ITE M 1.  BUSINESS

OVERVIEW

Ownership by MidAmerican Energy Holdings Company

On March 21, 2006, a wholly owned subsidiary of MidAmerican Energy Holdings Company (“MEHC”) acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of Scottish Power plc (“ScottishPower”). As a result of the acquisition, MEHC controls substantially all of PacifiCorp’s voting securities, which include both common and preferred stock. MEHC, a holding company owning subsidiaries that are principally engaged in energy businesses, is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”).

On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution may only be used by MEHC for the purpose of (i) paying when due MEHC’s debt obligations and (ii) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries, including PacifiCorp. Berkshire Hathaway will have up to 180 days to fund any such request in minimum increments of at least $250 million pursuant to one or more drawings authorized by MEHC’s Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to MEHC in exchange for additional shares of MEHC’s common stock. PacifiCorp has no right to make or to cause MEHC to make any equity contribution requests. The Berkshire Hathaway equity commitment will expire on February 28, 2011.

Operations

PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States regulated electricity company serving 1.7 million retail customers, including residential, commercial, industrial and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, 68 thermal, hydroelectric and wind-powered generating plants, with a plant net capacity of 9,286 megawatts (“MW”). PacifiCorp also owns, or has interests in, electric transmission and distribution assets, and transmits electricity through approximately 15,700 miles of transmission lines. PacifiCorp buys and sells electricity on the wholesale market with public and private utilities, energy marketing companies and incorporated municipalities in connection with excess electricity generation or other system balancing activities. The regulatory commission in each state approves rates for retail electric sales within that state. Subsidiaries of PacifiCorp support its electric utility operations by providing coal-mining facilities and services and environmental remediation services.

PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power. PacifiCorp’s electric generation, commercial and energy trading, and coal-mining functions are operated under the trade name PacifiCorp Energy. As a vertically integrated electric utility, PacifiCorp owns or has contracts for fuel sources, such as coal and natural gas, and uses these fuel sources, as well as wind, geothermal and water resources, to generate electricity at its power plants. This electricity, together with electricity purchased on the wholesale market, is then transmitted via a grid of transmission lines throughout PacifiCorp’s six-state region. The electricity is then transformed to lower voltages and delivered to customers through PacifiCorp’s distribution system.

PacifiCorp’s primary goal is to provide safe, reliable electricity to its customers at a reasonable cost. In return, PacifiCorp expects that all prudently incurred costs to provide such service will be included as allowable costs for state rate-making purposes, and PacifiCorp will be allowed an opportunity to earn a reasonable return on its investments.

PacifiCorp is experiencing growth in retail loads and expects this to continue for the foreseeable future. PacifiCorp seeks to manage this growth in customer demand through the construction and purchase of new cost-effective, environmentally prudent and efficient sources of power supply and through demand response and energy efficiency programs. During 2007, PacifiCorp added the 548-MW Lake Side natural gas-fired plant and the 140-MW (nameplate rating) Marengo wind plant, as well as expanded the capacity at its Blundell geothermal facility by 11 MW, to help meet its retail load growth and replace expiring wholesale supply contracts.

 

 

During 2008, PacifiCorp expects to place into service wind plants totaling 461 MW or more. Additionally, PacifiCorp continues to pursue other cost-effective wind plants scheduled for completion in 2009 and beyond. PacifiCorp is also investing in its transmission and distribution system to integrate new generation resources and effectively meet customer load growth. This planned generation, transmission and distribution system expansion will also facilitate meeting the commitments made to state regulatory commissions as a result of the sale of PacifiCorp to MEHC. PacifiCorp expects to fund this construction with cash from operations, long-term debt issuances and equity contributions from PPW Holdings LLC.

Employees

As of December 31, 2007, PacifiCorp, together with its subsidiaries, had 6,470 employees, 61% of which were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America.

Fiscal Year-End Change

In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. As a result of PacifiCorp’s election to change its fiscal year from March 31 to December 31, the audited periods presented in the Consolidated Statements of Income include the year ended December 31, 2007, the nine-month transition period ended December 31, 2006 and the year ended March 31, 2006.

The percentage of PacifiCorp’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, availability and price of coal and natural gas, precipitation and snow-pack levels, other weather-related impacts, environmental considerations and the market price of electricity.

PacifiCorp owns, or has interests in, various thermal, hydroelectric and wind generating plants. The following table shows PacifiCorp’s existing generating plants as of December 31, 2007:

 

(a)	Facility net capacity represents the total capability of a generating unit as demonstrated by actual operating or test experience, less power generated and used for auxiliaries and other station uses, and is determined using average annual temperatures. Net MW owned indicates current legal ownership.
(b)	For wind plants, nameplate ratings are used in place of facility net capacity. A generator’s nameplate rating is its full-load capacity (in MW) under normal operating conditions as defined by the manufacturer.
(c)	All or some of the renewable energy attributes associated with generation from these facilities may be used in future years to comply with state or federal renewable portfolio standards (“RPS”).
(d)	Hydroelectric project locations are stated by locality and river watershed.
(e)	For information regarding the decommissioning of certain of PacifiCorp’s hydroelectric plants, refer to “Hydroelectric Decommissioning” below.
(f)	Expected to be complete by the end of 2008.

Future Generation and Conservation

Integrated Resource Plans

As required by certain state regulations, PacifiCorp uses an Integrated Resource Plan (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. When the IRP is filed, each state commission with IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines. PacifiCorp requests “acknowledgement” of its IRP filing from the Utah Public Service Commission (the “UPSC”), the Oregon Public Utility Commission (the “OPUC”), the Idaho Public Utilities Commission (the “IPUC”) and the Washington Utilities and Transportation Commission (the “WUTC”) pursuant to those states’ IRP adequacy rules. The IRP can be used as evidence by parties in rate-making or other regulatory proceedings. PacifiCorp files its IRP on a biennial basis.

In May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need for approximately 3,171 MW of additional resources by summer 2016 to satisfy the difference between projected retail load obligations and available resources. PacifiCorp plans to meet this need through demand response and energy efficiency programs; the construction or purchase of additional generation, including cost-effective renewable energy, combined heat and power, and thermal generation; and wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources. PacifiCorp is currently seeking acknowledgement of its 2007 IRP from state regulators and expects the acknowledgement process to be complete in 2008.

Requests for Proposal

PacifiCorp has issued a series of separate requests for proposal (“RFP”), each of which focuses on a specific category of resources as provided in the IRP. The IRP and the RFP provide for the identification and staged procurement of resources in future years to achieve load/resource balance. As required by applicable laws and regulations, PacifiCorp files draft RFP with the UPSC, the OPUC and the WUTC prior to issuance to the market.

In February 2007, PacifiCorp filed a modified 2012 RFP in Utah for up to 1,700 MW of additional resources to become available beginning in 2012 through 2014. The RFP was approved by the UPSC and issued to the market in April 2007. In June 2007, proposals from qualifying bidders were received by commission-directed independent evaluators. These bids included various structures, ranging from purchase or lease of coal, natural gas, and geothermal power plants to power purchase agreements. PacifiCorp initiated negotiations with short-listed bidders in January 2008.

In January 2008, PacifiCorp issued to the market a 2008 renewable RFP for less than 100 MW or greater than 100 MW for a power purchase agreement with a term of less than five years, to become available prior to December 2009.

In February 2008, PacifiCorp filed an all source 2008 RFP with the UPSC, the OPUC and the WUTC for base load, intermediate or third quarter summer peaking products delivered into PacifiCorp’s system. The all source 2008 RFP seeks up to 2,000 MW of resources to become available beginning in 2012 through 2016.

 

In addition to new generation resources, substantial transmission investments are expected to be required to deliver energy to PacifiCorp’s growing customer base and to enhance system reliability. The actual investment requirement will depend on the location and other characteristics of the new generation resources. Refer to “Transmission and Distribution” below.

Demand-side Management

PacifiCorp has provided a comprehensive set of demand-side management programs to its customers since the 1970s. The programs are designed to reduce growth in peak load and energy consumption. Current programs offer customers services such as energy engineering and audits, as well as rebates for high efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors and process equipment and systems; new construction; and load management (curtailment) programs for large commercial and industrial customers and residential customers whose central air conditioners are controlled during summer peak load periods. Subject to random prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for demand-side management programs and services through the energy efficiency service charges to all retail electric customers. In 2007, $53   million was expended on the demand-side management programs in PacifiCorp’s six-state service area, resulting in an estimated 300,000 megawatt hours (“MWh”) of first year energy savings and 170 MW of peak load management.

Coal

PacifiCorp’s coal generation portfolio consists of 11 plants with a net owned capacity of 6,104 MW. These plants account for 66% of PacifiCorp’s total net owned generating capacity. As of December 31, 2007, PacifiCorp had an estimated 232 million tons of recoverable coal reserves in company-owned or leased mines, including those related to the underground mine described below. These mines supplied 31% of PacifiCorp’s total coal requirements during the year ended December 31, 2007 and the nine-month period ended December 31, 2006, compared to 32% during the year ended March 31, 2006. The remaining coal requirements are acquired through long- and short-term third-party contracts. PacifiCorp’s mines are located adjacent to many of its coal-fired generating plants, which significantly reduces overall transportation costs included in fuel expense.

PacifiCorp believes that the coal reserves available to the Craig, Huntington, Hunter and Jim Bridger plants, together with coal available under both long- and short-term contracts with external suppliers to supply its remaining plants, will be substantially sufficient to provide these plants with fuel for their currently expected useful lives. To meet applicable standards, PacifiCorp blends coal mined at its owned mines with contracted coal, and utilizes electricity plant technologies for controlling sulfur dioxide and other emissions.

In an effort to lower costs and obtain better quality coal, the Jim Bridger mine developed an underground mine to access 57 million tons of PacifiCorp’s coal reserves. Sustained operations at the underground mine commenced in March 2007 and production continues at its surface operations. The life of the underground mine is expected to be approximately 15 years.

During the year ended December 31, 2007, PacifiCorp-owned plants held sufficient sulfur dioxide emission allowances to comply with the Environmental Protection Agency (the “EPA”) Title IV requirements. The sulfur content of the coal reserves generally ranges from 0.30% to 0.94%, and the British thermal units value per pound of PacifiCorp’s coal reserves ranges from 8,600 to 12,400.

Recoverable coal reserves as of December 31, 2007, based on PacifiCorp’s most recent engineering studies, were as follows (in millions):

(a)	These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp has an ownership interest of 21%.
(b)	These coal reserves are leased by PacifiCorp and mined by a wholly owned subsidiary of PacifiCorp.
(c)	These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. (“PMI”) and a subsidiary of Idaho Power Company. PMI, a subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. The amount included above represents only PacifiCorp’s two-thirds interest in the coal reserves.

Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves. Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques ranges from 50% to 70%. Most of PacifiCorp’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 multi-year terms that may be renewed or extended only with the consent of the lessor 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. Refer to Note 7 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on asset retirement obligations.

Natural Gas

PacifiCorp’s natural gas-fired generation portfolio consists of five plants with a net owned capacity of 1,694 MW, including the 548-MW Lake Side plant, which commenced full combined-cycle operation in September 2007. These plants account for 18% of PacifiCorp’s total net owned generating capacity. PacifiCorp also leases, through May 2008, one natural gas-fired peaking plant with a net capacity of 200 MW.

PacifiCorp uses natural gas as fuel for its combined- and simple-cycle natural gas-fired plants. Oil and natural gas are also used for igniter fuel and to fuel generation for transmission support and standby purposes. Although these sources are presently in adequate supply and available to meet PacifiCorp’s needs, the increase in PacifiCorp’s generation fueled by natural gas requires a prudent and disciplined approach to natural gas procurement and hedging. PacifiCorp has developed a natural gas procurement strategy that addresses the need to economically hedge the estimated commodity risk (physical availability and price), transportation risk and storage risk associated with its forecasted natural gas requirements.

PacifiCorp manages its natural gas supply requirements by entering into forward commitments for physical delivery of natural gas. PacifiCorp also manages its exposure to increases in natural gas supply costs through forward commitments for the purchase of forecasted physical natural gas requirements at fixed prices and financial swap contracts that settle in cash based on the difference between a fixed price that PacifiCorp pays, and a floating market-based price that PacifiCorp receives. As of December 31, 2007, PacifiCorp had economically hedged 82% of its forecasted physical exposure and 97% of its financial exposure for 2008. For 2009, PacifiCorp currently has hedged 61% of its physical exposure and 84% of its financial exposure.

 

Hydroelectric

PacifiCorp’s hydroelectric portfolio consists of 47 plants with a net owned capacity of 1,158 MW. These plants account for 12% of PacifiCorp’s total net owned generating capacity, helping satisfy a significant portion of PacifiCorp’s reserve requirements and providing operational benefits such as flexible generation and voltage control. Hydroelectric plants are located in Utah, Oregon, Wyoming, Washington, Idaho, California and Montana.

 

The amount of electricity PacifiCorp is able to generate from its hydroelectric plants depends on a number of factors, including snow-pack in the mountains upstream of its hydroelectric plants, reservoir storage, precipitation in its watersheds, plant availability and restrictions imposed by oversight bodies due to competing water management objectives. When these factors are favorable, PacifiCorp can generate more electricity using its hydroelectric plants. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the Federal Energy Regulatory Commission (the “FERC”) with terms of 30 to 50 years. Several of PacifiCorp’s long-term operating licenses have expired and they are operating under temporary annual licenses issued by the FERC until new long-term operating licenses are issued. Hydroelectric relicensing and the related environmental compliance requirements are subject to a degree of uncertainty. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs and capital expenditures. If licenses are not issued, significant decommissioning costs may be incurred. Electricity generation reductions may also result from additional environmental requirements. As of December 31, 2007 and 2006, PacifiCorp had incurred $89 million and $79 million, respectively, in costs for ongoing hydroelectric relicensing, which are included in Construction work-in-progress in the Consolidated Balance Sheets. Refer to “Hydroelectric Relicensing” and “Hydroelectric Decommissioning” below.

Wind and Other Renewable Resources

PacifiCorp is pursuing renewable resources as a viable, economic and environmentally prudent means of generating electricity. The benefits of energy from renewable resources include low to no emissions, and typically little or no fossil fuel requirements. The intermittent nature of some renewable resources, such as wind, is complemented by other generating resources, such as thermal or hydroelectric generation, which are important to integrating intermittent wind resources into the electric system.

PacifiCorp currently generates power and associated energy from wind and other renewable resources through three PacifiCorp-owned wind plants (in Oregon, Washington and Wyoming), including the 140-MW (nameplate rating) Marengo wind plant that was placed into service in August 2007. PacifiCorp also acquires power and associated energy from renewable resources through various power purchase agreements, some associated with wind plants in Oregon, Wyoming, Utah and Idaho, and others associated with resources defined as “qualifying facilities” pursuant to the Public Utility Regulatory Policies Act. In addition to these wind plant resources, PacifiCorp owns a geothermal plant in Utah.

In connection with the March 2006 acquisition of PacifiCorp by MEHC, PacifiCorp committed to state regulatory commissions to bring at least 100 MW (nameplate ratings) of cost-effective wind resources into service by March 21, 2007, and, to the extent available, have 400 MW (nameplate ratings) (inclusive of the 100 MW (nameplate ratings) commitment) of cost-effective new renewable resources in PacifiCorp’s generation portfolio by December 31, 2007. PacifiCorp met the requirements of its commitment to bring 100 MW of cost-effective wind resources into service by March 21, 2007 with the completion of the 101-MW Leaning Juniper 1 wind plant, which was placed into service in September 2006. PacifiCorp has also met the requirements of its commitment to have 400 MW (nameplate ratings) of cost-effective new renewable resources in its portfolio by December 31, 2007 by completing the 140-MW (nameplate rating) Marengo wind plant, which was placed into service in August 2007; entering into power purchase agreements for output associated with the 65-MW Wolverine Creek wind plant and two biomass facilities owned by retail customers for 20 MW and 10 MW; completion of a 11-MW bottoming cycle to the Blundell geothermal facility; and beginning construction of the 94-MW Goodnoe Hills wind plant, which is expected to be placed into service during 2008.

 

WHOLESALE SALES AND PURCHASED ELECTRICITY

In addition to its portfolio of generating plants, PacifiCorp purchases electricity in the wholesale markets to meet its retail load and long-term wholesale obligations, for system balancing requirements and to enhance the efficient use of its generating capacity over the long term. PacifiCorp’s total energy requirements supplied by purchased electricity, under long- and short-term purchase arrangements, were 19% during the year ended December 31, 2007; 24% during the nine-month period ended December 31, 2006; and 22% during the year ended March 31, 2006. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. These wholesale activities are regulated by the FERC.

PacifiCorp enters into wholesale purchase and sale transactions to balance its electricity supply when generation and retail loads are higher or lower than expected. Generation can vary with the levels of outages, hydroelectric and wind generation conditions, operational factors and transmission constraints. Retail load can vary with the weather, distribution system outages, consumer trends and the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own plants. PacifiCorp may also sell into the wholesale market excess electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints. Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.

PacifiCorp’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, PacifiCorp has been able to purchase electricity from utilities in the Western United States for its own requirements. Delivery of these purchases is conducted through PacifiCorp and third-party transmission systems, which connect with market hubs in the Pacific Northwest to provide access to normally low-cost hydroelectric generation, and in the Southwestern United States to provide access to normally higher-cost fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements.

TRANSMISSION AND DISTRIBUTION

PacifiCorp operates one balancing authority area in the western portion of its service territory, and one balancing authority area in the eastern portion of its service territory. A balancing authority area is a geographic area with electric systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. PacifiCorp also schedules deliveries of energy over its transmission system in accordance with FERC requirements.

Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. During the year ended December 31, 2007, PacifiCorp delivered 67,114 gigawatt-hours (“GWh”), net of line losses, of electricity to retail and wholesale customers in its two balancing authority areas through approximately 15,700 miles of transmission lines.

PacifiCorp’s transmission system is part of the Western Interconnection, the regional grid in the West. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico that make up the Western Electricity Coordinating Council (the “WECC”). The map under “Service Territories” below shows PacifiCorp’s primary transmission system. PacifiCorp’s transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements.

 

Substantially all of PacifiCorp’s generating plants and reservoirs are managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp’s transmission and distribution systems are located:

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On property owned or leased by PacifiCorp;

 

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Under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights that are generally subject to termination;

 

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Under or over private property as a result of easements obtained primarily from the record holder of title; or

 

·

Under or over Native American reservations under grant of easement by the Secretary of Interior or lease by Native American tribes.

 

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

 

As of December 31, 2007, PacifiCorp owned, or participated in, an electric transmission system consisting of approximately:

As of December 31, 2007, PacifiCorp owned approximately 900 transmission and distribution substations.

PacifiCorp’s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp’s Open Access Transmission Tariff (“OATT”). In accordance with OATT, PacifiCorp offers several transmission services to wholesale customers:

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Network transmission service (guaranteed service that integrates generating resources to serve retail loads);

 

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Long- and short-term firm point-to-point transmission service (guaranteed service with fixed delivery and receipt points); and

 

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Non-firm point-to-point service (“as available” service with fixed delivery and receipt points).

These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp’s transmission business is managed and operated independently from the generating and marketing business, in accordance with the FERC Standards of Conduct.

 

 

Transmission costs are not separated from, but rather are “bundled” with, generation and distribution costs in rates approved by state regulatory commissions. Refer to “Regulatory Matters – Federal Regulatory Matters” below for further information related to the Energy Policy Act of 2005, which requires that the FERC establish and enforce standards for electric reliability; FERC Order 693, which addresses the FERC’s responsibility for establishing and enforcing electric reliability standards; and FERC Orders 890 and 890-A, which address OATTs.

In connection with the March 2006 acquisition of PacifiCorp by MEHC, PacifiCorp committed to state regulatory commissions to spend approximately $520 million in investments (to be made over several years following the acquisition and subject to subsequent regulatory review and approval) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization. As of December 31, 2007, PacifiCorp had incurred $112 million of capital expenditures and $16 million of operating expenses pursuant to this commitment.

In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The estimated $4.1 billion investment plan includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the Western United States. These transmission lines are expected to be placed into service beginning 2010 and continuing through 2014. PacifiCorp is also collaborating with other utilities to address transmission needs, including new development and system reliability.

 

SERVICE TERRITORIES

PacifiCorp serves approximately 1.7 million regulated retail customers in service territories aggregating approximately 136,000 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho and California. Except for Oregon and Washington, PacifiCorp has an exclusive right to serve electricity customers within its service territories and, in turn, has the obligation to provide electric service to those customers. Under Oregon law, certain commercial and industrial customers have the right to choose alternative electric suppliers. The impact of these programs on PacifiCorp’s financial results has not been and is not expected to be material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp’s service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC.

The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urban, manufacturing and government service centers. No single segment of the economy dominates the service territory, which helps mitigate PacifiCorp’s exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeast Idaho, the principal industries are manufacturing, health services, recreation, agriculture and mining or extraction of natural resources. In the western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern California, the principal industries are agriculture and manufacturing, with forest products, food processing, technology and primary metals being the largest industrial sectors. The following map highlights PacifiCorp’s retail service territory, plant locations and PacifiCorp’s primary transmission lines. PacifiCorp’s generating facilities are interconnected through PacifiCorp’s own transmission lines or by contract through transmission lines owned by others.

 

 

(a)	Access to other entities’ transmission lines through wheeling arrangements.
(b)	Access to other entities’ transmission lines through OATTs.

The geographic distribution of PacifiCorp’s retail electric operating revenues was as follows:

PacifiCorp receives authorization from state public utility commissions to serve areas within each state. This authorization is perpetual until withdrawn. In addition, PacifiCorp has received franchises that permit it to provide electric service to customers inside incorporated areas within the states. The average term of these franchises is approximately 30 years, although their terms range from five years to indefinite. PacifiCorp must renew franchises as they expire. Governmental agencies have the right to challenge PacifiCorp’s right to serve in a specific area and can condemn PacifiCorp’s property under certain circumstances. However, PacifiCorp vigorously challenges attempts from individuals and governmental entities to undertake forced takeover of portions of its service territory.

PacifiCorp is estimating growth in retail MWh sales in PacifiCorp’s franchise service territories to average between 1% and 3% annually over the next five years, with significant growth estimated in Wyoming due to the extraction of natural resources and large oil and natural gas industrial development within the state. Customer growth will depend on factors such as economic conditions, number of customers, weather, consumer trends, conservation efforts and changes in prices.

Seasonality

Customer demand is typically highest in the summer across PacifiCorp’s service territory when air conditioning and irrigation systems are heavily used. Customer demand also peaks in the winter months in the western portion of PacifiCorp’s service territory primarily due to heating requirements and in the eastern portion due to other electricity demands.

For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Strong Utah residential growth over the last several years and increasing installations of central air conditioning systems have contributed to increased summer peak load growth. During the year ended December 31, 2007, PacifiCorp’s peak load was 9,775 MW in the summer and 8,650 MW in the winter. During the year ended December 31, 2007, PacifiCorp’s average load was 7,185 MW for the summer and 7,028 MW for the winter.

RETAIL COMPETITION

During the year ended December 31, 2007, PacifiCorp continued to operate its retail business under state regulation, which generally prohibits retail competition. However, under a 1999 Oregon law, certain PacifiCorp commercial and industrial customers in Oregon have the right to choose alternative electricity suppliers. As a result of this law, a group of customers having a total load of approximately 12 average MW have chosen service from suppliers other than PacifiCorp. PacifiCorp does not expect this competitive program to have a material effect on its financial results during the year ending December 31, 2008.

In addition to Oregon’s program permitting limited retail competition, others in PacifiCorp’s service territories are seeking to have a choice of suppliers, exploring options to build their own generation or co-generation plants, or considering the use of alternative energy sources, such as natural gas. If these customers gain the right to receive electricity from alternative suppliers, they will make their energy purchasing decisions based upon many factors, including price, service and system reliability. The use of alternative energy sources is typically based on availability, price and the general demand for electricity.

REGULATORY MATTERS

PacifiCorp is subject to comprehensive regulation by the FERC, the UPSC, the OPUC, the Wyoming Public Service Commission (the “WPSC”), the WUTC, the IPUC, the California Public Utilities Commission (the “CPUC”), the WECC, and other federal, state and local regulatory agencies. These authorities regulate various matters, including, but not limited to, customer rates, service territories, allocation of costs by state, asset acquisitions and sales, wholesale sales and purchases of electricity, the operation of PacifiCorp’s electric generation and transmission facilities, issuances of securities, accounting policies and practices and other matters. In addition, PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act 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 PacifiCorp’s hydroelectric plants are licensed by the FERC as major projects under the Federal Power Act, and certain of these projects are licensed under the Oregon Hydroelectric Act.

 

 

Federal Regulatory Matters

For a discussion of California and Northwest Refund cases, refer to Note 15 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

The Bonneville Power Administration Residential Exchange Program

 

The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The program is administered by the Bonneville Power Administration (the “BPA”) in accordance with federal law. Pursuant to agreements between the BPA and PacifiCorp, benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits. In October 2000, PacifiCorp entered into a settlement agreement with the BPA that provided Residential Exchange Program benefits to PacifiCorp’s customers from October 2001 through September 2006. In May 2001, PacifiCorp entered into a load reduction agreement with the BPA that eliminated the BPA’s obligation to deliver power to PacifiCorp from October 2001 through September 2006 in exchange for cash payments. This agreement also contained a “reduction of risk discount” provision, which provided that the BPA would reduce the cash payments to PacifiCorp if by December 1, 2001, PacifiCorp and other utilities were able to negotiate and enter into settlement agreements with the publicly owned utilities and other of the BPA’s preference customers dismissing certain lawsuits. If these parties did not reach settlement by the specified date, the clause would expire and the BPA would make cash payments to PacifiCorp based on the original rate for the October 2002 through September 2006 period. Settlement was not reached and the clause expired, obligating the BPA to make the full cash payment to PacifiCorp. In May 2004, PacifiCorp, the BPA and other parties executed an additional agreement, which modified both the October 2000 and May 2001 agreements, which provides for a guaranteed range of benefits to customers from October 2006 through September 2011.

Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. In May 2007, the Ninth Circuit issued two decisions. The first decision sets aside the October 2000 Residential Exchange Program settlement agreement as being inconsistent with the BPA’s settlement authority. The second decision holds, among other things, that the BPA acted contrary to law when it allocated to its preference customers, which include public utilities, cooperatives and federal agencies, part of the costs of the October 2000 settlement the BPA reached with its investor-owned utility customers. As a result of the ruling, in May 2007, the BPA notified the Pacific Northwest’s six utilities, including PacifiCorp, that it was immediately suspending payments. This has resulted in increases to PacifiCorp’s residential and small-farm customers’ electric bills in Oregon, Washington and Idaho. In October 2007, the Ninth Circuit issued one published decision and three unpublished decisions. The published decision remanded the May 2004 agreement modifying the October 2000 and May 2001 agreements to the BPA for further action consistent with the Ninth Circuit’s May 2007 decisions. The other three unpublished decisions dismiss cases in which the publicly owned utilities sought review of the BPA’s decision to implement the reduction of risk discount provision and make the full cash payment to PacifiCorp. In February 2008, the BPA initiated a rate proceeding under section 7(i) of the Northwest Power Act to reconsider the level of benefits for the years 2002 through 2006 consistent with the Ninth Circuit’s decisions, to re-establish the level of benefits for years 2007 and 2008 and to set the level of benefits for years 2009 and beyond. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on PacifiCorp’s consolidated financial results.

FERC Market Oversight

FERC Order No. 693

In March 2007, the FERC issued Order No. 693, Mandatory Reliability Standards for the Bulk-Power System , which imposes penalties of up to $1 million per day per violation for failure to comply with new electric reliability standards. The FERC approved 83 reliability standards developed by the North American Electric Reliability Corporation (the “NERC”). Responsibility for compliance and enforcement of these standards has been given to the WECC. The 83 standards comprise over 600 requirements and sub-requirements with which PacifiCorp must comply. On June 18, 2007, the standards became mandatory and enforceable under federal law. PacifiCorp expects that the existing standards will change as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement. On January 18, 2008, the FERC approved eight additional cyber security and critical infrastructure protection standards proposed by the NERC. The additional standards will become effective on April 7, 2008. PacifiCorp cannot predict the effect that these standards will have on its consolidated financial results; however, they will likely have a significant impact on transmission operations and resource planning functions. Also during 2007, the WECC audited PacifiCorp’s compliance with several of the reliability standards approved by the FERC. PacifiCorp is analyzing the preliminary results of the audit and, at this time, cannot predict the impact of potential penalties, if any, on its consolidated financial results. 

FERC Orders No. 890 and 890-A

In February 2007, the FERC adopted a final rule in Order No. 890 designed to strengthen the pro forma OATT by providing greater specificity and increasing transparency. The most significant revisions to the pro forma OATT relate to the development of more consistent methodologies for calculating available transfer capability, changes to the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling behavior and to exempt intermittent generators, and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term point-to-point transmission service, and generation re-dispatch. As a transmission provider with an open-access transmission tariff on file with the FERC, PacifiCorp is required to comply with the requirements of the new rule. The first compliance filing, which amends the OATT, was filed in July 2007. Certain details related to the precise methodology that will be used to calculate available transfer capability were filed with the FERC in September 2007. A number of parties to the proceeding, including PacifiCorp, have requested rehearing or clarification of various portions of the final rule. In December 2007, the FERC issued Order No. 890-A generally affirming the provisions of the final rule as adopted in Order No. 890 with certain limited clarifications. Although PacifiCorp has requested a limited clarification of Order No. 890-A, the final rule as revised is not anticipated to have a significant impact on PacifiCorp’s financial results, but it will likely have a significant impact on its transmission operations, planning and wholesale marketing functions.

Energy Policy Act of 2005

On August 8, 2005, the Energy Policy Act was signed into law and has significantly impacted the energy industry. In particular, the law expanded the FERC’s regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority to issue civil penalties of up to $1 million per day. While the FERC has now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains uncertain.

The Energy Policy Act also gives the FERC “backstop” transmission siting authority and directs the FERC to oversee the establishment of mandatory transmission reliability standards as discussed above. The Energy Policy Act also extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007, with subsequent legislation extending the credit to December 31, 2008. Partly as a result of that portion of the law, PacifiCorp began development efforts to add additional wind plants.

Transmission Settlement

In January 2007, the FERC approved a settlement with PacifiCorp regarding PacifiCorp’s use of its transmission system while conducting wholesale power transactions with third parties. PacifiCorp discovered possible violations of its FERC-approved tariff during an internal investigation of its compliance with certain FERC regulations shortly before MEHC’s acquisition of PacifiCorp. Upon completion of the acquisition, PacifiCorp self-reported the potential violations to the FERC. The potential violations primarily related to the way PacifiCorp used its own transmission system to transmit energy using “network service” instead of “point-to-point” service as the FERC believes is required by PacifiCorp’s tariff. This use of transmission service neither enriched PacifiCorp’s shareholders nor harmed its retail customers. As part of the settlement, PacifiCorp voluntarily refunded $1 million to other transmission customers in April 2006 and paid a $10 million fine to the United States Treasury in January 2007.

Wholesale Electricity and Capacity

The FERC regulates PacifiCorp’s rates charged to wholesale customers for electricity, capacity and transmission services. Most of PacifiCorp’s electric wholesale sales and purchases take place under market-based rate pricing allowed by the FERC and are therefore subject to market volatility. A December 2006 decision of the Ninth Circuit changed the interpretation of the relevant standard that the FERC should apply when reviewing wholesale contracts for electricity or capacity from a stringent “public policy” standard to a broader “just and reasonable” standard making contracts more vulnerable to challenge. The decision raises some concerns regarding the finality of contract prices, particularly from the sellers’ side of the transactions. The United States Supreme Court is reviewing the case on appeal and the outcome of its ruling cannot be predicted at this time. All sellers subject to the FERC’s jurisdiction, including PacifiCorp, are currently subject to increased risk as a result of this decision.

The FERC conducts a triennial review of PacifiCorp’s market-based rate pricing authority. Each utility must demonstrate the lack of generation market power in order to charge market-based rates for sales of wholesale electricity and capacity in their respective balancing authority areas. Under the FERC’s market-based rules, PacifiCorp must file a notice of change in status when 100 MW of incremental generation becomes operational. Following separate filings by PacifiCorp of a change in status notice relating to new generation, the FERC in February and November 2007 confirmed that PacifiCorp does not have market power and may continue to charge market-based rates. In accordance with the filing schedule established by the FERC in Order No. 697, PacifiCorp’s next triennial review will occur in 2010.

Hydroelectric Relicensing

Several of PacifiCorp’s hydroelectric plants are in some stage of the relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of certain hydroelectric projects. The following summarizes the status of certain of these projects.

Klamath Hydroelectric Project – (Klamath River, Oregon and California)

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW (nameplate rating) Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license granted by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.

Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. PacifiCorp filed comments on the draft statement by the close of the public comment period on December 1, 2006. Subsequently, in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the hydroelectric project’s impact on endangered species under the proposed new FERC license. The United States Fish and Wildlife Service asserts the hydroelectric project is currently not covered by previously issued biological opinions, and that consultation under the Endangered Species Act is required by the issuance of annual license renewals. PacifiCorp disputes these assertions, and believes federal case law is clear that consultation on annual FERC licenses is not required. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.

Lewis River Hydroelectric Projects – (Lewis River, Washington)

PacifiCorp filed new license applications for the 136-MW (nameplate rating) Merwin and 240-MW (nameplate rating) Swift No. 1 hydroelectric projects in April 2004. An application for a new license for the 134-MW (nameplate rating) Yale hydroelectric project was filed with the FERC in April 1999. However, consideration of the Yale application was delayed pending filing of the Merwin and Swift No. 1 applications so that the FERC could complete a comprehensive environmental analysis.

In November 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and federal agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among the parties, issues related to the pending applications for new licenses for PacifiCorp’s Merwin, Swift No. 1 and Yale hydroelectric projects. As part of this settlement agreement, PacifiCorp agreed to implement certain protection, mitigation and enhancement measures prior to and during a proposed 50-year license period. However, these commitments are contingent on ultimately receiving licenses from the FERC and other required permits that are consistent with the settlement agreement. PacifiCorp has received water quality certificates from the Washington Department of Ecology and biological opinions from the United States Fish and Wildlife Service and the National Marine Fisheries Service. Regulatory documents needed to license the projects have been submitted to the FERC and PacifiCorp is awaiting the issuance of new FERC licenses.

Prospect Hydroelectric Project – (Rogue River, Oregon)

In June 2003, PacifiCorp submitted a final license application to the FERC for the Prospect Nos. 1, 2 and 4 hydroelectric projects, whose nameplate ratings total 37 MW. The Oregon Department of Environmental Quality issued a 401 Water Quality certificate for the project in April 2007, which effectively concluded the license process. The FERC is expected to issue a new license before the end of May 2008.

Hydroelectric Decommissioning

Powerdale Hydroelectric Project – (Hood River, Oregon)

In June 2003, PacifiCorp entered into a settlement agreement to remove the 6-MW (nameplate rating) Powerdale plant rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale dam and associated project features, which is subject to the FERC and other regulatory approvals, is projected to cost $6 million excluding inflation. Removal was scheduled to commence in 2010. However, in November 2006, flooding damaged the Powerdale plant and rendered its generating capabilities inoperable. In February 2007, the FERC granted PacifiCorp’s request to cease generation at the project until decommissioning activities begin. Also in February 2007, PacifiCorp submitted a request to the FERC to allow the company to defer the remaining net book value and any additional removal costs of this project as a regulatory asset. In May 2007, the FERC issued an order that approved PacifiCorp’s proposed accounting entries, thereby allowing PacifiCorp to reclassify the net book value and the estimated removal costs to a regulatory asset. PacifiCorp has received approval from its state commissions to defer and recover these costs.

Condit Hydroelectric Project – (White Salmon River, Washington)

In September 1999, a settlement agreement to remove the 10-MW (nameplate rating) Condit hydroelectric project was signed by PacifiCorp, state and federal agencies and non-governmental organizations. Under the original settlement agreement, removal was expected to begin in October 2006, with a total cost to decommission not to exceed $17 million, excluding inflation. In early February 2005, the parties agreed to modify the settlement agreement so that removal will not begin until October 2008 for a total cost to decommission not to exceed $21 million, excluding inflation. The settlement agreement is contingent upon receiving a FERC surrender order and other regulatory approvals that are not materially inconsistent with the amended settlement agreement. PacifiCorp is in the process of acquiring all necessary permits, within the terms and conditions of the amended settlement agreement. If the permitting process continues into the second quarter of 2008, the decommissioning will not begin until October 2009.

Cove Hydroelectric Project – (Bear River, Idaho)

In May 2006, the FERC approved PacifiCorp’s application to amend the Bear River license and authorized the removal of the 8-MW (nameplate rating) Cove hydroelectric plant and facilities. Decommissioning of the Cove facilities has been completed in accordance with the license amendment and the approved removal plan. The removal of the dam, flowline and all facilities, with the exception of the powerhouse that has been designated a historical landmark, was completed in November 2006. As of December 31, 2007, $3 million had been spent for the decommissioning of the Cove hydroelectric project.

American Fork Hydroelectric Project – (American Fork Creek, Utah)

In August 2004, the FERC authorized the removal of the 1-MW (nameplate rating) American Fork hydroelectric plant and facilities. Decommissioning of the American Fork facilities has been completed in accordance with the approved removal plan. The removal of the dam, flowline and all facilities, with the exception of the powerhouse that has been designated a historical landmark, was completed in December 2007. As of December 31, 2007, $4 million had been spent for the decommissioning of the American Fork hydroelectric project.

United States Mine Safety

Mining operations are regulated by the federal Mine Safety and Health Administration (“MSHA”), which administers federal mine safety and health laws, regulations and state regulatory agencies. The Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”), enacted in June 2006, amended previous mine safety and health laws to improve mine safety and health and accident preparedness. The MINER Act, portions of which are not yet fully implemented, requires operators of underground coal mines to develop a written emergency response plan specific to each mine they operate. These plans must be updated and re-certified by MSHA every six months. It also requires every mine to have at least two rescue teams located within one hour, and it limits the legal liability of rescue team members and the companies that employ them. The MINER Act also increases civil and criminal penalties for violations of federal mine safety standards and gives MSHA the ability to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay the penalties or fines.

State Regulatory Actions

PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. The following discussion provides a state-by-state update.

Utah

In December 2007, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million, or an average price increase of 11%. The increase is primarily due to increased capital spending and net power costs, both of which are driven by load growth. In February 2008, the UPSC issued an order determining that the proper test period should end December 2008. PacifiCorp is currently determining the reduction to the originally requested amount that will result from the change in the test period. Hearings on the revenue requirement portion of the case are scheduled for June 2008, with the rate-design phase scheduled for October 2008. PacifiCorp expects that initial rates, if approved, will become effective no later than August 2008.

 

In December 2006, the UPSC approved a stipulation settling PacifiCorp’s general rate case filed in March 2006 related to increased investments in Utah due to growing demand for electricity. The stipulation called for an annual increase of $115 million, or an average price increase of 10%, with $85 million of the increase effective December 11, 2006 and the remaining $30 million increase effective June 1, 2007.

Oregon

In August 2007, PacifiCorp filed a renewable cost adjustment clause that will allow for timely recovery between rate cases of the costs of eligible renewable resources and associated transmission under the RPS. The RPS required the OPUC to approve an automatic adjustment clause for timely recovery of these costs by January 1, 2008. In December 2007, the OPUC approved a settlement stipulation filed by the parties to the proceedings that established the renewable adjustment clause (“RAC”) mechanism, with an effective date of January 1, 2008. Under the RAC mechanism, PacifiCorp will submit a filing on April 1 of each year, with rates to become effective January 1 of the following year, to recover the revenue requirement of new renewable resources and associated transmission that are not reflected in general rates. As part of the RAC mechanism, the OPUC authorized PacifiCorp to defer eligible costs not yet included in rates until the next annual RAC filing.

In July 2007, as part of PacifiCorp’s annual compliance filing with the OPUC to update forecasted net power costs, PacifiCorp requested an increase of approximately $30 million, or an average price increase of 3%, to take effect January 1, 2008. The annual filing, called the transition adjustment mechanism (“TAM”), was adjusted for new contracts through October 2007 and for other changes to forecasted net power costs, such as coal and natural gas prices, through November 2007. In October 2007, the OPUC issued an order that approved the TAM increase subject to PacifiCorp updating its net power cost forecast to reflect changes adopted in the decision. In November 2007, PacifiCorp submitted a compliance filing with an updated net power cost forecast, which reflected a $22 million increase, or an average price increase of 2%. In December 2007, the OPUC approved the TAM with rates effective January 1, 2008.

In September 2006, the OPUC approved a settlement agreement resolving PacifiCorp’s February 2006 general rate case request related to investments in generation, transmission and distribution infrastructure and increases in fuel and general operating expenses, including the maintenance of low-cost but aging power plants. Pursuant to the settlement agreement, PacifiCorp received an annual increase for non-power cost items of $33 million effective January 1, 2007. Also on January 1, 2007, PacifiCorp received a $10 million increase for power costs through its annual TAM.

For a discussion of Oregon Senate Bill 408, refer to Note 3 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

Wyoming

In June 2007, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $36 million, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource recovery mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. In January 2008, PacifiCorp reached a settlement in principle with parties to the case, subject to entering into a final stipulation and approval by the WPSC. The settlement provides for an annual rate increase of $23 million, or an average price increase of 5%. In addition, the parties also agreed to a forecast power cost mechanism and discontinuation of the current power cost adjustment mechanism (“PCAM”) by April 2011, unless a continuation is specifically applied for by PacifiCorp and approved by the WPSC. PacifiCorp’s marginal cost pricing tariff proposal will not be implemented, but will be the subject of a collaborative process to seek a new pricing proposal. Also as part of the settlement, PacifiCorp agreed to withdraw from this filing its request for a renewable resource recovery mechanism. The stipulation was executed and filed with the WPSC in January 2008 and will be the subject of a hearing for approval beginning in March 2008. PacifiCorp expects the new rates to become effective by May 2008.

In February 2008, PacifiCorp filed its annual deferred net power cost adjustment application with the WPSC in the amount of $31 million for costs incurred during the period December 1, 2006 through November 30, 2007.

In February 2007, PacifiCorp filed its first annual deferred net power cost adjustment application with the WPSC in the amount of $3 million for costs incurred during the period July 1, 2006 through November 30, 2006. In March 2007, PacifiCorp received approval from the WPSC to implement interim rates effective April 1, 2007, in the amount of $3 million. In May 2007, PacifiCorp filed a stipulation and agreement with the WPSC that resolved all issues in the application and reduced the deferred net power cost adjustment to $2 million. The revised rates were effective July 1, 2007.

Washington

In February 2008, PacifiCorp filed a general rate case with the WUTC for an annual increase of $35 million, or an average price increase of 15%, with an effective date no later than January 2009.

In October 2006, PacifiCorp filed a general rate case with the WUTC for an annual increase of $23 million, or an average price increase of 10%. As part of the filing, PacifiCorp proposed a Washington-only cost-allocation methodology, which is based on PacifiCorp’s western resources. The rate case included a five-year pilot period on the proposed allocation methodology and a PCAM. In June 2007, the WUTC issued an order approving a rate increase of $14 million, or an average price increase of 6%, effective June 27, 2007, and accepted PacifiCorp’s proposed western balancing authority area cost-allocation methodology for a five-year pilot period. The WUTC found that PacifiCorp demonstrated the need for a PCAM, but it did not approve the design of the proposal in this case. The order authorized PacifiCorp to file a revised PCAM proposal, with or without a request to file power cost-only rate cases, outside the context of a general rate case within 12 months of the order.

Idaho

In June 2007, PacifiCorp filed a general rate case with the IPUC for an annual increase of $18 million, or an average price increase of 10%, with a request for an effective date of January 1, 2008. In November 2007, an all-party stipulation was reached on all issues in the general rate case, resulting in an annual increase of $12 million, or an average price increase of 6%. The IPUC approved the settlement stipulation in December 2007, with new rates effective January 1, 2008. The settlement also provides for rate increases effective January 1, 2009 and 2010 for PacifiCorp’s two special contract industrial customers and no additional rate changes for those two special contract customers effective prior to January 1, 2011. Additional rate increases for the remaining customer classes may be requested if needed to maintain cost of service coverage.

California

In October 2007, PacifiCorp filed two advice letters requesting authority to implement components of the post test-year adjustment mechanism (“PTAM”), a mechanism that allows for annual rate adjustments for changes in operating costs and plant additions outside of the context of a traditional rate case. The combined requested increase totaled $2 million, or an average price increase of 2%. The CPUC approved the increase in November 2007. In December 2007, PacifiCorp revised the increase based on updated capital additions, and the CPUC issued a revised order for a $1 million increase, or an average price increase of 1% effective January 1, 2008.

In August 2007, PacifiCorp filed an energy cost adjustment clause application with the CPUC to update actual and forecasted net variable power costs, requesting a rate increase of $6 million, or an average price increase of 8%, with an effective date of January 1, 2008. In December 2007, the CPUC issued an order for a $5 million increase, or an average price increase of 7%, with an effective date of January 1, 2008.

Depreciation Rate Changes

In August 2007, PacifiCorp filed applications with the regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation and extend the depreciable lives of certain assets, based on a new depreciation study. Agreements have been reached in each of these states and are in various stages of approval. When approved by the state commissions, the agreements will make the new depreciation rates effective January 1, 2008. For further discussion on depreciation rate changes, refer to Note 2 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

 

 

ENVIRONMENTAL REGULATION

PacifiCorp is subject to federal, state and local laws and regulations with regard to air and water quality, RPS, climate change, hazardous and solid waste disposal and other environmental matters and is subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance including fines, injunctive relief and other sanctions. PacifiCorp believes it is in material compliance with all laws and regulations. The most significant environmental laws and regulations affecting PacifiCorp include:

·

The federal Clean Air Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards. Rules issued by the EPA and certain states require substantial reductions in sulfur dioxide and nitrogen oxide emissions beginning in 2009 and extending through 2018. PacifiCorp has already installed certain emission control technology and is taking other measures to comply with required reductions. Refer to “Clean Air Standards” below for additional discussion regarding this topic.

 

·

The federal Water Pollution Control Act (“Clean Water Act”) and individual state clean water laws regulate cooling water intake structures and discharges of wastewater, including storm water runoff. PacifiCorp believes that it currently has, or has initiated the process to receive, all required water quality permits. Refer to “Water Quality Standards” below for additional discussion regarding this topic.

 

·

The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws, which may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Refer to Note 15 of Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding environmental contingencies.

 

·

The federal Surface Mining Control 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. Refer to Note 7 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

 

·

The FERC oversees the relicensing of existing hydroelectric projects and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric projects, dam safety inspections and environmental monitoring. Refer to Note 15 of Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding the relicensing of certain of PacifiCorp’s existing hydroelectric facilities.

 

PacifiCorp is subject to federal, state and local laws and regulations with regard to air and water quality, RPS, climate change, hazardous and solid waste disposal and other environmental matters. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to PacifiCorp. In particular, future mandates may impact the operation of PacifiCorp’s generating facilities and may require PacifiCorp to reduce emissions at its generating facilities through the installation of additional emission control equipment or to purchase additional emission allowances or offsets in the future. PacifiCorp is not aware of any established technology that reduces the carbon dioxide emission at coal-fired facilities and PacifiCorp is uncertain when, or if, such technology will be commercially available.

Expenditures for compliance-related items such as pollution control technologies, replacement generation, mine reclamation, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into the routine cost structure of PacifiCorp. An inability to recover these costs from PacifiCorp’s customers, either through regulated rates, long-term arrangements or market prices, could adversely affect PacifiCorp’s future financial results.

Clean Air Standards

The Clean Air Act provides a framework for protecting and improving the nation’s air quality and controlling mobile and stationary sources of air emissions. The major Clean Air Act programs, which most directly affect PacifiCorp’s electric generating facilities, are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional, more stringent requirements.

In connection with the March 2006 acquisition of PacifiCorp by MEHC, PacifiCorp committed to state regulators to spend approximately $812 million over several years to reduce emissions at PacifiCorp’s generating facilities to address existing and future air quality requirements. These costs and any additional expenditures necessitated by air quality regulations are expected to be recovered in rates and, as a result, would not have a material adverse impact on PacifiCorp’s consolidated results of operations. As of December 31, 2007, PacifiCorp had incurred $205 million in capital expenditures pursuant to this commitment.

National Ambient Air Quality Standards

The EPA implements national ambient air quality standards for ozone and fine particulate matter, as well as for other criteria pollutants that set the minimum level of air quality for the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area are required to make emissions reductions. The counties in Washington, Oregon, Montana, Wyoming, Colorado, Utah and Arizona where PacifiCorp’s major emission sources are located are in attainment of the current ambient air quality standards. A new, more stringent standard for fine particulate matter became effective on December 18, 2006, but is under legal challenge in the United States Court of Appeals for the District of Columbia Circuit. Air quality modeling and preliminary air quality monitoring data indicate that portions of the states in which PacifiCorp has major emission sources may not meet the new standards. Until three years of data are collected and attainment designations under the new fine particulate standard are made, the impact of these new standards on PacifiCorp will not be known.

In July 2007, the EPA proposed revisions to the primary and secondary national ambient air quality standards for ozone, including lowering the current level of the 8-hour standard from 0.08 parts per million to a range of 0.070 and 0.075 parts per million. The EPA also solicited public comments through October 9, 2007 on alternative levels between 0.060 parts per million and the current 8-hour standard. Final action on the standards must be completed by March 12, 2008. States will then have until June 2009 to characterize their attainment status, with the EPA’s determinations regarding non-attainment made by June 2010 and state implementation plans due in 2013. Until the EPA makes its final determination on the revised standards and attainment designations are made, the impact of any new standards on PacifiCorp will not be known.

Regulated Air Pollutants

In March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”), a two-phase program that utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons. The CAMR required initial reductions of mercury emissions in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. The individual states in which PacifiCorp operates facilities regulated under the CAMR submitted state implementation plans reflecting their regulations relating to state mercury control programs. On February 8, 2008, the United States Court of Appeals for the District of Columbia Circuit held that the EPA improperly removed electricity generating units from Section 112 of the Clean Air Act and, thus, that the CAMR was improperly promulgated under Section 111 of the Clean Air Act. The court vacated the CAMR’s new source performance standards and remanded the matter to the EPA for reconsideration. In light of this decision, it is not known the extent to which future mercury rules may impact PacifiCorp’s current plans to reduce mercury emissions at its coal-fired facilities.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. Some of PacifiCorp’s plants meet the threshold applicability criteria under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit state implementation plans by December 2007 to demonstrate reasonable progress toward achieving natural visibility conditions in certain Class I areas by requiring emission controls, known as best available retrofit technology, on sources with emissions that are anticipated to cause or contribute to impairment of visibility. Wyoming has not yet submitted its state implementation plan and is continuing to review the results of analyses relating to planned emission reductions at PacifiCorp’s Wyoming generating plants. Utah has not yet submitted its state implementation plan, but expects to do so in the near term. PacifiCorp believes that its planned emission reduction projects will satisfy the regional haze requirements in Utah and Wyoming; however, it is possible that some additional controls may be required once the respective state implementation plans have been submitted.

New Source Review

Under existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (i) beginning construction of a new major stationary source of an NSR-regulated pollutant, or (ii) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a “best available control technology” analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states and environmental groups, among others, potentially subject a utility to material expenses for fines and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.

As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested from numerous utilities information and supporting documentation regarding their capital projects for various generating plants. Between 2001 and 2003, PacifiCorp responded to requests for information relating to its capital projects at its generating plants and has been engaged in periodic discussions with the EPA over several years regarding this matter. An NSR enforcement case against another utility has been decided by the United States Supreme Court, holding that an increase in annual emissions of a facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. PacifiCorp cannot predict the outcome of the EPA’s review of the data it has submitted at this time.

In 2002 and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge, and in March 2006, a panel of the United States Court of Appeals for the District of Columbia Circuit invalidated portions of the EPA’s new NSR rules, holding that they conflicted with the wording of the statute. However, the EPA has asked the United States Supreme Court to review portions of the case. Until such time as the legal challenges are resolved and the revised rules are effective, PacifiCorp will continue to manage projects at its generating plants in accordance with the rules in effect prior to 2002, except for pollution-control projects, which are now subject to permitting under the PSD program. In 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the permitting process and allow facilities to undertake activities that improve their safety, reliability and efficiency without triggering NSR requirements. In April 2007, the EPA issued a supplemental notice of proposed rulemaking to determine emissions increases for electric generating units, proposing to use both hourly and annual emissions tests to determine whether utilities trigger the NSR permitting program when an existing power plant makes a physical or operational change. The supplemental proposal was issued three weeks after the United States Supreme Court issued a unanimous opinion in Environmental Defense v. Duke Energy that the EPA was correct in applying an annual emissions test to determine NSR compliance.

Refer to “Liquidity and Capital Resources” included in Item 7 of this Form 10-K for additional information regarding planned capital expenditures related to air quality standards. Refer to Note 15 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding commitments and litigation related to air quality standards.

Renewable Portfolio Standards

The RPS described below could significantly impact PacifiCorp’s financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state-to-state. Each state’s RPS requires some form of compliance reporting and PacifiCorp can be subject to penalties in the event of non-compliance.

In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative. PacifiCorp expects to be able to recover its costs of complying with the RPS, either through rate cases or an adjustment mechanism.

In June 2007, the Oregon Renewable Energy Act (the “Act”) was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the Act, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the Act, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy facilities and associated transmission costs. The OPUC and the Oregon Department of Energy have undertaken additional rulemaking proceedings to further implement the initiative. PacifiCorp expects to be able to recover its costs of complying with the RPS through the automatic adjustment mechanism. For further discussion of the automatic adjustment mechanism, refer to “Regulatory Matters – State Regulatory Actions – Oregon” above.

California law requires electric utilities to increase their procurement of renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from renewable resources by no later than December 31, 2010. However, PacifiCorp and other small multi-jurisdictional utilities (“SMJU”) are currently awaiting further guidance from the CPUC on the treatment of SMJUs in the California RPS program. PacifiCorp has filed comments requesting SMJU rules for flexible compliance with annual targets. PacifiCorp expects rules governing the treatment of SMJUs and any specific flexible compliance mechanisms to be released by CPUC staff for public review in early 2008. Absent further direction from the CPUC on treatment of SMJUs, PacifiCorp cannot predict the impact of the California RPS on its financial results.

Climate Change

As a result of increased attention to global climate change in the United States, numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority, and many congressional observers expect to see the passage of climate change legislation within the next several years. The Lieberman-Warner Climate Security Act of 2007 (S. 2191) was passed by the United States Senate Environment and Public Works Committee on December 5, 2007. The bill would impose an economy-wide cap on greenhouse gas emissions to reduce emissions 70% from 2005 levels by 2050. Included within the bill’s definition of a covered facility is any facility that uses more than 5,000 tons of coal in a calendar year, which includes all of PacifiCorp’s coal-fired generating plants. In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws. In April 2007, a United States Supreme Court decision concluded that the EPA has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles. Furthermore, pending cases that address the potential public nuisance from greenhouse gas emissions from electricity generators and the EPA’s failure to regulate greenhouse gas emissions from new and existing coal-fired plants are expected to become active. While debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse gas emissions, including:

 

PacifiCorp continues to add renewable electric capacity to its generation portfolio. In addition, PacifiCorp has engaged in voluntary programs designed to either reduce or avoid greenhouse gas emissions, including the EPA’s sulfur hexafluoride reduction program and refrigerator recycling programs. PacifiCorp is a member of the California Climate Action Registry and The Climate Registry, under which it reports and certifies its greenhouse gas emissions.

The impact of any pending judicial proceedings and any pending or enacted federal and state climate change legislation and regulation cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact PacifiCorp’s current and future fossil-fueled facilities, and, therefore, its financial results.

Water Quality Standards

The Clean Water Act establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the “best technology available for minimizing adverse environmental impact” to aquatic organisms. In July 2004, the EPA established significant new national technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water a day. These rules are aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit Court of Appeals remanded almost all aspects of the rule to the EPA, leaving companies with cooling water intake structures uncertain regarding compliance with these requirements. Petitions for certiorari are pending before the United States Supreme Court regarding the Second Circuit’s decision. Compliance and the potential costs of compliance therefore cannot be ascertained until such time as further action is taken by the EPA. Currently, PacifiCorp’s Dave Johnston plant exceeds the 50 million gallons of water per day in-take threshold. In the event that PacifiCorp’s existing intake structures require modification or alternative technology is required by new rules, expenditures to comply with these requirements could be significant.