coal to the plant through 2009 and have begun to negotiate a possible contract renewal.

 

Recent Corporate Events

 

On February 22, 2007, we completed the sale of approximately 4.17 million shares of common stock at a price of $36.00 per share, to certain institutional investors through a private placement offering. The Company used the proceeds, net of issuance costs, for debt reduction.

 

Results of Operations

 

Consolidated Results

 

Results for the year 2006 reflect solid utility performance, strong energy marketing results and improved power generation performance. Results for the year also reflect the impacts of scheduled and unscheduled plant outages and lower natural gas prices.

 

Earnings for Black Hills Power increased 4 percent over the prior year. Plant availability for Black Hills Power was 97.1 percent, despite scheduled and unscheduled plant outages at the Wyodak plant. Cheyenne Light results reflect a rate increase, effective January 1, 2006, and a full year of operations. Construction of the 90 MW coal-fired Wygen II plant is on schedule and expected to be in commercial service by January 1, 2008.

 

Strong earnings from energy marketing are attributable to a $24.3 million increase in realized marketing margins, partially offset by a $10.8 million loss in unrealized mark-to-market losses. Daily average physical gas volumes marketed increased 12 percent over 2005. This segment also commenced oil marketing operations in the Rocky Mountain region beginning in May 2006.

 

Power generation improved earnings for 2006 as the Las Vegas plants were returned to normal operations after extensive repairs and maintenance for scheduled and unscheduled outages. This segment had contracted fleet power plant availability of over 93 percent for the year, despite the plant outages.

 

The earnings decline for the oil and gas segment is primarily due to lower average prices received for gas and increased LOE and depletion costs. Production was 14.4 Bcfe for the year, a 5 percent increase over 2005. Fourth quarter 2006 production, on a Bcfe basis, increased 15 percent over the fourth quarter of 2005 reflecting our successful drilling efforts, primarily in the San Juan Basin. This increased production trend is expected to continue with production from the San Juan Basin augmented by increased production from the Piceance Basin, which was acquired in 2006. Year-end oil and gas reserves were lower than expected as price and technical performance issues affected the year-end calculation.

 

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Coal mining earnings decreased due to increased overburden expense resulting from a change in accounting, and higher mineral taxes, partially offset by increased revenues resulting primarily from a higher average price received.

 

Overview

 

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

 

 

 

The Corporate group represents 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 Condensed Consolidated Financial Statements from the date of acquisition.

 

Discontinued operations in 2006 represents the operations and gain on sale of our crude oil marketing and transportation business, sold in March 2006. In addition to crude oil marketing and transportation operations, the 2005 and 2004 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 and 2004 have been restated to reflect the operations discontinued.

 

Prior to the reclassification of the financial results of our Houston-based crude oil marketing and transportation business, BHER, into discontinued operations, the related revenues and cost of sales were presented on a gross basis. Accordingly, our operating revenues and expenses, as previously presented in the 2005 interim financial statements, are adjusted by the following to reflect crude oil marketing and transportation revenues and cost of sales in discontinued operations (in millions):

 

_________________________

*Completed asset sale on March 1, 2006.

 

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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 Energy 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.

 

The Retail Services Group’s income from continuing operations 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.

 

The Wholesale 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.

 

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.

 

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 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.

 

2005 Compared to 2004

 

Consolidated income from continuing operations for 2005 was $32.8 million, compared to $56.3 million in 2004, or $0.98 per share in 2005, compared to $1.71 per share in 2004. Income from discontinued operations was $0.6 million or $0.02 per share in 2005, compared to income of $1.7 million or $0.05 per share in 2004. Return on average common stock equity in 2005 and 2004 was 4.5 percent and 8.1 percent, respectively.

 

The Retail Services Group’s income from continuing operations increased $0.9 million in 2005 compared to 2004. Earnings from the electric and gas utility, acquired January 21, 2005, were $2.1 million and earnings from continuing operations from the electric utility decreased $1.2 million.

 

The Wholesale Energy Group’s income from continuing operations decreased $14.7 million in 2005 compared to 2004. Decreased earnings from power generation of $28.1 million and from coal mining of $0.5 million were offset by increased income from continuing operations of $5.7 million at our oil and gas operations and $8.2 million from energy marketing operations.

 

Corporate costs for the year ended December 31, 2005 increased $9.7 million after-tax, compared to 2004. The increase is primarily due to the 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. These costs were partially offset by allocating increased compensation and debt retirement costs down to the subsidiary level. In addition, the Company’s subsidiary, Daksoft, Inc., recorded a $1.0 million pre-tax gain in 2004, on the sale of its campground reservation system.

 

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Consolidated operating expenses for 2005 increased $214.8 million compared to 2004. Increased operating expenses reflect a $106.8 million increase in fuel and purchased power, a $52.2 million impairment charge at our power generation segment and a $33.4 million increase in Administrative and general costs. 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. The increase in Administrative and general costs was primarily the result of higher corporate development costs, including the write-off of previously capitalized development costs, higher legal and professional fees resulting from ongoing litigation, the additional Administrative and general costs of Cheyenne Light, and higher compensation costs.

 

Discussion of results from our operating segments is included in the following pages.

 

The following business group and segment information does not include discontinued operations or intercompany eliminations. Accordingly, 2005 and 2004 information has been revised to remove information related to operations that were discontinued.

 

Retail Services Group

 

Electric Utility

 

 

The following tables provide certain electric utility operating statistics:

 

 

 

54

 

We established a new summer peak load of 415 MW in July 2006 and a new winter peak load of 356 MW in December 2005. We own 435 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.

 

 

 

 

 

 

 

 

55

2006 Compared to 2005

 

Electric utility revenues increased 2 percent for the year ended December 31, 2006 compared to the same period in the prior year. Firm residential, industrial and contract wholesale sales increased 3 percent, 4 percent and 6 percent, respectively. For the year ended December 31, 2006, cooling degree days were 56 percent higher than normal and heating degree days were 10 percent lower than normal. Wholesale off-system sales decreased 11 percent due to an 18 percent decrease in average price received partially offset by an 8 percent increase in MW-hours sold.

 

Electric operating expenses were flat for the year ended December 31, 2006, compared to the prior year. Increases in fuel costs were primarily due to a 7 percent increase in average cost of steam generation and increased gas generation utilized for firm load demand and peaking needs due to scheduled and unscheduled outages at the Wyodak plant and warmer weather. Purchased power decreased primarily due to a 12 percent lower average cost per MW-hour offset by an 11 percent increase in MW-hours purchased. Operating expenses were also affected by increased repairs and maintenance costs for the Wyodak plant, incentive compensation costs and corporate allocations, partially offset by a decrease in power marketing legal costs relative to costs incurred in 2005 (See Note 18, “Commitments and Contingencies” to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of the power marketing legal settlement).

 

Income from continuing operations increased 4 percent primarily due to increased revenues and lower interest expense, offset by a 2005 deferred tax benefit adjustment of $1.9 million.

 

Rate Increase Settlement. During 2006 our electric utility filed an application with the SDPUC for an electric rate increase to be effective January 1, 2007. On December 28, 2006, we received an order from the SDPUC for a 7.8 percent increase in retail rates and approving the addition of tariff provisions for automatic adjustments. The cost adjustments will require the electric utility to absorb a portion of power cost increases partially depending on earnings on certain short-term wholesale sales of electricity. Absent certain conditions, the order also restricts Black Hills Power from requesting an increase in base rates that would go into effect prior to January 1, 2010. Our previous rate structure, in place since 1995, did not contain fuel or purchased power adjustment clauses and only provided the ability to request rate relief from energy costs in certain defined situations. South Dakota retail customers account for approximately 91 percent of the electric utility’s total retail revenues.

 

The cost adjustments will require the electric utility to absorb a portion of purchased power and natural gas cost increases, partially depending on earnings from certain short-term wholesale sales of electricity.

 

2005 Compared to 2004

 

Electric utility revenues increased 9 percent for the year ended December 31, 2005 compared to the same period in the prior year. Firm commercial, residential and contract wholesale sales increased 5 percent, 8 percent and 3 percent, respectively. Cooling degree days for the year were 59 percent higher than 2004 and heating degree days were 1 percent lower than 2004. Wholesale off-system sales increased 25 percent due to a 33 percent increase in average price received partially offset by a 6 percent decrease in MW-hours sold.

 

Electric operating expenses increased 18 percent for the year ended December 31, 2005, compared to the prior year. Higher operating expenses were primarily the result of an $18.5 million increase in fuel and purchased power costs. The increase in fuel and purchased power was due to a $16.9 million increase in purchased power, which includes $2.8 million of additional purchased power costs to cover the outage of Neil Simpson II, as well as a 31 percent increase in average price per MW-hour, and a 3 percent increase in MW-hours purchased. Fuel costs increased $1.6 million due to a 12 percent increase in average cost, partially offset by a 1 percent decrease in MW-hours generated. MW-hours produced through coal-fired generation decreased while higher cost gas generation was utilized in 2005. Purchased power and gas generation were utilized for firm load demand and peaking needs due to unscheduled plant outages and warmer weather. The increase in operating expense was also affected by increased power marketing legal expense, compensation costs and corporate allocations, partially offset by lower maintenance costs due to scheduled and unscheduled plant maintenance in 2004.

 

56

Income from continuing operations decreased $1.2 million primarily due to increased fuel and purchased power costs, legal expense, compensation costs and corporate allocations, partially offset by increased revenues, lower maintenance costs, lower interest expense due to the pay down of debt, and a $1.9 million benefit from a deferred tax adjustment.

 

Electric and Gas Utility

 

 

The following tables provide certain operating statistics for the Electric and gas utility segment:

 

 

 

 

 

57

 

 

 

2006 Rate Increase

 

On October 3, 2005, the WPSC entered a bench order approving a stipulation and agreement with the Wyoming Office of Consumer Advocate which resulted in an annual revenue increase beginning in 2006. The base rates for retail electric and natural gas service were effective January 1, 2006 and represent increases of 3.65 percent and 5.11 percent in electric and gas revenues, respectively.

 

2006 Compared to the Period January 21, 2005 to December 31, 2005

 

Gross margin increased 28 percent primarily due to an increase in base rates, a 5 percent increase in electric demand, an 8 percent increase in gas demand and a full year of operations in 2006. Cooling degree days were 78 percent above normal and heating degree days were 8 percent below normal. We consider gross margin to be the most useful performance measure as fluctuations in cost of gas and electricity flow through to revenues through cost recovery adjustments.

 

Operating expenses increased 17 percent primarily due to increased depreciation expense, the write-off of uncollectible accounts and increased operating costs due to a full year of operations in 2006.

 

Income from operations increased $3.4 million primarily due to higher margins and increased income from AFUDC associated with the advancing construction of the Wygen II power plant, partially offset by the increased operating costs.

 

Wholesale Energy Group

 

Oil and Gas

 

Oil and gas operating results were as follows:

 

 

The following tables provide certain operating statistics for the Oil and gas segment.

 

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The following is a summary of oil and natural gas production:

 

 

The following is a summary of LOE/Mcfe at December 31:

 

 

At the East Blanco Field in New Mexico and our Piceance Basin assets in Colorado, we own and operate the gas gathering system, including associated compression and processing facilities. LOE at our Colorado properties includes approximately $0.49/Mcfe in 2006 and at our New Mexico properties includes approximately $0.71/Mcfe in 2006 and $0.65/Mcfe in 2005 and 2004 for gathering, compression and processing costs.

 

The following is a summary of our proved oil and gas reserves at December 31:

 

 

These reserves are based on reports prepared by Ralph E. Davis Associates, Inc., an independent consulting and engineering firm. Reserves were determined using constant product prices at the end of the respective years. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results. The estimate takes into account 2006 production, the 2006 acquisition of approximately 60 Bcfe, additions of approximately 13 Bcfe and revisions to previous estimates of (29.6) Bcfe. The downward revision to previous estimates was primarily due to lower-than-expected results from certain segments of the 2006 drilling program in the San Juan Basin, and to a lesser extent, well performance at certain areas within our Finn-Shurley field. The decrease in natural gas and oil prices as of December 31, 2006 compared to December 31, 2005 also contributed to the revision.

 

Reserves reflect year end pricing held constant for the life of the reserves, as follows:

 

 

 

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2006 Compared to 2005

 

Revenues from oil and gas increased 9 percent for the year ended December 31, 2006 compared to the year ended December 31, 2005. Gas volumes sold increased 6 percent due to increased production from recently completed wells and property acquisitions. Oil volumes sold increased 2 percent due to increased drilling activity in the Finn-Shurley field, partially offset by increased federal royalties deducted as a result of expiring royalty relief on stripper wells. Average natural gas price received, net of hedges and exclusive of gas liquids, for the year ended December 31, 2006 was $6.08/Mcf compared to $6.36/Mcf in the same period of 2005. Average oil price received, net of hedges, for the year ended December 31, 2006 was $48.80/bbl compared to $35.99/bbl in the same period of 2005.

 

Lease operating expense increased 33 percent primarily due to generally higher field service costs experienced industry-wide and new San Juan compression costs, the East Blanco amine plant costs and operating costs associated with compression and gas treatment for the Piceance Basin properties. The LOE/Mcfe for the year increased 28 percent to $1.19 from $0.93/Mcfe in 2005. Depletion expense per Mcfe increased 26 percent over the prior year to $1.94/Mcfe in 2006 from $1.54/Mcfe in 2005. The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The increased rate is primarily a reflection of higher industry-wide drilling and completion costs that significantly increased our estimated future development costs in addition to increased costs from acquisitions and lower reserve estimates.

 

On March 17, 2006, we acquired certain oil and gas assets of Koch Exploration Company, LLC. The assets include approximately 40 Bcfe of proved reserves, including approximately 31 Bcfe of proved undeveloped reserves which are substantially all gas, and associated midstream and gathering assets. In addition, on August 30, 2006 we acquired from a third party most of the remaining working interests associated with these properties. This includes approximately 22.4 Bcfe of proven reserves, of which 17.9 Bcfe are proved undeveloped reserves. The associated acreage position is located in the Piceance Basin in Colorado.

 

2005 Compared to 2004

 

Revenues from oil and gas increased 47 percent for the year ended December 31, 2005 compared to the year ended December 31, 2004. Gas volumes sold increased 14 percent due to increased production from recently completed wells, and oil volumes sold decreased 9 percent primarily due to a normal decline in our mature Wyoming oil field and reduced enhanced oil recovery activities. Average natural gas price received, net of hedges and exclusive of gas liquids, for the year ended December 31, 2005 was $6.36/Mcf compared to $4.56/Mcf in the same period of 2004. Average oil price received, net of hedges, for the year ended December 31, 2005 was $35.99/Bbl compared to $26.24/Bbl in the same period of 2004.

 

Lease operating expense increased 5 percent primarily due to generally higher field service costs experienced industry-wide and the increase in number of producing wells as a result of the current drilling program. The LOE/Mcfe for the year decreased 4 percent from $0.97/Mcfe in 2004 to $0.93/Mcfe in 2005 due to higher production rates and efficiencies realized in certain of our fields where significant production increases have been achieved. Depletion expense per Mcfe (excluding liquids) increased 60 percent over the prior year from $0.96/Mcfe in 2004 to $1.54/Mcfe in 2005. The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The increased rate is primarily a reflection of higher industry-wide drilling and completion costs that significantly increased our estimated future development costs in addition to lower than expected reserve estimates.

 

Additional information on our Oil and Gas operations can be found in Note 23 to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

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Power Generation

 

Our power generation segment produced the following results:

 

_____________________________

 

The following table provides certain operating statistics for the Power Generation segment:

 

 

2006 Compared to 2005

 

Revenues for the year ended December 31, 2006 decreased 2 percent from the same period in 2005. Lower revenues are primarily due to scheduled and unscheduled outages for repair and maintenance at the Las Vegas I and Las Vegas II facilities, partially offset by higher capacity revenue at our Harbor facility due to a three year, year-round tolling agreement, which commenced April 1, 2005 and replaced a seasonal contract.

 

Operating expenses for the year ended December 31, 2006 decreased $64.4 million from the same period in 2005, primarily due to lower variable operating costs and the receipt of $3.9 million of insurance proceeds relating to the Las Vegas II power plant outage; lower variable costs at the Las Vegas I power plant due to lower fuel costs and depreciation expense, and the 2005 $50.3 million impairment charge on the Las Vegas I power plant; a $1.9 million impairment of goodwill relating to certain power fund investments and a $1.6 million charge related to a fuel contract termination. The decrease in operating expense was partially offset by increased repair and maintenance expense, net of insurance proceeds, incurred by the Las Vegas II power plant due to the outage.

 

Income from continuing operations increased $32.4 million, primarily due to the decrease in operating expense partially offset by an $8.0 million after-tax decrease in earnings from certain power fund investments and increased interest expense due to higher interest rates. In addition, 2005 results were impacted by a $2.8 million charge for a tax adjustment.

 

Plant availability of our contracted fleet was affected by the planned maintenance at Las Vegas I and unplanned outages at Las Vegas II. The availability of the remainder of our gas-fired fleet was approximately 96.7 percent and availability of our Wygen I coal-fired plant exceeded 95 percent.

 

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2005 Compared to 2004

 

Revenues for the year ended December 31, 2005 were flat compared to revenues in the same period in 2004. Increased revenues at our Las Vegas II facility and increased revenues from higher MW generated at our Gillette CT were offset by decreased revenues from Las Vegas I, due to a plant maintenance outage. In the twelve months of 2005, our Las Vegas II facility sold capacity and energy to NPC under a long-term tolling arrangement, which became effective April 1, 2004, as opposed to selling power into the market on a merchant basis for the first three months of 2004, only when it was economic to do so.

 

Operating expenses for the year ended December 31, 2005 increased $50.5 million, due primarily to a $50.3 million impairment charge on the Las Vegas I plant, a $1.9 million impairment of goodwill relating to certain power fund investments, increased fuel costs at our Gillette CT, a $1.6 million charge related to a fuel contract termination and increased corporate allocations. The increase in operating expenses was partially offset by a reduction in fuel expense at the Las Vegas II facility, which incurred fuel costs in the first three months of 2004, before the new long-term tolling arrangement took effect and lower fuel expense at Las Vegas I due to planned maintenance in the fourth quarter of 2005.

 

Income from continuing operations decreased $28.1 million, primarily due to the $32.7 million after-tax impact of the Las Vegas I impairment charge, a fuel contract termination charge and increased corporate allocations and tax adjustments that lowered earnings by $2.8 million, partially offset by a $6.1 million after-tax increase in earnings from certain power fund investments.

 

Plant availability of our contracted fleet was affected by the planned maintenance at Las Vegas I and unplanned outages at Las Vegas II. The availability of the remainder of our gas-fired fleet was approximately 99 percent and availability of our Wygen I coal-fired plant exceeded 95 percent.

 

Coal Mining

 

Coal mining results were as follows:

 

 

The following table provides certain operating statistics for the Coal mining segment:

 

 

 

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2006 Compared to 2005

 

Revenue from our Coal mining segment increased 6 percent for the year ended December 31, 2006 compared to 2005 primarily due to higher average prices received. Tons of coal sold were flat with the prior year as increased train load-out sales were offset by decreased sales to the Wyodak power plant due to scheduled and unscheduled outages.

 

Operating expenses increased 11 percent for the year ended December 31, 2006 primarily due to increased overburden expense resulting from a change in accounting rules requiring overburden removal to be expensed as incurred, higher depreciation expense and increased mineral taxes, partially offset by lower general and administrative costs.

 

Income from continuing operations decreased 15 percent primarily due to the increased mining costs partially offset by the increase in revenues.

 

2005 Compared to 2004

 

Revenue from our Coal mining segment increased 7 percent for the year ended December 31, 2005 compared to 2004. In 2004, the Company reached a tax settlement with the Wyoming Department of Revenue which resulted in a $1.7 million reduction in revenues and a corresponding reduction in mineral taxes in September, 2004. The Company also recorded an additional $0.4 million decrease to mineral taxes and $0.5 million decrease to interest expense related to the settlement. Revenues were also impacted by a 2 percent decrease in tons of coal sold, primarily due to unscheduled plant outages at the Neil Simpson II and Wyodak power plants, offset by higher average prices.

 

Operating expenses increased 12 percent for the year ended December 31, 2005 primarily due to the reduction of 2004 mineral tax expense due to the recording of the 2004 tax settlement and increased transportation and overburden removal costs and compensation expense and corporate allocations, partially offset by decreased depletion expense, due to lower depletion rates.

 

Income from continuing operations decreased 7 percent primarily due to increased transportation and overburden removal costs and compensation expense and corporate allocations, partially offset by the decrease in depletion expense. In addition, 2004 results were affected by a $0.4 million benefit from an income tax reserve adjustment and a $0.6 million after-tax benefit from the Wyoming tax settlement.

 

Energy Marketing

 

Our energy marketing company produced the following results:

 

 

 

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The following table provides certain operating statistics for the Energy marketing segment:

 

 

2006 Compared to 2005

 

Income from continuing operations increased $3.5 million primarily due to higher natural gas marketing margins and a 12 percent increase in physical gas volumes marketed as well as the addition of margins from oil marketing operations beginning in May 2006. Realized gross margins from natural gas marketing for the year ended December 31, 2006 increased $21.4 million over the same period in the prior year. Gas marketing unrealized mark-to-market losses for the year ended December 31, 2006 were $11.6 million higher than the same period in 2005.

 

Operating expenses increased 47 percent for the year ended December 31, 2006 compared to the same period in 2005 primarily due to increased compensation costs related to higher realized marketing margins and an increase in bad debt provision partially offset by lower professional fees as compared to costs incurred in 2005 related to litigation involving class action lawsuits alleging false reporting of natural gas price and volume information (see Note 18 of Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further discussion of legal proceedings regarding these class action lawsuits).

 

In March 2006, we sold the operating assets of our Houston, Texas based crude oil marketing and transportation business. Beginning with the first quarter of 2006, the operations of this business were classified as discontinued operations. Crude oil marketing revenues and cost of sales were presented on a gross basis in accordance with accounting standards generally accepted in the United States. Accordingly, the classification to discontinued operations had a significant affect on our consolidated presented revenues and cost of sales. For the years ended December 31, 2005 and 2004, revenues from crude oil marketing and transportation were $778.1 million and $636.6 million; and related cost of sales were $765.2 million and $620.3 million, respectively.

 

Subsequent to the sale of the crude oil marketing and transportation assets, Enserco, our natural gas marketing subsidiary, began marketing crude oil in the Rocky Mountain region out of our Golden, Colorado offices. Our primary strategy involves executing physical crude oil purchase contracts with producers, and reselling into various markets. These transactions are primarily entered into as back-to-back purchases and sales, effectively locking in a marketing fee equal to the difference between the sales price and the purchase price, less transportation costs. Under SFAS 133, mark-to-market accounting for the related commodity contracts in our back-to-back strategy results in an acceleration of marketing margins locked in for the term of the contracts. These are generally short-term contracts with automatic renewals if there is no notice of cancellation. (For discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas and oil marketing operations, see Note 2 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.)

 

2005 Compared to 2004

 

Income from continuing operations increased $8.2 million primarily due to higher natural gas marketing margins and volumes and a positive foreign tax credit reserve adjustment of $1.3 million. These items were partially offset by a charge for a litigation settlement accrual of $2.6 million relating to a class action lawsuit, initiated in 2003, that alleged false reporting of natural gas price and volume information. Gas marketing unrealized mark-to-market gains for the year ended December 31, 2005 were $6.2 million higher than unrealized mark-to-market losses for the same period in 2004. We expected approximately $2.0 million of the unrealized mark-to-market gain to reverse in 2006. In addition, realized gross margins from natural gas marketing increased $6.0 million.

 

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Critical Accounting Policies

 

We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We believe the following accounting policies are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting policies and related disclosures with our Audit Committee.

 

The following discussion of our critical accounting policies should be read in conjunction with Note 1, “Business Description and Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

Impairment of Long-lived Assets

 

We evaluate for impairment, the carrying values of our long-lived assets, including goodwill and other intangibles, whenever indicators of impairment exist and at least annually for goodwill as required by SFAS 142.

 

For long-lived assets with finite lives, this evaluation is based upon our projections of anticipated future cash flows (undiscounted and without interest charges) from the assets being evaluated. If the sum of the anticipated future cash flows over the expected useful life of the assets is less than the assets’ carrying value, then a permanent non-cash write-down equal to the difference between the assets’ carrying value and the assets’ fair value is required to be charged to earnings. In estimating future cash flows, we generally use a probability weighted average expected cash flow method with assumptions based on those used for internal budgets. Although we believe our estimates of future cash flows are reasonable, different assumptions regarding such cash flows could materially affect our evaluations.

 

During the third quarter of 2005, in accordance with our accounting policies, we evaluated for impairment the long-lived asset carrying values of our Las Vegas I power plant. The evaluation for impairment was prompted by plant operating losses driven by high natural gas prices. Natural gas prices were $13.92/MMBtu (NYMEX) on September 30, 2005, and were forecasted to maintain historically high price levels. In measuring the fair value of the Las Vegas I power plant and the resulting impairment charge of approximately $50.3 million pre-tax, we considered a number of possible cash flow models associated with the various probable operating assumptions and pricing for the capacity and energy of the facility. We then made our best determination of the relative likelihood of the various models in computing a weighted average expected cash flow for the facility. Inclusion of other possible cash flow scenarios and/or different weighting of those that were included could have led to different conclusions about the fair value of the plant. Further, the weighted average cash flow method is sensitive to the discount rate assumption. If we had used a discount rate that was 1 percent higher, the resulting impairment charge would have been approximately $0.3 million higher. If the discount rate would have been 1 percent lower, the impairment charge would have been approximately $0.3 million lower.

 

During the fourth quarter of 2005, we wrote off goodwill of approximately $1.9 million, net of accumulated amortization of $0.3 million, related to partnership “equity flips” at certain power fund investments. As these funds follow accounting policies which require their plant investments to be carried at fair value, our goodwill represented an excess investment cost in the funds that was only supported by the value of the potential increased partnership equity. When the “equity flip” was triggered by performance thresholds being met, the value of the additional partnership interest was recognized and our related goodwill impaired.

 

In 2004, an impairment charge of approximately $0.7 million after-tax was recorded to reduce the carrying value of the Pepperell plant to its estimated fair value, less cost to sell and is included in “Income from discontinued operations, net of income taxes” on the 2004 Consolidated Statement of Income.

 

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Full Cost Method of Accounting for Oil and Gas Activities

 

We account for our oil and gas activities under the full cost method whereby all productive and nonproductive costs related to acquisition, exploration and development drilling activities are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized. Net capitalized costs are subject to a “ceiling test” that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. This method values the reserves based upon actual oil and gas prices at the end of each reporting period adjusted for contracted price changes. The prices, as well as costs and development capital, are assumed to remain constant for the remaining life of the properties. If the net capitalized costs exceed the full-cost ceiling, then a permanent non-cash write-down is required to be charged to earnings in that reporting period. Although our net capitalized costs were less than the full cost ceiling at December 31, 2006, we can provide no assurance that a write-down in the future will not occur depending on oil and gas prices at that point in time. In addition, we annually rely on an independent consulting and engineering firm to verify the estimates we use to determine the amount of our proved reserves and those estimates are based on a number of assumptions about variables. We cannot be assured that these assumptions will not differ from actual results.

 

Oil and Natural Gas Reserve Estimates

 

Estimates of our proved oil and natural gas reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any oil and natural gas reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

 

Despite the inherent imprecision in these engineering estimates, estimates of our oil and natural gas reserves are used throughout our financial statements. For example, as we use the unit-of-production method of calculating depletion expense, the amortization rate of our capitalized oil and gas properties incorporates the estimated units-of-production attributable to the estimates of proved reserves. Our oil and gas properties are also subject to a “ceiling” limitation based in large part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

 

The estimates of our proved oil and natural gas reserves have been reviewed by independent petroleum engineers.

 

 

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Risk Management Activities

 

In addition to the information provided below, see Note 2 “Risk Management Activities,” of our Notes to Consolidated Financial Statements.

 

Derivatives

 

We account for derivative financial instruments in accordance with SFAS 133. Accounting for derivatives under SFAS 133 requires the recognition of all derivative instruments as either assets or liabilities on the balance sheet and their measurement is at fair value.

 

We currently use derivative instruments, including options, swaps, futures, forwards and other contractual commitments for both non-trading (hedging) and trading purposes. Our typical non-trading (hedging) transactions relate to contracts we enter into at our oil and gas exploration and production subsidiary to fix the price received for anticipated future production and interest rate swaps we enter into to convert a portion of our variable rate debt to a fixed rate. Our marketing and trading operations utilize various physical and financial contracts to effectively manage our marketing and trading portfolios.

 

Fair values of derivative instruments and energy trading contracts are based on actively quoted market prices or other external source pricing information, where possible. If external market prices are not available, fair value is determined based on other relevant factors and pricing models that consider current market and contractual prices for the underlying financial instruments or commodities, as well as time value and yield curve or volatility factors underlying the positions.

 

Pricing models and their underlying assumptions impact the amount and timing of unrealized gains and losses recorded, and the use of different pricing models or assumptions could produce different financial results. Changes in the commodity markets will impact our estimates of fair value in the future. To the extent financial contracts have extended maturity dates, our estimates of fair value may involve greater subjectivity due to the lack of transparent market data available upon which to base modeling assumptions.

 

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Counterparty Credit Risk  

 

We perform ongoing credit evaluations of our customers and adjust credit and tenor limits based upon payment history and the customer’s current creditworthiness, as determined by our review of their current financial information. We continuously monitor collections and payments from our customers and maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and established provisions, we can provide no assurance that our credit losses will be consistent with our estimates.

 

Pension and Other Postretirement Benefits

 

The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions used by actuaries in calculating the amounts. Those assumptions, as further described in Note 17 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, include, among others, the discount rate, the expected long-term rate of return on plan assets and the rate of increase in compensation levels and healthcare costs. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

 

We account for our Pension and Other Postretirement Benefit Plans under SFAS 87, 106 and 158. SFAS 158 requires the recognition of the overfunded or underfunded status of defined benefit postretirement plans as an asset or liability in the statement of financial position and recognition of changes in the funded status in other comprehensive income for fiscal years ending after December 15, 2006. Effective for fiscal years ending after December 15, 2008, SFAS 158 will require the measurement of the funded status of the plan to coincide with the date of the year end statement of financial position.

 

Defined Benefit Pension Plans

 

In accordance with SFAS 87, changes in pension obligations associated with fluctuations in long-term actuarial assumptions may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of the plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. For the years ended December 31, 2006, 2005 and 2004, we recorded non-cash expense related to our pension plans of approximately $2.8 million, $2.9 million and $2.6 million, respectively.

 

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Our pension plan assets are held in trust and primarily consist of equity and fixed income investments. Fluctuations in actual market returns result in increased or decreased pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.

 

In selecting an assumed rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan and weight the returns by applying the assumed rate of return for each asset class to the target allocation for each asset class in the portfolio. The value of our qualified pension plan assets increased $6.7 million to $66.0 million for the plan fiscal year ended September 30, 2006. Plan assets earned $8.2 million in 2006. Plan assets increased $6.5 million to $59.3 million as of September 30, 2005. Plan assets earned $8.9 million in 2005. In the recently completed actuarial valuation, for determining our 2007 pension expense, our assumed rate of return on plan assets remained at 8.5 percent. The expected long-term rate of return on plan assets was 8.5 percent, 9.0 percent and 9.5 percent for the 2006, 2005 and 2004 plan years, respectively.

 

The 8.5 percent assumed rate of return for the 2006 plan year was determined based on the following estimated long-term investment allocations and asset class returns:

 

 

The Plan’s expected long-term rate of return on assets assumption is based upon the weighted average expected long-term rate of returns for individual asset classes. The asset class weighting is determined using the target allocation for each asset class in the Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from long-term historical returns for the asset class, with adjustments if it is anticipated that long-term future returns will not achieve historical results. The Plan’s investment policy for 2006 targets an allocation of 50 percent U.S. stocks, 25 percent foreign stocks and 25 percent fixed income.

 

The expected long-term rate of return for equity investments was 9.5 percent for both the 2006 and 2005 plan years. For determining the expected long-term rate of return for equity assets, the Company reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns for the S&P 500 Index, which were, at December 31, 2006, 11.8 percent, 12.4 percent, 11.0 percent and 10.6 percent, respectively. Fund management fees were estimated to be 0.18 percent for S&P 500 Index assets and 0.45 percent for other assets. The expected long-term rate of return on fixed income investments was 6.0 percent; the return was based upon historical returns on 10-year treasury bonds of 7.1 percent from 1962 to 2006 and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 4.0 percent; expected cash returns were estimated to be 2.0 percent below fixed income investments.

 

The discount rate we utilize for determining benefit obligations and benefit cost is based on high grade bond rates. The discount rate was 5.75 percent, 6.0 percent and 6.0 percent in 2006, 2005 and 2004, respectively, for the pension cost determination. In the recently completed actuarial valuation, for determining our 2007 pension expense, we increased the discount rate to 5.95 percent. A 0.20 percent increase in the discount rate would cause annual pension expense to decrease by approximately $0.3 million.

 

During the first quarter of 2006, a contribution of $1.2 million was made to our Pension Plans. Based on our recently completed plan forecasts, we expect to make additional cash contributions to our Pension Plans of $0.5 million in the 2007 fiscal year.

 

Actual pension expense and contributions required will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the pension plan. We will continue to evaluate all of the actuarial assumptions, generally on an annual basis, including the expected long-term rate of return on assets and discount rate, and will adjust the assumptions as necessary.

 

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Non-qualified Pension Plans

 

We have various supplemental retirement plans for our key executives. Expenses recognized under the plans were $2.2 million in 2006, $2.0 million in 2005 and $2.3 million in 2004. The plans are unfunded. The actuarial assumptions used for our non-qualified pension plans are the same as those used for our qualified plan, except for the assumptions for rate of increases in compensation levels.

 

Other Postretirement Benefits

 

We do not pre-fund our other postretirement benefit plans. Our reported costs of providing other postretirement benefits are dependent upon numerous factors, including healthcare cost trends, and results from actual plan experience and assumptions of future experience. As a result of these factors, significant portions of other postretirement benefit costs recorded in any period do not reflect the actual benefits provided to plan participants. For the years ended December 31, 2006, 2005 and 2004, we recorded other postretirement benefit expense of approximately $1.6 million, $1.8 million and $1.5 million, respectively, in accordance with SFAS 106. Actual payments of benefits to retirees were approximately $0.7 million in 2006 and $0.6 million in 2005 and 2004.

 

The following table reflects the sensitivities associated with a change in the assumed healthcare cost trend rate.

 

 

In selecting assumed healthcare cost trend rates, we consider recent plan experience and various short and long-term cost forecasts for the healthcare industry. Based on these considerations, the healthcare cost trend rate used by the actuaries to determine our other postretirement benefit expense for 2006 expense determination was 10 percent in 2006, decreasing gradually to 5 percent in 2011. The healthcare cost trend rate assumption for 2005 expense determination was 11 percent in 2005, decreasing gradually to 5 percent in 2011. Our discount rate assumption for postretirement benefits is consistent with that used in the calculation of pension benefits. See the Defined Benefit Pension Plan discussion above regarding our discount rate assumptions.

 

Contingencies

 

When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are made based on currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position and results of operations.

 

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Valuation of Deferred Tax Assets

 

We use the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. The amount of deferred tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized.

 

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made.

 

Liquidity and Capital Resources

Overview

 

Information about our financial position as of December 31 is presented in the following table:

 

 

Our dividend payout ratio at December 31, 2006 was approximately 55 percent. Our dividend payout ratio at December 31, 2005 was approximately 128 percent which is higher than levels over the past 5 years. Based on current expectations for 2007, we expect payout ratios for 2007 to be in the range of 59 percent to 65 percent.

 

In 2007, we expect our beginning cash balance, cash provided from operations, and available credit facilities to be sufficient to meet our normal operating commitments, to pay dividends and to fund a portion of planned capital expenditures. We would expect to fund a significant portion of any additional investment in power generating facilities with long-term debt. Permanent financing to replace a $1.0 billion bridge facility for our pending acquisition of the Aquila utility assets is expected to come from a combination of new equity, mandatory convertible securities, borrowings under unsecured corporate credit facilities, and cash from internal operations. On February 22, 2007, we completed a private placement common stock offering raising approximately $145.5 million in net proceeds that were used to repay debt.

 

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Cash Flow Activities

 

2006

 

In 2006, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common stock, to pay our scheduled long-term debt maturities and to fund a portion of our property additions.

 

Cash flows from operations increased $84.8 million from the prior year amount, affected by a $41.2 million increase in income from continuing operations and by the following:

 

 

We had cash outflows from investing activities of $268.1 million, including approximately $92.2 million for construction expenditures for Wygen II, $75.4 million for the acquisition of oil and gas assets in the Piceance Basin in Colorado, and expenditures for development drilling of oil and gas properties of approximately $83.4 million and property, plant and equipment additions in the normal course of business, partially offset by $40.7 million cash received for the sale of our Texas based crude oil marketing and transportation assets.

 

We had cash inflows from financing activities of $11.7 million, primarily due to a $90.5 million increase in borrowings on our revolving bank facility partially offset by the payment of $44.0 million of cash dividends on common stock, the net payment of $21.3 million related to the Black Hills Colorado project level debt refinancing and payment of long-term debt maturities.

 

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2005

 

In 2005, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our scheduled long-term debt maturities and to fund a portion of our property additions.

 

Cash flows from operations increased $37.8 million from the prior year amount, as a $23.5 million decrease in income from continuing operations was more than offset by the following:

 

 

We had cash outflows from investing activities of $109.7 million, primarily for construction expenditures for Wygen II, acquisitions and development drilling of oil and gas properties and property, plant and equipment additions in the normal course of business and the $65.1 million cash payment related to the acquisition of Cheyenne Light, partially offset by $103.0 million cash received for the sale of Black Hills FiberSystems.

 

We had cash outflows from financing activities of $95.5 million, primarily due to the repayment of $81.5 million of project level debt at our Fountain Valley facility and the payment of cash dividends partially offset by an increase in short term borrowings.

 

Dividends

 

Dividends paid on our common stock totaled $1.32 per share in 2006. This reflects an increase in comparison to prior years’ dividend levels of $1.28 per share in 2005 and $1.24 per share in 2004. All dividends were paid out of operating cash flows. Our three-year annualized dividend growth rate was 3.2 percent. In February 2007, our board of directors increased the quarterly dividend 3 percent to $0.34 cents per share. If this dividend is maintained during 2007, it will be equivalent to $1.36 per share, an annual increase of $0.04 cents per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects.

 

Liquidity

 

Our principal sources of short-term liquidity include our cash on hand, our revolving credit facility and cash provided by operations. As of December 31, 2006 we had approximately $36.9 million of cash unrestricted for operations and $400 million of credit through a revolving bank facility. Our revolving credit facility can be used to fund our working capital needs and for general corporate purposes. At December 31, 2006, we had $145.5 million of bank borrowings outstanding and $49.4 million of letters of credit issued under this facility, with a remaining borrowing capacity of $205.1 million. Approximately $3.1 million of the cash balance at December 31, 2006 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company.

 

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The $400 million revolving bank facility has a five year term, expiring May 4, 2010. The facility contains a provision which allows the facility size to be increased by up to an additional $100 million through the addition of new lenders, or through increased commitments from existing lenders, but only with the consent of such lenders. The cost of borrowings or letters of credit issued under the facility is determined based on our credit ratings. At our current ratings levels, the facility has an annual facility fee of 17.5 basis points, and has a borrowing spread of 70 basis points over the LIBOR (which equated to a 6.02 percent one-month borrowing rate as of December 31, 2006).

 

The above credit facility includes customary affirmative and negative covenants such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and maintenance of the following financial covenants:

 

 

A default under the credit facility may be triggered by events such as a failure to comply with financial covenants or certain other covenants under the credit facility, a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to debt obligations of $20 million or more. A default under the credit facility would permit the participating banks to restrict the Company’s ability to further access the credit facility for loans or new letters of credit, require the immediate repayment of any outstanding loans with interest and require the cash collateralization of outstanding letter of credit obligations.

 

The credit facility prohibits the Company from paying cash dividends unless no default or no event of default exists prior to, or would result after, giving effect to such action.

 

If these covenants are violated and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate the payment of all principal and interest outstanding. As of December 31, 2006, we were in compliance with the above covenants.

 

Our consolidated net worth was $790.0 million at December 31, 2006, which was approximately $107.8 million in excess of the net worth we are required to maintain under the debt covenant described above. The long-term debt component of our capital structure at December 31, 2006 was 44.3 percent, our total debt leverage ratio was 50.0 percent, our recourse leverage ratio was approximately 50.6 percent and our interest expense coverage ratio was 4.9 to 1.

 

In addition to the above credit facility, at December 31, 2006, Enserco has a $260.0 million uncommitted, discretionary line of credit to provide support for the purchases of natural gas and crude oil. The line of credit is secured by all of Enserco’s assets and expires on May 10, 2007. At December 31, 2006 there were outstanding letters of credit issued under the facility of $158.7 million, with no borrowing balances on the facility.

 

Our ability to obtain additional financing, if necessary, will depend upon a number of factors, including our future performance and financial results, and capital market conditions. We cannot be assured that we will be able to raise additional capital on reasonable terms or at all.

 

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The following information is provided to summarize our cash obligations and commercial commitments at December 31, 2006:

 

 

 

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Guarantees

 

We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. At December 31, 2006, we had guarantees totaling $189.6 million in place. Of the $189.6 million, $165.2 million was related to guarantees associated with subsidiaries’ debt to third parties, which are recorded as liabilities on the Consolidated Balance Sheets, $20.3 million was related to performance obligations under subsidiary contracts and $4.1 million was related to indemnification for reclamation and surety bonds of subsidiaries. For more information on these guarantees, see Note 19 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

As of December 31, 2006, we had the following guarantees in place (in thousands):

 

 

Credit Ratings

 

As of February 28, 2007, our issuer credit rating was “Baa3” by Moody’s and “BBB-” by S&P. In addition, Black Hills Power’s first mortgage bonds were rated “Baa1” and “BBB” by Moody’s and S&P, respectively. In February 2007, Moody’s revised the outlook on our credit ratings from stable to negative. In February 2007, S&P affirmed its “BBB-” corporate credit rating on the Company and revised the outlook from negative to stable. If our issuer credit rating should drop below investment grade, pricing under the credit agreements would be affected, increasing annual interest expense by approximately $0.9 million pre-tax based on December 31, 2006 balances.

 

 

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Capital Requirements

 

Our primary capital requirements for the three years ended December 31 were as follows:

                

____________________________

 

Our capital additions for 2006 were $308.5 million. The capital expenditures were primarily for construction of the Wygen II power plant, acquisitions and development drilling of oil and gas properties and maintenance capital.

 

Our capital additions for 2005 were $208.9 million. The capital expenditures were primarily for the acquisition cost of Cheyenne Light, construction of the Wygen II power plant, development drilling of oil and gas properties and maintenance capital.

 

Our capital additions for 2004 were $91.0 million. The capital expenditures were primarily for maintenance capital and development drilling of oil and gas properties.

 

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Forecasted capital requirements for maintenance capital and developmental capital are as follows:

 

_________________________

 

We continue to actively evaluate potential future acquisitions and other growth opportunities in accordance with our disclosed business strategy. We are not obligated to a project until a definitive agreement is entered into and cannot guarantee we will be successful on any potential projects. Future projects are dependent upon the availability of economic opportunities and, as a result, actual expenditures may vary significantly from forecasted estimates.

 

Market Risk Disclosures

 

Our activities in the regulated and unregulated energy sector expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and counterparty risk. We have developed policies, processes, systems, and controls to manage and mitigate these risks.

 

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks:

 

 

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates, currency exchange rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

 

To manage and mitigate these identified risks, we have adopted the BHCRPP. These policies have been approved by our Executive Risk Committee and reviewed by our Board of Directors. These policies include governance, control infrastructure, authorized commodities and trading instruments, prohibited activities, employee conduct, etc. The Executive Risk Committee, which includes senior level executives, meets on a regular basis to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.

 

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Trading Activities

 

Natural Gas Marketing

 

We have a natural gas and crude oil marketing business specializing in producer services, end-use origination and wholesale marketing that conducts business in the western and mid-continent regions of the United States and Canada. For producer services our main objective is to provide value in the supply chain by acting as the producer’s “marketing arm” for wellhead purchases, scheduling services, imbalance management, risk management services and transportation management. We accomplish this goal through industry experience, extensive contacts, transportation and risk management expertise, trading skills and personal attention. Our end-use origination efforts focus on supplying and providing electricity generators and industrial customers with flexible options to procure their energy inputs and asset optimization services to these large end-use consumers of natural gas. Our wholesale marketing activity has two functions: support the efforts of producer services and end-use origination groups, and marketing and trading third party natural gas and crude oil.

 

To effectively manage our producer services, end-use origination and wholesale marketing portfolios, we enter into forward physical commodity contracts, financial instruments including over-the-counter swaps and options and storage and transportation agreements.

 

We conduct our gas marketing business activities within the parameters as defined and allowed in the BHCRPP and further delineated in the gas marketing CRPP as approved by the Executive Risk Committee.

 

Monitoring and Reporting Market Risk Exposures

 

We use a number of quantitative tools to measure, monitor and limit our exposure to market risk in our natural gas and oil marketing portfolio. We limit and monitor our market risk through established limits on the nominal size of positions based on type of trade, location and duration. Such limits include those on fixed price, basis, index, storage, transportation and foreign exchange positions and on the aggregate portfolio VaR.

 

Our market risk limits are monitored by our Risk Management function to ensure compliance with our stated risk limits. The Risk Management function operates independently from our energy marketing group. The limits are measured and monitored at a minimum each business day and are regularly reported to and reviewed by our Executive Risk Committee.

 

We measure and monitor the market risk inherent in the natural gas trading portfolio employing VaR analysis and scenario analysis. VaR is a statistical measure that quantifies the probability and magnitude of potential future losses related to open contract positions.

 

We use scenario analysis to test the impact of extreme moves in both specific delivery points and overall commodity prices on our portfolio value. In addition to VaR and scenario analysis, risk management daily activities include scrutinizing positions, assessing changes in daily mark-to-market and other non-statistical risk management techniques.

 

The contract or notional amounts, terms and mark-to-market values of our natural gas marketing and derivative commodity instruments at December 31, 2006 and 2005, are set forth in Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

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The following table provides a reconciliation of the activity in our energy trading portfolio that has been recorded at fair value under a mark-to-market method of accounting during the year ended December 31, 2006 (in thousands):

 

__________________________

 

 

On January 1, 2003, the Company adopted EITF Issue No. 02-3. The adoption of EITF 02-3 resulted in certain energy trading activities no longer being accounted for at fair value, therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities and our expected cash flows from those operations. EITF 98-10 was superseded by EITF 02-3 and allowed a broad interpretation of what constituted “trading activity” and hence what would be marked-to-market. EITF 02-3 took a much narrower view of what “trading activity” should be marked-to-market, limiting mark-to-market treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. At our natural gas marketing operations, we often employ strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 does not allow us to mark our inventory, transportation or storage positions to market. The result is that while a significant majority of our natural gas marketing positions are economically hedged, we are required to mark some parts of our overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.

 

At December 31, 2006, we had a mark to fair value unrealized loss of $(1.5) million for our natural gas and crude oil marketing activities. Of this amount, $(1.1) million was current and $(0.4) million was non-current. The sources of fair value measurements were as follows (in thousands):

 

 

 

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The following table presents a reconciliation of our energy marketing positions recorded at fair value under GAAP to a non-GAAP measure of the fair value of our energy marketing forward book wherein all forward trading positions are marked-to-market. The approach used in determining the non-GAAP measure is consistent with our previous accounting methods under EITF 98-10. In accordance with GAAP and industry practice, the Company includes a “Liquidity Reserve” in its GAAP marked-to-market fair value. This “Liquidity Reserve” accounts for the estimated impact of the bid/ask spread in a liquidation scenario under which the Company is forced to liquidate its forward book on the balance sheet date.

 

 

Activities Other than Trading

 

Oil and Gas Exploration and Production

 

We produce natural gas and crude oil through our exploration and production activities. Our reserves are natural “long” positions, or unhedged open positions, and introduce commodity price risk and variability in our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve our cash flows. We have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Executive Risk Committee and reviewed by our Board of Directors.

 

To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps and options. Our hedging policy allows up to 75 percent of our natural gas and 80 percent of our crude oil production from proven producing reserves to be hedged for a period up to two years in the future. Our hedging strategy is conducted from an enterprise-wide risk perspective; accordingly, we may not externally hedge a portion of our natural gas production when we have offsetting price risk for the fuel requirements of our power generating activities.

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The Company has entered into agreements to hedge a portion of its estimated 2007, 2008 and 2009 natural gas and crude oil production. The hedge agreements in place are as follows:

 

Natural Gas

 

 

Crude Oil

 

 

The hedge agreements entered into by the Company had a fair value of approximately $15.2 million as of December 31, 2006.

 

Power Generation

 

We have a portfolio of gas-fired generation assets located throughout several Western states. The outputs from most of these generation assets are sold under long-term tolling contracts with third parties whereby any commodity price risk is transferred to the third party. However, we do have certain gas-fired generation assets under long-term contracts that do possess market risk for fuel purchases.

 

It is our policy that fuel risk, to the extent possible, be hedged. Since we are “long” natural gas in our exploration and production segment, we look at our enterprise wide natural gas market risk when hedging at the subsidiary level. Therefore, we may attempt to hedge only enterprise-wide “long” or “short” positions.

 

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

 

Financing Activities

 

We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. At December 31, 2006, we had $150.0 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of 9.75 years. Further details of the swap agreements are set forth in Note 2 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

 

On December 31, 2006 and 2005, our interest rate swaps and related balances were as follows (in thousands):

 

 

 

We anticipate a portion of unrealized income recorded in accumulated other comprehensive income will be realized as increased interest income in 2007. Based on December 31, 2006 market interest rates, a gain of approximately $0.2 million would be realized and reported in pre-tax earnings during 2007. Estimated and realized amounts will likely change during 2007 as market interest rates change.

 

At December 31, 2006, we had $259.1 million of outstanding, variable-rate, long-term debt of which $109.1 million was not offset with interest rate swap transactions that effectively convert a portion of the debt to a fixed rate. A 100 basis point increase in interest rates would cause pre-tax interest expense to increase $1.1 million in 2007.

 

The table below presents principal (or notional) amounts and related weighted average interest rates by year of maturity for our short-term investments and long-term debt obligations, including current maturities (in thousands):

 

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Credit Risk

 

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. We have adopted the BHCCP that establishes guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. In addition, our Executive Credit Committee, which includes senior executives, meets on a regular basis to review our credit activities and to monitor compliance with the adopted policies.

 

For our energy marketing, production, and generation activities, we seek to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements, and securing our credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.

 

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of their current credit information. We maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and provisions established, we cannot assure you that we will continue to experience the same credit loss rates that we have in the past or that an investment grade counterparty will not default sometime in the future.

 

At the end of the year, our credit exposure (exclusive of retail customers of our regulated utility segments) was concentrated primarily with investment grade companies. Approximately 70 percent of our credit exposure was with investment grade companies. Of the remaining 30 percent credit exposure with non-investment grade rated counterparties, approximately 48 percent of this exposure was supported through letters of credit or prepayments, and the remaining primarily unsecured.

 

Foreign Exchange Contracts

 

Our natural gas and crude oil marketing subsidiary conducts its business in the United States and Canada. Transactions in Canada are generally transacted in Canadian dollars, which creates exchange rate risk. To mitigate this risk, we enter into forward currency exchange contracts to offset earnings volatility from changes in exchange rates between the Canadian and United States dollars. At December 31, 2006 and 2005, we had outstanding forward exchange contracts to sell approximately $0 and $29.0 million Canadian dollars, respectively. At December 31, 2006 and 2005, we also had outstanding forward exchange contracts to purchase approximately $44.0 million and $88.0 million Canadian dollars, respectively. These contracts had a fair value of $(0.3) million and $(1.0) million at December 31, 2006 and 2005, and have been recorded as Derivative assets/liabilities on the accompanying Consolidated Balance Sheets. All forward exchange contracts outstanding at December 31, 2006 settled by February 26, 2007.

 

New Accounting Pronouncements

 

See Note 1 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2006 or pending adoption.

 

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