ITEM 1.
BUSINESS
OVERVIEW
PacifiCorp is a regulated electricity company operating in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp conducts its retail electric utility business as Pacific Power and Utah Power, and engages in electricity production and sales on a wholesale basis under the name PacifiCorp. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services, environmental remediation and financing. The Company’s goals are to provide safe, reliable, low-cost electricity to its customers, with fair and increasing earnings to shareholders. Costs incurred by the Company to provide service to its customers are expected to be included as allowable costs for ratemaking purposes. However, there can be no assurance that these costs will be fully recovered through the regulatory process.
Western United States (“U.S.”) wholesale energy market prices were relatively stable during the year ended March 31, 2003 as compared to each of the years ended March 31, 2002 and 2001. The Company took several actions to maintain a balanced net energy position through the summer peak period and the remainder of the fiscal year through a combination of existing physical resources, electricity purchases, weather-related hedges and peaking generation facilities. The Company added a 120-megawatt (“MW”) gas-fired peaking plant in Utah, which came on line in August 2002, and also entered into an operating lease arrangement for a 200-MW peaking plant in Utah with West Valley Leasing Company, LLC, a subsidiary of PPM Energy, Inc. (“PPM”), formerly known as PacifiCorp Power Marketing, Inc., a subsidiary of PacifiCorp Holdings, Inc. (“PHI”). These actions, as well as the utilization of other flexible physical and financial hedging instruments, assisted the Company in maintaining a balanced energy position during the year ended March 31, 2003. The Company believes that its energy position is balanced for summer 2003.
For the year ended March 31, 2003, overall retail megawatt-hour (“MWh”) sales decreased approximately 1.2%. While the impact of weather was not significant for the year ended March 31, 2003, sales for the year ended March 31, 2002 were approximately 564,000 MWh, or 1.2%, higher than sales for the year ended March 31, 2003, due to the effects of weather. Excluding this weather impact, the loads for both years were relatively consistent, although load growth varied within individual states and customer classes. While residential and commercial loads reflected an increase of 1.2% and 3.6%, respectively, as a result of additional customers in the eastern portion of the Company’s service territory, the industrial class showed a 3.2% decrease as a result of the effects of the economic downturn and a decrease in industrial customers.
The Company’s hydroelectric resources are in watersheds with precipitation that averaged 85.0% of normal for the year ended March 31, 2003 and had ending snowpack at around 74.0% of normal. These drier than normal conditions reduced generation from Company-owned projects by 65,000 MWh as compared to the hydroelectric generation for the year ended March 31, 2002. Despite increased precipitation in April 2003, the reduced snowpack will continue to affect generation from the Company’s resources for the remainder of the normal runoff period through the end of September 2003. Beginning with the next hydrologic cycle in October 2003, the Company anticipates a return to normal water conditions. In the event of below-normal hydroelectric generation, the Company will either increase output from its thermal generation resources or purchase energy in the wholesale market, which would result in increased power costs to the extent existing hedges do not offset the impact of reduced hydroelectric generation.
Concluded regulatory actions in the year ended March 31, 2003 included approval in Oregon of a $15.4 million overall rate increase effective June 1, 2002. On March 6, 2003, a general rate increase of $8.7 million, or 2.8%, was granted in Wyoming. Rate actions submitted for regulatory approval include a general rate case filed on March 18, 2003 in Oregon, requesting an increase of $57.9 million, or 7.4%, in base rates to take effect in January 2004; a general rate case filed on May 15, 2003 in Utah establishing a maximum increase of $125.0 million, or 12.5%, in base rates to take effect in April 2004; and a general rate case filed on May 27, 2003 in Wyoming, requesting an increase of $41.8 million, or 13.1%, in base rates to take effect in March 2004.
The Company also made progress toward recovering the deferred net power costs incurred during the period of extreme volatility and unprecedented high price levels beginning in summer 2000 and extending through summer
2001. These costs have been authorized for recovery as follows: (i) $147.0 million in Utah; (ii) $131.0 million, plus carrying charges, in Oregon; and (iii) $25.0 million in Idaho. The Oregon rate order is the subject of a court appeal by intervening parties, which, if successful, would require refunds of amounts collected after January 22, 2003. In Wyoming, the Company’s request for recovery of deferred net power costs was denied, and, as a result, the Company wrote off the remaining net regulatory asset of $48.3 million during the year ended March 31, 2003. The Company filed a petition for rehearing on the Wyoming decision on April 4, 2003. The WPSC denied the petition on May 30, 2003. In Washington, the Company had requested recovery of approximately $17.5 million of excess power costs, which have not been deferred, or, alternatively, that the Company be allowed to file a general rate case, which is currently restricted through December 2005. This request was subsequently reduced to approximately $15.9 million based on revised estimates. A final decision in Washington is expected by June 2003. At March 31, 2003, the Company had $137.8 million of deferred power costs, net of amortization, remaining to be collected over two to three years.
The Company is subject to comprehensive regulation by the Federal Energy Regulatory Commission (the “FERC”) and state and local regulatory agencies. The Company is required to comply with various permits, approvals and licenses from the governmental agencies that regulate many aspects of the Company’s business, including customer rates, service territories, sales of securities, asset acquisitions and sales, accounting policies and practices, and the operation of its coal, steam and hydroelectric facilities. The Company believes that it has the necessary permits, approvals and licenses to operate its plants in material compliance with applicable requirements. The Company is also subject to regulation by the Securities and Exchange Commission (the “SEC”) under the Public Utility Holding Company Act of 1935 (the “PUHCA”), which includes restrictions on securities issuances, payment of dividends and transactions with affiliates. The Company is unable to predict the impact on its operating results of future regulatory activities of these agencies.
As a result of the western energy crisis from May 2000 through June 2001, the bankruptcy filing by Enron Corp. (“Enron”) and investigations by governmental authorities into electricity and natural gas trading activities, companies in the regulated and nonregulated utility business have been under an increased amount of public and regulatory scrutiny. This increased scrutiny could lead to significant changes in laws and regulations affecting the Company, including new accounting standards that could change the way the Company is required to record revenues, expenses, assets and liabilities. These types of changes in the industry and any resulting regulations may have a significant impact on the Company’s results and access to capital markets.
The Company’s operations are exposed to risks, including legislative and governmental regulations; volatility in the price and supply of purchased electricity, fuel and natural gas; uncertain recovery of purchased electricity and natural gas costs; weather conditions; economic conditions; availability of generation facilities; competition; technology; and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit, volumetric and commodity price risks associated with wholesale sales and purchases. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS RISK for further discussion.
The Company had 6,140 employees on March 31, 2003. Approximately 58.6% of the employees of the Company are covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America, International Brotherhood of Boilermakers and the United Mine Workers of America. In the Company’s judgment, employee relations are satisfactory.
The 8 1/4% Cumulative Quarterly Income Preferred Securities (Series A Preferred Securities) of PacifiCorp Capital I, and the 7.70% Trust Preferred Securities (Series B Preferred Securities) of PacifiCorp Capital II, each a wholly owned subsidiary trust of the Company, are traded on the New York Stock Exchange. All outstanding shares of the common stock of PacifiCorp are indirectly owned by Scottish Power plc (“ScottishPower”), whose American Depository Shares (“ADS”) are traded on the New York Stock Exchange.
From time to time, the Company may make or issue forward-looking statements that involve a number of risks and uncertainties under the safe-harbor provisions of the Private Securities Litigation Reform Act of 1995, as described in Forward-Looking Statements under ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Any forward-looking statements made or issued by the Company, including statements in this report, should be considered in light of these factors.
The website address of the Company is www.pacificorp.com. The Company makes available free of charge, on or through its website, its annual, quarterly and current reports, and any amendments to those reports, as soon as
reasonably practicable after electronically filing such reports with the SEC. Information contained on the Company’s website is not part of this report.
SERVICE TERRITORIES
The Company serves approximately 1.5 million retail customers in service territories aggregating about 136,000 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho and California. The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urbanized manufacturing and government service centers. No one segment of the economy dominates the service territory, which helps mitigate the Company’s exposure to economic changes. In the eastern portion of the service territory, mainly consisting of Wyoming and Utah, the principal industries are mining and extracting coal, oil, natural gas, uranium and oil shale. In the western portion of the service territory, mainly consisting of Oregon and southeastern Washington, the principal industries are agriculture and manufacturing, with pulp and paper, lumber and wood products, food processing, high technology and primary metals being the largest industrial sectors. The Company delivers electricity through approximately 57,000 miles of distribution lines and 15,000 miles of transmission lines.
The following map highlights the Company’s retail service territory.
The geographic distribution of the Company’s retail electric operating revenues for the year ended March 31, 2003 was as follows: Utah, 38.8%; Oregon, 31.9%; Wyoming, 12.7%; Washington, 8.2%; Idaho, 5.9%; and California, 2.5%.
In July 1998, the Company announced its intention to sell its California service territory, including its electric distribution assets. The Company and Nor-Cal Electric Authority (“Nor-Cal”) have engaged in detailed negotiations with a view toward executing a definitive sale agreement. Various factors have impeded consummation of the sale transaction. In June 2002, the California county of Siskiyou filed a validation action in California Superior Court, challenging the authority of Nor-Cal to enter into such a transaction as proposed and alleging certain conflicts of interest among Nor-Cal and its advisors. The validation action is ongoing, but based on the foregoing factors, consummation of the sale is uncertain.
In February 2003, the Oregon Public Power Coalition submitted a petition to Multnomah County, Oregon, calling for an election to form a government-owned and operated electric utility in the county. The county is conducting hearings, and a public vote could occur in November 2003. If approved by the voters, the measure would result in the formation of a public utility district and could result in condemnation of the Company’s property in Multnomah County, Oregon, making that property part of a government-owned and operated utility. The Company serves 68,000 homes and businesses in the county, which represents approximately 1.9 million MWh, or $108.1 million in annual revenues. The Company is vigorously opposing this action.
CUSTOMERS
Electricity sales and retail customers, by class of customer, for the years ended March 31, 2003, 2002 and 2001, were as follows:
As a result of the geographically diverse area of operations, the Company’s service territory has historically experienced complementary seasonal load patterns. In the western portion, customer demand peaks in the winter months due to heating requirements. In the eastern portion, customer demand peaks in the summer when irrigation and air-conditioning systems are heavily used. Many factors affect per-customer consumption of electricity. For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. The majority of the growth in residential customers has been generated from the eastern portion of the Company’s service territories, whereas the western portion has remained relatively flat in terms of its growth. Average annual usage for the year ended March 31, 2003 decreased generally due to the impact of the downturn in the economy on the Company’s commercial and industrial customers. Price is a significant factor in usage by all customers. In response to prior region wide electricity supply shortages, the Company is actively promoting electricity conservation programs that lower customer usage.
During the year ended March 31, 2003, no single retail customer accounted for more than 1.2% of the Company’s retail electric revenues and the 20 largest retail customers accounted for 13.0% of the Company’s total retail electric revenues.
POWER AND FUEL SUPPLY
The Company owns, or has interests in, 17 thermal generating plants with an aggregate nameplate rating of 7,309.8 MW and plant net capability of 6,776.9 MW, 53 hydroelectric generating plants with an aggregate nameplate rating of 1,067.3 MW and plant net capability of 1,115.8 MW, and one wind generating plant with an aggregate nameplate rating and plant net capability of 32.6 MW. During the year ended March 31, 2003, the Company’s thermal, hydroelectric and wind generation plants supplied 57.5%, 4.5% and 0.1%, respectively, of its energy requirements. Of the remainder, 26.0% was supplied by purchased electricity under existing short-term purchase contracts and 11.9% by long-term purchase arrangements. With its present generating facilities, under average water conditions, the Company expects that approximately 59.5% and 5.3% of its energy requirements for the year ending March 31, 2004 would be supplied by its thermal and hydroelectric plants, respectively; 21.9%
would be obtained under short-term or spot-market purchase contracts; and the remaining 13.3% through existing long-term purchase arrangements.
During the year ended March 31, 2002, the Company leased gas turbine peaking generators with 114.0 MW capacity to provide electric generation to meet system load requirements and provide voltage support in the Salt Lake Valley. The Company replaced these leased gas turbine peaking generators with a Company-owned gas-fired peaking plant in Salt Lake City, Utah, which became operational in August 2002 and consists of three generation units, each rated at 40.0 MW.
In May 2002, the Company entered into a 15-year operating lease for an electric generation facility with West Valley Leasing Company LLC, a subsidiary of PPM. The Company, at its sole option, may terminate the lease, or purchase the facility, after three years or after six years. The facility consists of five generation units, each rated at 40 MW, and is located in Utah.
To improve customer service and reliability, the Company is continuing its infrastructure improvement projects in targeted areas, particularly along Utah’s Wasatch Front, where there is rapidly growing demand for electricity. The scope of this $200.0 million investment through 2005 includes transmission line upgrades, new distribution substations, upgrades to existing distribution substations and other system enhancements. These projects are intended to provide additional capacity to meet future load demands throughout the Company’s system.
As of March 31, 2003, the Company had approximately 196 million tons of recoverable coal reserves in mines owned by the Company. The coal from these reserves and from long-term contracts will be used to support the Company’s fuel strategy at its generation plants that are near the mines. During the year ended March 31, 2003, these mines supplied approximately 32.7% of the Company’s total coal requirements, compared to approximately 32.5% during the year ended March 31, 2002. Coal is also acquired through other long-term and short-term contracts. The Company supplies its gas-fired generation plants with natural gas through long-term and short-term contracts.
WHOLESALE SALES AND PURCHASED ELECTRICITY
In addition to its base of thermal and hydroelectric generation assets, the Company utilizes a mix of long-term, short-term and spot-market purchases to meet its load obligations, wholesale obligations and balancing requirements. Many of the Company’s purchased electricity contracts have fixed price components, which provide some protection against price volatility. The Company enters into such wholesale purchase and sale transactions to provide hedges against periods of variable generation or variable retail load. Generation varies with the levels of outages or transmission constraints, and retail load varies with the weather, distribution system outages and the level of economic activity. During the year ended March 31, 2003, retail loads were lower than in the previous year due to milder weather and a generally weak western U.S. economy. The Company’s wholesale transactions are integral to its retail business, providing for a balanced and economically hedged position and enhancing the efficient use of its generating capacity over the long term.
Historically, the Company has been able to purchase electricity from utilities in the southwestern U.S. and the Pacific Northwest for its own requirements. The Company’s transmission system connects with market hubs in the Pacific Northwest to provide access to what is normally low-cost hydroelectric generation and connects with the southwestern U.S., which provides access to normally higher-cost fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements. If the Company is in a surplus electricity position, the Company is usually able to sell excess electricity into the wholesale market, subject to pricing and transmission constraints.
Under the requirements of the Public Utility Regulatory Policies Act of 1978, the Company purchases the output of qualifying facilities constructed and operated by entities that are not public utilities. During the year ended March 31, 2003, the Company purchased an average of 95 MW from qualifying facilities, compared to an average of 104 MW during the year ended March 31, 2002.
PROJECTED DEMAND
Future increases in demand are dependent upon several factors, including the impact of price movements, weather, economic conditions, Demand Side Management (“DSM”) programs and changes in technology. Resource availability, price volatility and load volatility may materially impact power costs to the Company.
For the years through March 31, 2008, the Company is estimating average annual growth in retail MWh sales in the Company’s franchise service territories to be in the range of 1.8% to 3.6%, dependent upon factors such as economic recovery and growth, customer numbers, weather, conservation efforts and changes in prices. If price increases occur in the region, the Company believes that demand growth may slow. The Company’s financial results will be impacted by a variety of factors, including economic and demographic growth, competition and the extent of deregulation in the electric industry.
Integrated Resource Plan
The Company’s Integrated Resource Plan (“IRP”) provides a framework and plan for the prudent future actions required to ensure that the Company continues to provide reliable and cost-effective electric service to its customers. Projected growth rates and retirement of existing resources indicate a need of about 4,000 additional MW of capacity between 2004 and 2014. These estimates are subject to ongoing review and could be revised. The IRP and the resulting Request for Proposals (“RFP”) process have been created to identify the Company’s future resource mix in a coordinated process with the stakeholders in each of the six states where the Company operates. As part of the IRP process, the Company is expecting to add capacity through a combination of the following sources: base-load resources or purchases (approximately 2,100 MW), peaking resources (approximately 1,200 MW) and shaped purchased electricity resources (approximately 700 MW). The Company also plans to implement DSM programs (450 average MW) and acquire renewable energy (approximately 1,400 MW). Shaped products and electricity purchase agreements are used in an effort to optimize physical assets and reduce cost. Before the Company commits to build assets, electricity purchase agreements and shaped products are reviewed and compared for economic benefit, risk reduction and long-term optionality.
The IRP was filed with the relevant state commissions on January 24, 2003. The Company has segregated the IRP supply-side action items into a series of four separate RFPs. Each RFP focuses on a specific category of supply-side resources and provides for the staged procurement of resources in future years in order to achieve load/resource balance. The first of these four RFPs was presented for consideration to the Oregon Public Utility Commission (the “OPUC”) on May 7, 2003. The expected cycle time for each RFP process is approximately six months. Approval for resources procured via the first RFP effort is expected toward the end of calendar year 2003. The subsequent three RFPs are anticipated to be released 30 to 90 days following the first RFP.
In addition to the four supply-side RFPs, the Company is preparing a separate RFP for the demand-side resources called for in the IRP. As part of the RFP process, the Company will develop and evaluate its own-build options consistent with the analyses in the IRP, such as new base-load or peaking generation facilities. The Company is also considering an additional generating unit at its Hunter station in Utah and has begun an air-quality permitting process for potential development of this unit. The RFP process includes an analysis of the customer benefits and the cost/risk balance of the available alternatives.
On March 6, 2003, the Utah Public Service Commission (the “UPSC”) opened a docket to consider adopting competitive bidding rules governing the acquisition of generating resources. An industrial-customer lobbying group and other interested parties approached the UPSC after legislation to impose new rules on generation procurement and affiliate transactions failed to garner support in the Utah legislature. Four conferences to consider current regulations and investigate proposals were held during April 2003. An update conference was held with the UPSC on May 8, 2003. At this meeting, all parties confirmed their intention to hold further technical conferences. These conferences will focus on two issues: the need for short-term interim rules on resource acquisition and the requirement to develop longer-term, more fully developed rules for affiliate transactions and resource acquisition.
CAPITAL EXPENDITURE PROGRAM
The following table shows actual capital expenditures for the year ended March 31, 2003 and the Company’s estimated capital expenditures for the years ending March 31, 2004 through 2006.
Actual and estimated future capital expenditures include upgrades to distribution and transmission lines and existing generation plants, connections for new customers, accommodating load growth, coal mine investments, air-quality and environmental expenditures, hydroelectric relicensing costs and information technology systems. All of these expenditures are subject to continuing review and revision by the Company, and actual costs could vary from estimates due to various factors, such as changes in business conditions, revised load-growth estimates, and increasing costs in labor, equipment and materials. The estimates of capital expenditures for the years ending March 31, 2004 through 2006 generally exclude the potential impact of future decisions regarding expansion of physical generation and transmission capacity arising from the RFP process. These additional expenditures may be significant but are spread over a number of years and are subject to future legislative and regulatory developments. They cannot be accurately estimated at this time.
COMPETITION
During the year ended March 31, 2003, the Company continued to operate its retail business under state regulation. Certain of the Company’s industrial customers in Oregon have the right to choose alternative electricity suppliers and others in the Company’s service territories are seeking choice of suppliers, options to build their own generation or co-generation plants, or the use of alternative energy sources such as natural gas. If these other customers gain the right to receive electricity from alternative suppliers, they will make their energy purchasing decision based upon many factors, including price, service and system reliability. Availability and price of alternative energy sources and the general demand for electricity also influence competition.
Any adoption of retail competition in the territories served by the Company and the unbundling of regulated energy service could have a significant adverse financial impact on the Company due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital and could result in increased pressure to lower the price of electricity. The Company cannot predict if or when it will be subject to changes in legislation or regulation, nor can the Company predict the impact of these changes.
The regional electricity market in which the Company competes has changing transmission regulatory structures, which could affect the ownership of transmission assets and related revenues and expenses. The Company currently owns and operates transmission facilities as part of its vertically integrated utility operations. Transmission costs are not separated from, but rather are “bundled” with, generation and distribution costs in approved retail rates. In 1996, the FERC issued new rules on transmission service to facilitate competition in the wholesale market on a nationwide basis. The rules give greater flexibility and more choices to wholesale electricity customers.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking, proposing a new Standard Market Design (“SMD”) for wholesale electricity markets, relating to open-access transmission service and standard electricity market design. The SMD proposed a number of remedies aimed at removing barriers to efficient competitive wholesale markets perceived by the FERC in the wake of the FERC’s Orders 888 and 2000. In an April 28, 2003 SMD White Paper, the FERC signaled a greater willingness to defer to regional solutions and not adopt overly prescriptive rules. It appears that the FERC will refocus its upcoming final rule around the formation of Regional Transmission Organizations (“RTOs”) to ensure that these entities have sound wholesale market rules. Renamed the “Wholesale Power Market Platform,” the FERC’s new proposal retains the initial SMD requirement that jurisdictional utilities transfer control of their transmission facilities to an RTO. At the same time, the FERC
affirmed that it would permit phased-in implementation and sequencing tailored to each region, and allow modifications that would benefit customers within each region. The FERC has now instituted an open-ended public comment period, specifically inviting reaction to certain aspects of the paper. It is expected that a final rule will not be issued until the U.S. Congress has completed action on pending energy legislation.
The Company, in conjunction with nine other utilities, is seeking to form an RTO (“RTO West”), in response to the FERC’s Order 2000. The 10 members of RTO West would be Avista Corporation, British Columbia Hydro Power Authority, BPA, Idaho Power Company, Northwestern Energy L.L.C. (formerly Montana Power Company), Nevada Power Company, PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc. and Sierra Pacific Power Company. Creation of RTO West is subject to regulatory approvals from the FERC. On September 18, 2002, the FERC voted that, with some modification and further development of certain details, the RTO West proposal satisfies the 12 characteristics and functions of the FERC’s Order 2000. The states served by these utilities will likely participate in regional state committees that will be established to address significant market design features for their respective regions, such as allocation of firm transmission rights to existing capacity and cost recovery for new transmission expansion. Some of these states may also assert jurisdiction over certain matters relating to the formation of RTO West. RTO West, if and when fully implemented, would serve as an independent transmission provider for the RTO West region and have operational authority needed for bulk electricity transfers over a majority of the 60,000 miles of transmission lines owned by its members.
As a result of this changing regulatory environment, which includes open-access transmission service, the Company may be subject to a competitive market that is substantially different than the current market structure. This change in competitive market structure could affect the Company’s load forecasts, plans for electricity supply and wholesale electricity sales and related revenues. The effect on the Company’s net income and financial condition could vary depending on the extent to which (i) additional generation is built to compete in the wholesale market, (ii) new ways for the Company to use the wholesale market to balance its retail position are developed, or (iii) current wholesale customers elect to purchase from other suppliers after existing contracts expire.
ENVIRONMENTAL MATTERS
The Company’s activities are subject to a broad array of federal, state and local laws and regulations designed to protect, restore and enhance the quality of the environment. The Company’s costs of complying with complex environmental laws and regulations, as well as internal voluntary programs and goals, are significant and will continue to be so for the foreseeable future.
In the year ended March 31, 2003, the Company spent approximately $12.5 million on environmental capital projects either required by law or necessary to meet the Company’s internal environmental goals. The Company currently estimates expenditures for environmental-related capital projects will total approximately $35.8 million, $86.4 million and $106.8 million in the years ending March 31, 2004, 2005 and 2006, respectively. The Company monitors these requirements and annually revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates.
Air Quality
The Company’s fossil-fuel-fired electricity generation plants, as well as other facilities with significant air emissions, are subject to air quality regulation under federal, state and local laws and regulations. The Company believes it has all required permits and other approvals to operate its plants and that the plants are in material compliance with applicable requirements. The Company uses emission controls, low-sulfur coal, environmentally conscious plant operating practices and continuous emissions monitoring to enable its plants to comply with emissions limits, opacity limits, visibility and other air-quality requirements.
The U.S. Environmental Protection Agency (the “EPA”) has initiated a regional haze program intended to improve visibility at specific federally protected areas, some of which are located near Company plants. The Company is working with the Western Regional Air Partnership to help develop the technical and policy tools needed to comply with those regulations. Carbon dioxide emissions are the subject of growing discussion and action in the context of global climate change, but such emissions are not currently subject to regulation. The Company is anticipating mitigating climate-change challenges with additions of renewable generation, conservation and thermal resources as outlined in the IRP. Likewise, carbon dioxide emissions risk has been anticipated in the Company’s IRP through the use of a “carbon adder.” The Company also supports development of trading and other market mechanisms, as well as offset strategies, where feasible, to reduce future compliance costs to customers. The U.S. Congress is currently
considering several proposed bills that would create enforceable limits on electricity plant emissions of sulfur dioxide, carbon dioxide, oxides of nitrogen and mercury. While the Company is unable at this time to predict with certainty the level of capital expenditures relating to air quality and carbon dioxide emissions, it believes these amounts could be significant but will be spread over a number of years. The Company also believes that the impact will be mitigated by recovery through the regulatory ratemaking process.
In 1999, the EPA commenced enforcement actions alleging violations of New Source Review requirements by the owners of certain coal-fired generating plants in the eastern and midwestern U.S. The Company is not part of those actions. However, in December 2000, the EPA notified the Company that it is investigating the Company’s Carbon, Dave Johnston, Huntington and Naughton coal-fired plants, and required the Company to provide information about the operation, maintenance, emissions, utilization and other aspects of these plants. In May 2003, the EPA notified the Company that it is investigating similar issues at the Bridger, Hunter and Wyodak plants. The Company is cooperating with these investigations by providing requested information to the EPA. No legal proceeding has been commenced.
Endangered Species
The federal Endangered Species Act of 1973 and similar state statutes protect species threatened with possible extinction. Protection of the habitat of endangered and threatened species makes it difficult and more costly to perform some of the Company’s core activities, including the siting, construction and operation of new and existing transmission and distribution facilities, as well as hydroelectric, thermal and wind generation plants. In addition, endangered species issues impact the relicensing of existing hydroelectric generating projects, generally raising the price the Company must pay to purchase wholesale electricity from hydroelectric facilities owned by others, reducing output and increasing the costs of operating the Company’s own hydroelectric resources.
Environmental Cleanups
Under the Comprehensive Environmental Response, Compensation and Liability Act; the Resource Conservation and Recovery Act; and similar state statutes, entities that disposed of, or arranged for the disposal of, hazardous materials may be liable for cleanup of the contaminated property. In addition, the current or former owners or operators of affected sites may be liable. The Company has been identified as a potentially responsible party in connection with a number of cleanup sites because of its current or past ownership or operation of the property or because the Company sent hazardous materials to the property in the past. The Company has completed several cleanup actions and is actively participating in investigations and remedial actions at other sites. The costs associated with those actions are not expected to be material to the Company’s consolidated financial position, results of operations, cash flows, liquidity or capital expenditures.
Mine Reclamation
The federal Surface Mining and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. The Company’s mining operations are subject to these reclamation and closure requirements. Significant expenditures are expected to be required when individual Company mining operations are closed and reclamation occurs. The costs associated with reclamation are subject to the regulatory process, and the Company expects to be allowed to recover these costs.
Water Quality
The federal Clean Water Act and individual state clean-water regulations require a permit for the discharge of wastewater, including storm-water runoff from electricity plants and coal storage areas, into surface water and ground water. The Company believes that it has management systems in place to monitor performance, identify problems and take action to ensure compliance with permit requirements. Additionally, the Company believes that it currently has, or has initiated the process to receive, all required permits.
Other Environmental Laws
The Company is required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. The Company believes that it is in material compliance with all applicable environmental laws.
REGULATION
The Company is subject to the jurisdiction of public utility regulatory authorities in each of the states in which it conducts retail electric operations. These authorities regulate various matters, including prices, services, accounting, issuances of securities and other matters. Commissioners are appointed by the respective states’ governors for varying terms. The Company is a “licensee” and a “public utility” as those terms are used in the Federal Power Act (“FPA”) and is therefore subject to regulation by the FERC as to accounting policies and practices, certain prices and other matters, including the terms and conditions of transmission service. Most of the Company’s hydroelectric plants are licensed by the FERC as major projects under the FPA, and certain of these projects are licensed under the Oregon Hydroelectric Act. The Company is also subject to the requirements and restrictions of the PUHCA.
Federal Energy Regulatory Commission Issues
On April 26, 2001, the FERC imposed a price mitigation plan limiting prices on spot-market sales in California 24 hours a day, seven days a week. On June 19, 2001, the FERC issued an order that extended the California price limits to all wholesale spot-market sales in the entire 11-state western region. On July 17, 2002, the FERC issued an order that became effective November 1, 2002, increasing the price cap to $250.00 per MWh from the previous $91.87 per MWh. However, the order also created an automatic mitigation procedure designed to limit the ability of generators to cause prices to rise above $91.87 per MWh.
The FERC’s June 19, 2001 order also required that all public utility sellers and buyers (the “Party” or “Parties”) in the California Independent System Operators’ (the “Cal ISO”) markets participate in settlement discussions to complete the task of settling past accounts and structuring the new arrangements for California’s energy future. The FERC appointed an Administrative Law Judge (“ALJ”) to serve as a settlement judge. On July 12, 2001, an ALJ issued a recommendation to the FERC based upon the settlement conference, proposing a methodology to calculate refunds for spot sales made to the Cal ISO and the California Power Exchange (the “CPX”) between October 2, 2000 and June 20, 2001. The FERC agreed with the ALJ-proposed methodology. A proceeding before a second ALJ was held beginning August 19, 2002 to determine each Party’s refund liability. On November 20, 2002, the FERC allowed all Parties to engage in 100 days of additional discovery into market manipulation. On December 12, 2002, an ALJ issued a Certification of Proposed Findings on California Refund Liability in which the ALJ preliminarily determined that $1.2 billion was still owed to suppliers by the Cal ISO and the CPX, which amount was calculated by offsetting a $1.8 billion refund against the $3.0 billion owed to suppliers. On March 3, 2003, the Parties filed supplemental evidence of market manipulation and proposed new findings of fact. On March 20, 2003, the Parties responded to the March 3, 2003 filings. On March 26, 2003, the FERC staff issued a final report on price manipulation in western markets (the “Staff’s Final Report”). Following issuance of the Staff’s Final Report, the FERC issued an Order on Proposed Findings on Refund Liability adopting many of the ALJ’s December 12, 2002 Proposed Findings and clarifying the method for calculating refunds for purchases made in the Cal ISO and CPX spot markets. In its order, the FERC adopted recommendations from the Staff’s Final Report, including a new proxy for gas prices, which could increase the amount of refunds, if any, owed by all Parties. The FERC expects that refunds will be distributed by the end of summer 2003. The Company’s level of exposure to refunds is dependent upon any final order issued by the FERC in response to the outcome of these proceedings. The Company has established a reserve of approximately $17.7 million for any refunds owed as a result of this FERC proceeding.
The FERC has also established a second proceeding to consider the possibility of requiring refunds for wholesale spot market bilateral sales in the Pacific Northwest between December 25, 2000 and June 20, 2001. In a decision issued on September 24, 2001, an ALJ recommended that the FERC should not require refunds for these sales. On December 19, 2002, the evidentiary record was reopened in this case for the purpose of allowing parties to submit additional evidence concerning potential refunds for wholesale spot market bilateral sales transactions in the Pacific Northwest for the period January 1, 2000 through June 21, 2001 and to submit proposed new and/or modified findings of fact. On March 3, 2003, parties filed supplemental evidence of market manipulation and proposed new findings of fact. On March 20, 2003, parties responded to the March 3, 2003 filings. In its March 26, 2003 report on price manipulation in western markets, the FERC staff recommended that the FERC remand back to an ALJ for consideration of the additional evidence received after the decision in September 2001. The Company’s obligation to make refunds, if any, will be dependent upon any final order issued by the FERC in response to the outcome of these proceedings and cannot be determined at this time.
On May 2, 2002, the Company filed a series of complaints with the FERC against five wholesale power suppliers (the “Respondents”) for charging excessive prices for wholesale electricity purchases scheduled for delivery during
summer 2002. The contracts covered in the complaint were signed during a period of extreme wholesale market volatility and before the FERC imposed its Westwide spot-market price mitigation (price caps). The Company is seeking reformation of the contract prices to levels that constitute just and reasonable rates. Hearings on this proceeding were completed on January 3, 2003. On February 26, 2003, an ALJ issued an Initial Decision recommending dismissal of the Company’s complaints. The Company has moved to reopen the evidentiary record in light of additional evidence. In addition, on March 28, 2003, the Company filed its Brief on Exceptions identifying the legal errors contained in the Initial Decision. The FERC staff and the Respondents filed their opposing exceptions on April 17, 2003. Oral arguments were held at the FERC on May 15, 2003, and a final order is expected by December 2003.
In May 2002, the Company responded to data requests from the FERC regarding trading practices connected with the power crisis during 2000 and 2001. The Company confirmed that it did not engage in any trading practices intended to manipulate the market as described in the FERC’s data requests issued in May 2002. The Staff’s Final Report recommends that the FERC issue show-cause orders to numerous market participants, including the Company, requiring them to demonstrate why their behaviors did not violate the Cal ISO and CPX tariffs as part of the ongoing FERC trading practices investigation. It is unknown at this time whether the FERC will act on the staff’s recommendations.
Hydroelectric Relicensing
The Company’s hydroelectric portfolio consists of 53 plants with a plant net capability of 1,115.8 MW. These plants account for about 14.1% of the Company’s total generating capacity and provide operational benefits such as peaking capacity, generation, spinning reserves and voltage control.
The Company operates the majority of its hydroelectric generating portfolio under long-term licenses from the FERC. These licenses are granted by the FERC for periods of 30 to 50 years. There is a complex regulatory process that the Company must comply with to apply for new licenses that begins five and one-half years before the expiration of an existing license and involves a number of federal and state agencies, as well as other stakeholders. Some state and federal agencies and, in some cases, Native American Tribal Councils have authority to require certain terms and conditions to be included in the FERC license. Often, existing licenses expire prior to the FERC’s issuing a new license. In these cases, the FERC has historically issued annual operating licenses so that the project can continue to operate while alternatives are evaluated. The Company expects that the FERC will continue this practice. Many of the Company’s long-term operating licenses have expired or are expiring in the next few years and will continue to operate under annual licenses granted by the FERC. The FERC will require the Company to implement certain protection, mitigation and enhancement measures, primarily to address environmental concerns relating to fisheries, water quality, wildlife, recreation, land use, cultural resources and erosion, as conditions to the new licenses. Through this process, the Company’s operations must also comply with current environmental polices such as the Clean Water Act and the Endangered Species Act of 1973.
It is difficult to determine the economic impact of any new measures, but capital expenditures and operating costs are expected to increase over the next license periods of 30 to 50 years. In addition, in-stream flow requirements and other constraints on operations may result in lower generating output and reductions in the Company’s operational flexibility and ability to “shape” production into the highest-value load periods.
The Company has entered into settlement agreements with stakeholders in the licensing processes regarding measures to be included in the new licenses for the North Umpqua, Bear River and Big Fork hydroelectric projects. The Company believes that negotiating settlement agreements results in more cost-effective measures that provide a more timely response to environmental needs. The terms of these settlement agreements are incorporated into the Company’s license applications with the FERC and the tribal, federal and state agencies’ terms, conditions and recommendations to the FERC. As part of these settlement agreements, the Company has agreed to implement certain measures prior to and during the next license period. Most of these commitments are contingent on the Company ultimately receiving an acceptable license from the FERC. Assuming the Company is granted a new license on these projects for 30 to 35 years, these measures will cost approximately $184.5 million over the license terms.
As of March 31, 2003, the Company had incurred approximately $95.4 million in costs for ongoing hydroelectric relicensing, which are included in assets on the Company’s Consolidated Balance Sheet. The Company expects that these and future costs will be found to be prudent and recoverable in rates and, as such, will not have a material adverse impact on the Company’s consolidated results of operations.
The Company analyzed the costs and benefits of relicensing the Condit and American Fork hydroelectric projects and, as a result, entered into settlement agreements to remove or decommission these projects rather than to pursue new licenses. The removal of the Condit dam is projected to cost the Company approximately $19.4 million. Decommissioning of the American Fork project is expected to cost $1.0 million. These settlement agreements are contingent on acceptable orders being issued by the FERC and on obtaining all necessary permits.
Depreciation Rate Changes
On October 1, 2002, the Company filed applications with the respective regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation, based on a new depreciation study. The new study reflects depreciable plant balances at March 31, 2002. In Utah, settlement discussions have resulted in a stipulation with intervenors. On April 17, 2003, the UPSC approved the stipulation. The rates approved in the stipulation will reduce annual Utah allocated depreciation expense by $6.0 million. The Company and the Idaho Public Utilities Commission (the “IPUC”) staff have agreed on a similar stipulation that will reduce Idaho’s annual allocated depreciation expense by $0.9 million. This stipulation was filed with the IPUC on April 30, 2003. If adopted by all states, these depreciation rate changes would reduce total Company depreciation expense by $20.3 million annually, which could ultimately result in lower revenues or offset anticipated price increases. Future decisions by the commissions in Oregon, Washington and California may impact this annual expense reduction.
Trail Mountain Coal Mine Closure Costs
On February 7, 2001, the Company filed applications with the UPSC, the OPUC, the Wyoming Public Service Commission (the “WPSC”) and the IPUC requesting accounting orders to defer $27.1 million in unrecovered costs associated with its Trail Mountain coal mine. The Company ceased operations at the mine on March 7, 2001. The mine is located in central Utah and supplied fuel to the Company’s Hunter generating plant. In April 2001, the WPSC and the IPUC approved deferred accounting treatment of their states’ share of the $27.1 million of nonrecovered Trail Mountain coal mine investment costs. Additional closure-related costs in the amount of $18.7 million were subsequently identified, and the total amount subject to possible deferral increased to approximately $45.8 million. The Company filed in Utah and Oregon to include the additional costs in its deferral application and received approval to defer the full $45.8 million for accounting purposes. In addition, the parties in Oregon signed a stipulation calling for a $1.1 million annual reduction in Oregon base rates due to the removal of the Trail Mountain coal mine assets from the rate base. The stipulation also provides for a $2.6 million annual surcharge for five years to recover Oregon’s share of mine closure costs. This stipulation was approved by the OPUC on May 20, 2002. On April 4, 2002, the UPSC approved deferral of Utah’s share of the $45.8 million, with a five-year amortization beginning April 1, 2001. On May 7, 2002, the Company filed a general rate case in Wyoming that sought to recover Wyoming’s share of the $45.8 million, to be recovered based on a five-year amortization period beginning April 1, 2001. On March 6, 2003, the WPSC approved a stipulation that includes one-fifth of Wyoming’s allocated share of Trail Mountain coal mine closure costs in annual base rates.
In April 2002, the Company established a regulatory asset for the full closure costs of the Trail Mountain coal mine, with a five-year amortization period beginning April 2001. The resulting regulatory asset at March 31, 2003 was $27.9 million, net of amortization. The reestablishment of the regulatory asset increased accumulated depreciation to reverse the effects of the retirement of the mine and decreased coal inventory costs for the closure-related costs.
Merger Credits
In connection with the merger between the Company and ScottishPower (the “Merger”), the Company was required to provide benefits to ratepayers through fixed reductions in rates, or “Merger Credits.” The Company’s total obligation for Merger Credits was $133.4 million through the period ending December 31, 2004. In May 2002, the UPSC allowed the Company to offset all future Merger Credits, which amounted to $20.6 million, against deferred net power costs. On June 7, 2002, the IPUC approved a stipulation agreement that allowed the Company to offset future Merger Credits against deferred net power costs in the amount of $2.3 million. These actions in Utah and Idaho eliminated the Merger Credit revenue reductions of approximately $1.1 million per month, which were set to expire December 31, 2003. In February 2003, the Company recorded $6.0 million in liabilities and current expenses for Merger Credits that will be refunded to Oregon customers during the calendar year ending December 31, 2003. Through March 31, 2003, the Company had provided an aggregate of $64.2 million in Merger Credits and interest to its customers through reduced rates. As of March 31, 2003, the Company was still obligated to provide $27.2 million of Merger Credits to customers in Oregon and Washington, through either bill credits or lower base rates.
Regulatory Established Returns
The regulatory commissions in the various states where the Company conducts its business approve an appropriate level of cost recovery for debt, preferred equity and common equity, which results in an allowed return on rate base (“ROR”) for the Company’s regulated utility business, including an allowed return on equity (“ROE”) representing a return on shareholder investment. The Utah, Oregon and Wyoming commissions have approved RORs in recent general rate cases of 8.9%, 8.6% and 8.4%, respectively, and ROEs of 11.0%, 10.8% and 10.8%, respectively. Rate cases are underway in Utah, Oregon, Wyoming and California, in which the Company has requested an ROE of 11.5% in each of these states. Commissions in Washington and Idaho have not had recent hearings in which there was a specific finding of fact on allowed ROR or ROE. However, these commissions monitor the Company’s achieved ROR and ROE for appropriateness under current market conditions.
Legislative Actions
The U.S. Senate has begun consideration of a comprehensive energy bill. The provisions of this proposed bill include repealing the PUHCA; prohibiting the FERC from making final its SMD rulemaking prior to July 1, 2005; extending the renewable-energy production tax credit for three years; authorizing federal utilities to participate in RTOs; establishing a process for developing mandatory reliability standards; reforming certain elements of the hydroelectric licensing process; enabling companies to use biodiesel to meet their alternative-fuel fleet requirements; and allowing Native American Tribes to enter into arrangements for energy facilities on tribal land. On April 11, 2003, the U.S. House of Representatives passed its version of comprehensive energy legislation. The bill contains many of the same proposals included in the U.S. Senate bill. The Company is unable to predict the prospects for enactment of a comprehensive energy bill, the specific content of final legislation or what material impact, if any, the outcome of this legislation may have on the Company’s consolidated financial position, results of operations, cash flows, liquidity or capital expenditures.
Among the legislative measures approved in the Company’s service territory, Senate Bill 61 in Utah has an impact on regulation and will go into effect in early summer 2003. This legislation provides an option for the UPSC to use a future test-year period in utility rate cases that more appropriately reflects the cost of providing service, and to reduce the period between capital investment or cost incurrence and recovery in rates.
Under the terms of legislation recently approved in Wyoming, the Consumer Advocate Staff (the “CAS”) will no longer report to the WPSC. Under the new statute, the CAS will be headed by a director who is appointed by, and reports directly to, the Governor. The CAS will continue to intervene in utility rate cases to represent the interests of all customers.
Concluded Regulatory Actions
Oregon - On May 20, 2002, the OPUC approved a one-year $15.4 million overall rate increase effective June 1, 2002 for the Company’s Oregon customers, to cover increases in power costs. This increase included an $18.7 million one-year surcharge relating to higher market costs for summer purchases and resolved a number of other outstanding issues. The Industrial Customers of Northwest Utilities (the “ICNU”) requested limited reconsideration of the portion of this order relating to the lease of the West Valley, Utah generating units, involving $1.2 million of revenues annually. On August 8, 2002, the OPUC ordered this reconsideration. The ICNU, the Company and the OPUC staff have filed testimony. Opening briefs were filed April 11, 2003; reply briefs were filed on April 18, 2003; and an order from an ALJ is expected in summer 2003.
On May 13, 2003, the OPUC approved the Company’s request to begin amortizing its year-ended March 31, 2002 costs under Oregon Senate Bill 1149 (“SB 1149”) effective May 21, 2003. See Deregulation - Oregon below. The total costs of $5.2 million will be amortized on a straight-line basis over a five-year period, resulting in an annual rate increase of $1.1 million, or 0.1%. The amortization is subject to refund pending completion of an OPUC staff audit, which is scheduled to occur sometime in summer 2003.
Wyoming - On May 7, 2002, the Company filed a general rate case seeking a permanent $30.7 million, or 9.8%, increase in electricity rates for its Wyoming customers. On December 18, 2002, the Company revised the requested increase to $21.4 million. On January 17, 2003, the Company and the WPSC staff reached agreement on certain issues, which resulted in the Company revising its requested increase to $20.0 million, or 6.4%. The Company’s filing also included a request to recover the replacement power costs resulting from the outage of the Company’s Hunter No. 1 generating plant and a proposal for recovering deferred net power costs as discussed under Deferred
Net Power Costs -Wyoming. Hearings in this case were held during January 2003. On March 6, 2003, the WPSC granted the Company a general rate increase of approximately $8.7 million, or 2.8%, and reduced the Company’s ROE from 11.0% to 10.8%. On April 4, 2003, the Company filed a request for rehearing to reconsider the Company’s request for recovery of power costs and the order’s adoption of the reduced ROE. The WPSC heard oral arguments on May 8, 2003 and denied the petition on May 30, 2003. See Deferred Net Power Costs - Wyoming below.
Idaho - On January 7, 2002, the Company filed a request with the IPUC to recover $38.0 million of deferred net power costs through a temporary 24-month surcharge on customer bills and to implement a new credit to pass through Residential Exchange Program benefits from two Bonneville Power Administrative (“BPA”) settlement agreements. Pass-throughs of BPA credits do not affect Company earnings. In addition, the Company requested an adjustment of individual rate classes to more closely reflect the actual cost of service and proposed a rate mitigation policy to ensure that no customer class would receive a rate increase during the period in which the proposed surcharge is in effect. Parties to the proceeding agreed to a stipulation that would allow recovery of $25.0 million of the deferred net power costs. This recovery would be achieved through a $22.7 million power cost surcharge over two years, plus termination of future Merger Credits in the amount of $2.3 million. The IPUC approved the stipulation on June 7, 2002. On June 28, 2002, the Company filed a petition asking the IPUC to reconsider the portion of its June 7, 2002 order requiring that the Company implement a one-time refund of $1.1 million relating to procedural issues in the form of a $20.00 per customer credit. Two individuals also filed petitions for reconsideration of several aspects of the IPUC’s order approving the stipulation. On July 24, 2002, the IPUC granted the Company’s petition for reconsideration and denied the petitions from the two other parties. Hearings on the reconsideration were held on September 10, 2002. On October 25, 2002, the IPUC ordered the one-time refund of $1.1 million to be reduced to $10,000.
Rate Actions Submitted for Regulatory Approval
Utah - The Company commenced a general rate case on May 15, 2003 based on the year ended March 31, 2003 and including known and measurable changes that will occur by January 1, 2004. The initial filing included a projected revenue requirement increase of $125.0 million that serves as a cap on the amount the Company can receive in the case. A subsequent detailed filing will be made in July 2003 identifying the final requested amount under this cap. If approved, the effective date of the increase would be January 1, 2004, although the Company would not collect any increase until April 1, 2004.
Oregon - On March 18, 2003, the Company filed a general rate case with the OPUC to recover rising costs, including insurance premiums, pension funding and health care. Similar cost trends are being experienced by many businesses across the country, including others in the utility sector. In addition, the filing requested an ROE of 11.5% to compensate the Company for general risks relating to the western U.S. utility environment, as well as some additional risks relating to utility industry restructuring in Oregon and multijurisdictional operations. The Company has requested an annual increase of $57.9 million, or 7.4%, in base rates to take effect in January 2004.
Wyoming - On May 27, 2003, the Company filed a general rate case with the WPSC to recover rising costs (including insurance premiums, pension funding and health care costs) and requested an increase in the ROE to 11.5% to compensate the Company for general risks relating to the western U.S. utility environment, as well as some additional risks relating to multijurisdictional operations. The Company has requested an annual increase of $41.8 million, or 13.1%, in base rates to take effect in March 2004.
California - On March 16, 2001, the Company filed an interim rate relief request with the California Public Utilities Commission (the “CPUC”) as Phase I in an effort to seek an increase in electricity rates for its customers in California. Subsequently, on December 20, 2001, the Company filed a general rate case to increase rates to compensatory levels. If approved by the CPUC, customer rates would increase 29.4% overall, or $16.0 million annually, with an authorized ROE of 11.5%. The annual amount requested incorporated the Phase I interim amount. On June 27, 2002, the CPUC approved an interim increase of $0.01 per kilowatt-hour (“kWh”) for certain customers, or approximately $4.7 million annually, or 8.8%, overall. This rate increase is subject to refund pending the outcome of the general rate case. On December 26, 2001, the California Office of Ratepayer Advocates (“ORA”) filed a motion to dismiss or defer the Company’s general rate case request. The Company responded to ORA’s motion on January 10, 2002. Following the expiration of the protest period, on February 25, 2002, the Company filed a motion for a prehearing conference to identify parties of record, establish a procedural schedule and address other issues. A discovery process began in mid-October 2002 and is ongoing. A prehearing conference
was held on February 25, 2003. The CPUC and intervenor filed their testimony on May 23, 2003 for results of operations and are scheduled to file testimony on June 4, 2003 for cost allocation and rate design issues. Evidentiary hearings are scheduled for the week beginning June 23, 2003.
Deferred Net Power Costs
The Company filed applications in Utah, Oregon, Wyoming, Washington and Idaho seeking deferred accounting treatment for net power costs materially in excess of the power costs assumed in setting existing retail rates. The applications sought to defer these power cost variances beginning November 1, 2000. As discussed below, the Company received authorization to defer some power costs in excess of those included in retail rates in all the states where requests to do so were made. At March 31, 2003, the Company had remaining deferred power costs, net of amortization, of $137.8 million, including carrying costs.
Utah - In Utah, pursuant to the UPSC’s approval of deferred accounting treatment for replacement power costs resulting from the Hunter No. 1 outage, the Company filed on August 23, 2001 seeking permission to recover $103.5 million in replacement power costs over a 12-month period. On November 2, 2001, the UPSC allowed the Company to apply overcollections under an interim relief order from an earlier general rate case toward Hunter No. 1 replacement power costs on an interim basis, subject to refund. The amount of the interim relief was approximately $29.5 million annually.
Also in Utah, on September 21, 2001, the Company filed for permission to defer $109.0 million of net power costs above the level adopted in the UPSC’s rate order of September 10, 2001. These costs were incurred during the period May 9, 2001 through September 30, 2001. A hearing relating to the deferral was held on December 7, 2001.
On May 1, 2002, the UPSC issued an order approving a stipulation agreement regarding recovery of deferred and nondeferred net power costs referred to above. The order allowed the Company to continue collecting a $29.5 million annual surcharge until March 31, 2004 and to apply $34.7 million of revenue already collected (subject to refund) against deferred net power costs. The order also allowed the Company to offset deferred net power costs against a regulatory liability of $27.0 million relating to the gain from the May 2000 sale of the Centralia, Washington electricity plant and coal mine (“Centralia”). These offsets reduced the regulatory asset for deferred net power costs. In addition, the UPSC allowed the elimination of $20.6 million for the final two years of Merger Credits associated with the Merger. This action eliminated the Merger Credit revenue reduction of approximately $1.0 million per month that was set to expire December 31, 2003. The Company recorded additional deferred net power costs of $37.9 million and committed not to file a general rate case with a rate effective date prior to January 1, 2004, with certain exceptions. This order should allow the Company to recover a total of $147.0 million of deferred net power costs in Utah by March 31, 2004. One party opposed the rate spread provisions of the stipulation and filed a petition with the Utah Supreme Court for review of the order. The case has been assigned to the Utah Court of Appeals.
Oregon - The November 2000 Oregon deferred-accounting filing encompassed all power costs that vary from the level in Oregon rates during the period from November 1, 2000 through September 9, 2001, including costs to replace lost generation resulting from the Hunter No. 1 outage. On January 18, 2001, the Company requested a 3.0%, or $22.8 million, annual rate increase effective February 1, 2001, to provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon, over an amortization period. This 3.0% rate increase was the maximum allowed on an annual basis for the recovery of deferred costs under the Oregon statutes then in force. On February 13, 2001, the OPUC authorized deferred accounting for power costs of $22.8 million. On February 21, 2001, the OPUC authorized the 3.0% rate increase effective February 21, 2001, subject to refund, pending the outcome of a separate phase of the proceeding to examine the prudence of these expenditures.
The Company filed with the OPUC on September 20, 2001 to increase the level of recovery of deferred net power costs incurred to serve Oregon customers from the then current 3.0% amortization level, or $22.8 million awarded in February 2001, to 6.0%, the maximum allowed on an annual basis for recovery of deferred costs under a change in Oregon law. On October 22, 2001, the OPUC suspended the Company’s request pending the outcome of the prudence phase of the proceeding.
In December 2001, the Company and the OPUC staff reached a stipulation in the prudence phase of the Company’s deferred net power cost proceeding. The stipulation provided that the Company would be permitted to recover 85.0% of the deferred net power costs in Oregon, or about $131.0 million, plus carrying charges. The stipulation allowed the Company to seek increased recovery in the event the Company’s appeal of the Commission’s order
limiting deferrals is successful. On July 18, 2002, the OPUC issued an order approving the stipulation and ending the prudence phase of the proceeding. On September 16, 2002, the Citizens’ Utility Board (the “CUB”) and the ICNU appealed this decision to the Marion County, Oregon Circuit Court. On October 11, 2002, the Company moved to intervene in this action. On March 26, 2003, the court issued a letter affirming the OPUC’s July 18, 2002 order. The ICNU and the CUB are likely to appeal to the Oregon Court of Appeals.
On August 6, 2002, the OPUC allowed the Company to increase the amortization level from 3.0% to 6.0%. The new rates were effective August 8, 2002. As of March 31, 2003, the Company had received $7.3 million in revenues as a result of this OPUC action. On August 19, 2002, the CUB and the ICNU filed a complaint with the OPUC, requesting that the OPUC require the Company to discontinue amortization of the additional 3.0%, challenging the approval itself based on procedural technicalities during the approval proceeding. On October 10, 2002, the Company filed a stipulation and tariff to allow the OPUC to reopen consideration of the increase in amortization of the deferred power costs from 3.0% to 6.0%. Subject to regulatory approval, the Company and the CUB have reached a stipulation agreement that the amortization level will remain at 6.0% and that the amounts amortized after the OPUC implements the tariff will be subject to refund. The refund will occur if an order or ruling is issued declaring all or a portion of these deferred costs imprudent or otherwise disallowing recovery. On October 14, 2002, the ICNU filed a response to the Company’s motion to implement the stipulation and proposed tariff. The ICNU’s response asked that the motion be denied as being procedurally improper. On December 10, 2002, the OPUC approved the voluntary stipulation and ordered the Company to file a tariff to implement the change. The tariff was approved by the OPUC, with an effective date of January 22, 2003. Amounts subject to refund would include only those collections occurring after January 22, 2003. On February 7, 2003, the ICNU filed a motion requesting the OPUC to reconsider parts of its December 10, 2002 order relating to conclusions regarding the August 6, 2002 decision to increase the amortization level. The OPUC denied this motion on March 27, 2003.
In addition, the ICNU and the CUB have filed a complaint against the Company regarding the implementation of the August 2002 rate change. The ICNU and the CUB filed opening briefs on March 27, 2003. The Company and the OPUC filed their respective briefs on April 23, 2003. The CUB and the ICNU filed their joint reply brief on May 7, 2003.
While the 6.0% increase established the maximum annual rate to be recovered, the Company continued to pursue the total amount to be recovered through its October 2, 2001 appeals to the Marion County, Oregon Circuit Court, mentioned above, of two OPUC orders. These orders established the mechanism to determine the amount of power costs to defer. On June 6, 2002, the Marion County, Oregon Circuit Court upheld the OPUC decision. On October 9, 2002, the Company appealed this decision to the Oregon Court of Appeals. On November 27, 2002, the Company filed its opening brief. The ICNU filed a response brief on January 14, 2003. The OPUC filed its brief on February 12, 2003, and the Company submitted its reply on March 5, 2003. Oral arguments have been set for July 17, 2003.
On September 7, 2001, the OPUC endorsed an agreement on deferral of net power costs after September 2001. From September 10, 2001 until May 31, 2002, the Company deferred the difference between 83.0% of actual net power costs and the new Oregon baseline power cost in tariffs. This mechanism was terminated on May 31, 2002, concurrent with the effective date of the settlement approved on May 20, 2002.
Wyoming - In Wyoming, on November 1, 2000, the Company filed for deferred accounting treatment of net power costs that vary from costs included in determining retail rates. On April 3, 2001, the Company filed an application to recover the excess power costs accrued during the period November 30, 2000 through January 31, 2001. On November 20, 2001, following an order by the WPSC dismissing the majority of the Company’s case based on a procedural issue, the Company requested authority to withdraw its deferred net power cost recovery filing without prejudice. On November 26, 2001, the WPSC granted this request. On May 7, 2002, the Company filed a request to recover replacement power costs of $30.7 million, resulting from the outage of the Company’s Hunter No. 1 generating plant and a proposal for recovering deferred net power costs authorized by the WPSC in December 2000, for $60.3 million. On March 6, 2003, the WPSC denied recovery of the Hunter No. 1 replacement power costs and the deferred net power costs. As a result, the Company wrote-off the remaining net asset of $48.3 million during the year ended March 31, 2003. The Company filed a petition for rehearing on the decision on April 4, 2003. The WPSC denied the petition on May 30, 2003.
Washington - On April 5, 2002, the Company filed a petition with the Washington Utilities and Transportation Commission (the “WUTC”) seeking authority to begin deferring net power costs in excess of those included in rates as of June 1, 2002 for later recovery in rates, either through a power cost adjustment mechanism or a limited rate
adjustment. Under the rate plan approved by the WUTC in August 2000 at the conclusion of the Company’s last general rate case in Washington, there are limitations on the Company’s ability to request changes to general rates prior to January 2006. On October 18, 2002, the Company filed testimony and supporting documents, requesting deferral and recovery of excess power costs estimated at the time to be $17.5 million, including carrying charges, or, alternatively, to allow the Company to file a general rate case, which is currently restricted through December 2005. Based on actual data through December 2002, the deferral is expected to total $15.9 million. Hearings were held March 20-24, 2003, and a decision is expected by June 2003.
Idaho - On March 28, 2003, the Company filed an application with the IPUC to defer certain costs for regulatory purposes. The costs include approximately $2.5 million in excess costs incurred for forward electricity purchases made during the western energy crisis for summer 2002, as well as $3.5 million in federal and state tax audit determination payments made during the year ended March 31, 2003 as a result of Internal Revenue Service (the “IRS”) income tax audits. Other regulatory action in Idaho regarding deferred net power costs is described under Concluded Regulatory Actions - Idaho.
Demand-Side Management
The Company continues to offer its energy exchange program in its service territories in Utah, Oregon, Wyoming, Washington and Idaho. This program consists of optional, supplemental services that give participating customers an opportunity to reduce their electricity usage in exchange for a payment at times and at prices determined by the Company. The program is designed to help address periods of high wholesale prices and peaks in demand when they occur. Customers with usage as low as one MW may participate in the program. As part of the RFP process, the Company is preparing a separate RFP for the demand-side resources called for in the IRP.
In Utah, the Company is working on several programs. The Company filed an evaporative cooling and central air conditioning incentive program to reduce summer peak loads by encouraging installation of either evaporative cooling or high-efficiency central (also known as unitary) air-conditioning equipment. This program was approved by the UPSC on March 24, 2003. On April 9, 2003, the Company filed an air-conditioning load-control services program to help the Company manage the growth of weather-driven peak loads. This program was approved by the UPSC on May 14, 2003. On April 24, 2003, the Company filed a request for an experimental interruptible-service rider to reduce peak summer loads. The requested effective implementation date of this program is June 1, 2003. On May 5, 2003, the Company filed a refrigerator recycling program, which is intended to encourage customers to remove and recycle secondary refrigerators and/or to upgrade primary refrigerators to more energy-efficient models. The Company has requested that this program be approved by June 16, 2003.
The Company has also filed for a DSM tariff in Utah. This tariff would allow the Company to recover DSM expenditures through a surcharge to customer bills. Several technical conferences have been held with interested parties, and hearings have been scheduled for mid-August 2003.
On January 31, 2003, the Company filed an irrigation load-control credit program with the IPUC. This optional program would offer participants load-control billing credits in exchange for prescheduled load-control events during three and a half months of the summer irrigation season (June 1 through September 15). On March 17, 2003, the IPUC approved the program.
Multistate Process (the “MSP”)
The Company continues its active involvement in a collaborative process with the six states it serves, to develop mutually acceptable solutions to the problems faced by the Company and the states as a result of the Company’s multistate operations. These problems pertain to the allocation of some of the cost of the Company’s existing investments and the recovery of the cost of future investments. Between April and December 2002, the Company and key parties from Utah, Oregon, Wyoming, Washington and Idaho, along with a key monitoring contact from California, analyzed over 50 options, which were narrowed to two possibilities. Both seek to clarify roles and responsibilities, including cost allocations for future generation resources, providing states with the ability to independently implement state energy policy objectives, and to achieve permanent consensus on each state’s responsibility for the costs and entitlement to the benefits of the Company’s existing assets. A second phase of the collaborative process is under way, in which the parties will further assess the two proposals, with the goal of agreeing to a single proposal in July 2003.
The MSP was initiated in response to the Company’s Structural Realignment Proposal (the “SRP”), which would change the Company’s legal and regulatory structure and result in the creation of six state electric distribution companies, a generation company that also holds transmission assets, and a service company, which are all intended to be subsidiaries of the holding company. Individual state proceedings and schedules for the SRP are on hold so long as reasonable progress is made through the MSP. Any proposal that results from the MSP must be subsequently approved by the utility commissions in Utah, Oregon, Wyoming, Washington, Idaho and California. Approval from the FERC may also be required.
Deregulation
Industry restructuring to open the electric wholesale market to competition was initially promoted by passage of the Energy Policy Act of 1992 (the “Energy Act”). The Energy Act gave the FERC authority to require electric utilities to provide infrastructure and transmit electricity to or for wholesale purchasers and sellers. The Energy Act also created a new class of independent power plant owners that are able to sell generation only in wholesale markets. Deregulation in the states where the Company operates has varied significantly. No significant actions have occurred in Utah, Wyoming, Washington or Idaho. Oregon and California developments are discussed below.
Oregon - During 1999, SB 1149 was enacted in Oregon requiring competition for all nonresidential customers of both the Company and Portland General Electric Company. Under the legislation, the Company is required to unbundle rates for generation, transmission, distribution and other retail services, and to offer residential customers a cost of service rate option and a portfolio of rate options that include new renewable-energy resources and market-based generation. SB 1149 authorizes the OPUC to make decisions on certain matters, in particular the method for valuation of stranded costs/benefits. The Company continues to participate in the OPUC proceedings to establish the rules and procedures related to SB 1149. Implementation of SB 1149 began March 1, 2002, when the Company provided all customers with a cost of service rate option for an indefinite period and allowed industrial and large commercial customers a choice of energy provider. For the calendar year ending December 31, 2003, 26 customers, representing less than three average MW of load, elected an alternative plan. To date, adoption of SB 1149 has not had a significant financial impact on the Company’s results.
California - In 1998, California became one of the first states in the country to implement electric industry restructuring with the goal of establishing a competitive market for electric generation. The framework for electric industry restructuring was established in Assembly Bill 1890 (“AB 1890”), passed by the California Legislature and signed by the Governor in 1996. Under AB 1890, large utilities were encouraged to divest a significant portion of their owned generation portfolio in order to reduce their market power and encourage development of a competitive power supply market. Certain plant types, primarily nuclear and hydroelectric plants, and small and multi-jurisdictional utilities were excluded. Beginning March 31, 1998, Californians were given the choice to purchase electricity from generation providers other than the traditional utilities (“direct access”). For those customers who did not choose direct access, investor-owned utilities were to continue to purchase electric power on their behalf. Investor-owned utilities continued to provide distribution services to substantially all customers within their service territories, including those customers who chose direct access. However, in response to the western power crisis, the CPUC suspended the ability of customers to choose suppliers, on a prospective basis, in fall 2001.
As required by AB 1890, electric rates for all customers were frozen at the level in effect on June 10, 1996, and, beginning January 1, 1998, rates for residential and small commercial customers were reduced by 10.0% from 1996 levels. On June 27, 2002, the CPUC approved an interim increase of $0.01 per kWh for certain customers, or approximately $4.7 million, or 8.8%, annually, overall.
In July 1998, the Company announced its intention to sell its California service territory, including its electric distribution assets, to Nor-Cal. Consummation of the sale is uncertain. See SERVICE TERRITORIES.
ITEM 2.
ITEM 2.
PROPERTIES
The Company owns, or has an interest in, 53 hydroelectric generating plants with an aggregate nameplate rating of 1,067.3 MW and plant net capability of 1,115.8 MW. It also owns or has interests in 17 thermal-electric generating plants with an aggregate nameplate rating of 7,309.8 MW and plant net capability of 6,776.9 MW. The Company also jointly owns one wind electricity generating plant with an aggregate nameplate rating and plant net capability of 32.6 MW. The following table summarizes the Company’s existing generating facilities:
Location
Energy Source
Unit
Installation
Date(s)
Nameplate
Rating (MW)
Plant Net
Capability
(MW)
HYDROELECTRIC PLANTS (a)
Swift (b)
Cougar, WA
Lewis River
240.0
263.6
Merwin
Ariel, WA
Lewis River
1931-1958
135.0
144.0
Yale
Amboy, WA
Lewis River
134.0
134.0
Five North Umpqua Plants
Toketee Falls, OR
N. Umpqua River
1950-1956
133.5
136.5
John C. Boyle
Keno, OR
Klamath River
80.0
84.0
Copco Nos. 1 and 2 Plants
Hornbrook, CA
Klamath River
1918-1925
47.0
54.5
Clearwater Nos. 1 and 2 Plants
Toketee Falls, OR
Clearwater River
41.0
41.0
Grace
Grace, ID
Bear River
1908-1923
33.0
33.0
Prospect No. 2
Prospect, OR
Rogue River
32.0
34.0
Cutler
Collingston, UT
Bear River
30.0
29.1
Oneida
Preston, ID
Bear River
1915-1920
30.0
28.0
Iron Gate
Hornbrook, CA
Klamath River
18.0
19.5
Soda
Soda Springs, ID
Bear River
14.0
14.0
Fish Creek
Toketee Falls, OR
Fish Creek
11.0
12.0
33 Minor Hydroelectric Plants (c)
Various
Various
1896-1990
88.8
*
88.6
*
Subtotal (53 Hydroelectric Plants)
1,067.3
1,115.8
THERMAL ELECTRIC PLANTS
Jim Bridger
Rock Springs, WY
Coal-Fired
1974-1979
1,541.1
*
1,413.4
*
Huntington
Huntington, UT
Coal-Fired
1974-1977
996.0
895.0
Dave Johnston
Glenrock, WY
Coal-Fired
1959-1972
816.8
762.0
Naughton
Kemmerer, WY
Coal-Fired
1963-1971
707.2
700.0
Hunter Nos. 1 and 2
Castle Dale, UT
Coal-Fired
1978-1980
727.9
*
662.5
*
Hunter No. 3
Castle Dale, UT
Coal-Fired
495.6
460.0
Cholla No. 4
Joseph City, AZ
Coal-Fired
414.0
*
380.0
*
Wyodak
Gillette, WY
Coal-Fired
289.7
*
268.0
*
Carbon
Castle Gate, UT
Coal-Fired
1954-1957
188.6
175.0
Craig Nos. 1 and 2
Craig, CO
Coal-Fired
1979-1980
172.1
*
165.0
*
Colstrip Nos. 3 and 4
Colstrip, MT
Coal-Fired
1984-1986
155.6
*
144.0
*
Hayden Nos. 1 and 2
Hayden, CO
Coal-Fired
1965-1976
81.3
*
78.0
*
Blundell
Milford, UT
Geothermal
26.1
23.0
Gadsby
Salt Lake City, UT
Gas-Fired
1951-2002
392.6
349.0
Hermiston
Hermiston, OR
Gas-Fired
237.0
*
236.0
*
Little Mountain
Ogden, UT
Gas-Fired
16.0
14.0
James River
Camas, WA
Black Liquor
52.2
52.0
Subtotal (17 Thermal Electric Plants)
7,309.8
6,776.9
OTHER PLANTS
Foote Creek
Arlington, WY
Wind Turbines
32.6
*
32.6
*
Subtotal (1 Other Plant)
32.6
32.6
Total Hydro, Thermal and Other Generating Facilities (71)
8,409.7
7,925.3
*
Jointly owned plants; amount shown represents the Company’s share only.
(a)
Hydroelectric project locations are stated by locality and river watershed.
(b)
On April 21, 2002, a failure occurred in the Swift power canal on the Lewis River in the state of Washington. The power canal and associated 70-MW hydroelectric facility (“Swift No. 2”) are owned by Cowlitz County Public Utility District (“Cowlitz”). It is anticipated that Cowlitz will repair Swift No. 2 in time for a calendar-year 2005 startup. The failure impacted, but did not damage, the Company-owned and operated 240-MW Swift No. 1 hydroelectric facility (“Swift No. 1”), which is upstream of the Swift power canal, by restricting both flow and generation flexibility (“shaping”). Repairs to the canal were completed and Swift No. 1 was returned to full capacity levels as of mid-July 2002 (though with limited shaping capabilities). Environmental, operations safety and fish mitigation issues remain to be resolved before full use of Swift No. 1 can resume. The Company continues to seek ways to mitigate any capacity and shaping limitations and to recover any business losses. The full impact of the Swift power canal outage and plans for repair of the Swift No. 2 facility are still being determined. The Company is seeking reimbursement from Cowlitz of the Company’s expenditures associated with the Swift No. 2 failure, including canal modifications and energy replacement costs. This event is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.
(c)
The Company is currently negotiating with the FERC and other interested parties to decommission the Condit, Powerdale and American Fork plants that have a combined net capability of 21.9 MW. In addition, the Company has entered into a sales agreement for the Naches and Naches Drop hydroelectric plants located near Yakima, Washington, with a combined net capability of 7.7 MW. The final phase of the sale is scheduled to close in September 2003.
The Company’s generating facilities are interconnected through its own transmission lines or by contract through the transmission lines of other transmission owners. Substantially all of the Company’s generating facilities and reservoirs are managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of the Company’s transmission and distribution systems are located, by franchise or permit, upon public lands, roads and streets and, by easement or license, upon the lands of other third parties.
Substantially all of the Company’s electric utility property is subject to the lien of the Company’s Mortgage and Deed of Trust.
The following table describes the Company’s recoverable coal reserves as of March 31, 2003. All coal reserves are dedicated to nearby Company-operated generating plants. Recoverability by surface mining methods typically ranges from 90.0% to 95.0%. Recoverability by underground mining techniques ranges from 50.0% to 70.0%. The Company believes that the respective coal reserves assigned to the Craig, Huntington, Hunter and Jim Bridger plants, together with coal available under both long-term and short-term contracts with external suppliers, will be sufficient to provide these plants with fuel that meets the Clean Air Act standards effective in 1999, for their current economically useful lives. Blending of Company-owned and contracted coal, together with electricity plant control technologies for controlling sulfur and other emissions, are utilized to meet the applicable standards. The sulfur content of the coal reserves ranges from 0.30% to 0.94%, and the British Thermal Units value per pound of the reserves ranges from 8,600 to 12,400. Coal reserve estimates are subject to adjustment as a result of the development of additional data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves. Recoverable coal reserves at March 31, 2003, based on most recent engineering studies, were as follows:
(a)
These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware nonstock corporation operated on a cooperative basis, in which the Company has an ownership interest of 21.4%.
(b)
These coal reserves are mined by subsidiaries of PacifiCorp and are in underground mines.
(c)
These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. and a subsidiary of Idaho Power Company. Pacific Minerals, Inc., a subsidiary of PacifiCorp, has a two-thirds interest in the joint venture.
Most of the Company’s coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multiyear terms that may be renewed or extended and require payment of rents and royalties. In addition, federal and state regulations require
that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities. In the year ended March 31, 2003, the Company expended $12.5 million in reclamation costs and accrued $18.5 million of estimated final mining reclamation costs for the Glenrock Mine. The Company and Idaho Power have previously contributed funds to a trust for the reclamation of the Bridger Mine. Due to recent declines in the equity markets, the funds have experienced declines in fair value, which may require the Company to resume funding in order to meet the reclamation obligations. At March 31, 2003, these reclamation funds totaled $68.5 million, of which the Company’s portion is $45.7 million, and the Company had an accrued reclamation liability for all mine reclamation of $121.6 million.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
The Company is a party from time to time in various legal claims, actions and complaints. Although it is impossible to predict with certainty whether or not the Company will ultimately be successful in its legal proceedings or, if not, what the impact might be, management believes that disposition of these matters will not have a material adverse effect on the Company’s consolidated financial results. See ITEM 1. BUSINESS - REGULATION for information concerning pending regulatory proceedings.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No information is required to be reported pursuant to this item.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PacifiCorp is an indirect subsidiary of ScottishPower, which owns all 312,176,089 shares of PacifiCorp’s outstanding common stock. Therefore, there is no public market for PacifiCorp’s common stock. Dividend information required by this item is included in QUARTERLY FINANCIAL DATA under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Company is restricted from paying dividends or making other distributions without prior OPUC approval, to the extent such payment or distribution would reduce the Company’s common stock equity below a specified percentage of its total capitalization. The percentage of total capitalization increases over time from 35.0% after December 31, 1999 to 40.0% after December 31, 2004. As of March 31, 2003, the minimum ratio was 38.0%. In addition, the Company must give the OPUC 30 days’ prior notice of any special cash dividend or any transfer involving more than five percent of the Company’s retained earnings in a six-month period. The Company is also subject to maximum debt-to-total capitalization ratios under various debt agreements.
Under the PUHCA, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. The Company has received approval to pay dividends out of unearned surplus of the lesser of $900.0 million or the proceeds received from sales of nonutility assets. At March 31, 2003, $300.0 million was available for dividends out of unearned surplus.
On December 19, 2002, the Company issued 14,851,485 shares of its common stock to PHI at a total price of $150.0 million, or $10.10 per share.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
SELECTED FINANCIAL INFORMATION (UNAUDITED)
(a)
Other Operations includes the operations of PPM and Pacific Klamath Energy, Inc. (“PKE”) until their transfer in March 2001 and of PacifiCorp Financial Services, Inc. (“PFS”), as well as the activities of PacifiCorp Group Holdings Company (“PGHC”), including financing costs and elimination entries, until their transfer in February 2002.
(b)
Amounts in 2002 represent the collection of a contingent note receivable relating to the discontinued operations of a former mining and resource development business, NERCO, Inc. (“NERCO”). The amount in 2000 represents discontinued operations of TPC Corporation.
(c)
Represents the effect of implementation of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), in the year ended March 31, 2002 and Revised Issue C15, Normal Purchase and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity (“Issue C15”), and Issue C16, Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract (“Issue C16”), in the year ended March 31, 2003.
ELECTRIC OPERATIONS (UNAUDITED)
(a)
Does not reflect elimination of interest on intercompany borrowing arrangements includes income taxes on a separate-company basis.
ELECTRIC OPERATIONS STATISTICS (UNAUDITED)
(a)
Excludes off-system sales.
(b)
Includes firm off-system sales.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
The Company has separated its nonutility operations from its regulated utility operations through corporate restructuring, in order to facilitate an increased focus on its regulated energy businesses in the western U.S. On December 31, 2001, NA General Partnership (“NAGP”) transferred all of the common stock of the Company to PHI. The Company then transferred all of the capital stock of PGHC to PHI in February 2002. PGHC includes the wholly owned subsidiary, PFS, a financial services business. As a result of this transfer, the operations of PGHC are included in the Company’s Statements of Consolidated Income and Statements of Consolidated Cash Flows for the year ended March 31, 2001 and for the first 10 months of the year ended March 31, 2002, but are not included for the year ended March 31, 2003.
In March 2001, the Company sold its interest in PPM and PKE, two nonutility energy companies, to PHI. As a result, the operations of the transferred companies are included in the Company’s Statements of Consolidated Income and Statements of Consolidated Cash Flows for the year ended March 31, 2001, but are not included for the years ended March 31, 2003 and 2002.
PGHC, while a subsidiary of the Company, completed the sales of its ownership of Powercor Australia Ltd. (“Powercor”) on September 6, 2000 and its 19.9% interest in Hazelwood Power Partnership (“Hazelwood”) on November 17, 2000. Powercor, an indirectly owned subsidiary of the Company, and Hazelwood represented the entire Australian Operations segment of the Company. Australian Operations’ financial results for the period from January 1, 2000 to the respective dates of sale are included in the Company’s financial results for the year ended March 31, 2001.
FORWARD-LOOKING STATEMENTS
The information in the tables and text in this document includes certain forward-looking statements that involve a number of risks and uncertainties under the safe-harbor provisions of the Private Securities Litigation Reform Act of 1995 that may influence the financial performance and earnings of the Company. When used in this report on Form 10-K, the words “estimates,” “expects,” “anticipates,” “forecasts,” “plans,” “intends” and variations of such words and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. There can be no assurance that the results predicted would be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The following are among the factors that could cause actual results to differ materially from the forward-looking statements:
•
changes in prices and availability of wholesale electricity, natural gas, fuel costs and other changes in operating costs, which could affect the Company’s cost recovery;
•
changing conditions in wholesale power markets, such as general credit constraints and thin trading volumes, that could make it difficult for the Company to enter into purchase and sale agreements;
•
the actions of securities rating agencies, including the determination of whether or when to make changes in the Company’s credit ratings and the impact of current or lowered ratings and other financial market conditions on the ability of the Company to obtain needed financing on reasonable terms or at all;
•
actions by state and federal regulatory bodies setting rates and adopting or modifying cost recovery, accounting and rate-setting mechanisms, as well as legislative or judicial actions affecting the same matters;
•
the effects of increased competition in energy-related businesses, including new market entrants and the effects of new technologies that may be developed in the future;
•
attempts by municipalities within the Company’s service territory to form public power entities and/or acquire the Company’s facilities;
•
hydroelectric conditions and gas and coal production levels, which could have a potentially serious impact on electric capacity and cost and on the Company’s ability to generate electricity;
•
changes in weather conditions and other natural disasters that could affect customer demand or electricity supply;
•
the impact from the possible formation of an RTO and the impact from the implementation of the FERC’s proposed SMD;
•
the impact of enhanced physical and information security requirements imposed through legislation or regulation;
•
the outcome of pending IRS tax audits and settlements;
•
the impact of regional, national and international economic and political conditions, including acts of terrorism, war or similar events;
•
employee work-force factors, including strikes, work stoppages, availability of qualified employees or loss of key executives;
•
the ability to obtain adequate insurance coverage and the cost of such insurance;
•
changes in, and compliance with, environmental and endangered species laws, regulations, decisions, and policies;
•
industrial, commercial and residential growth and demographic patterns in the Company’s service territories;
•
competition and supply in bulk electricity and natural gas markets;
•
unscheduled generation outages and disruption or constraints to transmission or distribution facilities;
•
changes in regulatory or other legislation, including industry restructuring and deregulation initiatives;
•
the outcome of threatened or pending litigation;
•
changes in tax rates and/or policies;
•
changes in actuarial assumptions and the return on assets associated with the Company’s pension plan, which could impact future funding obligations, costs and pension plan liabilities;
•
increasing health care costs associated with employee health insurance premiums and the obligation to provide postretirement health care benefits;
•
unanticipated delays or changes in construction costs relating to present or future generating facilities;
•
new accounting pronouncements;
•
the outcome of rate cases submitted for regulatory approval; and
•
the cost, feasibility and eventual outcome of hydroelectric facility relicensing proceedings.
Any forward-looking statements issued by the Company should be considered in light of these factors. The Company assumes no obligation to update or revise any forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting such forward-looking statements or if the Company later becomes aware that these assumptions are not likely to be achieved.
CRITICAL ACCOUNTING POLICIES
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the consolidated financial statements. The estimates and assumptions may change as time passes and accounting guidance evolves. Management bases its estimates and assumptions on historical experience and on other various judgments that it believes are reasonable at the time of application. Changes in these estimates and assumptions could have a material impact on the consolidated financial statements. If estimates and assumptions are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Critical accounting policies, in addition to certain less significant accounting policies, are discussed with senior members of management and the Company’s Board of Directors (the “Board”), as appropriate. Those policies that management considers critical are described below.
Regulation
The Company prepares its consolidated financial statements in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”). A regulated company must satisfy the following conditions in order to apply the accounting policies and practices of SFAS No. 71 an independent regulator must set rates to cover specific costs of delivering service, and the service territory must lack competitive pressures to reduce rates below the rates set by the regulator. SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its consolidated financial statements and requires that certain costs be deferred on the balance sheet until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities and amortized to the income statement as rates to customers are reduced. SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of those costs in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred cost rather than provide for expected levels of similar future costs.
If the Company should determine in the future that it no longer meets the criteria for continued application of SFAS No. 71, the Company could be required to write off its regulatory assets and liabilities unless regulators specify some other means of recovery or refund. The Company intends to seek recovery of costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, the Company cannot predict whether it will be successful. If the Company stopped applying SFAS No. 71 to its regulated operations, it would write off the related balances of its regulatory assets as an expense on its income statement. Based on the balances of the Company’s regulatory assets at March 31, 2003, if the Company had stopped applying SFAS No. 71 to its remaining regulated operations, it would have recorded an extraordinary loss, after tax, of approximately $918.2 million. While regulatory orders and market conditions may affect the Company’s cash flows, its cash flows would not be affected if it stopped applying SFAS No. 71, unless a regulatory order limited its ability to recover the cost of that regulatory asset.
At March 31, 2003, the Company’s SFAS No. 71 regulatory assets and liabilities for all states totaled $1,682.8 million and $137.0 million, respectively. As a result of potential regulatory and/or legislative actions in Utah, Oregon, Wyoming, Washington and Idaho, the Company may have regulatory asset write-offs and charges for impairment of long-lived assets in future periods. Impairment would be measured in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS No. 144”), which requires the recognition of impairment of long-lived assets when book values exceed expected future cash flows. Integral parts of future cash-flow estimates include estimated future prices to be received, the expected future cash cost of operations, sales and load growth forecasts and the nature of any legislative or regulatory cost-recovery mechanisms.
Revenue Recognition
Electricity sales to retail customers are determined based on meter readings taken throughout the month. The Company accrues an estimate of unbilled revenues each month for electric service provided after the meter reading date to the end of the month, after removing estimates for line losses. This estimate is based on the Company’s total electricity delivered during the month and sales based on meter readings. At March 31, 2003, the amount accrued for unbilled revenues was $109.2 million. There are several estimates in the determination of the unbilled revenue, relating to weather conditions and economic impacts. The estimates can vary significantly from period to period depending on monthly weather patterns, customers’ space heating and cooling, or changing irrigation patterns due to precipitation conditions.
Contingencies
The Company follows SFAS No. 5, Accounting for Contingencies (“SFAS No. 5”), to determine accounting and disclosure requirements for contingencies. The Company operates in a highly regulated environment. Governmental bodies such as the FERC, the SEC, the IRS, the Department of Labor, the EPA and others have authority over various aspects of the Company’s business operations and public reporting. Reserves are established when required in management’s judgment, and disclosures are made when appropriate regarding litigation, assessments and creditworthiness of customers or counterparties, among others. The evaluation of these contingencies is performed by various specialists inside and outside of the Company. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability. Management’s assessment of the Company’s exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could
materially impact the consolidated results of operations, cash flows and financial position of the Company. Management has applied its best judgment in applying SFAS No. 5 to these matters.
Asset Retirement Obligations
SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. At the same time the liability is recorded, the costs of the asset retirement obligation will be recorded as an addition to the carrying amount of the related asset. Over time, the liability is accreted to its present value and the addition to the carrying amount of the asset is depreciated over the asset’s useful life. Upon retirement of the asset, the Company will settle the retirement obligation against the recorded balance of the liability. Any difference in the final retirement obligation cost and the liability will result in either a gain or loss.
The Company adopted SFAS No. 143 on April 1, 2003, as required. The Company has identified legal obligations to retire generation plant assets and to incur removal costs and reclamation costs for certain environmental obligations at various generating facilities. The Company has estimated that its share of the cost to remove these facilities and settle the obligations is approximately $79.4 million at the date of retirement.
The Company has various transmission and distribution lines that operate under various land leases and rights-of-way that contain end dates and restorative clauses. The Company operates its transmission and distribution lines as if they will be operated in perpetuity and would continue to be used or sold without land remediation. As a result, the Company does not recognize the costs of final removal of the transmission and distribution lines in the financial statements.
The Company has legal obligations at its coal mines to perform reclamation as defined in the mine permits. The Company has estimated its cost for reclamation at the date of mine closure to be approximately $279.7 million.
Upon adoption of SFAS No. 143 on April 1, 2003, the Company recorded an asset retirement obligation liability at its net present value of $196.1 million, increased net depreciable assets by $37.3 million, removed $163.1 million of costs accrued for final removal from accumulated depreciation and reclamation liabilities and will result in a cumulative pretax effect of a change in accounting principle of $4.3 million, which, if approved by state regulators, will be recorded primarily as a net regulatory liability. The Company expects that adopting SFAS No. 143 will result in a reduction to depreciation charged throughout the year. Accretion and depreciation expense in the first year of adoption are expected to be $8.0 million and $2.7 million, respectively.
Amounts recorded under SFAS No. 143 are subject to various assumptions and determinations, such as determining whether a legal obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur and the credit-adjusted risk-free interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions will change amounts recorded in the future as expenses for asset retirement obligations.
If the Company retires any asset at the end of its useful life without a legal obligation to do so, the Company will record retirement costs at that time as incurred. The Company expects to recover asset retirement costs through the ratemaking process and has requested authorization from the state regulatory commissions to record a Regulatory asset or a Regulatory liability on the Company’s Consolidated Balance Sheet to account for the difference between asset retirement costs as currently approved in rates and its obligations under SFAS No. 143.
Pensions
The Company has defined-benefit pension plans that cover substantially all employees, and the Company also provides certain post-retirement benefits. The Company accounts for these plans in accordance with SFAS No. 87, Employers’ Accounting for Pensions (“SFAS No. 87”), and SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other than Pensions (“SFAS No. 106”). The expense and benefit obligations relating to the Company’s pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets, compensation increases, Company contributions and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The effect of modifications is generally recorded or amortized over future periods. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries.
The PacifiCorp Retirement Plan (the “Plan”) currently has assets with a fair value that is less than the accumulated benefit obligation under the Plan, primarily due to declines in the equity markets. As a result, the Company recognized a minimum pension liability in the fourth quarter of the year ended March 31, 2003. The liability adjustment was primarily recorded as a noncash increase of $234.5 million to Regulatory assets and did not affect the consolidated results of operations. The Company requested and received accounting orders from the regulatory commissions in Utah, Oregon and Wyoming to classify this charge as a Regulatory asset instead of a charge to Other comprehensive income. The Company has determined that SFAS No. 87 and SFAS No. 106 costs are currently recoverable in rates. This increase to Regulatory assets will be adjusted in future periods as the difference between the fair value of the trust assets and the accumulated benefit obligation changes.
The Company’s contributions to the Plan have exceeded the minimum funding requirements of the Employee Retirement Income Security Act (“ERISA”). The Company’s funding policy is to contribute amounts that are not less than the minimum amounts required to be funded under ERISA. The Company made $26.4 million in cash contributions to the Plan during the year ended March 31, 2003 and made $4.2 million in cash contributions to the Plan during the year ended March 31, 2002. The amount of the Company’s funding obligation for the year ending March 31, 2004 is expected to be approximately $33.4 million. The Company is funding the Plan at what it believes to be an adequate level. As a result of significant declines in the equity markets, the Company currently expects to make larger cash contributions in the future. Such cash requirements could be material to the Company’s cash flows. The Company believes it has adequate access to capital resources to support these contributions.
The Company discounted its future pension and other postretirement plan obligations using a rate of 6.75% at March 31, 2003, compared to 7.50% at March 31, 2002. The Company chooses a discount rate, which reflects yields on high-quality fixed-income investments. The pension liability and future pension expense both increase as the discount rate is reduced.
At March 31, 2003, the Company assumed that the Plan’s assets would generate a long-term rate of return of 8.75%. This rate is lower than the rate of 9.25% used at March 31, 2002. In establishing its assumption as to the expected return on Plan assets, the Company reviews the Plan’s asset allocation and develops return assumptions for each asset class based on historical performance and independent advisors’ forward-looking views of the financial markets. Pension expense increases as the expected rate of return on Plan assets decreases.
Based on the above assumptions, the Company expects to record pension expenses of $23.2 million for the year ending March 31, 2004, as compared to $11.9 million for the year ended March 31, 2003.
The following table reflects the sensitivities of the March 31, 2003 disclosures and the projected pension expense for the year ending March 31, 2004, associated with a change in certain actuarial assumptions by the indicated percentage:
The Company expects to record other postretirement benefit expense of $27.9 million for the year ending March 31, 2004, as compared to $23.5 million for the year ended March 31, 2003.
In valuing its postretirement benefit obligation, the Company must make an assumption regarding future increases in health care costs. A one percentage-point increase in assumed health care cost trend rates would increase the postretirement benefit obligation by approximately $25.9 million and the related Plan expense by approximately $4.2 million. A similar decrease in assumed health care cost trend rates would decrease the postretirement benefit obligation by approximately $22.6 million and the related Plan expense by approximately $2.5 million.
RESULTS OF OPERATIONS
Western U.S. wholesale energy market prices were relatively stable during the year ended March 31, 2003, as compared to each of the years ended March 31, 2002 and 2001. The Company took several actions to maintain a balanced net energy position through the summer peak period and the remainder of the fiscal year through a combination of existing physical resources, electricity purchases, weather-related hedges and peaking generation facilities. The Company added a 120-MW gas-fired peaking plant in Utah, which came on line in August 2002, and also entered into an operating lease arrangement for a 200-MW peaking plant in Utah with West Valley Leasing Company, LLC, a subsidiary of PPM. These actions, as well as the utilization of other flexible physical and financial hedging instruments, assisted the Company in maintaining a balanced energy position during the year ended March 31, 2003. The Company believes that its energy position is balanced for summer 2003.
For the year ended March 31, 2003, overall retail MWh sales decreased approximately 1.2%. While the impact of weather was not significant for the year ended March 31, 2003, sales for the year ended March 31, 2002 were approximately 564,000 MWh, or 1.2%, higher than sales for the year ended March 31, 2003, due to the effects of weather. Excluding this weather impact, the loads for both years were relatively consistent, although load growth varied within individual states and customer classes. While residential and commercial loads reflected an increase of 1.2% and 3.6%, respectively, as a result of additional customers in the eastern portion of the Company’s service territory, the industrial class showed a 3.2% decrease as a result of the effects of the economic downturn and a decrease in industrial customers.
The Company’s hydroelectric resources are in watersheds with precipitation that averaged 85.0% of normal for the year ended March 31, 2003 and had ending snowpack at around 74.0% of normal. These drier than normal conditions reduced generation from Company-owned projects by 65,000 MWh, as compared to the hydroelectric generation for the year ended March 31, 2002. Despite increased precipitation in April 2003, the reduced snowpack will continue to affect generation from the Company’s resources for the remainder of the normal runoff period through the end of September 2003. Beginning with the next hydrologic cycle in October 2003, the Company anticipates a return to normal water conditions. In the event of below-normal hydroelectric generation, the Company will either increase output from its thermal generation resources or purchase energy in the wholesale market, which would result in increased power costs to the extent existing hedges do not offset the impact of reduced hydroelectric generation.
Concluded regulatory actions in the year ended March 31, 2003 included approval in Oregon of a $15.4 million overall rate increase effective June 1, 2002. On March 6, 2003, a general rate increase of $8.7 million, or 2.8%, was granted in Wyoming. Rate actions submitted for regulatory approval included a general rate case filed on March 18, 2003 in Oregon requesting an increase of $57.9 million, or 7.4%, in base rates to take effect in January 2004; a general rate case filed on May 15, 2003 in Utah establishing a maximum increase of $125.0 million, or 12.5%, in base rates to take effect in April 2004; and a general rate case filed on May 27, 2003 in Wyoming, requesting an increase of $41.8 million, or 13.1%, in base rates to take effect in March 2004.
The Company also made progress toward recovering the deferred net power costs incurred during the period of extreme volatility and unprecedented high price levels beginning in summer 2000 and extending through summer 2001. These costs have been authorized for recovery as follows: (i) $147.0 million in Utah; (ii) $131.0 million, plus carrying charges, in Oregon; and (iii) $25.0 million in Idaho. The Oregon rate order is the subject of a court appeal by intervening parties, which, if successful, would require refund of amounts collected after January 22, 2003. In Wyoming, the Company’s request for recovery of deferred net power costs was denied, and, as a result, the Company wrote off the remaining net regulatory asset of $48.3 million during the year ended March 31, 2003. The Company filed a petition for rehearing on the Wyoming decision on April 4, 2003. The WPSC denied the petition on May 30, 2003. In Washington, the Company had requested recovery of approximately $17.5 million of excess power costs, which have not been deferred, or, alternatively, that the Company be allowed to file a general rate case, which is currently restricted through December 2005. This request was subsequently reduced to approximately $15.9 million based on revised estimates. A final decision in Washington is expected by June 2003. At March 31, 2003, the Company had $137.8 million of deferred power costs, net of amortization, remaining to be collected over two to three years.
Earnings (Loss) Overview of the Company
(a)
The Australian Operations were sold in fall 2000.
(b)
All Other Operations were transferred to PHI on February 4, 2002.
The Company’s earnings contribution on common stock for the year ended March 31, 2003 was $132.8 million, as compared to $314.6 million for the year ended March 31, 2002 and a loss of $106.1 million for the year ended March 31, 2001. The Company’s underlying results for the year ended March 31, 2003, as compared to the years ended March 31, 2002 and 2001, improved after taking into account rate increases, lower net power costs and the effect of the following items:
(i)
Included in Electric Operations results is the unrealized gain of $3.1 million, pretax, on SFAS No. 133 derivative instruments for the year ended March 31, 2003, as compared to $182.8 million, pretax, and none for the years ended March 31, 2002 and 2001, respectively;
(ii)
A $27.4 million pretax gain in the year ended March 31, 2002 relating to additional proceeds from the sale of the Australian Operations. In the year ended March 31, 2001, the Company recorded a $184.2 million pretax loss on the sale of the Australian Operations;
(iii)
Other Operations income for the year ended March 31, 2002 included a gain on the sale of the synthetic fuel operations of $11.3 million pretax. The year ended March 31, 2001 included operating losses from the synthetic fuel operations;
(iv)
The $146.7 million, after tax, of income in the year ended March 31, 2002 from the discontinued operations of a former mining and resource development business; and
(v)
The negative cumulative effect of accounting change of $1.9 million, after tax, due to the Derivatives Implementation Group revised Issue C15 and Issue C16 in the year ended March 31, 2003, as compared to the negative cumulative effect of accounting change of $112.8 million, after tax, due to the adoption of SFAS No. 133 in the year ended March 31, 2002.
REVENUES
Electric Operations
Residential revenues for the year ended March 31, 2003 increased $13.0 million, or 1.4%, from the year ended March 31, 2002 primarily due to increases of $17.8 million from higher rates approved by state regulatory agencies and $12.5 million relating to growth in the average number of residential customers of 1.6%, primarily in Utah and Oregon. These increases were partially offset by a decrease of $17.3 million from lower average customer usage due to milder weather as compared to the year ended March 31, 2002. Residential revenues for the year ended March 31, 2002 increased $49.6 million, or 5.8%, from the year ended March 31, 2001, due to $53.6 million in price increases, mainly in Utah and Oregon, and $12.0 million relating to growth in the average number of residential customers of 1.5%. These increases were partially offset by $11.1 million from lower volumes due to weather impacts and $4.8 million due to decreases in average customer usage.
Commercial revenues for the year ended March 31, 2003 increased $15.7 million, or 2.1%, from the year ended March 31, 2002, due to increases of $16.7 million from growth in the average number of commercial customers and $6.8 million from higher rates, offset in part by $7.8 million in reduced revenue from lower average customer usage due to current economic conditions. Commercial revenues for the year ended March 31, 2002 increased $37.2 million, or 5.2%, from the year ended March 31, 2001 primarily due to $32.7 million in price increases. A 2.3% increase in the average number of commercial customers increased revenues $17.7 million, and higher volumes due to weather resulted in a $7.9 million increase. These increases were partially offset by the $21.2 million impact of lower customer usage.
Industrial revenues for the year ended March 31, 2003 decreased $5.9 million, or 0.8%, from the year ended March 31, 2002, due to a $27.0 million decrease caused by reduced customer numbers and lower average customer usage mainly as a result of a weaker economy. This decrease was partially offset by a $21.1 million increase resulting from higher rates. Industrial revenues for the year ended March 31, 2002 decreased $25.0 million, or 3.4%, from the year ended March 31, 2001, due to a $40.8 million decrease from a reduction in energy volumes due to reduced customer usage. This decrease was partially offset by a $15.8 million increase resulting from higher prices.
Wholesale sales for the year ended March 31, 2003 decreased $632.7 million, or 37.6%, from the year ended March 31, 2002. This decrease in revenues resulted from the sharp decline in prices realized for short-term and spot-market sales as compared to those in the year ended March 31, 2002, the impact of which was $1.9 billion. Factors contributing to the lower market prices included new generation in the western U.S., the continuing effect of the FERC market mitigation and lower average natural gas prices paid as compared to average prices paid in the year ended March 31, 2002. In addition, demand growth in the Western Electricity Coordinating Council (the “WECC”) area was lower than the 10-year average, due to slower than historical U.S. economic growth and weather, which was milder than the year ended March 31, 2002 and normal weather patterns. The decrease due to prices was partially offset by a $1.3 billion, or 25.6%, increase due to higher volumes, as the Company sold excess power in the short-term, daily and hourly markets. Wholesale sales for the year ended March 31, 2002 decreased $393.4 million, or 18.9%, from the year ended March 31, 2001. Lower short-term and spot-market sales prices contributed $601.0 million to the decrease, and lower long-term sales volumes contributed $201.6 million. These decreases were partially offset by $373.1 million from higher volumes of short-term and spot-market sales and $35.6 million in higher long-term sales prices.
Other revenues for the year ended March 31, 2003 decreased $16.3 million, or 10.9%, from the year ended March 31, 2002, primarily due to a $26.8 million decrease in wheeling revenues, primarily due to lower volumes, a $6.1 million decrease from the amortization of the Centralia gain, a $6.0 million decrease relating to recognition of Oregon Merger Credits and lower DSM revenues of $3.6 million. These decreases were partially offset by a $20.7 million release of reserves on an electricity sales contract following a settlement of a dispute with respect to the contract and a $4.6 million increase in sales under a contract for renewable power. Other revenues for the year ended March 31, 2002 increased $18.1 million, or 13.8%, from the year ended March 31, 2001, due to $23.8 million from the amortization of the Centralia gain liability that offset revenue reductions in other revenue categories, $12.1 million in wheeling revenues from increased usage of the Company’s transmission system by third parties and $8.3 million from lower reserves. These increases were partially offset by a $14.9 million decrease in revenues due to lower load growth than anticipated by the alternative form of regulation in Oregon and a $12.4 million decrease due to DSM activities.
Australian Operations
The Australian Operations consisted of Powercor and a 19.9% interest in Hazelwood and were sold in fall 2000.
Other Operations
Revenues for the year ended March 31, 2002 decreased $109.6 million, or 89.7%, from the year ended March 31, 2001, primarily due to a $64.0 million decrease as a result of the sale of the synthetic-fuel operations, a decrease of $23.8 million due to the transfer of PPM and PKE to PHI and a $20.0 million decrease in interest income due to the collection of a contingent note receivable held by PGHC.
OPERATING EXPENSES
Electric Operations
Purchased electricity expense for the year ended March 31, 2003 decreased $826.2 million, or 40.5%, from the year ended March 31, 2002, primarily due to a $1.9 billion decrease from prices incurred for short-term and spot market purchases, which were 68.3% lower than average prices incurred for the year ended March 31, 2002. Lower market prices resulted from the same factors mentioned above for lower wholesale sales. Increased wholesale purchase volumes added $928.1 million, or 24.7 %, to purchased electricity expense as the Company increased the volume of system-balancing activities to balance its load requirements and to replace thermal generation lost from outages. These actions offset lower hydroelectric generation caused by below-normal precipitation levels. Purchased power costs also increased $185.5 million for the year ended March 31, 2003, as compared to the year ended March 31, 2002 due to lower deferrals of purchased power costs. Purchased electricity expense for the year ended March 31, 2002 decreased $439.6 million, or 17.7%, from the year ended March 31, 2001, primarily due to lower short-term and spot market purchase volumes of 15.6%, which decreased costs $295.1 million; lower long-term purchase volumes of 11.5%, which decreased costs $104.7 million; and lower short-term, spot-market and long-term purchase prices of $70.8 million. While long-term prices per MWh dropped 11.2%, short-term prices only dropped 1.4%. These decreases were partially offset by a $46.2 million increase in DSM costs.
Fuel expense for the year ended March 31, 2003 decreased $8.7 million, or 1.8%, from the year ended March 31, 2002, due to decreases of $20.7 million from lower natural gas volumes, $16.5 million from lower natural gas prices and $9.7 million from lower coal volumes, partially offset by the $21.2 million incremental impact from the Company’s lease of the West Valley gas-fired facility and an increase of $17.0 million from higher coal prices caused by higher employee benefit costs at Company-owned mines and the costs of external coal purchases. Fuel expense was comparable in the years ended March 31, 2002 and 2001.
Other operations and maintenance expense for the year ended March 31, 2003 increased $43.3 million, or 7.7%, from the year ended March 31, 2002, primarily due to the establishment of a $20.0 million reserve for FERC and California exposures in the year ended March 31, 2003; a $19.2 million increase in employee costs, including pensions and health care; an increase of $17.5 million for mine reclamation costs; an increase of $12.1 million in rent expense in the year ended March 31, 2003 for the West Valley operating lease; increased generation materials and contract services of $10.2 million, primarily due to the scope and timing of generating plant overhauls, and an $8.8 million increase due to lower capitalized costs. These increases were partially offset by a $22.1 million decrease resulting from the temporary lease of a generating turbine in the year ended March 31, 2002; a decrease of $13.7 million in DSM costs; and an $8.0 million reserve for bad debts recorded in the year ended March 31, 2002.
Other operations and maintenance expense for the year ended March 31, 2002 increased $25.8 million, or 4.8%, from the year ended March 31, 2001, primarily due to $24.7 million for the lease of a new generating turbine, $20.4 million in increased generation costs, increases in employee-related expenses of $5.9 million and tree-trimming costs of $1.4 million. These increases were partially offset by decreases due to the level and timing of capital projects and related expenditures of $31.6 million.
Depreciation and amortization expense for the year ended March 31, 2003 increased $33.0 million, or 8.2%, from the year ended March 31, 2002, primarily due to a $14.4 million increase due to the termination at March 31, 2002 of a two-year depreciation expense reduction ordered by state regulatory commissions; increased expenditures on Property, plant and equipment, which resulted in a $9.5 million increase in depreciation expense; increased amortization of Regulatory assets and liabilities of $4.7 million; and increased software amortization of $4.2 million. Depreciation and amortization expenses for the year ended March 31, 2002 increased $12.3 million, or 3.2%, from the year ended March 31, 2001, primarily due to an increase in Property, plant and equipment that resulted in an $8.4 million increase and increased software amortization of $3.4 million.
Administrative and general expenses for the year ended March 31, 2003 increased $35.6 million, or 14.5%, from the year ended March 31, 2002, primarily due to increased property and liability insurance costs of $31.7 million resulting from higher premiums, insurance reserves and storm damage, and increased employee expenses, including pensions and health care, of $6.0 million, offset by a $2.0 decrease in consulting expense. Administrative and general expenses for the year ended March 31, 2002 increased $124.6 million, or 103.0%, from the year ended March 31, 2001. Employee-related expenses increased by $44.0 million. Administrative and general expenses for the year ended March 31, 2002 included $16.9 million for the amortization of deferred transition costs allowed by state regulators. The level and timing of expenditures capitalized in 2002 fell from 2001 levels and resulted in a $38.3 million increase in expense. Additional consulting and outside services added $9.7 million to expense, asset
reserves added $5.4 million, lower charge-backs to Powercor added $2.8 million and increased insurance premiums added $2.9 million.
Taxes, other than income taxes, for the year ended March 31, 2003 increased $2.7 million, or 3.0%, from the year ended March 31, 2002, primarily due to settlements and adjustments that lowered property tax expense during the year ended March 31, 2002. Taxes, other than income taxes in the year ended March 31, 2002, decreased $6.8 million, or 7.0%, from the year ended March 31, 2001, primarily due to lower property tax expense resulting from the favorable resolution of outstanding property tax appeals and lower franchise taxes.
The Unrealized gain on SFAS No. 133 derivative instruments for the year ended March 31, 2003 was $3.1 million, as compared to $182.8 million for the year ended March 31, 2002, primarily due to implementation of Issue C15 on July 1, 2001, which resulted in the designation of the majority of the Company’s short-term contracts as normal purchases and sales. The Unrealized gain on SFAS No. 133 derivative instruments for the year ended March 31, 2002 pertains to the Company’s short-term sales obligations being favorably impacted by lower forward market prices that resulted from the significant changes in market fundamentals.
Australian Operations
The Australian Operations consisted of Powercor and a 19.9% interest in Hazelwood and were sold in fall 2000.
Other Operations
Operating expenses for the year ended March 31, 2002 decreased $126.8 million, or 93.4%, primarily due to the sale of the synthetic-fuel operations that resulted in a $98.4 million decrease and a $21.3 million decrease due to the transfer of PGHC to PHI.
OTHER OPERATING INCOME
Other operating income for the year ended March 31, 2002 increased $1.8 million. During the year ended March 31, 2002, the Company recorded $21.0 million relating to a regulatory settlement that resulted in the establishment of a regulatory asset. The Company also recorded an $11.3 million gain on the sale of the synthetic-fuel operations. Included within Other operating income in 2001 was income of $43.5 million relating to rate orders received which provided recovery for previously denied costs and resulted in the establishment of regulatory assets. In addition, the Company recorded a loss on the sale of Centralia of $13.9 million in the year ended March 31, 2001.
(GAIN) LOSS ON SALE OF OPERATING ASSETS
The $27.4 million Gain on sale of operating assets for the year ended March 31, 2002 pertained to further proceeds received in June 2001 from the resolution of a contingency under the provisions of the sale of the Australian Operations. In the year ended March 31, 2001, the Company recorded a $184.2 million loss on the sale of the Australian Operations.
INTEREST EXPENSE AND OTHER (INCOME) EXPENSE
(a)
Minority interest and other includes payments of $28.3 million on Preferred Securities of wholly owned subsidiary trusts for each of the three years ended March 31.
Interest expense for the year ended March 31, 2003 increased $42.6 million, or 18.7%, primarily due to higher average long-term debt balances and a $20.9 million increase in interest expense for regulatory liabilities. These increases were partially offset by lower average short-term and variable-interest rates. The Company issued $800.0 million of new long-term debt in November 2001. Interest expense for the year ended March 31, 2002
decreased $62.7 million, or 21.6%, as compared to the year ended March 31, 2001, primarily due to the sale of the Australian Operations and lower interest rates.
Interest income for the year ended March 31, 2003 decreased $25.9 million, or 54.5%, primarily as a result of an $11.1 million decrease in interest income on regulatory assets and lower average notes-receivable balances due to the transfer of PGHC to PHI in February 2002. These decreases were partially offset by the recognition of $1.1 million of interest income on an electricity sales contract settlement in September 2002 and $1.5 million of interest income on the settlement of an excise tax case with the state of Washington in March 2002. Interest income for the year ended March 31, 2002 increased $14.9 million, or 45.7%, as compared to the year ended March 31, 2001 primarily due to a $24.4 million increase in interest income for regulatory assets, partially offset by lower average interest rates.
Interest capitalized increased $11.1 million, as compared to the year ended March 31, 2002, due to higher capitalization rates, as a return on equity component was included, and higher qualifying construction work-in-progress balances. Interest capitalized for the year ended March 31, 2002 decreased $6.0 million, or 46.5%, as compared to the year ended March 31, 2001, due to lower capitalization rates, partially offset by higher qualifying construction work-in-progress balances.
Minority interest and other increased $20.8 million. Minority interest was constant year over year. Of the increase, $18.9 million pertained to Other income and expense of PGHC in the year ended March 31, 2002. During the year ended March 31, 2002, PGHC recorded $9.3 million in gains on sales of leased aircraft owned by PFS, $4.8 million in gains on various settlements and $3.7 million in gains on sales of nonutility investments. Other expense for Electric Operations increased in part due to the reversal in the year ended March 31, 2003 of a previously recorded gain of $3.4 million as a result of a regulatory order.
INCOME TAX EXPENSE
Income tax expense for the year ended March 31, 2003 decreased $78.9 million from the year ended March 31, 2002. The decline in the tax expense was primarily due to the lower taxable income in the year ended March 31, 2003 and the additional tax reserves established in the year ended March 31, 2002 for the amounts proposed as a result of the IRS audit. Income tax expense for the year ended March 31, 2002 decreased $4.3 million, or 2.4%, from the year ended March 31, 2001 primarily due to reduced taxable income.
The Company’s combined federal and state effective income tax rate from continuing operations was 40.6%, 37.5% and 195.7% for the years ended March 31, 2003, 2002 and 2001, respectively. The tax rate for the year ended March 31, 2003 varied from the statutory rate, primarily due to the tax effects of the regulatory treatment of depreciation, which were partially offset by income tax credits. The tax rate for the year ended March 31, 2002 was approximately the same as the statutory rate. The tax rate for the year ended March 31, 2001 varied significantly from the statutory rate, primarily due to the substantially nondeductible losses on the sales of the Australian operations and reserves for tax on outstanding IRS examination issues.
DISCONTINUED OPERATIONS
The Company recognized $146.7 million of income during the year ended March 31, 2002, as a result of collecting a contingent note receivable relating to the discontinued operations of its former mining and resource development business, NERCO, which was sold in 1993. This note from the buyer was recorded at the date of the NERCO sale, along with a corresponding deferred gain. Payments on this note were contingent upon the buyer receiving payment under a coal supply contract. The Company recognized this gain on a cost-recovery basis as payments were received from the buyer. In June 2001, the Company received full payment of the remaining balance of the note and recognized the remaining balance of the deferred gain. Deferred tax expense of $36.4 million was recognized on the gain in June 2001.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
The Company recorded a $1.9 million loss from the implementation of revised Issue C15 and Issue C16 during the year ended March 31, 2003 and recorded a $112.8 million loss from the implementation of SFAS No. 133 during the year ended March 31, 2002.
LIQUIDITY AND CAPITAL RESOURCES
OPERATING ACTIVITIES
Net cash flows provided by operating activities increased by $339.0 million to $681.6 million for the year ended March 31, 2003, as compared to $342.6 million for the year ended March 31, 2002. During the year ended March 31, 2003, the Company received cash recoveries of $111.1 million of previously deferred net power costs. In addition, the Company received $44.0 million during the year ended March 31, 2003 of additional cash revenues from general rate case increases. Net cash flows provided by operating activities decreased $302.1 million for the year ended March 31, 2002 from the year ended March 31, 2001. This decrease was largely due to the impact of significantly higher purchased electricity prices, combined with regulated rates that did not reflect the costs to purchase power, a portion of which was deferred under accounting orders, which were only partially offset by cash from working capital increases. The $706.4 million change in Accounts payable and accrued liabilities between the years ended March 31, 2002 and 2001 primarily reflected the higher amounts paid for electricity and larger income tax accruals for the year ended March 31, 2001.
INVESTING ACTIVITIES
Capital spending totaled $550.0 million for the year ended March 31, 2003 compared with $505.3 million for the year ended March 31, 2002. The increase was primarily due to expenditures for new generation, network growth, system upgrades and other capital projects. Proceeds from a finance note repayment in the year ended March 31, 2002 represented the payment of a note receivable held by PGHC relating to the discontinued operations of NERCO. Certain types of investing activities for the year ended March 31, 2002 do not appear in the year ended March 31, 2003, due to the transfer of PGHC and its subsidiaries from PacifiCorp to PHI.
FINANCING ACTIVITIES
Net cash used in financing activities was $161.9 million for the year ended March 31, 2003, as compared to net cash provided by financing activities of $244.3 million for the year ended March 31, 2002. Net short-term borrowings decreased $152.5 million, proceeds from long-term debt issuance decreased $791.1 million and common stock issuance increased $150.0 million. On December 19, 2002, the Company issued 14,851,485 shares of its common stock to PHI at a total price of $150.0 million, or $10.10 per share. The Company used the proceeds from the sale of these shares to repay debt and for general corporate purposes. The decreased utilization of external financing reflects the significant improvement in cash generated by operations.
The Company’s short-term borrowings are supported by $800.0 million of revolving credit agreements. As of March 31, 2003, these facilities were fully available and had no borrowings outstanding. In addition to these committed credit facilities, the Company had $123.2 million of money market accounts included in Cash and temporary cash investments at March 31, 2003, available to meet its liquidity needs.
For the year ended March 31, 2003, the Company issued no long-term debt and made scheduled long-term debt repayments of $144.6 million. For the year ended March 31, 2002, the Company had proceeds from long-term debt issuance of $791.1 million and made scheduled long-term debt repayments of $59.0 million. The Company has an effective shelf registration statement for up to $1.1 billion of long-term debt, of which the issuance of $800.0 million has been authorized by the applicable regulatory commissions, subject to certain conditions. Any such issuance would be subject to market conditions.
For the year ended March 31, 2003, the Company redeemed, at par, $7.5 million of its preferred stock, of which $3.8 million was pursuant to its mandatory scheduled redemption. During the year ended March 31, 2002, the Company redeemed, at par, $100.0 million of its preferred stock pursuant to its scheduled mandatory redemption.
For the year ended March 31, 2003, no dividends were declared or paid on common stock. During the year ended March 31, 2002, the Company declared dividends on common stock of $240.8 million and paid dividends on common stock of $298.6 million. The dividends were declared at a rate that was consistent with the Company’s historic pre-Merger rate per share. On April 17, 2003, the Board declared a dividend on common stock of $40.1 million, payable on May 28, 2003. The Company declared dividends of $7.2 million and paid dividends of $7.3 million on preferred stock during the year ended March 31, 2003 and had $1.8 million in preferred dividends declared but unpaid at March 31, 2003. The Company declared dividends of $9.8 million and paid dividends of $11.7 million on preferred stock during the year ended March 31, 2002 and had $1.9 million in preferred dividends declared but unpaid at March 31, 2002.
Management expects existing funds and cash generated from operations, together with existing credit facilities, to be sufficient to fund liquidity requirements for the next 12 months. However, many participants in the electric utility industry have experienced a period of negative news and ratings downgrades. While the Company to date has been able to adequately fund itself and expects to be able to continue to do so, further negative information about other industry participants may make it more difficult and expensive for the Company to obtain necessary financing or replace financing agreements at their maturity. If market conditions warrant during the year ending March 31, 2004, the Company may seek to issue long-term debt and redeem outstanding long-term debt to reduce its overall debt service costs.
CAPITALIZATION
The Company manages its capitalization and liquidity position through policies established by senior management and the Board. These policies, subject to periodic review and revision, have resulted from a review of historical and projected practices for businesses and industries that have financial and operating characteristics similar to those of the Company.
The Company’s policies attempt to balance the interests of all shareholders, ratepayers and creditors. In addition, given the changes that are occurring within the industry and market segments in which the Company operates, these policies are intended to remain sufficiently flexible to allow the Company to respond to these changes.
On a consolidated basis, the Company attempts to maintain total debt at approximately 48.0% to 54.0% of capitalization. The total debt-to-capitalization ratio was 49.6% at March 31, 2003. The Company expects to maintain, over time, its capital structure in accordance with its targets. The Company has made commitments in connection with the Merger not to make distributions that result in a reduction of common equity, without approval, to below 38.0% of total capitalization, excluding short-term debt and current maturities of long-term debt, increasing over time to 40.0%.
VARIABLE-RATE LIABILITIES
The Company’s capitalization policy targets consolidated variable-rate liabilities at between 10.0% and 25.0% of total capitalization. The Company was slightly below the target range at March 31, 2003, but anticipates that variable-rate exposure will be within the range during the year ending March 31, 2004.
AVAILABLE CREDIT FACILITIES
At March 31, 2003, the Company had $800.0 million of committed bank revolving credit agreements that became effective June 4, 2002: one facility for $500.0 million, having a 364-day term plus a one-year term loan option, and the other facility for $300.0 million, having a three-year term. At March 31, 2003, these facilities were fully available and there were no borrowings outstanding. The Company is currently seeking to replace the existing $500.0 million credit facility. While the Company believes the facility will be successfully replaced at costs
marginally higher than the existing facility, no assurance can be given as to this outcome. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $25.0 million was outstanding at March 31, 2003 at a weighted average rate of 1.4%.
At March 31, 2003, the Company had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. These committed bank arrangements expire periodically through the year ending March 31, 2006.
LIMITATIONS
In addition to the Company’s capital structure policies, its debt capacity is also governed by its contractual commitments. The Company’s credit agreement contains customary covenants and default provisions, including covenants to maintain a debt-to-capitalization ratio. The Company’s principal debt limitations are a 60.0% debt-to-defined capitalization test and an interest coverage covenant contained in its principal credit agreements. Based on the Company’s most restrictive agreement, management believes that the Company could have borrowed an additional $1.9 billion at March 31, 2003. The Company was in compliance with the covenants of its credit agreement as of March 31, 2003.
Under the Company’s principal credit agreements, it is an event of default if any person or group, other than ScottishPower, acquires 35.0% or more of the Company’s common shares or if, during any period of 14 consecutive months, individuals who were directors of the Company on the first day of such period (and any new directors whose election or nomination was approved by such individuals and directors) cease to constitute a majority of the Board.
CREDIT RATINGS
The Company’s credit ratings at March 31, 2003 were as follows:
Moody’s
S & P
Senior secured debt
A3
A
Senior unsecured debt
Baa1
BBB+
Preferred stock
Baa3
BBB
Commercial paper
P-2
A-2
The Company’s credit ratings are unchanged from March 31, 2002. These security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other rating.
The Company has no rating-downgrade triggers that would accelerate the maturity dates of its debt. A change in ratings is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition to drawing upon the Company’s credit agreements. However, interest rates on loans under the credit agreements and commitment fees are tied to credit ratings and would increase or decrease when ratings are changed. A ratings downgrade may reduce the accessibility and increase the cost of the Company’s commercial paper program, its principal source of short-term borrowing, and may result in the requirement that the Company post collateral under certain of the Company’s power purchase and other agreements.
In addition, a number of the Company’s agreements in the wholesale electric, wholesale gas and energy derivatives markets contain provisions that provide the right for either counterparty to receive cash or other security if mark-to-market exposures on a net basis exceed certain negotiated threshold levels. Generally, these threshold levels change based on long-term unsecured ratings. As such, a ratings downgrade could require the Company to provide additional funds to a counterparty if threshold amounts were exceeded. At March 31, 2003, the Company estimates that a one level downgrade, by either Standard & Poor’s or Moody’s, of its senior unsecured debt ratings would not result in any cash or collateral requirements.
OFF-BALANCE SHEET ARRANGEMENTS
The Company is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. In November 2002, the Financial Accounting Standards Board (the “FASB”) issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees (“FIN No. 45”). FIN No. 45
requires disclosure of certain direct and indirect guarantees. Also, FIN No. 45 requires recognition of a liability at inception for certain new or modified guarantees issued after December 31, 2002. The adoption of FIN No. 45 in January 2003 did not have a material impact on the consolidated financial statements. The following indemnification obligations of the Company fall within the definitions of “indirect guarantees” under FIN No. 45.
On May 4, 2000, the Company and other joint owners completed the sale to Transalta of an electricity plant and coal mine located in Centralia, Washington. Under the agreement relating to the plant, the joint owners agreed to indemnify Transalta if it were to incur certain losses after the closing date and arising as a result of certain breaches of covenants. Under the agreement relating to the mine, the Company provided similar indemnity. The maximum indemnification obligation under these agreements, with respect to the Company, is limited to $556.0 million, less a deductible of 1.0% of the purchase price (approximately $1.0 million). No indemnity claims have been made to date.
In connection with the sale of the Company’s Montana service territory, the Company entered into a purchase and sale agreement with Flathead Electric Cooperative (“Flathead”) dated October 9, 1998. Under the agreement, the Company indemnified Flathead for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The indemnification has a cap of $10.0 million. Two indemnity claims relating to environmental issues have been tendered, but remediation costs for these claims, if any, are not expected to be material.
The Company believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The table below shows the Company’s contractual obligations as of March 31, 2003.
Contractual Obligations
(a)
There have been no significant increases to the long-term obligations during the year ended March 31, 2003. The long-term debt matures at various dates through fiscal year 2032 and bears interest principally at fixed rates. Interest on variable long-term debt is set at the March 31, 2003 rates. The Company uses the proceeds from debt financing for general corporate purposes, including construction, improvement or maintenance of its utility system and the repayment of commercial paper and other short-term debt.
(b)
Wholly owned subsidiary trusts of the Company (the “Trusts”) have issued, in public offerings, redeemable preferred securities (the “Preferred Securities”) representing preferred undivided beneficial interests in the assets of the Trusts, with liquidation amounts of $25.00 per Preferred Security. The sole assets of the Trusts are Junior Subordinated Deferrable Interest Debentures (the “Junior Debentures”) of the Company that bear interest at the same rates as the Preferred Securities to which they relate, and certain rights under related guarantees by the Company. These Junior Debentures are unsecured and junior in terms of preference to all senior debt, including unsecured senior obligations. Under certain conditions, the Company may defer interest on the Junior Debentures.
(c)
The Company’s power contract commitments include purchases of coal, electricity and natural gas. The Company manages its energy resource requirements by integrating long-term, short-term and spot-market purchases with its own generating resources to dispatch the system economically and to meet commitments for wholesale sales and retail load growth. As part of its energy resource portfolio, the Company acquires a portion of its resource requirements through long-term purchases and/or exchange agreements.
(d)
These contractual obligations include commitments for capital expenditures.
(e)
The Company has entered into settlement agreements with various interested parties that are incorporated into the FERC hydroelectric licenses. Hydroelectric licenses have varying expiration dates, and many expire within the next five years. The contractual commitments listed here expire with the license expiration dates. However, the Company plans to acquire new licenses that will allow for continued operation for more than 30 years and expects contractual commitments to increase.
Commercial Commitments
The Company’s commercial commitments include surety bonds that provide indemnities for the Company in relation to various commitments it has to third parties for obligations in the event of default on behalf of the Company. The majority of these bonds are continuous in nature and renew annually. The estimates are based on current information and actual amounts may vary due to rate changes or changes to the general operations of the Company. The Company expects the level of its surety bonding beyond the year ended March 31, 2003 to remain at the historical average of approximately $30.0 million. As of March 31, 2003, the Company had $29.8 million, $21.1 million, $0.6 million and $0.3 million surety bond commitments for the years ending March 31, 2004, 2005-2006, 2007-2008 and thereafter, respectively.
INFLATION
The Company is subject to rate-of-return regulation and the impact of inflation on the level of cost recovery under regulation varies by state depending upon the type of test-period convention used in the state. In the Company’s state jurisdictions, a 12-month period of historical costs is typically used as the basis for developing a “test year,” which may also include various adjustments to eliminate abnormal or one-time events, normalize cost levels, or escalate the historical costs to a future level when the new rates will actually be in effect. To the extent that the levels of costs beyond the historical 12-month period can be established either through known adjustments or through the escalation of cost levels in establishing prices, the Company can mitigate the impacts of inflationary pressures. The Company is seeking to establish a uniform use of future test periods to deal with the rising cost of service and required capital investment.
NEW ACCOUNTING STANDARDS
In June 2001, the FASB issued SFAS No. 143. The statement requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation was incurred. At the same time the liability is recorded, the costs of the asset retirement obligation must be recorded as an addition to the carrying amount of the related asset. Over time, the liability is accreted to its present value, and the addition to the carrying amount of the asset is depreciated over the asset’s useful life. Upon retirement of the asset, the Company will settle the retirement obligation against the recorded balance of the liability. Any difference in the final retirement obligation cost and the liability will result in either a gain or loss. The Company adopted this statement as of April 1, 2003.
The Company has been recording retirement obligations relating to mining reclamation and closure costs prior to adoption of the standard. In addition, the Company has been recording accumulated removal costs as a part of accumulated depreciation in accordance with regulatory accounting. As a result of adoption of the standard, the net difference between these previously recorded amounts that qualify as asset retirement obligations and the fair value amounts determined under SFAS No. 143 will be recognized as a cumulative effect of a change in accounting principle, net of related income taxes. The Company expects to recover asset retirement costs through the ratemaking process and has requested authorization from the state regulatory commissions to record a Regulatory asset or Regulatory liability on the Consolidated Balance Sheet to account for the difference between asset retirement costs as currently approved in rates and obligations under SFAS No. 143.
Upon adoption of SFAS No. 143 on April 1, 2003 the Company recorded an asset retirement obligation liability at its net present value of $196.1 million, increased net depreciable assets by $37.3 million, removed $163.1 million of costs accrued for final removal from accumulated depreciation and reclamation liabilities and will result in a cumulative pretax effect of a change in accounting principle of $4.3 million, which if approved by state regulators, will be recorded primarily as a net regulatory liability. Accretion and depreciation expense in the first year of adoption are expected to be $8.0 million and $2.7 million, respectively.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (“SFAS No. 146”), which requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred instead of at the date of the company’s commitment to an exit plan. SFAS No. 146 is
effective for exit or disposal activities that are initiated after December 31, 2002 and had no effect on the Company’s financial position or results of operations.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”). This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This statement is effective for contracts entered into or modified after June 30, 2003. The Company is currently evaluating the impact of adopting this statement on its consolidated financial position and results of operations.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”). This statement affects the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. The new statement requires that those instruments be classified as liabilities. Most of this statement is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently evaluating the impact of adopting this statement on its consolidated financial position and results of operations.
In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable-Interest Entities (“FIN No. 46”), which requires existing unconsolidated variable-interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. FIN No. 46 applies immediately to variable-interest entities created after January 31, 2003 and applies, for periods beginning after June 15, 2003, to variable-interest entities acquired before February 1, 2003. The Company does not believe the implementation of FIN No. 46 will have a material impact on its financial position or results of operations.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
BUSINESS RISK
The Company participates in a wholesale energy market that includes: public utility companies; electricity and natural gas marketers, which may or may not be affiliated with public utility companies; government entities; and others. The participants in this market trade, or otherwise buy and sell, not only electricity and natural gas as commodities, but also derivative commodity instruments such as futures, swaps, options and other financial instruments. The pricing in this wholesale market is largely market-based and most transactions are conducted on an “over-the-counter” basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges).
The Company is subject to the various risks inherent in the energy business, including market risk, operating risk, regulatory risk, political risk, security risk, credit risk, interest rate risk, insurance risk and pension risk. Due to global uncertainties, including war and terrorism, the nation’s economy and financial markets have been disrupted. The total effects of these matters and other such incidences are not known at this time.
Market Risk
In general, market risk is the risk of fluctuations in the market price of electricity and fuel, as well as volumetric risk caused by changes in weather, the economy, unanticipated generation or network outages and customer behavior. Market price is influenced primarily by factors relating to supply and demand. Those factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric availability, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, changes in technology and other factors.
While the Company plans for resources to meet its current and expected retail and wholesale load obligations, resource availability, price volatility and load volatility may materially impact the power costs to the Company and profits from excess electricity sales in the future. Prices paid by the Company to provide certain load balancing resources to supply its load may exceed the amounts it receives through retail rates and wholesale prices.
Operating Risk
Operating risk is the risk that assets and mechanical systems, as well as business processes and procedures, might not perform as expected, with the result that the Company may be unable to meet a portion of its obligations without resorting to an unanticipated market transaction. Operating risk is primarily mitigated through a combination of sound maintenance practices, prudent and safe operational processes and insurance products, such as business interruption insurance.
Regulatory Risk
The Company is subject to the jurisdiction of federal and state regulatory authorities. The FERC establishes tariffs under which the Company provides wheeling service to the wholesale market and the retail market for states allowing retail competition, establishes both cost-based and market-based tariffs under which the Company sells electricity at wholesale and has licensing authority over most of the Company’s hydroelectric generation facilities. The utility regulatory commissions in each state independently determine the rates the Company may charge its retail customers in that state. Each state’s rate setting process is based upon the state commission’s acceptance of an allocated share of total Company costs as its “responsibility.” When different states adopt different methods to address this “interjurisdictional cost allocation” issue, some costs may not be incorporated into rates in any state. Ratemaking is done on the basis of “normalized” costs, so if in a specific year realized costs are higher than normal, rates will not be sufficient to cover those costs. Likewise, if in a given year costs are lower than normal or revenues are higher, the Company retains the resulting higher-than-normal profit. Each commission sets rates based on a “test year” of its choosing. In states that use a historical test year, rate adjustments could follow cost increases, or decreases, by up to two years. Regulatory lag results in a delay in recovery of costs currently incurred but not in rates, and also imposes a time-value-of-money burden on the Company. Further, each commission decides what level of expense and investment is “necessary, reasonable and prudent” in providing service. If a commission decides that part of the Company’s costs do not meet this standard, such costs will be “disallowed” and not recovered in rates. For these reasons, the rates authorized by the regulators may be less than the costs to the Company to provide electrical service to its customers in a given period.
Nearly all of the Company’s hydroelectric projects are in some stage of the FERC relicensing under the FPA. The relicensing process is a political and public regulatory process that involves sensitive resource issues. The Company is unable to predict the requirements that may be imposed during the relicensing process, the economic impact of those requirements, whether new licenses will ultimately be issued or whether the Company will be willing to meet the relicensing requirements to continue operating its hydroelectric projects.
Federal, state and local authorities regulate many of the Company’s activities pursuant to laws designed to restore, protect and enhance the quality of the environment. The Company is unable to accurately predict what material impact, if any, future changes in environmental laws and regulations may have on the Company’s consolidated financial position, results of operations, cash flows, liquidity and capital expenditure requirements.
Political Risk
The Company conducts its business in conformance with a multitude of federal and state laws. The U.S. Congress is considering significant changes in energy, air quality and tax policy. Energy legislation recently passed by the U.S. House of Representatives would make some changes in federal law that would affect the Company. The proposed changes effect the hydroelectric licensing process under the FPA and extension of the renewable energy production tax credit, which would likely benefit the Company’s efforts to develop, acquire and maintain a low-cost generation portfolio. Changes to the Clean Air Act contemplated by the proposed Clear Skies Act are being monitored closely by the Company because they may impact requirements for several emissions from fossil-fueled generation plants.
The laws of the states in which the Company operates affect the Company’s generation, transmission and distribution business. All but two of the legislatures monitored by the Company have concluded their regular business for their legislative year. The Company is not aware of any new laws positively or negatively affecting the Company in any significant manner, based on a review of bills passed by the Oregon, Washington and Idaho legislatures during their just-completed legislative sessions. Wyoming enacted an exemption to the state sales tax for renewable-energy equipment, which may make development of wind energy resources in the state more economically viable. Wyoming also passed legislation revamping the consumer advocate staff role in commission proceedings. Utah enacted legislation authorizing the UPSC to use a forward-looking test year of up to 20 months in
setting rates. This mechanism, if properly implemented, should enable the UPSC to set consistent rates that more accurately reflect costs during the actual rate period. California is expected to consider legislation repealing or reforming many elements of its 1996 restructuring law.
Security Risk
The emergence of terrorism threats, both domestic and foreign, is a risk to the entire utility industry, including the Company. Specific potential disruptions to operations and information technologies or destruction of facilities from terrorism are not readily determinable. The Company has identified critical assets, created a management structure to respond to threats and developed several approaches to security to meet the changed environment. A project is underway to implement a comprehensive security plan, starting with the most critical assets, to mitigate terrorism risks and to prepare contingency plans in case the Company’s facilities are targeted. Additionally the FERC is promulgating standards to which the Company will be subject.
Credit Risk
There has been a decrease in the number of counterparties in the wholesale energy markets with whom the Company has been able to prudently transact business for purposes of servicing its regulated customers. This decline is due to an overall lower credit ratings trend in the energy industry and the concern that these counterparties may face a liquidity crisis and be unable to meet their obligations. In addition, some counterparties are focusing less of their efforts on merchant energy trading, are pursuing lower risk/slower growth opportunities, are strengthening their balance sheets in order to maintain or achieve an investment grade rating or are looking to sell their energy trading divisions or to exit the marketplace entirely.
Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements thereon. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with such counterparty. The Company seeks to mitigate credit risk (and concentrations thereof) by applying specific eligibility criteria to prospective counterparties. However, despite mitigation efforts, defaults by counterparties occur from time to time. The Company continues to actively monitor the creditworthiness of those counterparties with whom it executes wholesale energy and gas purchase and sales transactions within the WECC, including those in California, and uses a variety of risk mitigation techniques to limit its exposure where it believes appropriate. When the Company considers a new business venture or asset purchase, market liquidity and the ability to optimize the investment are main considerations. The Company, like all participants in the regional market, has exposure to other participants that may have credit exposure to the utilities in California. To mitigate exposure to the financial risks of wholesale counterparties, the Company has entered into netting, margining, guarantee and prepayment arrangements. Counterparties may be assessed late fees for delayed receipts. If required, collection rights are exercised, including application of the counterparty’s credit support arrangement.
Interest Rate Risk
The Company manages its interest rate risk exposure principally by maintaining a blend of fixed- and variable-rate debt. The majority of debt is fixed-rate securities, portions of which are callable at fixed prices at the Company’s option. Changing interest rates will affect interest paid on variable-rate debt and interest earned by the Company’s pension plan assets and mining reclamation trust funds. The Company’s principal source of variable-rate debt is commercial paper, other short-term borrowings and pollution control revenue bonds remarketed on a periodic basis. Commercial paper and other short-term borrowing are commonly refinanced with fixed-rate long-term debt when needed and when interest rates are considered favorable.
Any adverse change to the Company’s credit rating could negatively impact the Company’s ability to borrow and the interest rates that are charged. The activity in the western electricity markets has had a negative impact on the willingness of the financial markets to provide financing on conditions and at rates that have historically been available to the Company.
Insurance Risks
The Company continues to experience risk relating to increases in various insurance costs and premiums, as well as available insurance coverage for certain property and liability exposures. The Company’s health care costs continue to rise faster than inflation, but not greater than the general industry trend.
The Company has faced a significantly changed insurance market over the past two years. Significant reductions in market capacity and an increase in the incidents of losses worldwide contributed to unprecedented insurance program costs.
Those increased costs came in the form of increased premiums for coverage, as well as substantial increases in self-insured retentions and exposures. Restrictions on the type of coverage available, the scope of the coverage and the limits of coverage were common. In addition, some insurance carriers are now requiring additional security for the self-insured exposures presented by some coverages. As a result, the Company has been required to post letters of credit as security for certain insurance programs, such as surety bonds, workers’ compensation and black lung disease coverage. Due to the changes in the market, the Company reevaluated each exposure to ensure that all critical coverage that could be obtained was pursued and critically evaluated. This evaluation resulted in the purchase of business interruption insurance in addition to some of the more traditional property and liability coverage elements. While the Company has elected to purchase terrorism insurance, which is now available with the passage of the Terrorism Re-Insurance Act, coverage gaps pertaining to the Company’s transmission and distribution assets and limits on earthquake and flood coverage persist.
Pension Risks
As a result of the decline in the equity markets and low interest rates, the Company anticipates that pension expense and Company cash contributions into the pension trust will increase significantly in the near future. The Company is exposed to further increases in both expense and contribution levels if the equity markets underperform the Company’s long-term return expectations. In addition, low interest rates increase both funding requirements and expense levels since the Company’s pension liability increases as the discount rate declines. To the extent that actual interest rates fall below currently assumed levels, pension expense and contribution requirements will increase.
RISK MANAGEMENT
The Company has a risk management committee responsible for the oversight of market and credit risk relating to the energy transactions of the Company. The risk management committee consists of the chief executive officer, officers from the finance, regulation, strategy, legal, wholesale marketing and independent risk management group areas. To limit the Company’s exposure to market risk, the risk management committee, with the approval of the Board, sets policies and limits and approves energy strategies, which are reviewed frequently to respond to changing market conditions. To limit the Company’s exposure to credit risk in these activities, the risk management committee reviews counterparty credit exposure, as well as credit policies and limits, on a monthly basis.
Risk is an inherent part of the Company’s business and activities. The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in its business and activities and to measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, the Company enters into various transactions, including derivative transactions, consistent with the Company’s risk management policy. The risk management policy governs energy transactions and is designed for hedging the Company’s existing energy and asset exposures. The policy also governs the Company’s use of derivative instruments, as well as its energy purchase and sales practices, and describes the Company’s credit policy and management information systems required to effectively monitor such derivative use. The Company’s risk management policy provides for the use of only those instruments that have a close volume or price correlation with its portfolio of assets, liabilities or anticipated transactions. The risk management policy includes, as its objective, a policy that such instruments will be primarily used for hedging and not for speculation.
The Company continues to take steps to manage commodity price volatility and reduce exposure. These steps included adding to the generation portfolio and entering into transactions that help to shape the Company’s system resource portfolio, including physical hedging products and financially settled (temperature-related) derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financial hydroelectric
generation hedge is in place for the next three years to reduce volume and price risks associated with the Company’s hydroelectric generation availability.
RISK MEASUREMENT
Interest Rate Exposure
In accordance with established policies, the Company may use interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company’s capital structure policy, which provides guidance on overall debt to equity and variable-rate debt as a percent of capitalization levels. At March 31, 2003, the Company had no financial derivatives in effect relating to its interest rate exposure.
The Company’s risk to interest rate changes is primarily a noncash fair market value exposure and generally not a cash or current interest expense exposure. This result is due to the size of the Company’s fixed-rate, long-term debt portfolio relative to variable rate debt.
The tests discussed below for exposure to interest rate fluctuations are based on a Value-at-Risk (“VaR”) approach using a one-year horizon and a 95.0% confidence level and assuming a one-day holding period in normal market conditions. The VaR model is a risk analysis tool that attempts to measure the potential change in fair value, earnings or cash flow from changes in market conditions and does not purport to represent actual losses (or gains) in fair value that may be incurred by the Company.
The table below shows the potential loss in fair market value (“FMV”) of the Company’s interest-rate-sensitive positions, for continuing operations, as of March 31, 2003 and 2002, as well as the Company’s quarterly high and low potential losses.
The decrease in potential loss from March 31, 2002 to March 31, 2003 was primarily due to a decline in interest rate volatility.
Commodity Price Exposure
The Company’s market risk to commodity price change is primarily related to its fuel and electricity commodities, which are subject to fluctuations due to unpredictable factors, such as weather, which impacts energy supply and demand. The Company’s energy purchase and sales activities are governed by the Company’s risk management policy and the risk levels established as part of that policy.
The Company’s energy commodity price exposure arises principally from its electric supply obligation in the western U.S. The Company manages this risk principally through the operation of its 8,409.7-MW generation and transmission system in the western U.S. and through its wholesale energy purchase and sales activities. Physically settled contracts are utilized to hedge the Company’s excess or shortage of net electricity for future months. The Company has also entered into several financially settled (temperature-related) derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financial hydroelectric generation hedge is in place for the next three years to reduce volume and price risks associated with the Company’s hydroelectric generation availability.
In January 2002, the Company began measuring the market risk in its electricity and natural gas portfolio daily utilizing a historical VaR approach, as well as other measurements of net position. The Company also monitors its portfolio exposure to market risk in comparison to established thresholds and measures its open positions subject to price risk in terms of volumes at each delivery location for each forward time period.
VaR computations for the electricity and natural gas commodity portfolio are based on a historical simulation technique, utilizing historical price changes over a specified period to simulate potential forward energy market price curve movements to estimate the potential unfavorable impact of such price changes on the portfolio positions scheduled to settle within the following 24 months. The quantification of market risk using VaR provides a consistent measure of risk across the Company’s continually changing portfolio. VaR represents an estimate of
reasonably possible changes in fair value that would be measured on its portfolio assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur.
The Company’s VaR computations for its electricity and natural gas commodity portfolio utilize several key assumptions, including a 99.0% confidence level for the resultant price changes and a holding period of five days. The calculation includes short-term derivative commodity instruments held for trading and balancing purposes, the expected resource and demand obligations from the Company’s long-term contracts, the expected generation levels from the Company’s generation assets and the expected retail and wholesale load levels. Optionality embedded within the Company’s long-term contracts, generation assets and other derivative instruments with option characteristics within the energy portfolio are treated in the historical simulation of VaR as static delta positions through the simulation process. Option deltas are recalculated on a daily basis to determine the portfolio position changes due to changes in market prices.
As of March 31, 2003, the Company’s estimated potential five-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 24 months was $17.6 million, as measured by the VaR computations described above, compared to $16.3 million as of March 31, 2002. The average daily VaR (five-day holding periods) for the year ended March 31, 2003 was $19.2 million. The maximum and minimum VaR measured during the year ended March 31, 2003 was $35.7 million and $9.5 million, respectively. The Company maintained compliance with its VaR limit procedures during the year ended March 31, 2003. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits. Market risks associated with derivative commodity instruments held for purposes other than hedging and balancing the Company’s energy commodity portfolio were not material as of March 31, 2003.
The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SFAS No. 133 from April 1, 2002 to March 31, 2003 and quantifies the reasons for the changes.
(a)
The cumulative effect of accounting change records the impact of Revised Issue C15 and Issue C16.
(b)
Reflects changes in the fair value of the mark-to-market values as a result of applying refinements in valuation modeling techniques.
(c)
Other changes in fair values reflect commodity price risk, which is influenced by contract size, term, location and unique or specific contract terms.
(d)
The Company has also recorded $506.9 million in net regulatory assets, as authorized by regulatory orders received, with respect to these contracts.
The forward market price curve is derived using daily market quotes from independent energy brokers, as well as direct information received from third-party offers and actual transactions executed by the Company. For contracts extending past 2006, the forward prices also include the use of a fundamentals model (cost-to-build approach) due to the limited market information available past 2006. The fundamentals model is updated as warranted, at least quarterly, to reflect changes in the market. Short-term contracts, without explicit or embedded optionality, are valued based upon the relevant portion of the forward market price curve. Contracts with explicit or embedded optionality and long-term contracts are valued by separating each contract into its component physical and financial forward, swap and option legs. Forward and swap legs are valued against the appropriate market curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward market price curve.
The Company also manages its exposure to price and volume risk by purchasing weather hedges. These products are designed to protect the Company from the effects of weather on its hydroelectric generation and load forecast. The Company records these instruments in its financial statements at market value in accordance with Emerging Issues
Task Force No. 99-2, Accounting for Weather Derivatives. At March 31, 2003, the net value of these instruments was a liability of $3.5 million.
The Company’s valuation models and assumptions are continuously updated to reflect current market information, and an evaluation and refinement of model assumptions are performed on a periodic basis.
The following table shows summarized information with respect to valuation techniques and contractual maturities of the Company’s energy-related contracts qualifying as derivatives under SFAS No. 133 as of March 31, 2003.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Index to Consolidated Financial Statements:
Report of Management
Report of Independent Accountants
Statements of Consolidated Income (Loss) for the Years Ended March 31, 2003, 2002 and 2001
Consolidated Balance Sheets as of March 31, 2003 and 2002
Statements of Consolidated Cash Flows for the Years Ended March 31, 2003, 2002 and 2001
Statements of Consolidated Changes in Common Shareholder’s Equity for the Years Ended March 31, 2003, 2002 and 2001
Notes to the Consolidated Financial Statements
REPORT OF MANAGEMENT
The management of PacifiCorp and its subsidiaries (the “Company”) are responsible for preparing the accompanying consolidated financial statements and ensuring their integrity and objectivity. The statements were prepared in accordance with accounting principles generally accepted in the United States of America. The financial statements include amounts that are based on management’s best estimates and judgments. Management also prepared the other information in this annual report on Form 10-K and is responsible for its accuracy and consistency with the financial statements.
The Company’s financial statements were audited by PricewaterhouseCoopers LLP (“PricewaterhouseCoopers”), independent public accountants. Management made available to PricewaterhouseCoopers all the Company’s financial records and related data, as well as the minutes of directors’ meetings.
Management of the Company established and maintains an internal control structure that provides reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition and the prevention and detection of materially fraudulent financial reporting. The Company maintains an internal auditing program that independently assesses the effectiveness of the internal control structure and recommends possible improvements. PricewaterhouseCoopers considered that internal control structure in connection with its audits. Management reviews significant recommendations by the internal auditors and PricewaterhouseCoopers concerning the Company’s internal control structure and ensures that appropriate cost-effective actions are taken.
The Company’s “Guide to Business Conduct” is distributed to employees throughout the Company to provide a basis for ethical standards and conduct. The guide addresses, among other things, potential conflicts of interests and compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information. In addition, the Company recently adopted and implemented the “PacifiCorp Code of Ethics for Principal Officers” in response to the Sarbanes-Oxley Act of 2002.
Judith A. Johansen
President and Chief Executive Officer
Richard D. Peach
Chief Financial Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of PacifiCorp:
In our opinion, the accompanying consolidated balance sheets and the related statements of consolidated income (loss), changes in common shareholder’s equity and cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the Consolidated Financial Statements, the Company changed its method of accounting for derivative instruments as of April 1, 2001.
PricewaterhouseCoopers LLP
Portland, Oregon
May 7, 2003
PACIFICORP AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME (LOSS)
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, continued
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN COMMON SHAREHOLDER’S EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - Summary of Significant Accounting Policies
Nature of operations - The Company (which includes PacifiCorp and its subsidiaries) is a United States (“U.S.”) electricity company operating in six western states. The Company conducts its retail electric utility business as Pacific Power and Utah Power and engages in electricity production and sales on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services, environmental remediation and financing.
Basis of presentation - The consolidated financial statements of the Company include its integrated electric utility operations and its wholly owned and majority-owned subsidiaries. Significant intercompany transactions and balances have been eliminated upon consolidation.
After obtaining the necessary regulatory approvals, on December 31, 2001, NA General Partnership (“NAGP”) contributed all of the common stock of the Company to PacifiCorp Holdings, Inc. (“PHI”), a direct wholly owned subsidiary of NAGP. NAGP is a wholly owned subsidiary of Scottish Power plc (“ScottishPower”). On February 4, 2002, PacifiCorp transferred all of the capital stock of PacifiCorp Group Holdings Company (“PGHC”), to PHI. This was a noncash transaction that resulted in a net reduction in shareholder’s equity of $575.0 million. PGHC includes the wholly owned subsidiary PacifiCorp Financial Services, Inc. (“PFS”), a financial services business. Accordingly, the consolidated results of operations, assets and liabilities of PGHC and its subsidiaries are not included with those of PacifiCorp commencing February 4, 2002.
In March 2001, the Company sold its interest in PPM Energy, Inc. (“PPM”), formerly PacifiCorp Power Marketing, and Pacific Klamath Energy to PHI, as further discussed in NOTE 17.
The Company completed the sales of its ownership of Powercor Australia Ltd. (“Powercor”) on September 6, 2000 and its 19.9% interest in Hazelwood Power Partnership (“Hazelwood”) on November 17, 2000, as further discussed in NOTE 17. Powercor and Hazelwood represented all of the Australian Operations segment of the Company.
On November 29, 1999, the Company and ScottishPower completed a merger under which the Company became an indirect subsidiary of ScottishPower (the “Merger”). As a result of regulatory requirements and the existence of debt instruments that are secured by the assets of the Company, the basis of assets and liabilities reported in the Company’s financial statements has not been revised to reflect the acquisition of the Company by ScottishPower. The assets, liabilities and shareholder’s equity continue to be presented at historical cost.
Change in fiscal year - In connection with the Merger, the Company’s year-end changed from December 31 to March 31. The Australian Operations’ year-end remained December 31 after the Merger. Consequently, the Company’s statements of consolidated loss and consolidated cash flows for the year ended March 31, 2001 include Australian Operation’s financial statements for the period from January 1, 2000 to the respective dates of sale.
Use of estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.
Regulation - Accounting for the electric utility business conforms with accounting principles generally accepted in the United States of America as applied to regulated public utilities and as prescribed by agencies and the commissions of the various locations in which the electric utility business operates. The Company prepares its financial statements as they relate to Electric Operations in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”) as further discussed in NOTE 2.
Foreign currency - The financial statements for foreign subsidiaries, which were sold in fall 2000, were prepared in currencies other than the U.S. dollar. The income statement amounts were translated at average exchange rates for the year, while the assets and liabilities were translated at year-end exchange rates. Translation adjustments were included in Accumulated other comprehensive income (loss), a separate component of Common equity. All gains and losses resulting from foreign currency transactions were included in the determination of net income.
Cash and cash equivalents - For the purposes of these financial statements, the Company considers all liquid investments with maturities of three months or less, at the time of acquisition, to be cash equivalents.
Allowance for doubtful accounts - The Company’s estimate for its allowance for doubtful accounts relating to trade receivables is based on two methods. The amounts calculated from each of these methods are combined to determine the total amount reserved. First, the Company evaluates specific accounts for which it has information that the customer may be unable to meet its financial obligations. In these cases, the Company uses its judgment, based on the best available facts and circumstances and records a specific reserve for that customer against amounts due to reduce the receivable to the amount that is expected to be collected. These specific reserves are reevaluated and adjusted as additional information is received that impacts the amount reserved. Second, a general reserve is established for all customers based on historical experience. The Company provided $13.9 million, $16.0 million and $10.6 million for doubtful accounts for the years ended March 31, 2003, 2002 and 2001, respectively. Write-offs of uncollectible accounts were $12.4 million, $8.8 million and $10.8 million for the years ended March 31, 2003, 2002 and 2001, respectively.
Inventory valuation - Inventories are generally valued at the lower of average cost or market.
Property, plant and equipment - Property, plant and equipment are stated at original cost of contracted services, direct labor and materials, interest capitalized during construction and indirect charges for engineering, supervision and similar overhead items. The cost of depreciable electric utility properties retired, including the cost of removal, less salvage, is charged to accumulated depreciation. The costs of major overhaul activities and other repairs and maintenance are expensed as the costs are incurred.
Depreciation and amortization - At March 31, 2003, the average depreciable lives of Property, plant and equipment by category for Electric Operations were: Production, 41 years; Transmission, 58 years; Distribution, 42 years and Other, 20 years. Average amortization life on computer software is eight years.
Depreciation and amortization are generally computed by the straight-line method in one of the following two manners, either as prescribed by the Company’s various regulatory jurisdictions for Electric Operations’ regulated assets, or over the assets’ estimated useful lives. Composite depreciation rates on utility plants (excluding amortization of capital leases) in the Electric and Australian Operations were 3.2%, 3.1% and 3.1% of average depreciable assets for the years ended March 31, 2003, 2002 and 2001, respectively.
Asset impairments - Long-lived assets to be held and used by the Company are reviewed for impairment when events or circumstances indicate costs may not be recoverable. Such reviews are performed in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS No. 144”), which the Company adopted February 1, 2002, effective as of April 1, 2001. The impacts of regulation on cash flows are considered when determining impairment. Impairment losses on long-lived assets are recognized when book values exceed expected undiscounted future cash flows with the impairment measured on a discounted future cash flows basis.
Allowance for Funds Used During Construction - The Allowance for Funds Used During Construction (the “AFUDC”) represents the cost of both debt and equity funds used to finance utility property additions during construction. As prescribed by regulatory authorities, the AFUDC is capitalized as a part of the cost of utility property and is recorded in the Statement of Consolidated Income (Loss) as Interest capitalized. Under regulatory rate practices, the Company is generally permitted to recover the AFUDC, and a fair return thereon, through its rate base after the related utility property is placed in service.
The composite capitalization rates for the years ended March 31, 2003, 2002 and 2001 were 7.2%, 3.6% and 7.3%, respectively. The Company’s AFUDC rates do not exceed the maximum allowable rates determined by regulatory authorities.
Derivatives - As discussed in NOTE 3, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, effective April 1, 2001. The statement requires that the Company recognize all derivatives, as defined in the statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not an effective hedge are adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative are either offset against the change in fair value of the hedged asset, liability or firm commitment recognized in earnings or are recognized in Accumulated other comprehensive income (loss) until the hedged items are recognized in earnings.
Deferred charges and other - Deferred charges and other are composed primarily of funds held in trust for the final reclamation of a leased coal mining property, investments to fund environmental remediation, unamortized debt expense, long term customer loans and receivables, certain employee benefit plan assets and net amounts for corporate-owned life insurance.
The Company maintains a trust relating to final reclamation of a leased coal mining property. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. In the years ended March 31, 2003 and 2002, the Company reviewed funding requirements based on estimated future gains and interest earnings on trust assets and the projected future reclamation liability. The Company determined that no funding was required in those years. Securities held in the reclamation trust fund are recorded at market value in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, as discussed in NOTE 5. Trust assets include debt and equity securities classified as available for sale. Securities available for sale are carried at fair value with net unrealized gains or losses excluded from income and reported as Accumulated other comprehensive income (loss). Realized gains or losses are determined on the specific identification method.
Income taxes - The Company uses the liability method of accounting for deferred income taxes. Deferred tax liabilities and assets reflect the expected future tax consequences, based on enacted tax law, of temporary differences between the tax bases of assets and liabilities and their financial reporting amounts.
Historically, Electric Operations did not provide deferred taxes on many of the timing differences between book and tax depreciation. In prior years, these benefits were flowed through to the utility customer as prescribed by the Company’s various regulatory jurisdictions. Deferred income tax liabilities and Regulatory assets have been established for those flow-through tax benefits, as shown in NOTE 15.
Investment tax credits for regulated Electric Operations are deferred and amortized to income over periods prescribed by the Company’s various regulatory jurisdictions.
Provisions for U.S. income taxes for the year ended March 31, 2001 were made on the undistributed earnings of the Company’s international businesses.
Stock-based compensation - As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, the Company has elected to account for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations in accounting for employee stock options issued to Company employees. Under APB No. 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recorded. All options are issued in ScottishPower American Depository Shares (“ADS”), as discussed in NOTE 14. Had the Company determined compensation cost based on the fair value at the grant date for all stock options vesting in each period under SFAS No. 123, the Company’s net income would have been reduced to the pro forma amounts below:
Revenue recognition - The Company records electric utility operating revenues when it delivers electricity to its customers. The determination of the energy sales to the customers is based on a reading of their meters, which reading is staggered throughout the month. The Company accrues estimated unbilled revenues for electric services provided after the meter read date to the month-end, based upon the Company’s total energy delivery.
New accounting standards - In June 2001, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). The statement requires the fair value of an asset retirement obligation to be recorded as a liability in the period in which the obligation was incurred. At the same time the liability is recorded, the costs of the asset retirement obligation must be recorded as an addition to the carrying amount of the related asset. Over time, the liability is accreted to its present value and the addition to the carrying amount of the asset is depreciated over the asset’s useful life. Upon retirement of the asset, the Company will settle the retirement obligation against the recorded balance of the liability. Any difference in the final
retirement obligation cost and the liability will result in either a gain or loss. The Company adopted this statement as of April 1, 2003.
The Company has been recording retirement obligations relating to mining reclamation and closure costs prior to adoption of the standard. In addition, the Company has been recording accumulated removal costs as a part of accumulated depreciation in accordance with regulatory accounting. As a result of adoption of the standard, the net difference between these previously recorded amounts that qualify as asset retirement obligations and the fair value amounts determined under SFAS No. 143 will be recognized as a cumulative effect of a change in accounting principle, net of related income taxes. The Company expects to recover asset retirement costs through the ratemaking process and has requested authorization from the state regulatory commissions to record a Regulatory asset or Regulatory liability on the Consolidated Balance Sheet to account for the difference between asset retirement costs as currently approved in rates and obligations under SFAS No. 143.
Upon adoption of SFAS No. 143 on April 1, 2003, the Company recorded an asset retirement obligation liability at its net present value of $196.1 million, increased net depreciable assets by $37.3 million, removed $163.1 million of costs accrued for final removal from accumulated depreciation and reclamation liabilities and will result in a cumulative pretax effect of a change in accounting principle of $4.3 million, which if approved by state regulators, will be recorded primarily as a net regulatory liability. Accretion and depreciation expense in the first year of adoption are expected to be $8.0 million and $2.7 million, respectively.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (“SFAS No. 146”), which requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred instead of at the date of the company’s commitment to an exit plan. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002 and had no effect on the Company’s financial position or results of operations.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”). This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This statement is effective for contracts entered into or modified after June 30, 2003. The Company is currently evaluating the impact of adopting this statement on its consolidated financial position and results of operations.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (“SFAS No. 150”). This statement affects the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. The new statement requires that those instruments be classified as liabilities. Most of this statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently evaluating the impact of adopting this statement on its consolidated financial position and results of operations.
In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable-Interest Entities (“FIN No. 46”), which requires existing unconsolidated variable-interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. FIN No. 46 applies immediately to variable-interest entities created after January 31, 2003 and applies for periods beginning after June 15, 2003, to variable-interest entities acquired before February 1, 2003. The Company does not believe the implementation of FIN No. 46 will have a material impact on its financial position or results of operations.
Reclassification - Certain amounts from prior years have been reclassified to conform to the 2003 method of presentation. These reclassifications had no effect on previously reported consolidated net income (loss).
NOTE 2 - Accounting for the Effects of Regulation
Regulated utilities have historically applied the provisions of SFAS No. 71,which is based on the premise that regulators will set rates that allow for the recovery of a utility’s costs, including cost of capital. Accounting under SFAS No. 71 is appropriate as long as (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise’s cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be collected from customers.
SFAS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least equal to the capitalized costs will result from the inclusion of that cost in allowable costs for ratemaking purposes. In addition, the rate action should permit recovery of the specific previously incurred costs rather than provide for expected levels of similar future costs. The Company records regulatory assets and liabilities based on management’s assessment that it is probable that a cost will be recovered (asset) or that an obligation has been incurred (liability). The final outcome, or additional regulatory actions, could change management’s assessment in future periods. A regulator can provide current rates intended to recover costs that are expected to be incurred in the future, with the understanding that if those costs are not incurred, future rates will be reduced by corresponding amounts. If current rates are intended to recover such costs, the Company recognizes amounts charged, pursuant to such rates, as liabilities and takes those amounts to income only when the associated costs are incurred. In applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, Electric Operations capitalizes certain costs as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.
The Emerging Issues Task Force (the “EITF”) of the FASB concluded in 1997 that SFAS No. 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their realization is provided for through future regulated cash flows. The Company continuously evaluates the appropriateness of applying SFAS No. 71 to each of its jurisdictions. At March 31, 2003, management concluded that SFAS No. 71 was appropriate for the Electric Operations. However, if deregulation activities progress, the Company may in the future be required to discontinue its application of SFAS No. 71 to all or a portion of its business. If the Company stopped applying SFAS No. 71 to its regulated operations, it would write off the related balances of its regulatory assets as an expense on its income statement. Based on the balances of the Company’s regulatory assets at March 31, 2003, if the Company had stopped applying SFAS No. 71 to its remaining regulated operations, it would have recorded an extraordinary loss, after tax, of approximately $918.2 million. While regulatory orders and market conditions may affect the Company’s cash flows, its cash flows would not be affected if it stopped applying SFAS No. 71 unless a regulatory order limited its ability to recover the cost of that regulatory asset.
The Company is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations, as to prices, services, accounting, issuance of securities and other matters. The jurisdictions in which the Company operates are in various stages of evaluating deregulation. At present, the Company is subject to cost based rate making for its Electric Operations business. The Company is a “licensee” and a “public utility” as those terms are used in the Federal Power Act (the “FPA”) and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (the “FERC”) as to accounting policies and practices, certain prices and other matters.
The Company has made progress toward recovering the deferred net power costs incurred during the period of extreme volatility and unprecedented high price levels beginning in summer 2000 and extending through summer 2001. These costs have been authorized for recovery as follows: (i) $147.0 million in Utah; (ii) $131.0 million, plus carrying charges, in Oregon; and (iii) $25.0 million in Idaho. The Oregon rate order is the subject of a court appeal by intervening parties, which, if successful, would require refunds of amounts collected after January 22, 2003. In Wyoming, the Company’s request for recovery of deferred net power costs was denied, and, as a result, the Company wrote off the remaining net regulatory asset of $48.3 million during the year ended March 31, 2003. The Company filed a petition for rehearing on the Wyoming decision on April 4, 2003. The WPSC denied the petition on May 30, 2003. In Washington, the Company had requested recovery of approximately $17.5 million of excess power costs, which have not been deferred, or, alternatively, that the Company be allowed to file a general rate case, which is currently restricted through December 2005. This request was subsequently reduced to approximately $15.9 million based on revised estimates. A final decision in Washington is expected by June 2003. At March 31, 2003, the Company had $137.8 million of deferred power costs, net of amortization, remaining to be collected over two to three years.
Deferred accounting treatment for the effects of SFAS No. 133 on the financial statements of the Company has been granted in all the states the Company serves. The regulatory orders direct the deferral, as a regulatory asset or liability, of the effects of fair valuing long-term contracts that are included in the Company’s rates.
Regulatory assets include the following:
(a)
Excludes $91.4 million and $99.3 million as of March 31, 2003 and 2002, respectively, of investment tax credits.
(b)
Represents the unamortized amount of retirement and severance costs relating to a transition plan that the state commissions allowed to be deferred and amortized.
(c)
Represents the deferred net power costs that vary from costs included in determining retail rates in Utah, Oregon and Idaho.
(d)
A Utah Public Service Commission (“UPSC”) order during the year ended March 31, 2001 allowed recovery of early retirement and pension costs, reclamation costs and Year 2000 and other information system costs that had previously been written off. A UPSC order during the year ended March 31, 2002 allowed recovery of an additional $21.0 million of mine reclamation, information system and transition costs that had previously been written-off. An Oregon Public Utility Commission (the “OPUC”) order during the year ended March 31, 2001 allowed recovery of Year 2000 information system costs.
(e)
Represents the current and noncurrent mark-to-market derivative adjustments on long-term purchased electricity contracts per SFAS No. 133.
(f)
Represents the State of Oregon Senate Bill 1149 (“SB 1149”) related transition and implementation costs allowed to be recovered by a systems benefit charge allotted to associated customers effective March 1, 2002.
(g)
See NOTE 14 - Employment Benefit Plans.
At March 31, 2003, $56.1 million of regulatory assets have been provided by regulators without a return on investment to the Company. The remaining recovery period for these assets is approximately two years.
Regulatory liabilities include the following:
(a)
Represents the gain on the sale of the Centralia, Washington power plant and coal mine (“Centralia”) that is being returned to customers as ordered by the state commissions in connection with approving the sale. The gain amounts claimed by the jurisdictions the Company serves exceeded the actual gain on the transaction by $13.9 million resulting in a loss on sale that was recorded in Other operating income in the year ended March 31, 2001. The Company is no longer required to return a portion of the gain relating to Utah customers as discussed in Deferred Net Power Costs below.
The Company evaluates the recovery of all regulatory assets periodically and as events occur. The evaluation includes the probability of recovery as well as changes in the regulatory environment. Because of the potential regulatory and/or legislative action in Utah, Oregon, Wyoming, Washington and Idaho, the Company may have regulatory asset write-offs and charges for impairment of long-lived assets in future periods. Impairment would be measured in accordance with the Company’s asset impairment policy, as discussed in NOTE 1.
Depreciation Rate Changes
On October 1, 2002, the Company filed applications with the respective regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation based on a new depreciation study. The new study reflects depreciable plant balances at March 31, 2002. In Utah, settlement discussions have resulted in a stipulation with intervenors. On April 17, 2003, the UPSC approved the stipulation. The rates approved in the stipulation will reduce annual Utah allocated depreciation expense by $6.0 million. The Company and the Idaho Public Utilities Commission (the “IPUC”) staff have agreed on a similar stipulation that will reduce Idaho’s annual allocated depreciation expense by $0.9 million. This stipulation was filed with the IPUC on April 30, 2003. If adopted by all states, these depreciation rate changes would reduce total Company depreciation expense by $20.3 million annually, which could ultimately result in lower revenues or offset anticipated price increases. Future decisions by the commissions in Oregon, Washington and California may impact this annual expense reduction.
Trail Mountain Coal Mine Closure Costs
On February 7, 2001, the Company filed applications with the UPSC, the OPUC, the Wyoming Public Service Commission (the “WPSC”) and the IPUC requesting accounting orders to defer $27.1 million in unrecovered costs associated with its Trail Mountain coal mine. The Company ceased operations at the mine on March 7, 2001. The mine is located in central Utah and supplied fuel to the Company’s Hunter generating plant. In April 2001, the WPSC and the IPUC approved deferred accounting treatment of their state’s share of the $27.1 million of nonrecovered Trail Mountain coal mine investment costs. Additional closure-related costs in the amount of $18.7 million were subsequently identified, and the total amount subject to possible deferral increased to approximately $45.8 million. The Company filed in Utah and Oregon to include the additional costs in its deferral application and received approval to defer the full $45.8 million for accounting purposes. In addition, the parties in Oregon signed a stipulation calling for a $1.1 million annual reduction in Oregon base rates due to the removal of the Trail Mountain coal mine assets from the rate base. The stipulation also provides for a $2.6 million annual surcharge for five years to recover Oregon’s share of mine closure costs. This stipulation was approved by the OPUC on May 20, 2002. On April 4, 2002, the UPSC approved deferral of Utah’s share of the $45.8 million with a five-year amortization beginning April 1, 2001. On May 7, 2002, the Company filed a general rate case in Wyoming that sought to recover Wyoming’s share of the $45.8 million, to be recovered based on a five-year amortization period beginning April 1, 2001. On March 6, 2003, the WPSC approved a stipulation that includes one-fifth of Wyoming’s allocated share of Trail Mountain coal mine closure costs in annual base rates.
In April 2002, the Company established a regulatory asset for the full closure costs of the Trail Mountain coal mine with a five-year amortization period beginning April 2001. The resulting regulatory asset at March 31, 2003 was $27.9 million, net of amortization. The reestablishment of the regulatory asset increased accumulated depreciation to reverse the effects of the retirement of the mine and decreased coal inventory costs for the closure-related costs.
Merger Credits
In connection with the merger between the Company and ScottishPower (the “Merger”), the Company was required to provide benefits to ratepayers through fixed reductions in rates, or “Merger Credits.” The Company’s total obligation for Merger Credits was $133.4 million through the period ending December 31, 2004. In May 2002, the UPSC allowed the Company to offset all future Merger Credits, which amounted to $20.6 million, against deferred net power costs. On June 7, 2002, the IPUC approved a stipulation agreement that allowed the Company to offset future Merger Credits against deferred net power costs in the amount of $2.3 million. These actions in Utah and Idaho eliminated the Merger Credit revenue reductions of approximately $1.1 million per month, which were set to expire December 31, 2003. In February 2003, the Company recorded $6.0 million in liabilities and current expenses for Merger Credits that will be refunded to Oregon customers during the calendar year ending December 31, 2003. Through March 31, 2003, the Company had provided an aggregate of $64.2 million in Merger Credits and interest to its customers through reduced rates. At March 31, 2003, the Company was still obligated to provide $27.2 million of Merger Credits to customers in Oregon and Washington, through either bill credits or lower base rates.
Concluded Regulatory Actions
Oregon - On May 20, 2002, the OPUC approved a one-year $15.4 million overall rate increase effective June 1, 2002 for the Company’s Oregon customers to cover increases in power costs. This increase included an $18.7 million one-year surcharge relating to higher market costs for summer purchases and also resolved a number of other outstanding issues. The Industrial Customers of Northwest Utilities (the “ICNU”) requested limited reconsideration of the portion of this order relating to the lease of the West Valley, Utah generating units, involving $1.2 million of revenues annually. On August 8, 2002, the OPUC ordered this reconsideration. The ICNU, the Company and the OPUC staff have filed testimony. Opening briefs were filed April 11, 2003, reply briefs were filed on April 18, 2003 and an order from an administrative law judge is expected in summer 2003.
On May 13, 2003, the OPUC approved the Company’s request to begin amortizing its year ended March 31, 2002 costs under SB 1149 effective May 21, 2003. See Deregulation - Oregon below. The total costs of $5.2 million will be amortized on a straight-line basis over a five-year period, resulting in an annual rate increase of $1.1 million, or 0.1%. The amortization is subject to refund pending completion of an OPUC staff audit, which is scheduled to occur sometime in summer 2003.
Wyoming - On May 7, 2002, the Company filed a general rate case seeking a permanent $30.7 million, or 9.8%, increase in electricity rates for its Wyoming customers. On December 18, 2002, the Company revised the requested increase to $21.4 million. On January 17, 2003, the Company and the WPSC staff reached agreement on certain issues, which resulted in the Company revising its requested increase to $20.0 million, or 6.4%. The Company’s filing also included a request to recover the replacement power costs resulting from the outage of the Company’s Hunter No. 1 generating plant and a proposal for recovering deferred net power costs as discussed under Deferred Net Power Costs - Wyoming. Hearings in this case were held during January 2003. On March 6, 2003, the WPSC granted the Company a general rate increase of approximately $8.7 million, or 2.8%, and reduced the Company’s return on equity (“ROE”) from 11.0% to 10.8%. On April 4, 2003, the Company filed a request for rehearing to reconsider the Company’s request for recovery of power costs and the order’s adoption of the reduced ROE. The WPSC heard oral arguments on May 8, 2003 and denied the petition on May 30, 2003. See Deferred Net Power Costs - Wyoming below.
Idaho - On January 7, 2002, the Company filed a request with the IPUC to recover $38.0 million of deferred net power costs through a temporary 24-month surcharge on customer bills and to implement a new credit to pass through Residential Exchange Program benefits from two Bonneville Power Administration (“BPA”) settlement agreements. Pass-throughs of BPA credits do not affect Company earnings. In addition, the Company requested an adjustment of individual rate classes to more closely reflect the actual cost of service and proposed a rate mitigation policy to ensure that no customer class would receive a rate increase during the period in which the proposed surcharge is in effect. Parties to the proceeding agreed to a stipulation that would allow recovery of $25.0 million of the deferred net power costs. This recovery would be achieved through a $22.7 million power cost surcharge over two years plus termination of future Merger Credits in the amount of $2.3 million. The IPUC approved the stipulation on June 7, 2002. On June 28, 2002, the Company filed a petition asking the IPUC to reconsider the portion of its June 7, 2002 order requiring that the Company implement a one-time refund of $1.1 million relating to procedural issues in the form of a $20.00 per customer credit. Two individuals also filed petitions for reconsideration of several aspects of the IPUC’s order approving the stipulation. On July 24, 2002, the IPUC granted the Company’s petition for reconsideration and denied the petitions from the two other parties. Hearings on the reconsideration were held on September 10, 2002. On October 25, 2002, the IPUC ordered the one-time refund of $1.1 million to be reduced to $10,000.
Rate Actions Submitted for Regulatory Approval
Utah - The Company commenced a general rate case on May 15, 2003 based on the year ended March 31, 2003 and including known and measurable changes that will occur by January 1, 2004. The initial filing included a projected revenue requirement increase of $125.0 million that serves as a cap on the amount the Company can receive in the case. A subsequent detailed filing will be made in July 2003 identifying the final requested amount under this cap. If approved, the effective date of the increase would be January 1, 2004, although the Company would not collect any increase until April 1, 2004.
Oregon - On March 18, 2003, the Company filed a general rate case with the OPUC to recover rising costs, including insurance premiums, pension funding and health care. Similar cost trends are being experienced by many businesses across the country, including others in the utility sector. In addition, the filing requested an ROE of
11.5% to compensate the Company for general risks relating to the western U.S. utility environment, as well as some additional risks relating to utility industry restructuring in Oregon and multijurisdictional operations. The Company has requested an annual increase of $57.9 million, or 7.4%, in base rates to take effect in January 2004.
Wyoming - On May 27, 2003, the Company filed a general rate case with the WPSC to recover rising costs (including insurance premiums, pension funding and health care costs) and requested an increase in the ROE to 11.5% to compensate the Company for general risks relating to the western U.S. utility environment, as well as some additional risks relating to multijurisdictional operations. The Company has requested an increase of $41.8 million, or 13.1%, in base rates to take effect in March 2004.
California - On March 16, 2001, the Company filed an interim rate relief request with the California Public Utilities Commission (the “CPUC”) as Phase I in an effort to seek an increase in electricity rates for its customers in California. Subsequently, on December 20, 2001, the Company filed a general rate case to increase rates to compensatory levels. If approved by the CPUC, customer rates would increase 29.4% overall or $16.0 million annually, with an authorized return on equity of 11.5%. The annual amount requested incorporated the Phase I interim amount. On June 27, 2002, the CPUC approved an interim increase of $0.01 per kilowatt-hour (“kWh”) for certain customers, or approximately $4.7 million annually, or 8.8%, overall. This rate increase is subject to refund pending the outcome of the general rate case. On December 26, 2001, the California Office of Ratepayer Advocates (“ORA”) filed a motion to dismiss or defer the Company’s general rate case request. The Company responded to ORA’s motion on January 10, 2002. Following the expiration of the protest period, on February 25, 2002 the Company filed a motion for a prehearing conference to identify parties of record, establish a procedural schedule and address other issues. A discovery process began in mid-October 2002 and is ongoing. A prehearing conference was held on February 25, 2003. The CPUC and intervenor filed their testimony on May 23, 2003 for results of operations and are scheduled to file testimony on June 4, 2003 for cost allocation and rate design issues. Evidentiary hearings are scheduled for the week beginning June 23, 2003.
Deferred Net Power Costs
The Company filed applications in Utah, Oregon, Wyoming, Washington and Idaho seeking deferred accounting treatment for net power costs materially in excess of the power costs assumed in setting existing retail rates. The applications sought to defer these power cost variances beginning November 1, 2000. As discussed below, the Company received authorization to defer some power costs in excess of those included in retail rates in all the states where requests to do so were made. At March 31, 2003, the Company had remaining deferred power costs, net of amortization, of $137.8 million, including carrying costs.
Utah - In Utah, pursuant to the UPSC’s approval of deferred accounting treatment for replacement power costs resulting from the Hunter No. 1 outage, the Company filed on August 23, 2001 seeking permission to recover $103.5 million in replacement power costs over a 12-month period. On November 2, 2001, the UPSC allowed the Company to apply overcollections under an interim relief order from an earlier general rate case toward Hunter No. 1 replacement power costs on an interim basis, subject to refund. The amount of the interim relief was approximately $29.5 million annually.
Also in Utah, on September 21, 2001, the Company filed for permission to defer $109.0 million of net power costs above the level adopted in the UPSC’s rate order of September 10, 2001. These costs were incurred during the period May 9, 2001 through September 30, 2001. A hearing relating to the deferral was held on December 7, 2001.
On May 1, 2002, the UPSC issued an order approving a stipulation agreement regarding recovery of deferred and nondeferred net power costs referred to above. The order allowed the Company to continue collecting a $29.5 million annual surcharge until March 31, 2004 and to apply $34.7 million of revenue already collected (subject to refund) against deferred net power costs. The order also allowed the Company to offset deferred net power costs against a regulatory liability of $27.0 million relating to the gain from the May 2000 sale of Centralia. These offsets reduced the regulatory asset for deferred net power costs. In addition, the UPSC allowed the elimination of $20.6 million for the final two years of Merger Credits associated with the Merger. This action eliminated the Merger Credit revenue reduction of approximately $1.0 million per month that was set to expire December 31, 2003. The Company recorded additional deferred net power costs of $37.9 million and committed not to file a general rate case with a rate effective date prior to January 1, 2004, with certain exceptions. This order should allow the Company to recover a total of $147.0 million of deferred net power costs in Utah by March 31, 2004. One party opposed the rate spread provisions of the stipulation and filed a petition with the Utah Supreme Court for review of the order. The case has been assigned to the Utah Court of Appeals.
Oregon - The November 2000 Oregon deferred-accounting filing encompassed all power costs that vary from the level in Oregon rates during the period from November 1, 2000 through September 9, 2001, including costs to replace lost generation resulting from the Hunter No. 1 outage. On January 18, 2001, the Company requested a 3.0%, or $22.8 million, annual rate increase effective February 1, 2001, to provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon, over an amortization period. This 3.0% rate increase was the maximum allowed on an annual basis for the recovery of deferred costs under the Oregon statutes then in force. On February 13, 2001, the OPUC authorized deferred accounting for power costs of $22.8 million. On February 21, 2001, the OPUC authorized the 3.0% rate increase effective February 21, 2001, subject to refund, pending the outcome of a separate phase of the proceeding to examine the prudence of these expenditures.
The Company filed with the OPUC on September 20, 2001 to increase the level of recovery of deferred net power costs incurred to serve Oregon customers from the then current 3.0% amortization level, or $22.8 million awarded in February 2001, to 6.0%, the maximum allowed on an annual basis for recovery of deferred costs under a change in Oregon law. On October 22, 2001, the OPUC suspended the Company’s request pending the outcome of the prudence phase of the proceeding.
In December 2001, the Company and the OPUC staff reached a stipulation in the prudence phase of the Company’s deferred net power cost proceeding. The stipulation provided that the Company would be permitted to recover 85.0% of the deferred net power costs in Oregon, or about $131.0 million, plus carrying charges. The stipulation allowed the Company to seek increased recovery in the event the Company’s appeal of the Commission’s order limiting deferrals is successful. On July 18, 2002, the OPUC issued an order approving the stipulation and ending the prudence phase of the proceeding. On September 16, 2002, the Citizens’ Utility Board (the “CUB”) and the ICNU appealed this decision to the Marion County, Oregon Circuit Court. On October 11, 2002, the Company moved to intervene in this action. On March 26, 2003, the court issued a letter affirming the OPUC’s July 18, 2002 order. The ICNU and the CUB are likely to appeal to the Oregon Court of Appeals.
On August 6, 2002, the OPUC allowed the Company to increase the amortization level from 3.0% to 6.0%. The new rates were effective August 8, 2002. As of March 31, 2003, the Company had received $7.3 million in revenues as a result of this OPUC action. On August 19, 2002, the CUB and the ICNU filed a complaint with the OPUC, requesting that the OPUC require the Company to discontinue amortization of the additional 3.0%, challenging the approval itself based on procedural technicalities during the approval proceeding. On October 10, 2002, the Company filed a stipulation and tariff to allow the OPUC to reopen consideration of the increase in amortization of the deferred power costs from 3.0% to 6.0%. Subject to regulatory approval, the Company and the CUB have reached a stipulation agreement that the amortization level will remain at 6.0% and that the amounts amortized after the OPUC implements the tariff will be subject to refund. The refund will occur if an order or ruling is issued declaring all or a portion of these deferred costs imprudent or otherwise disallowing recovery. On October 14, 2002, the ICNU filed a response to the Company’s motion to implement the stipulation and proposed tariff. The ICNU’s response asked that the motion be denied as being procedurally improper. On December 10, 2002, the OPUC approved the voluntary stipulation and ordered the Company to file a tariff to implement the change. The tariff was approved by the OPUC with an effective date of January 22, 2003. Amounts subject to refund would include only those collections occurring after January 22, 2003. On February 7, 2003, the ICNU filed a motion requesting the OPUC to reconsider parts of its December 10, 2002 order relating to conclusions regarding the August 6, 2002 decision to increase the amortization level. The OPUC denied this motion on March 27, 2003.
In addition, the ICNU and the CUB have filed a complaint against the Company regarding the implementation of the August 2002 rate change. The ICNU and the CUB filed opening briefs on March 27, 2003. The Company and the OPUC filed their respective briefs on April 23, 2003. The CUB and the ICNU filed their joint reply brief on May 7, 2003.
While the 6.0% increase established the maximum annual rate to be recovered, the Company continued to pursue the total amount to be recovered through its October 2, 2001 appeals, to the Marion County, Oregon Circuit Court, mentioned above, of two OPUC orders. These orders established the mechanism to determine the amount of power costs to defer. On June 6, 2002, the Marion County, Oregon Circuit Court upheld the OPUC decision. On October 9, 2002, the Company appealed this decision to the Oregon Court of Appeals. On November 27, 2002, the Company filed its opening brief. The ICNU filed a response brief on January 14, 2003. The OPUC filed its brief on February 12, 2003, and the Company submitted its reply on March 5, 2003. Oral arguments have been set for July 17, 2003.
On September 7, 2001, the OPUC endorsed an agreement on deferral of net power costs after September 2001. From September 10, 2001 until May 31, 2002, the Company deferred the difference between 83.0% of actual net power costs and the new Oregon baseline power cost in tariffs. This mechanism was terminated on May 31, 2002, concurrent with the effective date of the settlement approved on May 20, 2002.
Wyoming - In Wyoming, on November 1, 2000, the Company filed for deferred accounting treatment of net power costs that vary from costs included in determining retail rates. On April 3, 2001, the Company filed an application to recover the excess power costs accrued during the period November 30, 2000 through January 31, 2001. On November 20, 2001, following an order by the WPSC dismissing the majority of the Company’s case based on a procedural issue, the Company requested authority to withdraw its deferred net power cost recovery filing without prejudice. On November 26, 2001, the WPSC granted this request. On May 7, 2002, the Company filed a request to recover replacement power costs of $30.7 million, resulting from the outage of the Company’s Hunter No. 1 generating plant and a proposal for recovering deferred net power costs authorized by the WPSC in December 2000, for $60.3 million. On March 6, 2003, the WPSC denied recovery of the Hunter No. 1 replacement power costs and the deferred net power costs. As a result, the Company wrote off the remaining net asset of $48.3 million, during the year ended March 31, 2003. The Company filed a petition for rehearing on the decision on April 4, 2003. The WPSC denied the petition on May 30, 2003.
Washington - On April 5, 2002, the Company filed a petition with the Washington Utilities and Transportation Commission (the “WUTC”) seeking authority to begin deferring net power costs in excess of those included in rates as of June 1, 2002 for later recovery in rates, either through a power cost adjustment mechanism or a limited rate adjustment. Under the rate plan approved by the WUTC in August 2000 at the conclusion of the Company’s last general rate case in Washington, there are limitations on the Company’s ability to request changes to general rates prior to January 2006. On October 18, 2002, the Company filed testimony and supporting documents, requesting deferral and recovery of excess power costs estimated at the time to be $17.5 million, including carrying charges, or, alternatively, to allow the Company to file a general rate case, which is currently restricted through December 2005. Based on actual data through December 2002, the deferral is expected to total $15.9 million. Hearings were held March 20-24, 2003, and a decision is expected by June 2003.
Idaho - On March 28, 2003, the Company filed an application with the IPUC to defer certain costs for regulatory purposes. The costs include approximately $2.5 million in excess costs incurred for forward electricity purchases made during the western energy crisis for summer 2002, as well as $3.5 million in federal and state tax audit determination payments made during the year ended March 31, 2003 as a result of Internal Revenue Service (the “IRS”) income tax audits. Other regulatory action in Idaho regarding deferred net power costs is described under Concluded Regulatory Actions - Idaho.
NOTE 3 - Derivative Instruments
On April 1, 2001, the Company adopted SFAS No. 133, as amended by SFAS No. 138 and numerous interpretations of the Derivatives Implementation Group (the “DIG”) that are approved by the FASB, collectively “SFAS No. 133.” Under SFAS No. 133, derivative instruments are recorded on the Consolidated Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings unless specific hedge accounting criteria are met. As contracts settle, they are recorded in the Statements of Consolidated Income (Loss).
The Company’s primary business is to serve its retail customers. The Company’s business is exposed to risks relating to, but not limited to, changes in certain commodity prices and counterparty performance. The Company enters into derivative instruments, including electricity, natural gas, oil and coal forward, option and swap contracts, and weather contracts to manage its exposure to commodity price and volume risk and to ensure supply, thereby attempting to minimize variability in net power costs for customers. The Company has policies and procedures to manage the risks inherent in these activities and a risk management committee to monitor compliance with the Company’s risk management policies and procedures.
In June 2002, the Company’s SFAS No. 133 contract assessments were updated to reflect the revised Issue C15, Normal Purchase and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity (“Issue C15”), guidance from the DIG, effective April 1, 2002. The revision to Issue C15 includes criteria to be considered for designation of a contract as a “capacity contract” and disallows the use of the exception for contracts that include a pricing element that is not clearly and closely related to the price of energy. The effects of adoption of the revised Issue C15 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $2.1 million unfavorable (net of a tax benefit of $1.3 million) on the Company’s Consolidated Statements of
Income (Loss). For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting the revised Issue C15 was $0.7 million favorable to the Company.
In October 2001, the DIG issued guidance under Issue C16, Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option Contract (“Issue C16”). The guidance disallows normal purchases and normal sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Issue C16 was effective April 1, 2002. The effects of adoption of Issue C16 at April 1, 2002 resulted in a cumulative effect of accounting change adjustment of $0.2 million favorable (net of tax of $0.2 million) on the Company’s Consolidated Statements of Income (Loss). For contracts qualifying for deferred accounting under SFAS No. 71, the effect of adopting Issue C16 was $126.5 million unfavorable to the Company. The applicable contracts pertain to the purchase and transport of natural gas. The costs of these contracts have been allowed in rates and the liability is, therefore, offset by a corresponding amount included in regulatory assets.
In June 2002, the EITF reached a partial consensus on Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (“EITF No. 02-3”). The partial consensus requires that all mark-to-market gains and losses arising from energy trading contracts (whether realized or unrealized) accounted for under EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (“EITF No. 98-10”) be presented on a net basis in the income statement and that the gross transaction volume be disclosed for those energy trading contracts that are physically settled. The net presentation requirement is effective beginning in the first interim period ending after July 15, 2002 and the disclosure requirements are effective for financial statements issued for fiscal years ending after July 15, 2002. Reclassification of all historical periods is required. The impact to the Company of adopting EITF No. 02-3 was immaterial.
The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in its business and activities and measure quantitative market risk exposure and to identify qualitative market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, the Company enters into various transactions, including derivative transactions, consistent with the Company’s risk management policy. The risk management policy governs energy purchase and sales activities and is designed for hedging the Company’s existing energy and asset exposures. The policy also governs the Company’s use of derivative instruments as well as its energy purchase and sales practices and describes the Company’s credit policy and management information systems required to effectively monitor such derivative use. The Company’s risk management policy provides for the use of only those instruments that have a close volume or price correlation with its portfolio of assets, liabilities or anticipated transactions. The risk management policy includes, as its objective, that such instruments will be primarily used for hedging and not for speculation.
The accounting treatment for the various classifications of derivative financial instruments under SFAS No. 133 is as follows:
Normal purchases and normal sales - The contracts that qualify as normal purchases and normal sales are excluded from the requirements of SFAS 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date.
Cash flow hedge - The unrealized gains and losses relating to these forward contracts are included in Accumulated other comprehensive income (loss), a component of shareholder’s equity. As the forward contracts are settled, the realized gains and losses are recorded on the Statements of Consolidated Income (Loss) as a component of Operating revenues or Purchased electricity and the unrealized gains and losses are reversed from Accumulated other comprehensive income (loss).
Trading activity - The unrealized gains and losses relating to these forward contracts are reflected in the Statements of Consolidated Income (Loss) as a component of Operating revenues. As the forward contracts are settled, the realized gains or losses are recorded and the unrealized gains and losses are reversed.
The Company has the following types of commodity transactions:
Coal, natural gas and other fuel purchase contracts - The Company enters into long-term and short-term coal, natural gas, diesel and other purchase contracts to provide adequate fuel resources to its electricity generation facilities and its other fuel needs. These contracts generally have limited optionality and require the Company to
take physical delivery of the commodity. These contracts are generally determined to be normal purchases and normal sales contracts under SFAS No. 133.
Weather derivatives - To a limited degree, the Company has executed contracts to hedge changes in hydroelectric generation due to variation in streamflows. The Company has also executed contracts to hedge changes in retail electricity demand due to abnormal ambient temperatures. These contracts are not exchange traded and settlement is based on climatic or other physical variables. Therefore, on a periodic basis, the Company estimates and records a gain or loss in earnings corresponding to the total expected future cash flow from these contracts in accordance with EITF No. 99-2, Accounting for Weather Derivatives. At March 31, 2003, the amount recorded for these contracts was a $3.5 million unrealized loss.
Wholesale electricity purchase and sales contracts - The Company makes continuing projections of future retail and wholesale loads and future resource availability to meet these loads based on a number of criteria, including historic load and forward market and other economic information and experience. Based on these projections, the Company purchases and sells electricity on a forward yearly, quarterly, monthly, daily and hourly basis to match actual resources to actual energy requirements and sells any surplus at the best available price. This process involves hedging transactions, which include the purchase and sale of firm capacity and energy under long-term contracts, forward physical or financial contracts for the purchase and sale of a specified amount of capacity or energy at a specified price over a given period of time (typically for one month, three months or one year) and forward purchases and sales of transmission service.
Upon adoption of SFAS No. 133 on April 1, 2001, all wholesale contracts were examined and it was determined that some of the forward contracts for the purchase or sale of wholesale electricity were considered to be derivatives based on the accounting guidance at that time. The effects of changes in fair value of certain derivative instruments entered into to hedge the Company’s future retail resource requirements are subject to regulation and, therefore, are deferred pursuant to SFAS No. 71. The Company requested and received deferred accounting orders for the effects of SFAS No. 133 as it relates to the change in fair value of long-term wholesale electricity contracts not meeting the definition of normal purchases and normal sales contracts. At the date of adopting SFAS No. 133, the Company recorded a net regulatory asset relating to the fair value of long-term wholesale contracts (which did not meet the definition of normal purchases and normal sales contracts) of $711.0 million. Short-term wholesale electricity purchase contracts not meeting the definition of normal purchases and normal sales contracts were designated as cash flow hedges to hedge the risk of changes in the cost of providing electricity to serve the Company’s retail load. These hedges were fully effective. At the date of adopting SFAS No. 133, the Company recorded an unrealized after tax gain of $617.2 million as a component of equity related to the fair value of short-term wholesale purchase contracts. Short-term wholesale electricity sales contracts not meeting the definition of normal purchases and normal sales contracts were marked to market through income, resulting in a $112.8 million after tax loss on adoption of SFAS No. 133.
In June 2001, the DIG issued guidance which provided that certain forward electricity purchase or sales agreements, including capacity contracts, could be excluded from the requirements of SFAS No. 133 by expanding the normal purchases and normal sales exclusion. The Company implemented this new guidance, on a prospective basis, beginning July 1, 2001. As a result, substantially all of the Company’s short-term wholesale electricity contracts were determined to meet the normal purchases and normal sales exclusion. No further market value changes were recognized for those excluded contracts and unrealized gains (losses) recorded in Other comprehensive income relating to the existing cash flow hedges as of July 1, 2001 were realized by September 30, 2002.
To mitigate exposure to credit risk, the Company has entered into master netting agreements with most of its significant trading counterparties. Unrealized gains and losses on contracts with parties under master netting agreements are presented net on the financial statements.
The following table summarizes the SFAS No. 133 movements for the year ended March 31, 2003:
Short-term contracts, without explicit or embedded optionality, are valued based upon the relevant portion of the forward market price curve. Contracts with explicit or embedded optionality and long-term contracts are valued by separating each contract into its component physical and financial forward, swap and option legs. Forward and swap legs are valued against the appropriate market curve. The optionality is valued using a modified Black-Scholes model approach or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward market price curve.
The forward market price curve is derived using daily market quotes from independent energy brokers, as well as direct information received from third-party offers and actual transactions executed by the Company. For contracts extending past 2006, the forward prices also include the use of a fundamentals model (cost-to-build approach), due to the limited information available past 2006. The fundamentals model is updated as warranted, at least quarterly, to reflect changes in the market.
As the FASB continues to issue interpretations, the Company may change the conclusions that it has reached and, as a result, the accounting treatment and financial statement impact could change in the future.
NOTE 4 - Related Party Transactions
There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PHI. Loans from the Company to ScottishPower or PHI are prohibited under the Public Utility Holding Company Act of 1935 (“PUHCA”). Loans from ScottishPower or PHI to PacifiCorp generally require state regulatory and Securities and Exchange Commission (the “SEC”) approval. Affiliate transactions with the Company are subject to certain approval and reporting requirements of the regulatory authorities.
The tables below detail the Company’s related party transactions and balances with other unconsolidated related parties.
(a)
Amounts due from affiliates are included in Other current assets on the Balance Sheet. The Company recharges to ScottishPower payroll costs and related benefits of employees working on international assignment to ScottishPower.
(b)
Amounts shown relate to activities of the Company and its subsidiaries with PHI and its subsidiaries. Expenses recharged reflect costs for support services to PHI and its subsidiaries.
(c)
These expenses and liabilities primarily represent payroll costs and related benefits of ScottishPower employees working for the Company.
(d)
Includes current portion of income taxes payable to PHI of $37.3 million and $5.3 million at March 31, 2003 and 2002, respectively. PHI is the tax paying entity for the consolidated group.
(e)
Short-term demand loans to PacifiCorp, in accordance with regulatory authorizations, are included in Notes payable and commercial paper.
(f)
These revenues represent wheeling revenues received from PPM.
(g)
These expenses represent primarily operating lease payments for a generation facility owned by a subsidiary of PPM, as discussed below.
(h)
PGHC, while a subsidiary of the Company, had a note receivable, interest receivable and related interest income from a directly owned subsidiary of ScottishPower.
Interest rates on related party borrowings approximate lender’s short-term borrowing cost or cost of capital as required by the relevant regulatory approval or exemption. The average rates for the years ended March 31, 2003, 2002 and 2001 were 1.7%, 3.0% and 6.3%, respectively.
In May 2002, the Company entered into a 15-year operating lease on an electric generation facility with West Valley Leasing Company LLC, a subsidiary of PPM, which was approved by the OPUC. The facility consists of five generation units each rated at 40 megawatts (“MW”) and is located in Utah. The Company, at its sole option, may terminate the lease, or purchase the facility, after three years and after six years. Scheduled lease payments are $3.0 million annually per unit. All of these units were operational at the end of July 2002.
NOTE 5 - Securities Available for Sale
The amortized cost and fair value of reclamation trust securities and other investments, included in Deferred charges and other assets on the Company’s Consolidated Balance Sheet, which are classified as available for sale, were as follows:
The quoted market price of securities is used to estimate their fair value.
The amortized cost and estimated fair value of debt securities at March 31, 2003 and 2002 by contractual maturities are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.
Proceeds, gross gains and gross losses from realized sales of available-for-sale securities using the specific identification method were as follows for the years ended March 31, 2003, 2002 and 2001:
NOTE 6 - Short-Term Debt and Borrowing Arrangements
The Company’s short-term debt and borrowing arrangements were as follows:
At March 31, 2003, the Company had $800.0 million of committed bank revolving credit agreements that became effective June 4, 2002; one facility for $500.0 million having a 364-day term plus a one-year term loan option, and the other facility for $300.0 million having a three-year term. The Company is currently seeking to replace the existing $500.0 million facility. While the Company believes the facility will be successfully replaced at costs marginally higher than the existing facility, no assurance can be given as to this outcome. As of March 31, 2003, these facilities were fully available and there were no borrowings outstanding.
NOTE 7 - Long-Term Debt
The Company’s long-term debt was as follows:
(a)
Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution control revenue bonds.
(b)
Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates.
First mortgage bonds of the Company may be issued in amounts limited by Electric Operations’ property, earnings and other provisions of the mortgage indenture. Approximately $12.0 billion of the eligible assets (based on original cost) of PacifiCorp are subject to the lien of the mortgage. Approximately $1.5 billion of first mortgage bonds were redeemable at the Company’s option at March 31, 2003 at redemption prices dependent upon U.S. Treasury yields. Approximately $654.5 million of pollution control revenue bonds were redeemable at the Company’s option at par at March 31, 2003. Subsidiary notes are redeemable at the subsidiary’s option at face amount. The remaining long-term debt was not redeemable at March 31, 2003.
On November 21, 2001, the Company issued $500.0 million of its 6.9% Series of First Mortgage Bonds due November 15, 2011 and $300.0 million of its 7.7% Series of First Mortgage Bonds due November 15, 2031. The Company used the proceeds for general corporate purposes, including the repayment of commercial paper and short-term debt borrowed from PGHC. The Company has an effective shelf registration statement for up to $1.1 billion of long-term debt, of which $800.0 million has been authorized to be issued by the applicable regulatory commissions, subject to certain conditions. Any such issuance would be subject to market conditions.
The annual maturities of long-term debt, capitalized lease obligations and redeemable preferred stock outstanding are $140.4 million, $243.8 million, $289.2 million, $243.0 million and $173.0 million for the years ending March 31, 2004 through 2008, respectively.
The Company made interest payments, net of capitalized interest, of $287.9 million, $246.7 million and $337.5 million for the years ended March 31, 2003, 2002 and 2001, respectively. This includes interest on leveraged lease debt that is netted against revenue on leveraged leases for the year ended March 31, 2001 and for nine months of the year ended March 31, 2002.
NOTE 8 - Environmental Costs, Mine Reclamation and Closure Costs
The Company’s mining operations are subject to reclamation and closure requirements. Reclamation and closure costs are estimated based on engineering studies. The Company monitors these requirements and periodically revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates. The Company expenses current mine reclamation costs. Costs for future reclamation are accrued using the units-of-production method such that estimated final mine reclamation and closure costs are fully accrued at completion of mining activities, except where the Company has decided to close a mine. The Company believes that it has adequately provided for its reclamation obligations, assuming ongoing operations of its mines. Total estimated final reclamation costs, including the Company’s and minority interest joint owners’ portions, for all mines with which the Company is involved was $215.0 million at March 31, 2003. These amounts are expected to be paid over the next 30 years.
The liabilities for environmental cleanup-related costs are generally recorded on an undiscounted basis. These liabilities are recorded in the Company’s Consolidated Balance Sheet in Deferred credits - Other at March 31, 2003 and 2002 as follows:
(a)
Amounts include the Company’s and minority interest joint owners’ portions of mine reclamation costs. Amount also includes $9.3 million and $12.2 million at March 31, 2003 and 2002, respectively, that is included in Current liabilities - Other.
(b)
Expected to be paid over 19 years. Amount also includes $1.3 million at March 31, 2003 and 2002 that is included in Current liabilities - Other.
(c)
Expected to be paid over 22 years.
The Company had trust fund assets included in Deferred Charges and Other of $68.5 million and $80.4 million at March 31, 2003 and 2002, respectively, relating to mine reclamation, including the minority interest joint owners’ portions.
NOTE 9 - Commitments and Contingencies
The Company follows SFAS No. 5, Accounting for Contingencies (“SFAS No. 5”), to determine accounting and disclosure requirements for contingencies. The Company operates in a highly regulated environment. Governmental bodies such as the FERC, the SEC, the IRS, the Department of Labor, the United States Environmental Protection Agency (the “EPA”) and others have authority over various aspects of the Company’s business operations and public reporting. Reserves are established when required in management’s judgment, and disclosures regarding litigation, assessments and creditworthiness of customers or counterparties, among others, are made when appropriate. The evaluation of these contingencies is performed by various specialists inside and outside of the Company.
Litigation - From time to time, the Company and its subsidiaries are parties to various legal claims, actions and complaints, certain of which involve material amounts. Although the Company is unable to predict with certainty whether it will ultimately be successful in these legal proceedings or, if not, what the impact might be, management currently believes that disposition of these matters will not have a materially adverse effect on the Company’s consolidated financial position or results of operations.
Environmental issues - The Company is subject to numerous environmental laws including the Federal Clean Air Act, as enforced by the EPA and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act of 1973, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act of 1980, relating to environmental cleanups; and the Resource Conservation and Recovery Act of 1976 and the Clean Water Act, relating to water quality. These laws could potentially impact future operations. Contingencies identified at March 31, 2003 principally consist of Clean Air Act matters, which are the subject of discussions with the EPA and state regulatory authorities. The Company expects that future costs relating to these matters may be significant and consist primarily of capital expenditures. The Company expects these costs will be included in rates and, as such, will not have a material adverse impact on the Company’s consolidated results of operations.
Hydroelectric relicensing - The Company’s hydroelectric portfolio consists of 53 plants with a plant net capability of 1,115.8 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. Nearly all of the Company’s hydroelectric projects are in some stage of relicensing under the FPA. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. The Company expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs, operations and maintenance expense and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. The Company has accumulated approximately $95.4 million in costs for ongoing hydroelectric relicensing that are reflected in assets on the Consolidated Balance Sheet. The Company expects that these and future costs will be included in rates and, as such, will not have a material adverse impact on the Company’s consolidated results of operations.
Swift power canal - On April 21, 2002, a failure occurred in the Swift power canal on the Lewis River in the state of Washington. The power canal and associated 70-MW hydroelectric facility (“Swift No. 2”) are owned by Cowlitz County Public Utility District (“Cowlitz”). It is anticipated that Cowlitz will repair Swift No. 2 in time for a calendar-year 2005 startup. The failure impacted, but did not damage, the Company-owned and operated 240-MW Swift No. 1 hydroelectric facility (“Swift No. 1”), which is upstream of the Swift power canal, by restricting both flow and generation flexibility (“shaping”). Repairs to the canal were completed and Swift No. 1 was returned to full capacity levels as of mid-July 2002 (though with limited shaping capabilities). Environmental, operations safety and fish mitigation issues remain to be resolved before full use of Swift No. 1 can resume. The Company continues to seek ways to mitigate any capacity and shaping limitations and to recover any business losses. The full impact of the Swift power canal outage and plans for repair of the Swift No. 2 facility are still being determined. The Company is seeking reimbursement from Cowlitz of the Company’s expenditures associated with the Swift No. 2 failure, including canal modifications and energy replacement costs. This event is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.
California and Enron Reserves - Beginning in summer 2000, market conditions in California resulted in defaults of amounts due to the Company from certain counterparties in California. In addition, in December 2001, Enron Corp. (“Enron”) declared bankruptcy and defaulted on certain wholesale contracts. The Company has provided reserves for its California exposures and its Enron receivable, net of the effect of applying the master netting agreement with Enron, in the aggregate amount of $14.3 million.
The Company is also a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California market during past periods of high energy prices. The Company established a reserve of $17.7 million for these refunds. The Company’s ultimate exposure to refunds is dependent upon any order issued by the FERC in this proceeding. See NOTE 2 - Regulation.
Guarantees - The Company is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. In November 2002, the FASB issued Interpretation No. 45, Accounting and Disclosure Requirements for Guarantees (“FIN No. 45”). FIN No. 45 requires disclosure of certain direct and indirect guarantees. Also, FIN No. 45 requires recognition of a liability at inception for certain new or modified guarantees issued after December 31, 2002. The adoption of FIN No. 45 in January 2003 did not have a material impact on the consolidated financial statements. The following indemnification obligations of the Company fall within the definitions of “indirect guarantees” under FIN No. 45.
On May 4, 2000, the Company and other joint owners completed the sale to Transalta of an electricity plant and coal mine located in Centralia, Washington. Under the agreement relating to the plant, the joint owners agreed to indemnify Transalta if it were to incur certain losses after the closing date and arising as a result of certain breaches of covenants. Under the agreement relating to the mine, the Company provided similar indemnity. The maximum indemnification obligation under these agreements, with respect to the Company, is limited to $556.0 million, less a deductible of 1.0% of the purchase price (approximately $1.0 million). No indemnity claims have been made to date.
In connection with the sale of the Company’s Montana service territory, the Company entered into a purchase and sale agreement with Flathead Electric Cooperative (“Flathead”) dated October 9, 1998. Under the agreement, the Company indemnified Flathead for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The indemnification has a cap of $10.0 million. Two indemnity claims relating to environmental issues have been tendered, but remediation costs for these claims, if any, are not expected to be material.
The Company believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote.
Construction - The Company has an ongoing construction program and, as a part of this program, substantial commitments have been made. The Company estimates spending $669.3 million, $679.7 million and $678.6 million for the years ending March 31, 2004, 2005 and 2006, respectively. At March 31, 2003, the Company had firm commitments for construction costs of $61.9 million.
Leases - The Company has certain properties under leases with various expiration dates and renewal options. Rentals on lease renewals are subject to negotiation. Certain leases provide for options to purchase at fair market value. The Company is also committed to pay all taxes, expenses of operation (other than depreciation) and maintenance applicable to the leased property.
Net rent expense for the years ended March 31, 2003, 2002 and 2001 was $7.3 million, $27.1 million and $8.7 million, respectively. During the year ended March 31, 2002, the Company leased a new generating turbine that added $24.7 million to rent expense. Future minimum lease payments under noncancellable operating leases are $5.5 million, $4.9 million, $4.5 million, $2.6 million and $1.4 million for 2004 through 2008, respectively, and $9.8 million thereafter.
Future minimum lease payments under capital leases are $3.4 million, $3.4 million, $3.5 million, $3.6 million and $3.7 million for the years ended March 31, 2004 through 2008, respectively, and $52.2 million thereafter. The amount of interest in those lease payments is $42.1 million.
Future minimum lease payments on the West Valley City, Utah lease discussed in NOTE 4 are $14.7 million, $14.7 million, $2.8 million, none and none for the years ending March 31, 2004 through 2008, respectively.
Long-term wholesale sales and purchased electricity contracts - The Company manages its energy resource requirements by integrating long-term firm, short-term and spot-market purchases with its own generating resources to economically dispatch the system (within the boundaries of the FERC requirements) and meet commitments for wholesale sales and retail load growth. The long-term wholesale sales commitments include contracts with minimum sales requirements of $313.4 million, $263.7 million, $223.3 million, $183.1 million and $141.6 million for the years ending March 31, 2004 through 2008, respectively and $1.1 billion thereafter. As part of its energy resource portfolio, the Company acquires a portion of its electricity through long-term purchases and/or exchange
agreements which require minimum fixed payments of $386.0 million, $363.9 million, $337.2 million, $366.3 million and $247.4 million for the years ending March 31, 2004 through 2008, respectively, and $2.3 billion thereafter.
Excluded from the minimum fixed annual payments above are commitments to purchase electricity from several hydroelectric projects under long-term arrangements with public utility districts. These purchases are made on a “cost of service” basis for a stated percentage of project output and for a like percentage of project annual costs (operating expenses and debt service). These costs are included in operations expense. The Company is required to pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced. The arrangements provide for nonwithdrawable electricity and the majority also provide for additional electricity, withdrawable by the districts upon one to five years’ notice. For the year ended March 31, 2003, such purchases approximated 2.4% of energy requirements.
At March 31, 2003, the Company’s share of long-term arrangements with public utility districts was as follows:
(a)
Annual costs in millions of dollars. Includes debt service totaling $6.5 million. The Company’s minimum debt service obligation was $8.5 million at March 31, 2003 and $8.0 million, $6.9 million, $9.2 million, $12.1 million and $12.3 million for the years ending March 31, 2004 through 2008, respectively.
The Company has a 4.0% interest in the Intermountain Power Project (the “Project”), located in central Utah. The Company and the city of Los Angeles have agreed that the City will purchase capacity and energy from Company plants equal to the Company’s 4.0% entitlement of the Project at a price equivalent to 4.0% of the expenses and debt service of the Project.
Short-term wholesale sales and purchased electricity contracts - At March 31, 2003, the Company had short-term wholesale forward sales commitments that included contracts with minimum sales requirements of $218.4 million, $122.7 million and $16.4 million for the years ended March 31, 2004, 2005 and 2006, respectively. At March 31, 2003, short-term forward purchase agreements require minimum fixed payments of $178.7 million, $68.6 million and $30.6 million for the years ending March 31, 2004, 2005 and 2006, respectively.
Fuel contracts - The Company has “take or pay” coal and natural gas contracts that require minimum fixed payments of $258.7 million, $231.9 million, $186.3 million, $154.2 million and $158.8 million for the years ending March 31, 2004 through 2008, respectively, and $932.0 million thereafter.
Resource management - The Company, as a public utility and a franchise supplier, has an obligation to manage resources to supply its customers. Rates charged to most customers are tariff rates authorized by regulatory agencies as discussed in NOTE 2.
NOTE 10 - Jointly Owned Facilities
At March 31, 2003, the Company’s participation in jointly owned facilities was as follows:
(a)
The Centralia plant was sold on May 4, 2000. The joint owners of the plant retained ownership in the Skookumchuck Dam and related facilities.
(b)
Includes kilovolt lines and substations.
(c)
Additionally, the Company has contracted to purchase the remaining 50.0% of the output of the plant.
(d)
Plant, inventory, fuel and decommissioning costs totaling $14.9 million relating to the Trojan Plant were included in regulatory assets at March 31, 2003.
(e)
Represents the excess of the cost of the acquired interest in purchased facilities over their original net book value.
Under the joint agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. The Company’s portion is recorded in its applicable operations, maintenance and tax accounts, which is consistent with wholly owned plants.
NOTE 11 - Guaranteed Preferred Beneficial Interests In Company’s Junior Subordinated Debentures
Wholly owned subsidiary trusts of the Company (the “Trusts”) have issued, in public offerings, redeemable preferred securities (“Preferred Securities”) representing preferred undivided beneficial interests in the assets of the Trusts, with liquidation amounts of $25.00 per Preferred Security. The sole assets of the Trusts are Junior Subordinated Deferrable Interest Debentures of the Company that bear interest at the same rates as the Preferred Securities to which they relate and certain rights under related guarantees by the Company.
Preferred Securities outstanding were as follows:
(a)
Amount is net of unamortized issuance costs of $6.2 million and $6.4 million at March 31, 2003 and 2002, respectively.
(b)
Amount is net of unamortized issuance costs of $4.0 million and $4.1 million at March 31, 2003 and 2002, respectively.
All of the 8.25% Cumulative Quarterly Income Preferred Securities, Series A, and 7.70% Trust Preferred Securities, Series B, were redeemable at the Company’s option at face amount at March 31, 2003.
NOTE 12 - Common and Preferred Stock
Common Stock - The Company has one class of common stock with no par value. A total of 750,000,000 shares were authorized, and 312,176,089 and 297,324,604 shares were issued and outstanding at March 31, 2003 and 2002, respectively.
On August 22, 2002, the Company’s Board of Directors (the “Board”) approved the issuance of up to 50 million additional shares of its common stock (“Shares”) to be sold, from time to time, to its direct parent, PHI, in such amounts and at such times as would be determined by the Company, subject to regulatory approval, which has been received. Issuance and sale of the Shares is subject to the receipt of cash for the Shares in an amount per share not less than the book value of the Shares at the end of the month prior to the date of the issuance. On December 19, 2002, the Company issued 14,851,485 Shares to PHI, receiving $150.0 million in cash proceeds, equal to $10.10 per share, the book value of the Shares at the end of November 2002. Proceeds were used to repay debt and for general corporate purposes.
Common Dividend Restrictions - ScottishPower is the sole indirect shareholder of the Company’s common stock. The Company is restricted from paying dividends or making other distributions without prior OPUC approval to the extent such payment or distribution would reduce the Company’s common stock equity below a specified percentage of its total capitalization. The percentage of total capitalization increases over time from 35.0% after December 31, 1999 to 40.0% after December 31, 2004. As of March 31, 2003, the minimum ratio was 38.0%. In addition, the Company must give the OPUC 30 days’ prior notice of any special cash dividend or any transfer involving more than 5.0% of the Company’s retained earnings in a six-month period. The Company is also subject to maximum debt to total capitalization levels under various debt agreements.
Under the PUHCA, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. The Company has received approval to pay dividends out of unearned surplus of the lesser of $900.0 million or the proceeds received from sales of nonutility assets. At March 31, 2003, $300.0 million was available for dividends out of unearned surplus.
Preferred Stock
Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. Upon voluntary or involuntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Any premium paid on redemptions of preferred stock is capitalized, and recovery is sought through future rates. Dividends on all preferred stock are cumulative.
Mandatory redemption requirements at stated value plus accrued dividends on No Par Serial Preferred Stock are as follows: 37,500 shares of the $7.48 series are redeemable on each June 15 from 2002 through 2006, with all shares outstanding on June 15, 2007 redeemable on that date. If the Company is in default in its obligation to make any future redemptions on the $7.48 series, it may not pay cash dividends on common stock.
The Company had $1.8 million and $1.9 million in preferred dividends declared but unpaid at March 31, 2003 and 2002, respectively.
NOTE 13 - Fair Value of Financial Instruments
(a)
Includes long-term debt classified as currently maturing, less capitalized lease obligations.
The carrying value of cash and cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments.
The fair value of the Company’s long-term debt and redeemable preferred stock has been estimated by discounting projected future cash flows, using the current rate at which similar loans would be made to borrowers with similar credit ratings and for the same maturities. Current maturities of long-term debt were included. The fair value of Preferred Securities was estimated using quoted market prices at March 31, 2003 and 2002.
NOTE 14 - Employment Benefit Plans
Retirement plans - The Company has pension plans covering substantially all employees. Benefits under the plan in the U.S. are based on the employee’s years of service and average monthly pay in the 60 consecutive months of highest pay out of the last 120 months, with adjustments to reflect benefits estimated to be received from Social Security. Pension costs are funded annually by no more than the maximum amount that can be deducted for federal income tax purposes. At March 31, 2003, plan assets were primarily invested in common stocks, bonds and U.S. government obligations.
Components of the net periodic pension benefit cost (income) and significant assumptions are summarized as follows:
(a)
Includes a contribution of $5.0 million to the PacifiCorp/IBEW Local 57 Retirement Trust Fund.
The change in the projected benefit obligation, change in plan assets and funded status are as follows:
(a)
Represents an adjustment to the obligation to provide benefits to employees who elected a special termination benefit in the year ended March 31, 2001 but revoked the election in the year ended March 31, 2003.
(b)
Represents an increase in the Company’s projected benefit obligation as a consequence of the ad hoc cost of living benefit increase for retired employees that was approved on March 13, 2002.
(c)
Represents a reduction in the Company’s projected benefit obligation and assets as a consequence of the transfer of obligation to a new plan being jointly administered by the International Brotherhood of Electrical Workers Local Union 57 and the Company. The new plan was created according to negotiated agreements between the Union and the Company. As a result of these agreements, the nature of the Company’s obligation changed from a fixed future benefit to a fixed percentage of pay commitment.
The PacifiCorp Retirement Plan and the Supplemental Executive Retirement Plan, together the “Plans,” currently have assets with a fair value that is less than the accumulated benefit obligation under the Plans primarily due to declines in the equity markets. As a result, the Company recognized a minimum pension liability in the fourth quarter of the year ended March 31, 2003. The liability adjustment was recorded as a noncash charge of $234.5 million to Regulatory assets, $43.8 million to Intangible assets and $2.2 million of Other comprehensive income, and did not affect the consolidated results of operations. The Company requested and received accounting orders from the regulatory commissions in Utah, Oregon and Wyoming to classify this charge as a regulatory asset instead of a charge to Other comprehensive income. The Company has determined that SFAS No. 87, Employers’ Accounting for Pensions (“SFAS No. 87”), and SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other than Pensions (“SFAS No. 106”) costs for the PacifiCorp Retirement Plan are currently recoverable in rates. This increase to Regulatory assets will be adjusted in future periods as the difference between the fair value of the trust assets and the accumulated benefit obligation changes.
Employee Savings and Stock Ownership Plan - The Company has an employee savings and stock ownership plan that qualifies as a tax-deferred arrangement under the Internal Revenue Code. Participating U.S. employees may defer up to 25.0% of their compensation, subject to certain statutory limitations. The Company matches 50.0% of employee contributions on amounts deferred up to 6.0% of total compensation with that portion vesting over five years. The Company makes an additional contribution equal to a percentage of the employee’s eligible earnings. These contributions are immediately vested. Company contributions to the Savings and Stock Ownership Plan were $17.4 million, $16.8 million and $18.0 million for the years ended March 31, 2003, 2002 and 2001, respectively, and represent amounts expensed for such periods.
Other Postretirement Benefits - Electric Operations provides health care and life insurance benefits through various plans for eligible retirees on a basis substantially similar to those who are active employees. The cost of postretirement benefits is accrued over the active service period of employees. The transition obligation represents the unrecognized prior service cost and is being amortized over a period of 20 years. The Company funds postretirement benefit expense through a combination of funding vehicles. The Company contributed $22.6 million for the year ended March 31, 2003 and nothing for the years ended March 31, 2002 and 2001. These funds are invested in common stocks, bonds and U.S. government obligations.
Components of the net periodic postretirement benefit cost and significant assumptions are summarized as follows:
The change in the accumulated postretirement benefit obligation (the “APBO”), change in plan assets and funded status are as follows:
(a)
Represents an adjustment to the obligation to provide benefits to employees who elected a special termination benefit in the year ended March 31, 2001, but revoked the election in the year ended March 31, 2003.
The assumed health care cost rate of increase gradually declines over four to seven years. The health care cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed health care cost trend rate by one percentage point would have increased the APBO as of March 31, 2003 by $25.9 million and the annual net periodic postretirement benefit costs by $4.2 million. Decreasing the assumed health care cost trend rate by one percentage point would have reduced the APBO as of March 31, 2003 by $22.6 million and the annual net periodic postretirement benefit costs by $1.9 million.
Postemployment Benefits - Electric Operations provides certain postemployment benefits to former and inactive employees and their dependants during the period following employment but before retirement. The costs of these benefits are accrued as they are incurred. Benefits include salary continuation, severance benefits, disability benefits and continuation of health care benefits for terminated and disabled employees and workers compensation benefits. Accrued costs for postemployment benefits were $5.2 million, $5.4 million and $8.7 million for the years ended March 31, 2003, 2002 and 2001, respectively.
Stock Option Incentive Plan - During 1997, the Company adopted a Stock Option Incentive Plan (the “Option Plan”). The exercise price of options granted under the Option Plan was 100.0% of the fair market value of the common stock on the day prior to the date of the grant. Stock options generally became exercisable in two or three equal installments on each of the first through third anniversaries of the grant date. The maximum exercise period under the Option Plan was 10 years. The Option Plan expired on November 29, 2001.
Upon completion of the Merger, all stock options granted prior to January 1999 became 100.0% vested. All outstanding stock options were converted into options to purchase ScottishPower ADS. Stock options to purchase ScottishPower ADS granted in connection with the Merger vest over the same number of years as stock options granted prior to the Merger.
The table below summarizes the stock option activity under the Option Plan.
Information with respect to options outstanding and options exercisable as of March 31, 2003 was as follows:
At March 31, 2002, options for 2,773,244 ScottishPower ADS were exercisable with a weighted average exercise price of $34.14 per share. The weighted average life of the options outstanding at March 31, 2002 was six years.
The fair value of options granted was $3.4 million and $0.4 million for the years ended March 31, 2002 and 2001, respectively. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used:
NOTE 15 - Income Taxes
The Company, as a wholly owned subsidiary, is included in a consolidated tax return. Under the terms of the Company’s tax sharing agreement, the Company’s provision for income taxes has been computed on the basis that it files a separate consolidated income tax returns with its subsidiaries. Amounts payable for federal and state taxes are remitted to the Company’s parent.
The Company’s combined federal and state effective income tax rate from continuing operations were 40.6%, 37.5% and 195.7% for the years ended March 31, 2003, 2002 and 2001, respectively.
The difference between taxes calculated as if the statutory federal tax rate of 35.0% was applied to income from continuing operations before income taxes and the recorded tax expense is reconciled as follows:
(a)
The Company did not have enough capital gains to offset the capital losses resulting from the sale of the Australian Operations in the year ended March 31, 2001. In accordance with U.S. federal income tax law, a portion of the excess capital loss was reattributed to another member of the federal consolidated tax return so that a benefit could be taken during the year ended March 31, 2001.
(b)
The Company has established, and periodically reviews, an estimated contingent tax reserve on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings.
The Company has concluded its settlement discussions with the IRS Appeals Division for the 1991, 1992 and 1993 tax years. A tax payment of $10.3 million was made upon settlement.
The examination of the Company’s 1994 through 1998 tax years was completed in July 2002. The IRS issued a Revenue Agent’s Report on July 31, 2002 for these years. Further, the IRS also issued a Revenue Agent’s Report on July 17, 2002 containing solely the issues agreed upon with the Company. The tax impact for the agreed upon issues is a liability of $40.9 million, for which a contingency tax reserve was previously provided. The Company has filed an administrative appeal for the unresolved issues and believes that final settlement and payment will not have a material adverse impact upon its consolidated financial position or results of operations.
The IRS started its examination of the 1999 and 2000 tax years in September 2002.
The provision for income taxes is summarized as follows:
The tax effects of significant items comprising the Company’s net deferred tax liability were as follows:
The Company made net income tax payments of $82.2 million and $83.1 million for the years ended March 31, 2003 and 2002, respectively, and received net income tax refunds of $63.9 million for the year ended March 31, 2001. The income tax payments include payments for current federal and state income taxes, as well as amounts paid in settlement of prior years’ liabilities as a result of income tax proceedings.
NOTE 16 - Discontinued Operations
The Company recognized $146.7 million of income in the year ended March 31, 2002 as a result of collecting a contingent note receivable relating to the discontinued operations of its former mining and resource development business, NERCO, Inc. (“NERCO”), which was sold in 1993. This note from the buyer was recorded at the date of the NERCO sale along with a corresponding deferred gain. Payments on this note were contingent upon the buyer receiving payment under a coal supply contract. The Company recognized this gain on a cost-recovery basis as payments were received from the buyer. In June 2001, the Company received $189.9 million, which was full payment of the remaining balance of the note and recognized the remaining balance of the deferred gain. Deferred tax expense of $36.4 million was recognized on the gain in June 2001.
NOTE 17 - Dispositions
On December 31, 2001, NAGP contributed all of the common stock of PacifiCorp to PHI. On February 4, 2002, PacifiCorp transferred all of the capital stock of PGHC to PHI. Accordingly, the results of operations and assets of PGHC are not included with those of PacifiCorp commencing February 4, 2002.
In October 2001, PFS sold its synthetic fuel operations. The sale resulted in a gain of approximately $11.3 million, pretax.
During the year ended March 31, 2002, the Company sold aircraft owned by subsidiaries of PFS. PFS received proceeds of approximately $36.0 million and recorded a $9.3 million pretax gain on the sale.
In connection with an internal restructuring of the Company, the Company transferred its interest in two nonutility energy companies to PHI in March 2001. The transfer price of $72.4 million was based on an estimate of market value and was financed through a loan from PGHC. The income and cash flow impacts from the two companies are included in the 2001 results, but the assets and liabilities associated with those businesses were removed from the consolidated balance sheet upon the transfer to PHI. No gain was recognized on the transfer. The difference between the transfer price and the book value was recorded as an adjustment to equity.
During the year ended March 31, 2001, PGHC completed the sale of its ownership of Powercor and its 19.9% interest in Hazelwood for approximately AUS $2.4 billion and approximately AUS $88.0 million, respectively. Powercor and Hazelwood represented all of the Australian Operations segment of the Company. The Company recorded an after tax loss on the sale of $197.7 million. In June 2001, upon resolution of a contingency under the provisions of the Powercor sale agreement, PGHC received further proceeds due from the sale that resulted in income of $27.4 million in 2002.
The gain (loss) on the sale of the Australian Operations for the years ended March 31, 2002 and 2001 was as follows:
(a)
The Company did not have enough capital gains to offset this capital loss and does not anticipate any further tax benefit from this loss.
In July 1998, the Company announced its intention to sell its California service territory, including its electric distribution assets. The Company and Nor-Cal Electric Authority (“Nor-Cal”) have engaged in detailed negotiations with a view toward executing a definitive sale agreement. Various factors have impeded consummation of the sale transaction. Most recently, in June 2002, the California county of Siskiyou filed a validation action in California Superior Court, challenging the authority of Nor-Cal to enter into such a transaction as proposed and alleging certain conflicts of interest among Nor-Cal and its advisors. The validation action is ongoing, but based on the foregoing factors, consummation of the sale is uncertain.
On May 4, 2000, the utility partners, including the Company, who owned the 1,340-MW coal-fired Centralia Power Plant sold the plant and the adjacent coal mine, which was wholly owned and operated by the Company, for approximately $500.0 million. The Company operated the plant and owned a 47.5% share. The Company recorded a loss of approximately $13.9 million on the sale.
All assets subject to disposition continued to be utilized in operations of the Company. As such, no separate accounting treatment or classification has been given to such assets.
NOTE 18 - Concentration of Customers
During the year ended March 31, 2003, no single retail customer accounted for more than 1.2% of the Company’s Electric Operations’ retail electric revenues and the 20 largest retail customers accounted for 13.0% of total retail electric revenues. The geographical distribution of the Company’s Electric Operations’ retail operating revenues for the year ended March 31, 2003 was Utah, 38.8%; Oregon, 31.9%; Wyoming, 12.7%; Washington, 8.2%; Idaho 5.9%; and California, 2.5%.
NOTE 19 - Segment Information
The Company previously operated in two business segments (excluding other and discontinued operations): Electric Operations and Australian Operations. The Australian Operations were sold in fall 2000. The Company currently has one segment, Electric Operations, which includes the regulated retail and wholesale electric operations in the six western states in which it operates. Australian Operations included the deregulated electric operations in Australia. Other Operations consisted of PFS, the western energy trading activities and other energy development businesses, as well as the activities of PGHC, including financing costs. PGHC and its subsidiaries, including PFS, were transferred to PHI in February 2002 as discussed in NOTE 1.
NOTE 20 - Subsequent Events
On April 17, 2003, the Board declared a dividend on common stock of 12.86 cents per share for a total of $40.1 million, payable on May 28, 2003.
In addition, certain regulatory actions that occurred after March 31, 2003 are described in NOTE 2.
SUPPLEMENTAL INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
(a)
Certain amounts from prior years have been reclassified to conform to the year ended March 31, 2003 method of presentation.
(b)
Short term and spot-market Wholesale sales averaged $188.89, $117.34, $34.15 and $25.17 per MWh in the first, second, third and fourth quarters of 2002, respectively.
(c)
Includes a $178.1 million gain on application of SFAS No. 133, effective April 1, 2001, and a $27.4 million gain on the sale of the Australian Operations.
See NOTE 16 for information regarding discontinued operations.
On March 31, 2003, there was one common shareholder of record.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
No information is required to be reported pursuant to this item.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of directors of the Company as of March 31, 2003.
Ian M. Russell, (50). Chairman of the Board of the Company. Director since November 1999.
Mr. Russell was appointed Chief Executive of ScottishPower in April 2001 and Chairman of PacifiCorp in January 2002. He previously served as Deputy Chief Executive of ScottishPower since November 1998, having previously been appointed Finance Director of ScottishPower in April 1994 and serving in both capacities from November 1998 to December 1999. In his present capacity, he is responsible for United Kingdom and U.S. operations.
Judith A. Johansen, (44). President and Chief Executive Officer of the Company. Director since December 2000.
Ms. Johansen was elected President and Chief Executive Officer on June 4, 2001 and served as Executive Vice President since December 1, 2000. She was Administrator and Chief Executive Officer of the BPA in Portland, Oregon from June 1998 to November 2000. From 1996 to May 1998, Ms. Johansen was vice president of business development with Avista Energy and from 1994 to 1996 was BPA’s Vice President for Generation Supply.
Barry G. Cunningham, (58). Senior Vice President of the Company since February 2002. Director since April 2002.
Mr. Cunningham was named PacifiCorp’s Senior Vice President of Generation in February 2002. Mr. Cunningham joined PacifiCorp in 1977 and served as Vice President in 1999 and as Assistant Vice President from 1998 to 1999.
Nolan E. Karras, (58). Director since February 1993.
Mr. Karras is President of The Karras Company, Inc., investment advisers, Roy, Utah, and has served in that capacity since 1983. He is Chief Executive Officer of Western Hay Company, Inc., a nonexecutive director of Scottish Power plc and Beneficial Life Insurance Company and is a Registered Principal for Raymond James Financial Services. He also served as a Member of the Utah House of Representatives from 1981 to 1990 and as Speaker of the Utah House of Representatives from 1989 to 1990. At present, Mr. Karras serves as the Chair of the Utah State Board of Regents.
William D. Landels, (60). Executive Vice President of the Company. Director since November 1999.
Mr. Landels has been with ScottishPower since 1985. He was elected Executive Vice President and Director of the Company effective upon the Merger with ScottishPower in November 1999. Prior to that, he served with the ScottishPower Group in various senior management roles, including as Managing Director of Manweb, Managing Director of Energy Supply and Managing Director of Distribution.
Andrew N. MacRitchie, (39). Executive Vice President of the Company. Director since May 2000.
Mr. MacRitchie was elected Executive Vice President in May 2000. Mr. MacRitchie has been with ScottishPower since 1986. He served as the Transition Director for the PacifiCorp Merger from December 1999 to May 2000. He served as ScottishPower’s U.S. Chief of Staff on the PacifiCorp Merger from December 1998 to December 1999, and, prior to that, he served as Manager, Business and Organizational Development.
Michael J. Pittman, (50). Senior Vice President of the Company. Director since May 2000.
Mr. Pittman was elected a Senior Vice President of the Company in May 2000. He formerly served as a Vice President of the Company from May 1993. Mr. Pittman is Chair of the PacifiCorp Foundation for Learning.
A. Richard Walje, (51). Senior Vice President of the Company. Director since July 2001.
Mr. Walje was named PacifiCorp’s Vice President and Chief Information Officer in May 2000 and Senior Vice President of Corporate Business Services in May 2001. Mr. Walje also served as PacifiCorp’s Vice President for Transmission and Distribution Operations and Customer Service from 1998 to 2000. Mr. Walje also serves on the PacifiCorp Foundation Board of Directors.
Matthew R. Wright, (38). Executive Vice President of the Company. Director since July 2001.
Mr. Wright was appointed Executive Vice President of Power Delivery in January 2002. Mr. Wright served as Senior Vice President of Strategy and Planning in 2001 and as Vice President of Regulation from 1999 to 2001. Prior to joining PacifiCorp, Mr. Wright served the ScottishPower group in various management positions since 1995.
The following is a list of the executive officers of the Company not named above. There are no family relationships among the executive officers of the Company. Officers of the Company are normally elected annually.
Richard D. Peach, (39). Chief Financial Officer since January 2003. Director since May 2003.
Mr. Peach was named the Company’s Chief Financial Officer effective January 2003. Mr. Peach served as Senior Vice President of Finance since March 2002. Prior to his appointment as Chief Financial Officer, Mr. Peach was also Group Controller for ScottishPower since March 2000 and served in a various management positions since 1995. In May 2003, Mr. Peach was named a Director of PacifiCorp.
Donald N. Furman, (46). Senior Vice President since July 2001.
Mr. Furman was named PacifiCorp’s Senior Vice President of Regulation and Government Affairs in July 2001. Mr. Furman served as Vice President of Transmission and Business Development from 1997 to 2001 and as President of PPM from 1995 to 1997.
Andrew P. Haller, (51). Senior Vice President, General Counsel and Corporate Secretary since December 2000. Director since May 2003.
Mr. Haller was chief executive for the U.S. operations of Kvaerner Process prior to joining PacifiCorp. Mr. Haller began his career with Kvaerner in 1987, and held various senior counsel and management positions, including Senior Vice President and General Counsel-Americas. From 1998 to 1999, he served as the Associate General Counsel for the parent company, Kvaerner ASA, in its U.S. corporate headquarters. In May 2003, Mr. Haller was named a Director of PacifiCorp.
Robert A. Klein, (age 55), Senior Vice President, since August 2001.
Mr. Klein has served as the Company’s Senior Vice President of Commercial and Trading since August 2001 and was named ScottishPower’s Energy Risk Director in March 2003. Prior to joining the Company in December 2000, Mr. Klein served as Senior Vice President and General Manager of Equitable Resources’ deregulated marketing business from 1998 to 1999 and as Director of Corporate Risk for Coral Equity from 1997 to 1998.
Robert Moir, (53). Senior Vice President since February 2002.
Mr. Moir was named PacifiCorp’s Senior Vice President of Distribution in February 2002. Mr. Moir served as Vice President since May 2000. Mr. Moir has been with ScottishPower since 1967.
Bruce N. Williams, (44). Treasurer since February 2000.
Mr. Williams has been with PacifiCorp since 1985. Prior to being elected Treasurer, he served as Assistant Treasurer of the Company.
In addition to its Guide to Business Conduct, which is distributed to all employees and provides a basis for employee ethical standards and conduct, the Board has approved and implemented a “Code of Ethics for Principal Officers,” as discussed in Section 406 of the Sarbanes-Oxley Act of 2002.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
BOARD REPORT ON EXECUTIVE COMPENSATION
INTRODUCTION
The Board submits this Board Report on Executive Compensation, which outlines the compensation provided to its executive officers. The Remuneration Committee of the Board of Directors of ScottishPower (the “Remuneration Committee”), assisted by its outside advisors, has the responsibility to recommend compensation levels and executive compensation plans for officers of the Company and to administer executive compensation plans as authorized. The Remuneration Committee is composed entirely of independent, nonemployee directors. The Remuneration Committee must approve any stock-based compensation. The following describes the components of the Company’s executive compensation program and the basis upon which recommendations and determinations were made for the period from April 1, 2002 to March 31, 2003.
COMPENSATION PHILOSOPHY
The Company’s philosophy is that executive compensation should be linked closely to corporate performance and increases in shareholder value. The Company’s compensation program has the following objectives:
(i)
provide competitive total compensation that enables the Company to attract and retain key executives;
(ii)
provide variable compensation opportunities that are linked to Company and individual performance; and
(iii)
establish an appropriate balance between incentives focused on short-term objectives and those encouraging sustained earnings performance and increases in shareholder value.
Qualifying compensation for deductibility under Internal Revenue Code (“IRC”) Section 162(m) is one of the factors the Remuneration Committee considers in designing its incentive compensation arrangements. IRC Section 162(m) limits to $1.0 million the annual deduction by a publicly held corporation of compensation paid to any executive, except with respect to certain forms of incentive compensation that qualify for exclusion. Although it is the Board’s intent to design and administer compensation programs that maximize deductibility, the Remuneration Committee views the objectives outlined above as more important than compliance with the technical requirements necessary to exclude compensation from the deductibility limit of IRC Section 162(m). Nevertheless, the Remuneration Committee believes that nearly all compensation paid to the executive officers for services rendered in the year ended March 31, 2003 is fully deductible.
COMPENSATION PROGRAM COMPONENTS
In the year ended March 31, 2003, the Remuneration Committee focused its market-based comparisons on the relevant industry for each officer. The Remuneration Committee utilized the U.S. electric utility industry as its exclusive basis for market comparison for positions with a principal focus on electric operations. For positions with a corporate-wide focus, the Remuneration Committee used a weighting of approximately 67.0% general industry and 33.0% electric utility industry. In all cases, compensation is targeted at market median levels, with an assumption that total compensation greater than market median, in any specific time period, anticipates that Company performance exceed the median performance of peer companies.
The Company’s executive compensation programs have three principal elements: Base Salary, Annual Incentive Compensation and Long-Term Incentive Compensation, as described below.
Base Salaries
Base salaries and target incentive amounts are reviewed for adjustment at least annually based upon competitive pay levels, individual performance and potential, and changes in duties and responsibilities. Base salary and the incentive target are set at a level such that total annual compensation for satisfactory performance would approximate the midpoint of pay levels in the comparison group used to develop competitive data. In the year ended March 31, 2003, the base salary of each executive officer was increased, based on market analysis, to reflect competitive market changes, individual performance and changes in the responsibilities of some officers.
Annual Incentive Compensation
All PacifiCorp officers (except ScottishPower executives on international assignment), including those listed in the Summary Compensation Table, participated in the Company’s Annual Incentive Program. Performance goals were based on PacifiCorp performance, operational performance and individual performance, and may include ScottishPower performance based on the level, influence and impact of the officer.
Long-Term Incentive Compensation
Historically, the Board annually reviewed and approved grants of restricted stock and stock options under the Stock Incentive Plan. However, on November 29, 2001, the Stock Incentive Plan expired. Restricted stock and stock option awards made under the Stock Incentive Plan on or before April 24, 2001 will continue to remain outstanding until such time as they become vested or expire.
Restricted stock awards under the Stock Incentive Plan are subject to terms, conditions and restrictions determined by the Board to be consistent with the plan and the best interests of the shareholders. In general, restricted stock awards vest over a four-year period from the date of grant, subject to compliance with the stock ownership and other terms of the grant. The restrictions include stock transfer restrictions and forfeiture provisions designed to facilitate the participants’ achievement of specified stock ownership goals. Participants are also required to invest their own personal resources in ScottishPower ADS or ordinary shares (“Ordinary Shares”) in order to meet the vesting requirements associated with these grants. The Summary Compensation Table below shows the grants of restricted stock made to the listed executive officers under the Stock Incentive Plan in the years ended March 31, 2002 and 2001.
On April 25, 2002, the Remuneration Committee approved grants of stock options and performance share awards under ScottishPower’s Executive Share Option Plan 2001 (“ExSOP”) and the Long-Term Incentive Plan (“LTIP”), respectively, for a select group of executive officers and other senior managers. See Long-Term Incentive Plan below. Two separate ExSOP grants were awarded on May 2, 2002 to senior managers of the Company. The first grant is a standard grant, which has a three-year vesting schedule starting on the first anniversary of the grant date, and the second grant is a one-time enhanced grant, which has a three year cliff vesting based on performance.
All stock options awarded to officers and senior management of the Company in the years ended March 31, 2003, 2002 and 2001 are nonstatutory, nondiscounted options with a three-year vesting requirement and a 10-year term from the date of the grant.
SCOTTISHPOWER EXECUTIVE OFFICERS ON INTERNATIONAL ASSIGNMENT
Executive officers who are international assignees from ScottishPower are maintained on their home country remuneration program. The compensation for these individuals is determined by the Remuneration Committee. ScottishPower’s compensation philosophy and components are the same as PacifiCorp’s except as noted below.
Annual Performance-Related Bonus
Executives on international assignment participate in ScottishPower’s performance-related pay schemes. All payments under the schemes are nonpensionable and noncontractual and are subject to the approval of the Remuneration Committee.
The fiscal 2003 scheme for executive officers provided a bonus of up to a maximum of 60.0% of salary determined by PacifiCorp performance, operational performance and individual performance.
Long-Term Incentive Plan
The LTIP links the rewards closely between management and shareholders, and focuses on long-term corporate performance. The award will vest only if the Remuneration Committee is satisfied that certain threshold performance measures are achieved. The number of shares that actually vest is dependent upon the Company’s comparative Total Shareholder Return performance, over a three-year performance period. ExSOP grants to ScottishPower executives at PacifiCorp on international assignment are subject to the performance criterion that the average annual percentage increase in the ScottishPower’s earnings per share (“EPS”) be at least 3.0% (adjusted for any increase in the Retail Price Index). This criterion is assessed at the end of the third financial year, the first year being the financial year starting immediately before the date of the grant. If not satisfied on the third anniversary, the
criterion may be retested, from the same base, on the fourth and fifth anniversaries of the grant. Unvested options lapse at the fifth anniversary.
COMPENSATION OF THE CHIEF EXECUTIVE OFFICER
On June 4, 2001, Ms. Johansen assumed responsibilities as Chief Executive Officer and President of PacifiCorp. Ms. Johansen has a base salary of $500,000 and a maximum annual incentive award of 75.0% of base salary. She is also eligible for participation in the LTIP and ExSOP.
The Board Report on Executive Compensation detailed above has been submitted by all the members of the Board as listed in ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY.
EXECUTIVE COMPENSATION
The following table sets forth information concerning compensation for services in all capacities to the Company for the years ended March 31, 2003, 2002 and 2001 of those persons who were the Chief Executive Officer of the Company during any portion of the year ended March 31, 2003 and the four other most highly compensated executive officers of the Company who were serving as executive officers at the end of the last completed fiscal year.
Summary Compensation Table
(a)
May include amounts deferred pursuant to the Compensation Reduction Plan, under which key executives and directors may defer receipt of cash compensation until retirement or a preset future date. Amounts deferred are invested in ScottishPower ADS or a cash account on which interest is paid at a rate equal to the Moody’s Intermediate Corporate Bond Yield for AA-rated Public Utility Bonds.
(b)
Salary includes foreign housing benefits paid to Mr. Landels. These amounts were $99,285.00, $126,610.58 and $66,322.75 for the years ended March 31, 2003, 2002 and 2001, respectively.
(c)
Amounts in this column for the year ended March 31, 2003 include a promotion bonus in the amount of $41,556 for Ms. Johansen. Amounts in this column for the year ended March 31, 2002 include a retention bonus in the amount of $125,610 and $104,000 for Messrs. Pittman and Walje, respectively. Amounts in this column for the year ended March 31, 2001 include special bonuses and hire-on bonuses. These amounts are $150,000 and $110,000 for Ms. Johansen and Mr. Haller, respectively.
(d)
On March 31, 2003, the aggregate value of all restricted stock holdings, based on the market value of ScottishPower ADS at March 31, 2003, without giving effect to the diminution of value attributed to the restrictions on such stock, was $146,939, $116,951, $46,900 and $46,900, for Ms. Johansen and Messrs. Haller, Pittman and Walje, respectively. The aggregate number of restricted share holdings was 6,125, 4,875, 1,955 and 1,955 for Ms. Johansen and Messrs. Haller, Pittman and Walje, respectively. Regular quarterly dividends are paid on the restricted stock. Participants may defer receipt of restricted stock awards to their stock accounts under the Compensation Reduction Plan.
(e)
Amounts for the year ended March 31, 2003 represent the number of ADS option shares awarded under the ScottishPower ExSOP during the year ended March 31, 2003, except for Mr. Landels’ options, which are for ScottishPower Ordinary Shares. Amounts shown for the years ended March 31, 2002 and 2001 represent the number of ADS options awarded under the PacifiCorp Stock Incentive Plan.
(f)
Represents the dollar value of restricted stock shares awarded under the PacifiCorp Stock Incentive Plan that vested and were distributed to the named officer.
(g)
Represents the number of ScottishPower ADS, except for Mr. Landels, which are Ordinary Shares, contingently granted in 2003, 2002 and 2001 that can be earned under the terms of the ScottishPower LTIP.
(h)
Amounts shown for the year ended March 31, 2003 include:
(i)
Company contributions to the PacifiCorp K Plus Employee Savings and Stock Ownership Plan for each of Ms. Johansen and Messrs. Haller, Pittman and Walje were $11,487, $11,613, $9,450 and $9,905, respectively.
(ii)
Portions of premiums on term life insurance policies that PacifiCorp paid for Ms. Johansen and Messrs. Haller, Pittman and Walje in the amounts of $683, $425, $410 and $373, respectively. These benefits are available to all employees.
(iii)
This column also includes vehicle allowances paid to Ms. Johansen and Messrs. Landels, Haller, Pittman and Walje in the amounts of $9,000, $12,000, $9,000, $9,000, and $9,000, respectively.
(iv)
During each of the years ended March 31, 2003, 2002 and 2001, Mr. Landels purchased 411 shares under the ScottishPower Employee Share Ownership Plan. Under the terms of the plan, ScottishPower matches the number of shares bought by the individual. The value of the 411 shares bought by ScottishPower for Mr. Landels was $2,321 for each of the years ended March 31, 2003, 2002 and 2001.
(v)
Includes additional international assignment payments of $71,141, $112,150 and $92,709 for the years ended March 31, 2003, 2002 and 2001, respectively, for cost of living and foreign service premium, according to the terms of Mr. Landels’ contract.
Option Grants in Last Fiscal Year
(a)
All options are for ScottishPower ADS, except Mr. Landels’ options, which are for ScottishPower Ordinary Shares. One ScottishPower ADS is equal to four ScottishPower Ordinary Shares. All options awarded were ScottishPower ExSOP grants, dated May 2, 2002.
(b)
All standard options become exercisable for one-third of the shares covered by the option on each of the first three anniversaries of the grant date and all enhanced options become exercisable after the third anniversary of the grant date. Mr. Landels’ options can be exercised only between the third and tenth anniversaries of the date of the grant, and exercise is subject to the satisfaction of a performance condition, that being a predetermined level of EPS growth over a maximum of a three-year performance period from the date of the grant.
Aggregated Option Exercises in 2003 and Year-End Option Values
(a)
All options are for ScottishPower ADS, except Mr. Landels’ options, which were for ScottishPower Ordinary Shares, and include options granted under the PacifiCorp Stock Incentive Plan and the ExSOP.
Severance Arrangements
The Company’s Executive Severance Plan provides severance benefits to certain executive-level employees who are designated by the Board, including the executive officers named in the Summary Compensation Table (other than Mr. Landels). Severance benefits are payable for voluntary terminations as a result of a “material alteration in position” that has a detrimental impact on the executive’s employment or involuntary terminations (including a Company-initiated resignation) for reasons other than cause. A “material alteration in position” includes:
•
a material reduction in the scope of the executive’s duties and responsibilities or authority; or
•
any reduction in base pay or a reduction in annualized base salary and target annual bonus of at least 15.0%, if the change is not due to a general reduction unrelated to the change in assignment.
The Executive Severance Plan also provides enhanced severance benefits in the event of certain terminations during the 24-month period following a qualifying change-in-control transaction. Executives designated by the Board are eligible for change-in-control benefits resulting from either a Company-initiated termination without “cause” or a resignation generally within two months after a “material alteration in position.” For this purpose, “cause” means the
executive’s gross misconduct or gross negligence or conduct that indicates a reckless disregard for the consequences and has a material adverse effect on the Company or its affiliates, and “material alteration in position” means:
•
a change in reporting relationship to a lower level;
•
a material reduction in the scope of duties and responsibilities or in authority;
•
relocation of work location to an office more than 100 miles from the executive’s office or more than 60 miles from the executive’s home; or
•
a “material reduction in compensation,” which includes any reduction in annualized base salary or a reduction in the annualized base salary and target bonus opportunity combined of at least 15.0%, if the change is not due to a general reduction unrelated to the change in assignment.
If qualified for the enhanced severance benefits, an executive would receive severance pay in an amount equal to either two, two and one-half or three times the “annual cash compensation” of such executive, depending on the level set by the Board. “Annual cash compensation” is defined as annualized base salary, target annual incentive opportunity and annualized auto allowance in effect on the earlier of a material alteration or termination, whichever is greater. The Company is required to make an additional payment to compensate the executive for the effect of any excise tax. The executive would also receive continuation of subsidized health insurance from six to 24 months depending on length of service and a minimum of 12 months’ executive-level outplacement services.
The Executive Severance Plan does not apply to a termination for reasons of normal retirement, death or total disability or to a termination for cause or a voluntary termination other than as specified above. Except in the event of a change-in-control, the definition of cause is determined by the Company in its discretion and by the Board in the event of an appeal by the employee.
Other than in connection with a change in control, executives named in the Summary Compensation Table (other than Mr. Landels) are eligible for a severance payment equal to one or two times the executive’s total cash compensation, six months of health insurance benefits and outplacement benefits. For this purpose, total cash compensation includes annualized base salary, the target annual incentive opportunity and the annualized auto allowance in effect on the earlier of a material alteration or termination.
Retirement Plans
The Company has adopted noncontributory defined benefit retirement plans for its employees, other than employees subject to collective bargaining agreements that do not provide for coverage. Certain executive officers, including the executive officers named in the Summary Compensation Table, other than Mr. Landels, are also eligible to participate in the Company’s nonqualified supplemental executive retirement plan. The following description assumes participation in both the retirement plans and the supplemental plan. Participants receive benefits at retirement payable for life based on length of service with the Company and average pay in the 60 consecutive months of highest pay out of the last 120 months, and pay for this purpose would include salary and annual incentive plan payments reflected in the Summary Compensation Table above. Benefits are based on 50.0% of final average pay plus up to an additional 15.0% of final average pay depending upon whether the Company meets certain performance goals set for each fiscal year by the Board. Participants may also elect actuarially equivalent alternative forms of benefits. Retirement benefits are reduced to reflect Social Security benefits as well as certain prior employer retirement benefits. Participants are entitled to receive full benefits upon retirement after age 60 with at least 15 years of service. Participants are also entitled to receive reduced benefits upon early retirement after age 55 or after age 50 with at least 15 years of service and five years of participation in the supplemental plan.
The following table shows the estimated annual retirement benefit payable upon retirement at age 60 as of March 31, 2003. Amounts in the table reflect payments from the retirement plan and the supplemental plan combined.
Estimated Annual Pension At Retirement (a)
(a)
The benefits shown in this table assume that the individual will remain in the employ of the Company until retirement at age 60, that the plans will continue in their present form and that the Company achieves its performance goals under the supplemental plan in all years.
(b)
The number of credited years of service used to compute benefits under the plans for Ms. Johansen and Messrs. Haller, Walje and Pittman are two, two, 17 and 23, respectively.
Retention Agreements
To retain executives who would otherwise have had the right to resign for any reason between 12 and 14 months following the ScottishPower Merger and qualify for the enhanced change-in-control supplemental retirement benefits, the Company entered into retention agreements with qualifying executives (Messrs. Pittman and Walje). Those retention agreements provided for the same enhanced supplemental retirement benefits if the qualifying executives satisfied the retention criteria. Qualifying executives were required to waive their rights to unilaterally resign and receive the enhanced supplemental retirement benefits, but they are now eligible to receive these same enhancements since they have continued employment through the established retention date of December 1, 2002.
These retention agreements also require qualifying executives to waive any rights to executive severance benefits, which they may have otherwise claimed due to material alterations in their positions as of the date of the retention agreement. Unless there is a subsequent “involuntarily termination” or “material alteration” in position as defined in the Severance Plan, this waiver of severance benefits applies to these executives through November 28, 2004. The executives’ waiver of severance benefits was in exchange for the enhanced supplemental retirement benefits described above, retention bonuses determined individually in the Company’s discretion for each executive and special stock option awards that vest over a three-year retention period at 25.0% for each of the first two years and 50.0% in the third year.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All common shares of the Company are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland. The Company has no compensation plans under which equity securities of the Company are authorized to be issued.
The following table sets forth certain information as of March 31, 2003 regarding the beneficial ownership of ScottishPower Ordinary Shares by (1) each of the executive officers named in the Summary Compensation Table under ITEM 11. EXECUTIVE COMPENSATION above, (2) each director of the Company as detailed under ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT and (3) all executive officers and directors as a group. As of March 31, 2003, each of the directors and executive officers identified above and all directors and executive officers of the Company as a group owned less than 1% of the outstanding Ordinary Shares of ScottishPower.
(a)
Includes ownership of (i) shares held by family members even though beneficial ownership of such shares may be disclaimed, (ii) shares held for the account of such persons pursuant to the Company’s Compensation Reduction Plan and the Company’s K Plus Savings and Stock Ownership Plan and (iii) shares granted and vested or unvested shares for which the individual has voting but not investment power under the Company’s Stock Incentive Plan.
(b)
Options granted in ScottishPower ADS under the Company’s Stock Incentive Plan have been converted into options in Ordinary Shares in the above table. One ADS equates to four Ordinary Shares.
On May 10, 2003, LTIP awards in the amount of 49,833, 34,971, 21,936, 31,395 and 28,779 were awarded to Ms. Johansen and Messrs. Landels, Haller, Pittman and Walje, respectively. Options under the ExSOP in the amount of 61,475, 58,285, 13,530, 38,729 and 17,751 were awarded to Ms. Johansen and Messrs. Landels, Haller, Pittman and Walje, respectively. All awards were for ADS, except for Mr. Landels, which were for Ordinary Shares.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
RELATED TRANSACTIONS
According to the terms of Andrew Haller’s offer letter, the Company made a $200,000 loan to Mr. Haller on May 21, 2001 for the repayment of obligations to his former employer. The promissory note documenting such loan, as amended, includes the following terms: (i) initial payment of $35,000 was due on December 1 and paid on December 31, 2001; (ii) a second payment of $32,988.56 was due and paid on June 30, 2002; (iii) the remaining $143,855.55 is payable in five equal payments of $32,988.56 on June 30 in each year from 2003 to 2006. As of March 31, 2003, the outstanding loan balance was $148,974.29, including accrued interest.
All other information required by this item is set forth in ITEM 11. EXECUTIVE COMPENSATION and in ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT above.
ITEM 14.
ITEM 14.
CONTROLS AND PROCEDURES
(a)
The principal executive officer and principal financial officer of the Company have evaluated the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934 as of a date within 90 days prior to the filing date of this report. Based on that evaluation, such officers have concluded that the Company’s disclosure controls and procedures are effective to ensure that material information relating to the Company and its subsidiaries is made known to such officers in a timely manner for inclusion in the Company’s periodic filings with the SEC.
(b)
There were no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls after the date of their most recent evaluation by the Company’s principal executive officer and principal financial officer.
ITEM 15.
ITEM 15.
AUDIT FEES AND SERVICES
Not applicable for the fiscal year covered by this report.
PART IV
ITEM 16.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)
1.
The list of all financial statements filed as a part of this report is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
2.
Schedules:*
*
All schedules have been omitted because of the absence of the conditions under which they are required or because the required informa-tion is included elsewhere in the financial statements included under ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
3.
Exhibits:
Exhibit
Number
Exhibit Title
2.1(a)*
Agreement and Plan of Merger, dated as of December 6, 1998, by and among Scottish Power plc, NA General Partnership, Scottish Power NA 1 Limited and Scottish Power NA 2 Limited. (Exhibit 1 to the Form 6-K, dated December 11, 1998, filed by Scottish Power plc, File No. 1-14676).
2.1(b)*
Amended and Restated Agreement and Plan of Merger, dated as of December 6, 1998, as amended as of January 29, 1999 and February 9, 1999, and amended and restated as of February 23, 1999, by and among New Scottish Power PLC, Scottish Power plc, NA General Partnership and PacifiCorp (Exhibit (2)b, Form 10-K for year ended December 31, 1998, File No. 1-5152).
3.1*
Third Restated Articles of Incorporation of the Company (Exhibit (3)b, Form 10-K for the year ended December 31, 1996, File No. 1-5152).
3.2*
Bylaws of the Company effective November 29, 1999 (Exhibit (3)b, Form 10-K for the year ended March 31, 2000, File No. 1-5152).
4.1*
Mortgage and Deed of Trust dated as of January 9, 1989, between the Company and Morgan Guaranty Trust Company of New York (The Chase Manhattan Bank, successor), Trustee, Ex. 4-E, Form 8-B, File No. 1-5152 as supplemented and modified by fourteen Supplemental Indentures as follows:
Exhibit
Number
File Type
File Date
File Number
(4)(b)
33-31861
(4)(a)
8-K
January 9, 1990
1-5152
4(a)
8-K
September 11, 1991
1-5152
4(a)
8-K
January 7, 1992
1-5152
4(a)
10-Q
Quarter ended March 31, 1992
1-5152
4(a)
10-Q
Quarter ended September 30, 1992
1-5152
4(a)
8-K
April 1, 1993
1-5152
4(a)
10-Q
Quarter ended September 30, 1992
1-5152
4(a)
10-Q
Quarter ended September 30, 1993
1-5152
(4)b
10-K
Quarter ended June 30, 1994
1-5152
(4)b
10-K
Quarter ended December 31, 1994
1-5152
(4)b
10-K
Quarter ended December 31, 1995
1-5152
(4)b
10-K
Quarter ended December 31, 1996
1-5152
99(a)
8-K
November 21, 2001
1-5152
4.2*
Third Restated Articles of Incorporation and Bylaws. See 3.1 and 3.2 above.
In reliance upon item 601(4)(iii) of Regulation S-K, various instruments defining the rights of holders of long-term debt of the Registrant and its subsidiaries are not being filed because the total amount authorized under each such instrument does not exceed 10% of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.
12.1
Statements of Computation of Ratio of Earnings to Fixed Charges
12.2
Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
Consent of PricewaterhouseCoopers LLP with respect to Annual Report on Form 10-K.
Powers of Attorney
99.1
Section 906 Certification of Judith A. Johansen
99.2
Section 906 Certification of Richard D. Peach
99.3
Code of Ethics for Principal Officers
______________
*
Incorporated herein by reference.
(b)
Reports on Form 8-K.
On Form 8-K, dated March 6, 2003, under Item 5. Other Events, the Company filed a news release reporting that the WPSC issued an order allowing approximately $9.0 million of the requested $20.0 million general rate increase. Additionally, the WPSC’s order disallowed the Company’s request for recovery of $60.3 million of excess power costs related to the western power crisis in 2000 and 2001 and $30.7 million of excess power costs resulting from the outage of the Company’s Hunter No. 1 generating plant from November 2000 to May 2001.
(c)
See (a) 3. above.
(d)
See (a) 2. above.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED THEREUNTO DULY AUTHORIZED.
Date: May 30, 2003
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE
TITLE
DATE
*IAN M. RUSSELL
Chairman of the Board of Directors
May 30, 2003
Ian M. Russell
/s/ JUDITH A. JOHANSEN
President, Chief Executive Officer and Director
May 30, 2003
Judith A. Johansen
/s/ RICHARD D. PEACH
Chief Financial Officer and Director
May 30, 2003
Richard D. Peach
)
)
Nolan E. Karras
)
)
)
William D. Landels
)
*ANDREW N. MacRITCHIE
)
)
Andrew N. MacRitchie
)
)
)
Michael J. Pittman
)
*A. RICHARD WALJE
) Director
)
May 30, 2003
A. Richard Walje
)
/s/ MATTHEW R. WRIGHT
)
)
Matthew R. Wright
)
*BARRY G. CUNNINGHAM
)
)
Barry G. Cunningham
)
/s/ ANDREW P. HALLER
)
)
Andrew P. Haller
)
*By: /s/ JUDITH A. JOHANSEN
)
)
)
Judith A. Johansen, as
Attorney-in-Fact
CERTIFICATIONS
I, Judith A. Johansen, principal executive officer of PacifiCorp, certify that:
1)
I have reviewed this annual report on Form 10-K of PacifiCorp;
2)
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3)
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4)
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b)
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5)
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6)
The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
/s/ Judith A. Johansen
Judith A. Johansen
President and Chief Executive Officer, PacifiCorp
May 30, 2003
CERTIFICATIONS
I, Richard Peach, principal financial officer of PacifiCorp, certify that:
1)
I have reviewed this annual report on Form 10-K of PacifiCorp;
2)
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3)
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4)
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b)
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5)
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6)
The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
/s/ Richard Peach
Richard D. Peach
Chief Financial Officer, PacifiCorp
May 30, 2003