Portland General Electric Co 10-K 2009
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended December 31, 2008
For the Transition period from to
Commission File Number 1-5532-99
PORTLAND GENERAL ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
121 SW Salmon Street
Portland, Oregon 97204
(Address of principal executive offices, including zip code,
and Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, no par value
(Title of class)
New York Stock Exchange
(Name of exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of large accelerated filer, accelerated filer, and Smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of June 30, 2008, the aggregate market value of voting common stock held by non-affiliates of the Registrant was $1,407,939,478. For purposes of this calculation, executive officers and directors are considered affiliates.
As of February 18, 2009, there were 62,575,257 shares of common stock outstanding.
Documents Incorporated by Reference
PORTLAND GENERAL ELECTRIC COMPANY
FOR THE YEAR ENDED DECEMBER 31, 2008
TABLE OF CONTENTS
The following abbreviations or acronyms used in the text and Notes to Consolidated Financial Statements are defined below:
Portland General Electric Company (PGE or the Company) is a vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. PGE operates as a cost-based, regulated electric utility. PGEs revenue requirements are determined based upon the forecast cost to serve retail customers, including an opportunity to earn a reasonable rate of return. PGE also participates in the wholesale market by purchasing and selling electricity and natural gas to utilities and energy marketers in order to balance its supply of power to meet the needs of retail customers and manage its net variable power costs (NVPC). PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis.
PGE was incorporated in 1930 and is publicly-owned, with its common stock listed on the New York Stock Exchange under the ticker symbol POR. The Company was a wholly-owned subsidiary of Enron Corp. (Enron) for the period from July 1, 1997 through April 3, 2006.
In 1997, Portland General Corporation, the former parent of PGE, merged with Enron, with Enron continuing in existence as the surviving corporation and PGE operating as a wholly-owned subsidiary of Enron. In December 2001, Enron, along with certain of its subsidiaries (collectively Debtors), filed for bankruptcy under Chapter 11 of the federal Bankruptcy Code. PGE was not included in the filing. On April 3, 2006, in accordance with Enrons Chapter 11 plan, PGEs 42.8 million shares of common stock held by Enron were canceled, PGE issued 62.5 million of new shares of common stock, with 27 million shares issued to the Debtors creditors holding allowed claims and 35.5 million shares issued to a Disputed Claims Reserve, and PGE and Enron entered into a separation agreement. PGE ceased to be a subsidiary of Enron. On June 18, 2007, the Disputed Claims Reserve sold substantially all of its remaining holdings of PGE stock in a public offering.
PGEs state-approved service area allocation of approximately 4,000 square miles is located entirely within Oregon and includes 52 incorporated cities, of which Portland and Salem are the largest. The Company estimates that at the end of 2008 its service area population was 1.6 million, comprising about 43% of the states population. The Company added 6,409 retail customers during 2008, and as of December 31, 2008 served 810,197 retail customers.
As of December 31, 2008, PGE had 2,753 employees, with 888 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (Local 125). Such agreements cover 854 and 34 employees for the five-year periods ending February 28, 2009 and August 1, 2011, respectively. PGE is in negotiations with Local 125 for a new agreement to replace the one scheduled to expire February 28, 2009. The existing agreement will remain in effect following the expiration date unless either party gives at least 60 days written notice of termination.
The Companys Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available and may be accessed free of charge through the Investors section of the Companys Internet website at www.portlandgeneral.com as soon as
reasonably practicable after the reports are electronically filed with, or furnished to, the U.S. Securities and Exchange Commission (SEC). It is not intended that the Companys website and the information contained therein or connected thereto be incorporated into this Annual Report on Form 10-K. Information may also be obtained via the SEC Internet website at www.sec.gov.
Regulation and Rates
PGE is subject to federal and state regulation, both of which can have a significant impact on the business and operations of the Company. In addition to those activities and agencies discussed below, the Company is subject to regulation by certain environmental agencies, as described in Environmental Matters in this Item 1.
PGE is subject to federal regulation by the Federal Energy Regulatory Commission (FERC) and by the Nuclear Regulatory Commission (NRC).
The Company is a licensee and a public utility, as defined in the Federal Power Act, and is subject to regulation by the FERC as to accounting policies and practices, licensing of hydroelectric projects, transmission services, wholesale sales, issuance of short-term debt, and certain other matters. The Energy Policy Act of 2005 granted the FERC increased statutory authority to implement mandatory transmission and reliability standards, as well as enhanced oversight of power and transmission markets, including protection against market manipulation.
Wholesale - PGE has authority under its FERC tariff to charge market-based rates for wholesale energy sales made to other utilities and energy marketers. Under FERC Order 697, Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, re-authorization for continued use of market-based rates requires the filing of updated market studies on a regional schedule. PGEs current authorization is effective until June 2010, at which time the Company, as part of the western region, will file for re-authorization.
Transmission - Terms and conditions related to the transmission of electric energy are contained in PGEs Open Access Transmission Tariff (OATT), which is filed with the FERC. In 2007, the FERC issued Order 890, Preventing Undue Discrimination and Preference in Transmission Services, which includes requirements for greater specificity and transparency in the OATT and for enhanced coordination of transmission planning. PGE has submitted filings to incorporate into its OATT the requirements of the order. FERC Order 693, Mandatory Reliability Standards for the Bulk-Power System, issued in 2007, approved mandatory reliability standards developed by the North American Electric Reliability Corporation (NERC). Responsibility for compliance and enforcement of these standards has been given to the Western Electricity Coordinating Council (WECC), a regional electric reliability organization.
Pipeline - The Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 provide FERC authority in matters related to extension, enlargement, safety, and abandonment of jurisdictional pipeline facilities, as well as transportation rates and accounting for interstate natural gas commerce. PGE is subject to such authority due to the Companys 79% ownership interest in the 17-mile interstate pipeline that provides natural gas to its Port Westward and Beaver plants.
Hydroelectric Licensing - Under the Federal Power Act, PGEs hydroelectric generating plants are subject to FERC licensing requirements. Such requirements include an extensive public review process that involves numerous natural resource issues and environmental conditions. PGE holds FERC licenses for the Companys projects on the Deschutes and Willamette Rivers and is currently in the process of relicensing its four hydroelectric projects on the Clackamas River.
The NRC regulates the licensing and decommissioning of nuclear power plants. In 1993, the NRC issued a possession-only license amendment to PGEs operating license for the Trojan Nuclear Plant (Trojan), and in early 1996 approved the Trojan Decommissioning Plan, which has allowed PGE to proceed in decommissioning the plant. The NRC approved the completed transfer of spent nuclear fuel from the Trojan spent fuel pool to a separately licensed dry cask storage system that will house the nuclear fuel on the plant site until permanent storage is available. PGE completed the radiological decommissioning of the Trojan site in 2004 pursuant to an NRC-approved License Termination Plan, with the plants Facility Operating License terminated by the NRC in 2005. Spent fuel storage activities will continue to be subject to NRC regulation until all nuclear fuel is removed from the site and the storage installation is fully decommissioned.
State of Oregon Regulation
PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC), which is comprised of three members appointed by Oregons governor to serve non-concurrent four-year terms. The OPUC reviews and approves the Companys retail prices (see Ratemaking below) and establishes conditions of utility service. In addition, the OPUC regulates the issuance of stock and long-term debt, prescribes accounting policies and practices, and reviews applications to sell utility assets, engage in transactions with affiliated companies, and acquire substantial influence over a public utility. The OPUC also reviews the Companys generation and transmission resource acquisition plans, pursuant to an integrated resource planning process.
Oregons Energy Facility Siting Council (EFSC) has regulatory and siting responsibility for large electric generating facilities, high voltage transmission lines, gas pipelines, and radioactive waste disposal sites. The EFSC also has responsibility for overseeing the decommissioning of Trojan. Members of the EFSC are appointed by the states governor, with staff support provided by the Oregon Department of Energy.
Ratemaking - Under Oregon law, the OPUC is required to ensure that the prices and terms of service are fair, non-discriminatory, and provide regulated companies an opportunity to earn a fair return on their investments. Customer prices are determined through formal rate proceedings that generally include testimony by participating parties, data requests, public hearings, and the issuance of a final order. Participants in such proceedings, which are conducted under established procedural schedules, include PGE, OPUC staff, and interveners.
Other ratemaking proceedings can involve charges or credits related to specific costs, programs, or activities, as well as the recovery or refund of deferred amounts recorded pursuant to specific OPUC authorization. Such amounts are generally collected from, or refunded to, retail customers through the use of supplemental tariffs.
Utility Rate Treatment of Income Taxes - In 2005, Oregon adopted Senate Bill 408 (SB 408). The law attempts to more closely match income tax amounts forecasted to be collected in revenues with the amount of income taxes paid to governmental entities by electric and natural gas investor-owned utilities or their consolidated group. The law requires that utilities file a report with the OPUC each year regarding the amount of taxes paid by the utility (with certain adjustments), as well as the amount of taxes authorized to be collected in rates, as defined by the statute. This report is filed by October 15th of the year following the reporting year. If the OPUC determines that the difference between the two amounts is greater than $100,000, the utility is required to adjust future rates, with a regulatory asset or liability recorded for the total amount (including accrued interest) to be collected from, or refunded to, retail customers. The first adjustment under SB 408 applied to taxes paid to governmental entities and collected from customers on or after January 1, 2006.
Application of the provisions of SB 408 can, in certain situations, result in unusual outcomes, commonly termed the double whammy effect. As the provisions of the law apply to PGE, if the Company records higher operating income as compared to its latest general rate case, customers are surcharged for the increase in income taxes, further increasing earnings. Conversely, if the Company records lower operating income as compared to its latest rate case, customers would receive refunds for the decrease in income taxes, further decreasing earnings.
For further information, see Note 6, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements.
Oregon Renewable Energy Act - Enacted in 2007 by the Oregon legislature, the Oregon Renewable Energy Act (the Act) established a Renewable Energy Standard which requires that utilities meet specified percentages of their Oregon retail load with electricity generated by renewable resources by certain dates. PGE and other large electricity providers are required to serve at least 5% of their retail load within the state from renewable resources from 2011 through 2014, 15% for 2015 through 2019, 20% for 2020 through 2024, and 25% in 2025 and subsequent years. PGE anticipates that it will meet the 2011 requirement of the Act with existing or currently planned renewable resources. Further, the Company expects that, with additional resources included in its current planning process, it will meet the 2015 requirement. It is anticipated that subsequent years requirements will be met by the acquisition of additional renewable resources, as determined pursuant to the Companys integrated resource planning process. For further information, see Power and Fuel Supply in this Item 1.
The Act also provides for the recovery in customer rates of all prudently incurred costs required to comply with the Renewable Energy Standard. The OPUC has approved the establishment of a renewable adjustment clause mechanism (RAC), which became effective January 1, 2008. Under the RAC, PGE 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 yet reflected in general rates. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in rates until the next annual RAC filing.
Retail Customer Choice Program - Implemented in 2002 as part of Oregons electricity restructuring law, the retail customer choice program allows the Companys commercial and industrial customers direct access to other suppliers of electricity (Electricity Service Suppliers, or ESSs). While direct access customers purchase their electricity from other suppliers, PGE continues to deliver the energy to these customers. The program provides for transition adjustments for customers that choose to purchase energy at market prices from investor-owned utilities or from ESSs. Such adjustments reflect the above-market or below-market cost of energy resources owned or purchased by the utility and are designed to ensure that such costs or benefits do not unfairly shift to the utilitys remaining energy customers. The retail customer choice program has no material effect on the financial condition or results of operation of the Company. During 2008, ESSs supplied customers with a total average load of approximately 269 MWa, representing 20% of PGEs non-residential load and 12% of the Companys total retail load for the year. In early 2009, the three ESSs registered to transact business with PGE supplied a total of 28 customers, representing 214 accounts, with a total average load of approximately 222 MWa, representing 16% of the Companys non-residential load and 10% of total retail load.
Cost-of-service and market price options are also available to PGEs commercial and industrial customers. The Company offers an option by which certain large non-residential customers may, for a minimum three- or five-year term, elect to be removed from cost-of-service pricing, with energy supplied by an ESS or at a daily market rate by PGE. A total of 32 commercial and industrial customers, less than 1% of those eligible, were receiving service from PGE under market-based pricing options at the end of 2008.
Residential and small commercial customers can purchase electricity from PGE from a portfolio of rate options that include a basic cost-of-service rate, a time-of-use rate, and renewable resource rates. As of December 31, 2008, approximately 71,000 customers were enrolled in renewable energy options, with 2,100 enrolled in time-of-use options.
Energy Efficiency Funding - Oregons electricity restructuring law also provides for a public purpose charge to fund cost-effective energy efficiency measures, new renewable energy resources, and weatherization measures for low-income housing. This charge, equal to 3% of retail revenues, is collected from customers and remitted to the Energy Trust of Oregon (ETO) and other agencies for administration of these programs. In 2008, approximately $47 million in such charges were billed to customers.
PGE also remits to the ETO amounts collected under a new Energy Efficiency Adjustment tariff to fund additional energy efficiency measures. The tariff, which became effective on June 1, 2008, includes an approximate 1% average price increase and is expected to provide about $14 million annually for measures that enable customers to reduce their energy use.
PGE is subject to the provisions of Statement of Financial Accounting Standards No. (SFAS) 71, Accounting for the Effect of Certain Types of Regulation, and currently applies its provisions to reflect the effects of rate regulation in its financial statements. The Company periodically assesses the applicability of the statement to its business, considering both the current and anticipated future rate environment and related accounting guidance. For further information, see Regulatory Assets and Liabilities in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements.
Customers and Revenues
PGE conducts retail electric operations exclusively in Oregon within a state-approved service area. Competitors within the Companys service territory include the local natural gas company, which competes in the residential and commercial space heating, water heating, and appliance markets, and fuel oil suppliers, which compete primarily for residential space heating customers. In addition, commercial and industrial customers may choose to purchase their energy requirements from ESSs, in accordance with Oregons electricity restructuring law.
The following table summarizes PGEs revenues for the years indicated, with certain averages for retail customers (excluding direct access customers) (dollars in millions, except as indicated):
For further information, see Results of Operation in Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation.
Residential customers comprised 88% of the Companys total customers as of December 31, 2008 and 2007, with the remainder consisting of commercial and industrial customers. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating season, and the condition of the economy. Generally, a 1% increase in Oregons unemployment rate results in an approximate 0.7% decrease in demand from the Companys residential customers.
Commercial and industrial customer classes are not dominated by any single industry. While the 20 largest customers constitute 6% of total retail revenues, they represent nine different commercial and industrial groups, including high technology, paper manufacturing, metal fabrication, health services, and governmental agencies. No single customer represents more than 5% of PGEs total retail load or 2% of total retail revenues. While demand by the Companys commercial and industrial customers is generally not affected by weather, these classes can be affected by employment. Generally, a 1% decrease in Oregons employment rate results in an approximate 0.4% decrease in demand from the Companys commercial and industrial customers.
PGEs direct access customers consist of commercial and industrial customers who purchase their electricity from an ESS, with PGE delivering the electricity. The revenue earned in connection with the transmission and delivery of this electricity is included in Other retail revenue, net of transition adjustments. PGE served an average of 417 direct access customer accounts in 2008, 322 in 2007, and 239 in 2006.
Residential Exchange Program (REP) - In May 2007, the Bonneville Power Administration (BPA), which provides federal hydropower benefits under the REP, suspended payments under the program to investor-owned utilities, which meant that monthly payments in a total expected annual amount of $76.5 million to PGE were suspended. Because PGE passes REP payments along to its residential and small farm customers in the form of monthly billing credits, the suspension had no net income impact to the Company, but resulted in an approximate 14% average price increase to those customers.
In April 2008, the BPA partially restored benefits on a temporary basis. As a result, prices for residential and small farm customers were reduced by an average of 6.3%. The BPA provided $43 million in interim benefits to the Company, the majority of which was credited to customers by the end of 2008.
In September 2008, the BPA and PGE, as ordered by the OPUC, entered into an agreement, terminating on September 30, 2011, that will provide monthly payments totaling approximately $40 million over the 12-month period ending September 30, 2009. Such benefits will be credited to eligible customers. Remaining benefits under the agreement will be based upon certain power exchange rates and other amounts to be determined in BPA proceedings.
PGE will continue to pursue ongoing benefits for its customers. Various parties have challenged the agreements under which the BPA will provide the future benefits to the customers of investor-owned utilities, including PGE, and others who purchase electricity directly from the BPA.
PGE participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. The Companys wholesale market participation includes purchases and sales of power resulting from economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers, and purchases and sales of natural gas. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, water conditions, and seasonal demand.
The majority of PGEs wholesale sales are to utilities and power marketers and are predominantly short-term. The Company may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power, with only the net amount of those purchases or sales required to meet retail and wholesale obligations physically settled.
Other includes sales of natural gas or oil in excess of generating plant requirements and revenues from transmission services, pole contact rentals, and certain other electric services to customers.
Demand for electricity by residential customers is affected by weather. Retail customer demand is typically highest in the winter across PGEs service territory when heating and lighting are heavily used. Customer demand also peaks in the summer months primarily due to the use of air conditioning. Within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns for residential customers.
Heating degree-days is an indication of the likelihood that customers will use heating and cooling degree-days is an indication of the likelihood that customers will use air conditioning. Heating and cooling degree-days data is used to measure the effect of weather on the demand for electricity. A degree-day is measured by the difference between a base temperature of 65 degrees Fahrenheit and the average temperature for a given day. The following table indicates the heating and cooling degree-days for 2008, 2007 and 2006, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:
PGEs all-time high net system load peak was 4,073 MW and occurred in December 1998. The Companys all-time summer peak was 3,743 MW, which was driven by unusually warm weather and increased air conditioning demand, and occurred in August 2008. For 2008, PGEs peak load was 4,031 MW, which occurred in December. PGEs average load was 2,623 MW for the winter and 2,324 MW for the summer in 2008, compared to 2,638 MW for winter and 2,271 MW for summer in 2007.
Power and Fuel Supply
PGE relies primarily upon its generating resources, as well as long- and short-term power purchase contracts, to meet its customers energy requirements. The Company also continues to emphasize the expansion of renewable energy resources, as well as energy efficiency measures, to meet such needs and enhance customers ability to manage their energy use more efficiently. The following table summarizes PGEs average resource capability (in MW) for the last three years:
That portion of PGEs energy requirements generated by its plants will vary from year to year and is determined by various factors, including planned and forced outages, availability and price of coal and natural gas, precipitation and snow-pack levels, and the market price of electricity. For information regarding actual generating output and purchases for the period 2006-2008, see the Results of Operation section of Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation.
PGEs current generating portfolio consists of thermal, hydro, and wind resources. For a complete listing of these facilities, see Item 2. - Properties.
Dispatchable Standby Generation (DSG) - PGE has a DSG program under which the Company can start, operate, and monitor customer-owned standby generators when needed to meet peak demand. The program helps provide operating reserves for the Companys generating resources and, when operating, can supply most or all of DSG customer loads. As of December 31, 2008, there were 23 projects that together provide approximately 48 MW of diesel-fired capacity at peak times.
PGE supplements its own generation with long- and short-term wholesale contracts as needed to meet its retail load requirement and provide the most economic mix on a variable cost basis. Such contracts have terms ranging from one to 30 years and expire at varying dates through 2035. The following briefly describes the Companys major power purchase contracts:
Capacity/exchange - These contracts provide PGE with firm capacity to help meet the Companys peak loads. The contracts range from 30 MW to 300 MW and expire at various dates from 2009 through 2016. They include seasonal exchange contracts with other western utilities that help meet both winter- and summer-peaking requirements.
Mid-Columbia hydro - PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of four hydroelectric projects on the mid-Columbia River. The projects currently provide a total of 545 MW of firm capacity. Under terms of its contract with one of the districts, the Companys share of the combined output of two of the projects is expected to decline from the current 233 MW to an estimated 158 MW in 2010 as the energy requirements of the district increase.
Confederated Tribes - PGE has a two-thirds ownership interest in the 450 MW Pelton/Round Butte hydroelectric project on the Deschutes River in central Oregon, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (Tribes). A 50-year joint license for the project, which is operated by PGE, was issued by the FERC in 2005. PGE has a long-term agreement that requires the Company to purchase, at market prices, the Tribes interest in the output of the project during the term of the license.
Wind - The Company has two long-term contracts, which extend to 2028 and 2035, that provide for the purchase of renewable wind-generated electricity.
Other - These consist of long-term contracts to purchase power from various counterparties, including other Pacific Northwest utilities, over terms extending up to 2018.
Short-term contracts - These contracts are for delivery periods of one month up to one year in length. They are entered into with various counterparties to provide additional firm energy to help meet the Companys load requirement.
For further information regarding PGEs power purchase contracts, see Note 15, Commitments and Guarantees, in the Notes to Consolidated Financial Statements.
Solar - As part of its efforts to secure additional renewable energy resources, PGE has invested in two photovoltaic solar power projects through separate limited liability companies. The first project, with an installed capacity of approximately 104 kW, is located on property owned by the Oregon Department of Transportation. The second project, with a total installed capacity of approximately 1,095 kW, is located on the rooftops of three distribution warehouses in Portland. The projects were placed in service in December 2008 and January 2009. PGE serves as managing member for the limited liability companies, in which it has an initial interest of less than 1%, and operates both facilities under an agreement with the investor member.
PGE contracts for natural gas and coal supplies required to fuel the Companys thermal generating plants, with certain plants also able to operate on fuel oil if needed. In addition, the Company uses forward, swap, option, and futures contracts to manage its exposure to volatility in natural gas prices.
PGEs base of thermal, hydroelectric, and wind generating resources, along with wholesale power market products, currently provides the Company with the flexibility to respond to seasonal fluctuations in the demand for electricity from its retail and wholesale customers. PGE anticipates that generating capacity within the WECC, as well as an active wholesale market, will continue to provide sufficient supply to supplement the Companys generation and long-term power contracts. To meet anticipated future energy requirements and help assure continued system reliability, PGE utilizes an integrated resource planning process for acquisition of new supply. The process incorporates input from several sources and includes long-term projections of resource adequacy prepared by both PGE and the WECC.
Integrated Resource Plan
PGEs Integrated Resource Plan (IRP), required by the OPUC, describes the Companys energy supply strategy. The primary goal of the IRP is to identify an acquisition plan for generation, transmission, demand-side and energy efficiency resources that, along with the Companys existing portfolio, provide the best combination of expected cost and associated risks and uncertainties for PGE and its customers.
PGE filed an IRP with the OPUC in June 2007 covering the years 2008 through 2015. It proposed additional energy efficiency programs as well as renewable and demand-side resources. It also proposed power purchase agreements of varying terms and the acquisition of additional peaking capacity.
The OPUC did not officially acknowledge the Companys IRP, but found key elements of the plan to be reasonable and directed PGE to proceed with a Request for Proposal (RFP) for up to 218 MWa of new renewable resources. PGE issued the RFP in 2008 and developed a final short list of proposals in November, with negotiations expected to be completed in 2009. PGE began construction of Phases II and III of Biglow Canyon and proceeded with its proposed expansion of energy efficiency programs. Also during 2008, PGE began evaluating proposals received in response to an RFP issued for 50 MW of demand response measures, with agreements expected to be completed in 2009.
As requested by the OPUC, PGE has begun preparation of a new IRP that addresses resource requirements through 2020. PGE expects to file the updated IRP by late 2009.
Transmission and Distribution
PGE operates one balancing authority area in its service territory. A balancing authority area is an electric system bounded by interchange metering. PGE is responsible for continuously balancing electric supply to its customers with PGEs generated power and the power the Company purchases and sells with other entities so that generation internal to the balancing authority area, plus net imported power, matches customer loads. PGE 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, 2008, PGE delivered approximately 21.4 million MWh to retail and wholesale customers in its balancing authority area through approximately 1,100 miles of transmission lines.
PGEs transmission system is part of the Western Interconnection, the regional grid in the western United States. The Western Interconnection includes the interconnected transmission systems of 11 western states, two Canadian provinces and parts of Mexico, and it is subject to the reliability rules of the WECC and the NERC. PGEs transmission system, together with contractual rights on other transmission systems, enables the Company to integrate and access generation resources to meet its customers load requirements. PGEs generation is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of the Companys transmission and distribution systems are located:
PGEs wholesale transmission services are regulated by the FERC pursuant to the Companys OATT, which is filed with the FERC and provides for market-based rates. In accordance with its OATT, PGE offers several transmission services to wholesale customers:
These services are offered on a non-discriminatory basis, with all potential customers provided an equal opportunity to access PGEs transmission system. PGEs transmission business is managed and operated independently from the power marketing business in accordance with the FERCs Standards of Conduct.
PGE is currently considering several generation interconnection projects (collectively referred to as the Southern Crossing Project) under the Companys OATT. The Southern Crossing Project is being designed to integrate several of PGEs generation resources to include Boardman and Coyote Springs and other proposed wind and thermal generation projects. The addition of these generation resources necessitates the development of a significant, new, high-voltage transmission system across the Oregon Cascades to PGEs service territory. The Company is working closely with other utilities and the WECC to coordinate the Southern Crossing Project.
For additional information, see the Transmission and Distribution section of Item 2. - Properties.
PGE operates in a state that is recognized for its environmental leadership and awareness. Accordingly, the Companys policy of environmental stewardship seeks to minimize risk and waste in its operations and promote the efficient use of energy.
PGEs operations are subject to a wide range of environmental protection laws, including those related to air and water quality, noise, waste disposal, endangered species, and climate change. The U.S. Environmental Protection Agency (EPA) and certain state agencies, including the Oregon Environmental Quality Commission (OEQC), the Oregon Department of Environmental Quality (DEQ), the Oregon Department of Energy, and the EFSC, have direct jurisdiction over environmental matters that include the siting and operation of generation and transmission facilities and the accumulation, cleanup, and disposal of toxic and hazardous substances. In addition, the Companys hydroelectric facilities are regulated and licensed by the FERC and are, in some cases, located on property under the jurisdiction of the U.S. Forest Service, which has authority over environmental protection in those cases.
Clean Air Standards
Clean Air Act - PGEs operations, principally its thermal generation plants, are subject to the federal Clean Air Act (CAA). Primary pollutants addressed by the CAA that affect PGE are sulfur dioxide (SO2), nitrogen oxides, carbon monoxide, and particulate matter. State governments also monitor and administer certain portions of the CAA and must set standards that are at least equal to federal standards. Oregons air quality standards currently equal or exceed federal standards.
PGE manages its air emissions by the use of low sulfur fuel, emission controls, emission monitoring, and combustion controls. The SO2 emissions allowances awarded under the CAA, along with expected future annual allowances, are anticipated to be sufficient to permit the Company to operate its thermal generation plants at forecasted capacity for at least the next several years within the limitations of current SO2 emission requirements.
Clean Air Mercury Rule - The federal government adopted the Clean Air Mercury Rule in 2005 to regulate mercury air emissions from coal-fired generating plants. That rule was vacated by an appellate court decision in 2008; however, the states in which PGE facilities are located have adopted the following regulations concerning mercury emissions that could have an impact on the Companys Boardman and Colstrip plants:
Regional Haze - In accordance with federal regional haze rules aimed at visibility impairment in several federally protected areas, the DEQ conducted an assessment of emission sources that has
indicated that the Boardman generating plant may cause or contribute to visibility impairment in several federally protected areas and would be subject to a Regional Haze Best Available Retrofit Technology (BART) Determination.
In December 2008, the DEQ issued a proposed plan that would require the installation of controls at Boardman in three phases. PGE estimates that the DEQ plan would cost between $575 million and $636 million (100% of total costs, excluding AFDC, in nominal dollars). PGE has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change.
The comment and public input period for the DEQ proposed plan has closed. PGE commented with an alternative BART/Reasonable Progress proposal that would allow for decision points along the DEQ timeline to provide flexibility to make the most responsible decision on future controls at those points. The OEQC is expected to adopt a rule in April 2009 now that the public process has been completed. The rule will be submitted to the EPA for approval as part of the Oregon Regional Haze State Implementation Plan (SIP). The Company expects the EPA to issue a decision on the SIP in early 2010.
Greenhouse gas emissions and their potential impacts on climate change have recently received increased public attention, with several legislative efforts initiated to establish mandatory control of greenhouse gas emissions. PGE is participating as a stakeholder in the Western Climate Initiative, a regional accord with a stated goal of reducing greenhouse gas emissions to 15% below 2005 levels by the year 2020. The DEQ, also a participant in the regional accord, has issued a notice of advanced rulemaking that would require reporting of greenhouse gas emissions for stationary sources. Any future laws that impose mandatory reductions in greenhouse gas emissions could have a material impact on PGE, as the Company relies on fossil fuels as a resource for power generation. PGEs Beaver, Coyote Springs, and Port Westward natural gas fired facilities and the Companys ownership shares of the Boardman and Colstrip coal plants provide nearly 75% of the Companys net generation capability.
Water Quality and Endangered Species Protection
Populations of many migratory fish species in the Pacific Northwest have declined significantly over the last several decades. Many of these distinct populations have been granted protection under the federal Endangered Species Act (ESA). Long-term recovery plans for these species include major operational changes to the regions hydroelectric projects. Significant changes thus far include modification in the timing of stored water releases, a spill program to assist juvenile fish at federal dams located in the Columbia River and Snake River basins, and continued investment in fish protection infrastructure (ladders and screens). These changes have resulted in occasional reductions in hydroelectric generation capability and the seasonal shifting of other generation from the fall and winter periods to the spring and summer periods. While PGE does not own facilities on these rivers, the Company does have contracts for power generated at facilities on the mid-Columbia River in central Washington and may be adversely affected by such reductions and seasonal shifting at those facilities. The timing of stored water releases also has an influence on the availability and prices of power in the regional wholesale market in which PGE participates to acquire adequate power to serve its retail customers.
PGE is implementing a series of fish protection measures at its hydro generation facilities on the Clackamas, Deschutes, and Willamette rivers that were prescribed by the U.S. Fish and Wildlife
Service and the National Marine Fisheries Service under their authority granted in the ESA and are contained in the Companys FERC operating licenses.
In accordance with a 2002 agreement with state and federal agencies, environmental groups, and others, PGE is proceeding with decommissioning the Companys 22 MW Bull Run hydroelectric project, which included the Marmot and Little Sandy dams, located in the Sandy River basin. During 2008, the project ceased generation, as planned. Decommissioning and removal of project facilities continues in accordance with a FERC Surrender Order issued in 2004.
PGE has a comprehensive program to comply with requirements of both federal and state regulations related to hazardous waste storage, handling and disposal. The handling and disposal of hazardous waste from PGE facilities is subject to regulation under the federal Resource Conservation and Recovery Act. In addition, the use, disposal, and clean-up of polychlorinated biphenyls, contained in certain electrical equipment, is regulated by the federal Toxic Substances Control Act.
PGE is also subject to regulation under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA), referred to as Superfund. CERCLA can assert joint and several liability for investigation and remediation costs for designated Superfund sites. PGE is currently listed by the EPA as a Potentially Responsible Party (PRP) at two Superfund sites discussed below.
Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (USDOE) is responsible for the permanent storage and disposal of spent nuclear fuel. PGE has contracted with the USDOE for permanent disposal of spent nuclear fuel for Trojan. Trojan spent nuclear fuel is stored in the Independent Spent Fuel Storage Installation (ISFSI), an NRC-licensed interim dry storage facility that houses the fuel at the plant site until the permanent off-site storage is available. No federal repository is expected to be available until 2020. Shipment of the spent nuclear fuel stored in the ISFSI to the off-site storage is not expected to be completed prior to 2033.
Portland Harbor - A 1997 investigation by the EPA of a segment of the Willamette River, known as the Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included the Portland Harbor on the federal National Priority List pursuant to CERCLA and listed sixty-nine PRPs, including PGE.
The Portland Harbor is currently undergoing a remedial investigation and feasibility study (RI/FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs, not including PGE. In the AOC, the EPA determined that the RI/FS would focus on a segment of the river approximately 5.7 miles in length.
In January 2008, PGE received a request from the EPA requiring the Company to provide information concerning its properties in or near the area being examined in the RI/FS, as well as several miles beyond that 5.7 mile segment. PGE requested, and the EPA has granted, an extension to August 2009 to respond. The boundaries of the site will be determined at the conclusion of the RI/FS in a Record of Decision, expected in 2010, in which the EPA will document its findings and select a preferred cleanup alternative.
Harbor Oil - In 2005, PGE received a Special Notice Letter for Remedial Investigation/Feasibility Study from the EPA, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site, located in north Portland. The site includes the location of a company, Harbor Oil, Inc., that PGE utilized to process used oil from power plants and electrical distribution systems until 2003. The Harbor Oil facility continues to be utilized by other entities for the processing of used oil and other lubricants. The EPA has approved an RI/FS work plan for the site and on-site sampling commenced in 2008.
For further information on EPA actions, see Environmental Matters in Note 18, Contingencies, in the Notes to Consolidated Financial Statements.
Certain risks and uncertainties that may affect PGEs business, financial condition, results of operation or cash flows, or that may cause the Companys actual results to vary from the forward-looking statements contained in this Annual Report on Form 10-K, include those set forth below.
Recovery of PGEs costs is subject to regulatory review and approval, and the inability to recover costs may adversely affect the Companys results of operation.
The prices that the OPUC authorizes PGE to charge for its retail services are the major factor in determining the Companys operating income, financial position, liquidity, and credit ratings. The OPUC has the authority to disallow recovery of any costs that it considers excessive or imprudently incurred. Furthermore, the regulatory process does not provide assurance that PGE will be able to achieve the earnings level authorized. In PGEs most recent general rate case, the Companys initial proposal included an overall rate increase of 8.9%, compared to a 7.3% overall increase approved by the OPUC. The Company will seek to manage costs at levels consistent with the reduced rate increase. However, if the Company is unable to do so, or if such cost management results in increased operational risk, the reduced rate increase could adversely affect the Companys operations or results of operations. For further information, see the Overview section of Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation.
Currently, PGE utilizes a PCAM by which the Company can adjust future prices to reflect a portion of the difference between each years forecasted and actual NVPC. Use of the approved cost sharing methodology requires that PGE absorb certain power cost increases before the Company is allowed to recover any amount from customers. Accordingly, application of the PCAM is expected to only partially mitigate the potentially adverse financial impact of forced generating plant outages, severe weather, reduced hydro availability, and volatile wholesale energy prices.
The current capital and credit market conditions may adversely affect the Companys access to capital, cost of capital, and ability to execute its business plan as scheduled.
Access to capital markets is important to PGEs ability to operate. The Company will face significant capital requirements for several large projects in the near term and expects to issue both debt and equity in 2009 in order to fund such projects. In addition, because of contractual commitments and regulatory requirements, the Company has limited ability to delay or terminate these projects, which include Biglow Canyon and the smart meter project. For further information concerning PGEs capital requirements, see Capital Requirements in the Liquidity and Capital Resources section of Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation.
Recently, the general economic and capital market conditions in the United States and other parts of the world have deteriorated significantly and have adversely affected access to capital and increased the cost of capital. If these conditions continue or become worse, the Companys future cost of debt and equity capital and access to capital markets could be adversely affected. In addition, restrictions on PGEs ability to access capital markets could affect its ability to execute its business plan as scheduled.
The current economic downturn has reduced the demand for electricity and has impaired the financial soundness of customers, which has adversely affected PGEs results of operation and could continue to do so. The economic downturn could also impair the financial soundness of the Companys vendors and service providers.
The slowing of the Oregon and national economies has resulted in reduced demand for electricity and could result in a continued reduction in such demand. This reduced demand has decreased the Companys earnings and cash flow and could continue to do so. In Oregon, the economic slow-down has included a sustained decline in the housing market and rising unemployment. Oregons unemployment rate rose from an average of 5.2% for 2007 to an average of 6.3% for 2008, compared to the national average unemployment rate of 5.8%. Oregons seasonally-adjusted unemployment rate increased to 9% in December 2008.
In addition, the Companys uncollectible customer accounts increased in the fourth quarter of 2008. If customers are not successful in generating sufficient revenue or are precluded from securing financing, they may not be able to pay, or may delay payment of, amounts owed to the Company. Any further inability of customers to pay the Company could adversely affect the Companys earnings and cash flow.
Furthermore, as a result of the current economic downturn affecting the economies of the state of Oregon, the United States and other parts of the world, the Companys vendors and service providers could experience serious cash flow problems. As a result, PGEs vendors and service providers may be unable to perform under existing contracts or may significantly increase their prices or reduce their output or performance on future contracts.
PGE faces regulatory and litigation risk with respect to recovery of the Companys investment in the closed Trojan Nuclear Plant.
There remains uncertainty regarding the ultimate outcome of legal and regulatory proceedings related to PGEs recovery of its investment in Trojan, which was closed in 1993. With respect to the OPUC proceedings, the Utility Reform Project (URP) and the class action plaintiffs have separately appealed, to the Oregon Court of Appeals, the September 30, 2008 OPUC order requiring PGE to refund $33.1 million to customers. With respect to the class actions, the Circuit Court has not yet ruled on the plaintiffs motion to lift the abatement of the class action proceedings. The outcome of these proceedings could have a material adverse affect on PGEs results of operation and liquidity. For further information regarding Trojan legal and regulatory proceedings, see Legal Matters in Note 18, Contingencies, in the Notes to Consolidated Financial Statements and Item 3. - Legal Proceedings.
Adverse market performance could result in further reductions in the fair market value of benefit plan trust assets and increase the Companys liabilities related to such plans. Such changes could result in a significant increase in funding requirements.
Performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under the Companys pension plan. Sustained adverse market performance, such as the losses in market value that reduced the value of the Companys pension plan trust assets in 2008, may result in lower rates of return for these assets than projected by the Company and could increase PGEs funding requirements related to the pension plan. Additionally, changes in interest rates affect the Companys liabilities under the pension plan. As interest rates decrease, the Companys liabilities increase, potentially requiring additional funding.
Performance of the capital markets also affects the value of assets that are held in trust to satisfy future obligations under the Companys non-qualified employee benefit plans, which include deferred compensation plans and a Supplemental Executive Retirement Plan. A reduction in the value of these assets is recorded through current earnings and would adversely affect the funded status of the plans.
If PGE is unable to obtain sufficient financial returns on its benefit plan trust assets, the Companys operating results and cash flows could be negatively affected. For further information regarding PGEs contribution obligations under its pension and non-qualified benefit plans, see Current Market Conditions - Valuation of Investments in the Overview section of Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation, the Contractual Obligations and Commercial Commitments table in the Liquidity and Capital Resources section of Item 7, and Pension and Other Postretirement Plans in Note 10, Employee Benefits, in the Notes to Consolidated Financial Statements.
Wholesale energy markets are subject to forces that are often not predictable and which can result in price volatility, deterioration of liquidity, and general market disruption, adversely affecting PGEs costs and ability to manage its energy portfolio and procure required energy supply.
Wholesale electricity prices in the western United States are influenced primarily by factors related to supply and demand. These factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, and changes in technology. Volatility in wholesale energy markets can affect the availability and price of purchased power and demand for energy.
Changes in the creditworthiness of large wholesale counterparties can also affect PGEs variable power costs. Further, disruption in wholesale markets could result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, affect wholesale energy prices, and impair PGEs ability to manage its energy portfolio. Changes in wholesale energy prices can also affect the market value of derivative instruments and cash requirements to purchase electricity. Although the Companys PCAM can be expected to partially mitigate adverse financial effects related to wholesale market conditions, cost sharing features of the mechanism do not provide for full recovery in customer prices.
Fluctuations in the price of natural gas purchased as fuel for electricity generation can also impact the Companys liquidity. Recently, as a result of declining wholesale power and natural gas prices, PGE has been required to provide increased margin deposits pursuant to existing purchased power and natural gas agreements. If wholesale power and natural gas prices continue to decline, PGE could be required to continue to provide increased margin deposits, which could adversely affect the Companys liquidity.
Fluctuations in the price of natural gas purchased as fuel for electricity generation can also impact results of operations. PGE purchases natural gas in the open market or pursuant to short-term or variable-price contracts as part of its normal business operations. If market prices rise, especially during periods when the Company requires greater-than-expected volumes that must be purchased at market or short-term prices, PGE could incur greater costs than originally estimated. The Company may not be able to fully recover these increased costs through ratemaking.
Under certain circumstances, one or more of the banks participating in PGEs credit facilities could decline to fund an advance requested by the Company or could withdraw from participation in the credit facility.
The Company has a $370 million multi-year revolving credit facility, of which $10 million expires in July 2012 and $360 million expires in July 2013, and a $125 million 364-day revolving credit facility, which expires in December 2009. Each facility is with a group of banks. These facilities supplement operating cash flow and provide a primary source of liquidity. The facilities are also used as backup for commercial paper borrowings and are available for general corporate purposes. The Company is required to make certain representations to the banks each time it requests an advance under one of the facilities.
These facilities are commitments on the part of the banks to make loans and, in the case of the multi-year revolving credit facility, to issue letters of credit. However, in the event of the occurrence of certain events that could result in a material adverse change in the business, financial condition or results of operation of PGE, the Company may not be able to make certain representations in which case the banks would not be required to lend. We are also subject to the risk that one or more of the participating banks may default on its obligation to make loans under the credit facilities.
In addition, it is possible that the Company might not be aware of certain developments at the time it makes such a representation in connection with a request for an advance, which could cause the representation to be untrue at the time made and constitute an event of default. Such a circumstance could result in a loss of the banks commitments under the facilities and in certain circumstances an acceleration of repayment of any outstanding advance.
Adverse changes in PGEs credit ratings could negatively affect its access to the capital markets and its cost of borrowed funds.
Access to capital markets is important to PGEs ability to operate and to complete its ongoing capital projects, such as Biglow Canyon and the smart meter project. In their normal course of business, credit rating agencies re-examine PGEs credit ratings on a periodic basis and when certain events occur. A ratings downgrade could increase the interest rates and fees on PGEs revolving credit facilities, increasing the cost of funding day-to-day working capital requirements, and could also require the Company to pay higher interest rates on future long-term debt. In addition, access to the commercial paper market, a principal source of short-term financing, could be restricted, possibly resulting in higher interest costs. The Companys secured and unsecured debt is currently rated at investment grade by Moodys Investors Service (Moodys) and Standard and Poors (S&P). In January 2009, S&P revised its outlook on PGE from stable to negative and affirmed PGEs corporate credit rating. The outlook revision reflects the possibility that, in 2009, PGEs debt balances may increase and credit metrics may weaken to levels that would not be commensurate with S&Ps expectations for the current BBB+ corporate rating. Should Moodys and/or S&P reduce their rating on the Companys unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, which could have an adverse effect on the Companys liquidity.
The effects of weather on electricity usage can adversely affect operating results.
Weather conditions can adversely affect PGEs revenues and costs and have an impact on the Companys financial and operating results. Temperatures outside the normal range can affect customer demand for electricity, with warmer-than-normal winters or cooler-than-normal summers reducing energy sales and revenues. Weather conditions are the dominant cause of usage variations from normal seasonal patterns, particularly for residential customers. Severe weather can also disrupt energy delivery and damage the Companys transmission and distribution system.
Rapid increases in load requirements resulting from unexpected adverse weather changes, particularly if coupled with transmission constraints, could adversely impact PGEs cost and ability to meet the energy needs of its customers. Conversely, rapid decreases in load requirements could result in the sale of excess energy at depressed market prices.
Weather conditions that reduce stream flows could adversely affect PGEs hydro production and increase the Companys generation or power purchase costs required to meet the shortfall.
PGE derives a portion of its power supply from its hydroelectric facilities and from those owned by certain public utility districts in the state of Washington and the city of Portland, with whom the Company has long-term power purchase contracts. Regional rainfall and snow pack levels affect stream flows and the resulting amount of generation available from these facilities. Shortfalls in low-cost hydro production would require increased generation from the Companys higher cost thermal plants and/or power purchases in the wholesale market, which could have an adverse effect on operating results. As indicated above, application of the Companys PCAM could help mitigate adverse financial effects of such shortfalls. However, full recovery is not assured and any inability to fully recover such costs in future rates could have a negative impact on the Companys results of operation.
Forced outages at PGEs generating plants can increase the cost of power required to serve customers because the cost of replacement power purchased in the wholesale market generally exceeds the Companys cost of generation.
Forced outages at the Companys generating plants could result in replacement power costs greater than those included in customer prices. As indicated above, application of the Companys PCAM could help mitigate adverse financial impacts of such outages. However, full recovery is not assured and any inability to fully recover such costs in future rates could have a negative impact on the Companys results of operation.
Measures required to comply with state and federal regulations related to emissions from thermal electric generating plants could result in increased capital expenditures and changes to the Companys operations that could increase operating costs, reduce generating capacity and adversely affect PGEs results of operation.
Oregon and federal regulators are currently considering the air emission standards applicable to PGEs thermal generating plants in Oregon as part of separate regulatory processes related to haze, mercury, and the Companys air permits. Oregon regulators have adopted measures that will require installation of mercury controls at PGEs Boardman coal plant. Additional emissions controls could be required at Boardman, although specific measures will depend on the outcome of the regulators reviews. For further information, see Environmental Matters in Item 1. - Business.
Although the full impact of required state and federal remediation measures is not yet determinable, they could have an adverse effect on future operations, operating costs, and generating capacity at both Boardman and Colstrip. The Company would seek to recover through the ratemaking process any costs of additional emission control equipment or emission reduction measures that may be required. However, there can be no assurance that such recovery would be granted.
In addition, PGE could be subject to litigation brought by environmental groups and other private parties alleging violations of state or federal law and seeking the imposition of penalties, damages, injunctive relief, and the closure of plants. For further information, see Sierra Club et al. v. Portland General Electric Company in Item 3. - Legal Proceedings.
Failure of PGEs wholesale suppliers to perform their contractual obligations could adversely affect the Companys ability to deliver electricity and increase the Companys costs.
PGE relies on suppliers to deliver natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure of suppliers to comply with existing contracts in a timely manner could disrupt PGEs ability to deliver electricity and require the Company to incur additional expenses to meet the needs of its customers. In addition, as these contracts expire, PGE could be unable to continue to purchase natural gas, coal or electricity on terms and conditions equivalent to those of existing agreements. Cost and availability of natural gas and coal can also impact the cost and output of the Companys thermal generating plants.
The construction of new generating facilities, or modifications to existing facilities, is subject to risks that could result in the disallowance of certain costs for recovery in prices, reduced plant efficiency, or higher operating costs.
Long-term increases in both the number of customers and demand for energy will require continued expansion and reinforcement of PGEs generation, transmission, and distribution systems.
Construction of new generating facilities, or modifications to existing facilities, could be affected by various factors, including unanticipated delays and cost increases, which could result in the disallowance of certain costs in the rate determination process. In addition, the failure to complete construction projects according to specifications could result in reduced plant efficiency, equipment failure, and plant performance that falls below expected levels, which could increase operating costs.
Capital expenditures and changes in operations required to comply with both existing and new environmental laws related to fish and wildlife could adversely affect PGEs results of operation.
A portion of PGEs total energy requirement is comprised of generation from hydroelectric projects on the Columbia, Clackamas, Deschutes, and Willamette rivers. Operation of these projects is subject to extensive regulation related to the protection of fish and wildlife. The listing of various species of salmon, wildlife, and plants as threatened or endangered has resulted in significant changes to federally-authorized activities, including those of hydroelectric projects. Salmon recovery plans could include further major operational changes to the regions hydroelectric projects, including those owned by PGE and those from which the Company purchases power under long-term contracts. In addition, new interpretations of existing laws and regulations could be adopted or become applicable to such facilities, which could further increase required expenditures for salmon recovery and endangered species protection and reduce the amount of hydro generation available to meet the Companys energy requirements. The Company would likely seek recovery of any such expenditures through the ratemaking process; however, there can be no assurance that such recovery would be granted.
Legislative or regulatory efforts to reduce greenhouse gas emissions, in response to concerns related to climate change, could lead to increased capital and operating costs and have an adverse impact on the Companys operations or results of operation.
The outcome of legislative or regulatory efforts regarding greenhouse gas emissions, whether at the international, federal, regional, state, or local level, or the timing of any such laws or regulations that could be enacted, could have a material adverse effect on future results of operations and cash flows unless the additional costs incurred to comply with such laws or regulations can be recovered through regulated rates and/or future market prices for electricity. The cost of compliance with such measures could also make some of PGEs electric generating units uneconomical to operate or maintain. The Company would likely seek to recover through the ratemaking process any costs of additional emission control equipment or emission reduction measures, such as the cost of sequestration or purchasing allowances, or offset the cost of credits that may be required; however, there can be no assurance that such recovery would be granted.
PGE expects that future federal, and possibly state, legislation or regulation may result in the imposition of limitations on the Companys greenhouse gas emissions from fossil fuel-fired electric generating units. A number of bills have been introduced in the U.S. Congress that would require greenhouse gas emission reductions from fossil fuel-fired electric generation facilities and other sectors of the economy, although no such bill has yet been enacted. Compliance with these greenhouse gas emission reduction requirements could require PGE to make significant expenditures, including with respect to carbon capture and sequestration technology, purchase of emission allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and replacement with lower emitting generation facilities.
The costs of compliance with these expected greenhouse gas requirements are subject to significant uncertainties, including with respect to the timing of the implementation of emission rules, required
levels of emission reductions, emission allocation requirements, the maturation, regulation and commercialization of carbon capture and sequestration technology, and PGEs selected compliance alternatives. As a result, PGE cannot estimate the effect of any such legislation on its results of operations, financial condition or cash flows; however, the costs of compliance with such requirements could be material.
PGE is subject to various legal and regulatory proceedings, the outcome of which is uncertain, and resolution unfavorable to PGE could adversely affect the Companys results of operation, financial condition or cash flows.
From time to time in the normal course of its business, PGE is subject to various regulatory proceedings, lawsuits, claims and other matters, which could result in adverse judgments, settlements, fines, penalties, injunctions, or other relief. These actions are subject to many uncertainties and management cannot predict the outcome of individual matters with assurance. The final resolution of some of the matters in which PGE is involved could require the Company to make additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have an adverse effect on its cash flows and results of operation. Similarly, the terms of resolution could require the Company to change its business practices and procedures, which could also have an adverse effect on its cash flows, financial position or results of operation.
Certain pending legal and regulatory proceedings, such as the Trojan litigation, the proceedings related to refunds on wholesale market transactions in the Pacific Northwest, and the investigation and any resulting remediation efforts related to the Portland Harbor site, may have an adverse effect on results of operations and cash flows for future reporting periods. For further information, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements and Item 3. - Legal Proceedings.
Storms and other natural disasters could damage the Companys facilities and disrupt its delivery of electricity resulting in significant property loss or repair costs and customer dissatisfaction.
The Company has exposure to natural disasters that can cause significant damage to its generation, transmission, and distribution facilities. Such events can interrupt the delivery of electricity, increase repair and service restoration expenses, and reduce revenues. Such events, if repeated or prolonged, can also affect customer satisfaction and the level of regulatory oversight. As a regulated utility, the Company is required to provide service to all customers within its service territory and generally has been afforded liability protection against customer claims related to service failures beyond the Companys reasonable control.
To the extent reasonably possible, PGE utilizes insurance as a means to cost effectively mitigate the risk of physical loss or damage to the Companys property resulting from natural disasters, subject to certain coverage terms and conditions. The Company believes that the losses sustained to its transmission and distribution property relating to the December 2008 winter storm that affected Oregon will likely exhaust all remaining benefits available under the Companys transmission and distribution property insurance policy. As a result, PGE would be responsible for any damage sustained to its transmission and distribution property related to future storms, unless additional insurance is obtained. Related losses through the end of the term of the current insurance policy, which terminates in October 2009, would increase costs. The Company would likely seek recovery of any future uninsured storm-related losses through the ratemaking process; however, there can be no assurance that any recovery would be granted. If such recovery is not granted, these increased costs could have
an adverse effect on PGEs results of operation in a future period. Additionally, PGE may not be able to obtain subsequent insurance policies for its transmission and distribution property with similar terms and rates.
PGEs business is subject to extensive regulation that affects the Companys operations and costs.
PGE is subject to regulation by the FERC and the OPUC, and by federal, state and local authorities under environmental and other laws. Such regulation significantly influences the Companys operating environment and affects many aspects of its business. Changes to regulations are ongoing, and the Company cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Companys business. However, changes in these regulations could delay or adversely affect business planning and transactions, and substantially increase the Companys costs.
PGE has an aging workforce with a significant number of employees approaching retirement age.
The Company anticipates higher averages of retirement rates over the next ten years and will likely need to replace a significant number of employees in key positions. PGEs ability to successfully implement a workforce succession plan is dependent upon the Companys ability to employ and retain skilled professional and technical workers. Without a skilled workforce, the Company would face greater challenges in providing quality service to its customers and meeting regulatory requirements, both of which could affect operating results.
Conditions that may be imposed in connection with the renewal of hydroelectric licenses could require large capital expenditures.
PGE is currently involved in renewing the federal license for its hydroelectric projects on the Clackamas River. The FERC, under the Federal Power Act, may impose conditions with respect to environmental, operating and other matters in connection with the renewal of PGEs license. The Company cannot predict with certainty the requirements that might be imposed during the relicensing process, the economic impact of those requirements, whether a new license will ultimately be issued or whether PGE will be willing to meet the relicensing requirements to continue operating its Clackamas hydroelectric projects. The Company would likely seek recovery of any additional costs related to such licensing requirements through the ratemaking process.
PGEs principal property, plant, and equipment are located on land owned by the Company in fee or land under the control of the Company pursuant to existing leases, federal or state licenses, easements or other agreements. In some cases, meters and transformers are located on customer property. The Company leases its corporate headquarters complex, located in Portland, Oregon. The Indenture securing the Companys First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility property and franchises, other than expressly excepted property.
The Companys service territory and generating facilities are indicated below:
The following are generating facilities owned by PGE as of December 31, 2008:
PGE holds FERC licenses under the Federal Power Act for its hydroelectric generating plants. The Companys Sullivan plant operates under a FERC license that expires in 2035, while the Pelton and Round Butte plants operate under a license that expires in 2055.
The Company filed an application with the FERC in 2004 to relicense the Clackamas River hydroelectric projects. A settlement agreement, resolving most of the issues raised in the relicensing proceeding and providing for a 45-year license term, was signed by the thirty-three participating parties in March 2006 and was submitted to the FERC for review and approval. The settlement agreement also provides for a collaborative process for the resolution of water temperature issues downstream of the project, which must be settled prior to the issuance of a new license. Pending approval of the new license, the project will operate under annual licenses issued by the FERC. It is expected that the FERC will issue a new license for the Clackamas River projects in 2010.
Transmission and Distribution
PGE owns and/or has contractual rights associated with transmission lines that deliver electricity from its Oregon generation facilities to its distribution system in its service territory and also to the Western Interconnect. As of December 31, 2008, PGE owned an electric transmission and distribution system consisting of approximately:
In addition to the transmission and distribution lines presented in the table above, PGE has approximately 24,000 circuit miles of primary and secondary distribution lines that deliver electricity to its customers.
The Company also has an ownership in and other contractual rights associated with transmission lines that deliver electricity as follows:
The California-Oregon AC Intertie and the Pacific DC Intertie are primarily used for the transmission of interstate purchases and sales of electricity among utilities, including PGE.
As of December 31, 2008, PGE owned 173 transmission and distribution substations throughout its service territory.
Citizens Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen ONeill v. Public Utility Commission of Oregon, Public Utility Commission of Oregon Docket Nos. DR 10, UE 88, and UM 989, Marion County Oregon Circuit Court, Case No. 94C-10417, the Court of Appeals of the State of Oregon, the Oregon Supreme Court, Case No. SC S45653.
Following the closure of Trojan, PGE, in its 1993 general rate filing, sought OPUC approval to recover through rates future decommissioning costs and full recovery of, and a rate of return on, its Trojan investment. PGEs request was challenged and PGE requested from the OPUC a Declaratory Ruling (Docket DR 10) regarding recovery of the Trojan investment and decommissioning costs. In August 1993, the OPUC issued a Declaratory Ruling in PGEs favor. The Declaratory Ruling was appealed to the Marion County Circuit Court, which in November 1994 upheld the OPUCs Declaratory Ruling. The Citizens Utility Board (CUB) appealed the decision to the Oregon Court of Appeals.
In PGEs 1995 general rate case (Docket UE 88), the OPUC issued an order (1995 Order) granting PGE full recovery of Trojan decommissioning costs and 87% of its remaining undepreciated investment in the plant. The URP filed an appeal of the 1995 Order to the Marion County Circuit Court, alleging that the OPUC lacked authority to allow PGE to recover Trojan costs through its rates. The CUB also filed an appeal to the Marion County Circuit Court challenging the portion of the 1995 Order that authorized PGE to recover a return on its remaining undepreciated investment in Trojan.
In April 1996, the Marion County Circuit Court issued a decision that contradicted the Courts November 1994 ruling. The 1996 decision found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan. The 1996 decision was appealed to the Oregon Court of Appeals, where it was consolidated with the earlier appeal of the 1994 decision.
In June 1998, the Oregon Court of Appeals ruled that the OPUC does not have the authority to allow PGE to recover a rate of return on its undepreciated investment in Trojan, but upheld the OPUCs authority to allow PGEs recovery of its undepreciated investment in Trojan and its costs to decommission Trojan (1998 Decision). The court remanded the matter to the OPUC for reconsideration of its 1995 Order in light of the courts decision (1998 Remand).
In August 1998, PGE and the URP each filed a Petition for Review with the Oregon Supreme Court seeking review of that portion of the 1998 Decision relating to PGEs return on its undepreciated investment in Trojan. On November 19, 2002, the Oregon Supreme Court dismissed both Petitions for Review.
In September 2000, PGE, CUB, and the OPUC Staff settled proceedings related to PGEs recovery of its investment in the Trojan plant (Settlement). The URP did not participate in the Settlement and filed a complaint with the OPUC, challenging PGEs application for approval of the accounting and ratemaking elements of the Settlement.
In March 2002, after a full contested case hearing (Docket UM 989), the OPUC issued an order (Settlement Order) denying all of the URPs challenges and approving PGEs application for the accounting and ratemaking elements of the Settlement. The URP appealed the Settlement Order to the
Marion County Circuit Court. On November 7, 2003, the Marion County Circuit Court remanded the case to the OPUC to reduce rates or order refunds (2003 Remand). The opinion did not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC each appealed the 2003 Remand to the Oregon Court of Appeals.
On October 10, 2007, the Oregon Court of Appeals issued an opinion that reversed the Settlement Order and remanded the Settlement Order to the OPUC for reconsideration. The Oregon Court of Appeals also vacated the 2003 Remand.
As a result of its reconsideration of the Settlement Order, on September 30, 2008, the OPUC issued an order that requires PGE to refund $33.1 million to customers.
In the order, the OPUC also made the following findings:
On October 22, 2008, the URP and the Class Action Plaintiffs (described in the Dreyer proceeding below) separately appealed the September 30, 2008 order to the Oregon Court of Appeals.
On December 1, 2008, the OPUC issued an order that suspended the requirements imposed on PGE by the refund methodology outlined in the September 30, 2008 order for 60 days. On January 24, 2009, counsel for the URP and the Class Action Plaintiffs filed a motion with the Oregon Court of Appeals requesting a stay of the refund pending final disposition of their appeal. On February 2, 2009, the OPUC issued Order No. 09-039, which suspended the requirements imposed on PGE by the refund methodology, pending the Court of Appeals decision on the Motion for Stay filed by the URP and Class Action Plaintiffs. Based on the OPUC orders and request for stay, the timing of the refunds to customers is uncertain, but could occur during 2009.
Management cannot predict the ultimate outcome of the above matter. However, it believes that this matter will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on the results of operation and cash flows in a future reporting period.
Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court, Case No. 03C 10639; and Morgan v. Portland General Electric Company, Marion County Circuit Court, Case No. 03C 10640.
On January 17, 2003, two class action suits were filed in Marion County Circuit Court against PGE on behalf of two classes of electric service customers. The Dreyer case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the Morgan case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million plus interest for the Current Class and $70 million plus interest for the Former Class, from the inclusion of a return on investment of Trojan in the rates PGE charges its customers.
On April 28, 2004, the plaintiffs filed a Motion for Partial Summary Judgment and on July 30, 2004, PGE also moved for Summary Judgment in its favor on all of the Class Action Plaintiffs claims. On December 14, 2004, the Judge granted the Plaintiffs motion for Class Certification and Partial Summary Judgment and denied PGEs motion for Summary Judgment. On March 3, 2005, PGE filed a Petition for a Writ of Mandamus with the Oregon Supreme Court asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed. On March 29, 2005, PGE filed a second Petition for an Alternative Writ of Mandamus with the Oregon Supreme Court seeking to overturn the Class Certification.
On August 31, 2006, the Oregon Supreme Court issued a ruling on PGEs Petitions for Alternative Writ of Mandamus abating these class action proceedings until the OPUC responded with respect to the certain issues that had been remanded to the OPUC by the Marion County Circuit Court in the proceeding described above.
On October 5, 2006, the Marion County Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions for one year.
On October 17, 2007, the plaintiffs in the class action suits filed a motion with the Marion County Circuit Court to lift the abatement.
At a status conference on October 15, 2008, the Circuit Court set a schedule for the filing of briefs on the plaintiffs motion to lift the abatement. Oral argument occurred on January 12, 2009. A decision on the motion to lift the abatement is pending.
Management cannot predict the ultimate outcome of the above matter. However, it believes that this matter will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on the results of operation and cash flows in a future reporting period.
Puget Sound Energy, Inc. v. All Jurisdictional Sellers of Energy and/or Capacity at Wholesale Into Electric Energy and/or Capacity Markets in the Pacific Northwest, Including Parties to the Western System Power Pool Agreement, Federal Energy Regulatory Commission, Docket Nos. EL01-10-000, et seq. (Pacific Northwest Refund proceeding).
On July 25, 2001, the FERC called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In November 2003 and February 2004, the FERC denied all requests for rehearing of its June 2003 decision. Parties appealed various aspects of these FERC orders to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).
On August 24, 2007, the Ninth Circuit issued its decision on appeal, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest Refund proceeding purchases of energy made by the
California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to (i) address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (iii) further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERCs findings based on the record established by the administrative law judge and did not rule on the FERCs ultimate decision to deny refunds. Two requests for rehearing have been filed with the court, with a decision now pending.
On May 17, 2007, the FERC approved a settlement between PGE and certain parties in the California refund case in Docket No. EL00-95, et seq. This resolves the claims as between PGE and the California parties named in the settlement as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 21, 2001. The settlement with the California parties does not resolve potential claims from other market participants relating to transactions in the Pacific Northwest.
Management cannot predict the outcome of the Pacific Northwest Refund proceeding, or whether the FERC will order refunds in the Pacific Northwest, and if so, how such refunds would be calculated. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGEs results of operation and cash flows in a future reporting period.
Sierra Club et al. v. Portland General Electric Company, U.S. District Court for the District of Oregon, Case No. CV 08-1136-HA.
On January 15, 2008, plaintiffs sent PGE a sixty-day notice of intent to sue for alleged violations of the federal Clean Air Act (CAA), Oregons State Implementation Plan (SIP) at PGEs Boardman Coal Plant, and the Plants CAA Title V permit. On September 30, 2008, the plaintiffs sued PGE for these and additional alleged violations of various environmental related regulations.
The plaintiffs seek injunctive relief that includes permanently enjoining PGE from operating the Boardman Coal Plant except in accordance with the CAA, Oregons SIP, and the Plants Title V Permit. In addition, plaintiffs seek civil penalties against PGE including $27,500 per day per alleged violation for violations occurring before March 15, 2004 and $32,500 per day per alleged violation occurring thereafter. The total amount of monetary penalties and damages asserted in the complaint cannot be determined with certainty. However, based solely on the complaint, the Company estimates that the amount is approximately $60 million. The Company believes that it has strong defenses to the plaintiffs claims and intends to vigorously defend against this lawsuit.
From time to time in the normal course of business, PGE is subject to various other regulatory proceedings, lawsuits, claims and other matters, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. Management currently does not believe any of these other matters will have a material adverse effect on the Companys financial position, results of operation or cash flows.
PGEs common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol POR. As of February 20, 2009, there were 1,252 holders of record of PGEs common stock and the closing sales price of PGEs common stock on that date was $16.74 per share. The following table sets forth, for the periods indicated, the highest and lowest sales prices of PGEs common stock as reported on the NYSE.
While PGE expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Companys Board of Directors. The amount of any dividend declaration depends upon factors that the Board of Directors deem relevant and may include, but are not limited to, PGEs results of operation and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.
As required by Section 303A.12 of the NYSE Listed Company Manual, Peggy Y. Fowler, the Chief Executive Officer of the Company, certified to the NYSE on May 29, 2008 that she was not aware of any violation by the Company of the NYSEs corporate governance listing standards.
The following consolidated selected financial data should be read in conjunction with Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation and Item 8. - Financial Statements and Supplementary Data.
Information Regarding Forward-Looking Statements
The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements relate to expectations, beliefs, plans, objectives for future operations, cash flows from operations, assumptions, business prospects, the outcome of litigation and regulatory proceedings, growth in demand for energy, future capital expenditures, market conditions, long-term earnings growth, the cost, completion and benefits of capital projects, future events, liquidity or performance, and other matters. Words or phrases such as anticipates, believes, should, estimates, expects, intends, plans, predicts, projects, will likely result, will continue, or similar expressions are intended to identify such forward-looking statements.
Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGEs expectations, beliefs and projections are expressed in good faith and are believed by PGE to have a reasonable basis including, without limitation, managements examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that PGEs expectations, beliefs or projections will be achieved or accomplished.
In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
PGE is a vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon, as well as the wholesale sale of electricity and natural gas in the western United States and Canada. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.
The Companys revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, customer usage patterns (which are affected by the condition of the local economy), and the availability and price of purchased power and fuel. PGE is a winter peaking utility that typically experiences its highest retail energy sales during the winter heating season, with a slightly lower peak in the summer that generally results from air conditioning demand.
General Rate Case Results - On January 23, 2009, the OPUC issued its final order concerning PGEs general rate case and proposed tariffs, which became effective on January 1, 2009. PGEs initial filing proposed an 8.9% average price increase related to higher purchased power and fuel costs, increased investment in utility plant, and higher operating expenses, compared to the 7.3% average price increase approved by the OPUC. The OPUC approved a cost of capital that provides for a capital structure of 50% equity and 50% debt and a return on equity of 10.1%. The order authorizes $121 million of increased revenues, consisting of approximately $95 million for NVPC and $26 million for other costs. Certain customer credits, including those related to 2007 results of the Companys PCAM, reduced the average price increase to approximately 5.6%. The OPUC also authorized PGE to file tariffs to implement a decoupling mechanism. For further information, see Decoupling Mechanism in Legal, Regulatory and Environmental Matters in this Item. Management is taking measures to manage costs in response to the final results of this general rate case.
Current Market Conditions - Volatile capital market conditions have adversely affected both access to capital and the cost of capital in global markets. PGE is continually assessing the impact of these market conditions on its operations, which include, but are not limited to, the following:
For additional information with respect to these and other matters, see Liquidity and Capital Resources in this Item 7. and Item 7A. - Quantitative and Qualitative Disclosures About Market Risk.
Customers - During 2008, PGE served an average of 811,315 retail customers compared to 800,587 during 2007, an increase of 1.3%. This customer growth, along with more extreme weather in 2008, resulted in a 1.9% increase in retail energy deliveries relative to 2007. On a weather adjusted basis, retail energy deliveries increased 0.8% from 2007.
The slow-down of the states economy, including a sustained decline in the housing market, continued throughout 2008 and into 2009. Oregons unemployment rate rose from an average of 5.2% for 2007 to an average of 6.3% for 2008, compared to the national average unemployment rate of 5.8%. Oregons seasonally-adjusted unemployment rate increased to 9% in December 2008. PGE projects weather adjusted energy deliveries for 2009 will be comparable to weather adjusted energy deliveries for 2008, which is a result of the increase in the unemployment rate.
Installation of a limited number of new smart meters has begun as part of the smart meter projects acceptance testing phase, with full deployment expected to be completed by the end of 2010 for residential and commercial customers. PGE expects the project to provide improved services as well as operational efficiencies and cost savings. A new tariff, effective from June 1, 2008 through December 31, 2010, provides for recovery of costs related to this project, including the remaining net investment of the meters being removed, during this period.
Capital and Financing - PGE maintains liquidity through revolving credit facilities totaling $495 million and access to the commercial paper market. As of December 31, 2008, the unused available credit under the credit facilities is $166 million, with $228 million available as of February 20, 2009.
During 2008, PGE issued $50 million and repurchased $56 million of long-term debt, and in December PGE entered into a $125 million 364-day revolving credit facility. In January 2009, PGE issued $130 million of long-term debt.
PGE has major capital projects in process, which require financing in 2009 and 2010. PGE estimates that as of December 31, 2008, and after considering the issuance of $130 million of First Mortgage Bonds in January 2009, it could issue up to $598 million of additional First Mortgage Bonds under the most restrictive issuance test as delineated in the Mortgage and Deed of Trust securing the bonds.
In May 2008, PGEs Board of Directors approved a 4.3% increase in the Companys quarterly common stock dividend, from $0.235 per share to $0.245 per share. Dividends declared totaled $61 million in 2008, $58 million in 2007, and $42 million in 2006.
Power Supply - PGE utilizes its own generating resources and wholesale market purchases to meet the energy and capacity needs of its customers. In 2008, the Companys generating plants provided approximately 62% of its retail load requirement, compared to 56% in 2007 and 37% in 2006. The sequential increases are primarily due to the addition of Port Westward and Biglow Canyon Phase I to the Companys generation portfolio in June and December 2007, respectively. Generation from PGEs hydroelectric plants provided approximately 10% of its retail load requirement in each of the last three years (2006-2008). Current forecasts indicate below normal regional hydro conditions for 2009.
Biglow Canyon Phases II and III are currently under construction, with completion expected by the end of 2009 and 2010, respectively. The two phases will have a combined installed capacity of approximately 324 MW, further increasing the diversity of the Companys generating resource portfolio while minimizing related environmental impacts. For further information regarding estimated future capital expenditures, see Capital Requirements in Liquidity and Capital Resources in this Item 7.
As part of the Companys integrated resource planning process, PGE in 2008 issued a request for proposals for 218 MWa of new renewable energy resources and has identified a final short list of bidders, with agreements expected to be completed in 2009. Such resources, which are in addition to
Biglow Canyon, are required to become available between 2009 and 2014 to meet requirements of Oregons Renewable Energy Standard.
PGE is currently preparing a new IRP to be filed by late 2009. PGE expects the new IRP to further define the Companys future energy and capacity needs and assess the economic viability of the proposed Boardman environmental retrofits.
Legal, Regulatory and Environmental Matters - On September 30, 2008, the OPUC issued an order in the matter of recovery of PGEs investment in Trojan. The order requires PGE to refund $33.1 million to customers who received service during the period October 1, 2000 through September 30, 2001. For further information, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements.
In December 2008, the DEQ issued a proposed plan that would require the installation of emission controls at Boardman under a phased-in approach. For further discussion of this matter, see Clean Air Standards, in Capital Requirements under Liquidity and Capital Resources in this Item 7.
PGE is a party to other proceedings whose ultimate outcome could have a material impact on the results of operations and cash flows in future reporting periods. These include matters related to:
For further information regarding the above and other matters, see Note 18, Contingencies, in the Notes to Consolidated Financial Statements.
The following price adjustments, as approved by the OPUC, became effective on January 1, 2009:
The above items, combined with other miscellaneous tariff changes, result in an overall retail price increase of approximately 5.6% effective January 1, 2009.
Recent and pending rate actions include, but are not limited to, the following:
The American Recovery and Reinvestment Act of 2009 - On February 17, 2009, the American Recovery and Reinvestment Act of 2009 (the Act) was enacted. The Act provides for tax and appropriation benefits to the utility industry including the following:
PGE is currently evaluating the impact of and alternatives under the Act.
Results of Operation
The following tables provide financial and operational information to be considered in conjunction with managements discussion and analysis of results of operation for 2008 compared to 2007, and for 2007 compared to 2006, which follow hereafter.
The consolidated statements of income for the periods presented (dollars in millions):
Revenues, energy sold and delivered (based on MWh), and retail customers consist of the following for the periods presented (dollars in millions and MWh in thousands):
PGEs total system load and retail load requirement for the periods presented are as follows (MWh in thousands):
Net income for the year ended December 31, 2008 was $87 million, or $1.39 per diluted share, compared to $145 million, or $2.33 per diluted share, for the year ended December 31, 2007. The decrease was due primarily to the following:
Partially offsetting the above decreases were:
Net income for the year ended December 31, 2007 was $145 million, or $2.33 per diluted share, compared to $71 million, or $1.14 per diluted share, for the year ended December 31, 2006. The increase was due primarily to the following:
2008 Compared to 2007
Revenues in 2008 were comparable to 2007, with an increase of $2 million, which is the result of the following offsetting factors:
Total retail revenues decreased $8 million, or 1%, due primarily to the following offsetting factors:
The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:
On a weather adjusted basis, retail energy deliveries increased 0.8% in 2008 compared to 2007, with deliveries to residential, commercial, and industrial customers increasing (decreasing) by 1.0%, (0.4)%, and 2.9%, respectively. PGE forecasts comparable total weather adjusted energy deliveries for 2009 relative to 2008.
Other retail revenues for 2008 and 2007 include $34 million and $42 million, respectively, in customer credits under the Residential Exchange Program administered by the BPA, with such amounts fully offset within Retail sales to residential and commercial customers. As a result of a decision by the Ninth Circuit, the BPA suspended such benefits in May 2007. In April 2008, benefits were temporarily restored under an Interim Relief agreement with the BPA. The resumption of customer credits, as approved by the OPUC, resulted in an average price reduction of approximately 6.3% for residential and small farm customers, effective April 15, 2008.
Wholesale revenues result from sales of electricity to utilities and power marketers which are made in conjunction with the Companys effort to secure reasonably priced power for its retail customers, manage risk and administer its current long-term wholesale contacts. Such sales can vary significantly period to period. Wholesale revenues in 2008 decreased $6 million, or 3%, from 2007 as a result of:
Other operating revenues increased $16 million, or 62%, primarily due to sales of fuel oil of $15 million in 2008, which resulted in realized gains totaling $11 million. Pursuant to an assessment of reliability requirements, PGE reduced its oil inventory level at its Beaver generating plant.
Purchased power and fuel expense for 2008 decreased slightly from 2007. Decreases were related to the following:
Offsetting the above decreases were:
The average variable power cost of PGEs total system load was $40.01 and $39.19 per MWh in 2008 and 2007, respectively, an increase of 2%. Averages exclude the effect of amounts related to regulatory power cost deferrals and wholesale credit provisions.
Current forecasts indicate that regional hydro conditions in 2009 will be below normal levels. Volumetric water supply forecasts for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies. The following indicates the forecast of the April-to-September 2009 runoff (issued February 20, 2009) compared to the actual runoffs for 2008 and 2007 (as a percentage of normal):
Production and distribution expense increased $19 million, or 13%, in 2008 due to the following factors:
Administrative and other expense increased $6 million, or 3%, in 2008 due to the following factors:
Depreciation and amortization expense increased $27 million, or 15%, in 2008 due largely to the following offsetting factors:
Taxes other than income taxes increased $3 million, or 4%, in 2008 due primarily to higher property taxes resulting from increases in assessed values, increased franchise fees resulting from higher retail revenues, and an increase in payroll taxes.
Other income (expense), net decreased $29 million, or 121%, in 2008 due primarily to the following factors:
Interest expense increased $16 million, or 22%, in 2008 primarily due to a higher level of outstanding long-term debt resulting from the issuance of additional First Mortgage Bonds during the second half of 2007 and into 2008. Long-term debt outstanding has increased as a result of funding the Companys capital projects. During 2008, the average outstanding balance of long-term debt was $1,310 million
compared to $1,158 million for 2007, which resulted in an increase in interest expense of approximately $13 million. Additionally, the credit to interest expense for AFDC decreased $3 million as a result of lower construction work in progress balances during 2008 compared to 2007.
Income taxes decreased $39 million, or 53%, in 2008, with an effective tax rate of 28.4% in 2008 compared to 33.8% in 2007. These decreases are due primarily to lower taxable income and an increase of $9 million in federal and state energy tax credits generated from the operation of Biglow Canyon Phase I in 2008.
2007 Compared to 2006
Revenues in 2007 increased $223 million, or 15%, in 2007 from 2006 as a result of the following:
Total retail revenues increased $149 million, or 11%, in 2007 due primarily to the following offsetting factors:
Lower energy sales to industrial customers resulted from a greater portion of industrial customers choosing direct access and purchasing their energy requirements from an ESS. Reduced revenues from these customers reflect the lower energy sales as well as an increase in transition adjustment credits, reflecting the difference between the cost and market value of PGEs power supply portfolio, as provided by Oregons electricity restructuring law. The increase in the transition adjustment credits is due to both an increase in the number of customers served by ESSs and an increase in the rate of the transition adjustment credit.
On a weather adjusted basis, retail energy deliveries increased 1.1% in 2007, with deliveries to residential, commercial, and industrial customers increasing by 0.7%, 1.0%, and 2.2%, respectively, which was primarily driven by the increase in average customers served in 2007 discussed above.
Wholesale revenues in 2007 increased $66 million, or 49%, from 2006 as a result of:
Other operating revenues increased $8 million, or 44%, in 2007, primarily the result of increased gains from the sale of natural gas in excess of generating plant requirements.
Purchased power and fuel expense for 2007 increased $116 million, or 15%, from 2006. The average variable power cost of PGEs total system load was $39.19 and $33.65 per MWh in 2007 and 2006, respectively, an increase of 16%. Averages exclude the effect of amounts related to regulatory power cost deferrals, unrealized gains on derivative instruments, and wholesale credit provisions.
Increases in Purchased power and fuel expense were due primarily to the following:
Partially offsetting the above increases were:
The addition of Port Westward in June 2007 and the full-year operation of Boardman combined to increase thermal production by 65% in 2007, resulting in reduced reliance on higher cost purchases in the wholesale market. Partially offsetting the increase in thermal production was a 10% decrease in Company-owned hydro production, resulting from lower stream flows.
Production and distribution expense increased $10 million, or 7%, in 2007 compared to 2006, due primarily to the following:
Administrative and other expense increased $20 million, or 12%, in 2007 compared to 2006, due to the following factors:
Depreciation and amortization expense decreased $38 million, or 17%, from 2006 due primarily to the net effect of the following factors:
Taxes other than income taxes increased $5 million, or 7%, in 2007 primarily due to a $3 million increase in city franchise fees resulting from customer price increases during 2007 and a $2 million increase in property taxes resulting from higher assessed property values.
Other income (expense), net increased $7 million, or 41%, in 2007 due primarily to the net effect of the following factors:
Interest expense increased $5 million, or 7%, in 2007, primarily due to a higher level of outstanding long-term debt resulting from the issuance of additional First Mortgage Bonds in 2007. During 2007, the average outstanding balance of long-term debt was $1,158 million compared to $947 million for 2006.
Income taxes increased $38 million, or 106%, in 2007, with an effective tax rate of 33.8% in 2007 compared to 33.5% in 2006. These increases were due primarily to higher taxable income in 2007.
Liquidity and Capital Resources
Discussions, forward-looking statements and projections in this section, and similar statements in other parts of the Form 10-K, are subject to PGEs assumptions regarding the availability and cost of capital. See The current capital and credit market conditions may adversely affect the Companys access to capital, cost of capital, and ability to execute its business plan as scheduled in Item 1A. - Risk Factors.
PGE has undertaken projects which will require significant capital spending in the next several years. The following table presents managements projected primary cash requirements for 2009 through 2013, as well as actual total capital expenditures for 2008 (in millions):
* - Represents 80% of estimated total costs. For further explanation see Boardman emissions controls below.
Due to timing and cost uncertainties, estimated future expenditures related to the addition of up to 218 MWa of renewable energy sources and significant new high voltage transmission projects (including the Southern Crossing Project proposed by PGE) are not included in the table above. For further information, see Integrated Resource Plan in the Power and Fuel Supply section and the Transmission and Distribution section of Item 1. - Business. The following provides information regarding the items presented in the table above.
Ongoing capital expenditures - Consists of upgrades to and replacement of transmission, distribution and generation infrastructure, as well as new customer connections.
Biglow Canyon - Both Phases II and III are currently under construction. The estimated total cost of Phase II is $326 million, including $10 million of AFDC, and Phase III is $433 million, including $27 million of AFDC. Phases II and III are expected to be completed by the end of 2009 and 2010, respectively, with installed capacities of 149 MW and 175 MW, respectively.
Hydro licensing and construction - As required under the 50-year license that the FERC issued to PGE in 2005 for its Pelton/Round Butte project on the Deschutes River, PGE began construction of a selective water withdrawal system in late 2007 in an effort to restore fish passage on the upper portion of the river. The system will collect juvenile salmon and steelhead, allowing them to bypass the dam when migrating to the Pacific Ocean, and will regulate downstream water temperature. Completion of the system, at a total cost of approximately $105 million to $110 million, is expected in 2009. PGEs portion of the costs is expected to be approximately $80 million, including AFDC.
The Company filed an application with the FERC in 2004 to relicense the Clackamas River hydroelectric projects. A settlement agreement, resolving most of the issues raised in the licensing proceeding and providing for a 45-year license term, was signed by the thirty-three participating parties in March 2006 and was submitted to the FERC for review and approval. In June 2008, PGE filed an application with the DEQ proposing final resolution to the remaining lower Clackamas River temperature issues. Pending issuance of the new license, the project will operate under annual licenses
issued by the FERC. It is expected that the DEQ will complete its water quality certification process in 2009 and the FERC will issue a new license for the Clackamas River projects in 2010.
Smart meter project - Pursuant to its smart meter project, PGE plans to install approximately 850,000 new customer meters that will enable two-way remote communication with the Company. Approximately 16,000 new meters are being installed as part of the projects systems acceptance testing phase, with the remaining meters to be installed starting in 2009 and continuing into 2010. PGE estimates the capital cost of the smart meter project to range from $130 million to $135 million. The project is expected to provide improved services, operational efficiencies, and a reduction in future operating expenses.
Boardman emissions controls - In accordance with federal regional haze rules aimed at visibility impairment in several federally protected areas, the DEQ conducted an assessment of emission sources that has indicated that the Boardman generating plant may cause or contribute to visibility impairment in several federally protected areas and would be subject to a Regional Haze Best Available Retrofit Technology (BART) Determination.
In December 2008, the DEQ issued a proposed plan that would require the installation of controls at Boardman in three phases. The first phase would require installation of controls for nitrogen oxides (NOx) as required under the Clean Air Act, with estimated completion in 2011. The second phase would address mercury and sulfur dioxide removal using a semi-dry scrubber and bag house, with estimated completion in 2014. The DEQ proposes that these first two phases would meet federal requirements for installing BART. The third phase would require the installation of Selective Catalytic Reduction for additional NOx control, with estimated completion in 2017. The DEQ proposes that the third phase would meet reasonable progress requirements towards haze emission reduction goals. PGE estimates that the DEQ proposed plan would cost between $575 million and $636 million (100% of total costs, excluding AFDC, in nominal dollars). PGE has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change.
The comment and public input period for the DEQ proposed plan has closed. PGE has commented with an alternative BART/Reasonable Progress proposal that would allow for decision points along the DEQ timeline to provide flexibility to make the most responsible decision on future controls at those points. The OEQC is expected to adopt a rule in April 2009 now that the public process has been completed. The rule will be submitted to the EPA for approval as part of the Oregon Regional Haze State Implementation Plan (SIP). The Company expects the EPA to issue a decision on the SIP in early 2010.
In 1985, PGE sold an undivided 15% interest in Boardman and a 10.714% undivided interest in the Pacific Northwest Intertie (Intertie) transmission line (jointly, the Boardman Assets) to a third party financial institution (Purchaser). This transaction reduced PGEs ownership interest in Boardman from 80% to 65%. The Purchaser leased the Boardman Assets to a lessee (Lessee) unrelated to PGE or the Purchaser. The term of the lease ends on December 31, 2013. Concurrently with the sale, PGE assigned to the Lessee certain agreements for the sale of power and transmission services from Boardman and the Intertie (P&T Agreements) to a regulated electric utility (Utility) unrelated to PGE, the Purchaser, or the Lessee. The payments by the Utility under the P&T Agreements generally cover the payment obligations of the Lessee under the lease, but do not cover all capital expenditures and are not expected to cover a material portion of the costs relating to the controls for the Boardman generating plant. The Purchaser has certain rights to participate in the financing of the portion of the
total cost attributable to its interest. As a result of these agreements, PGEs share of the total cost for the emission controls on the Boardman generating plant is expected to be 80% if the Purchaser does not exercise its rights under the agreements to finance the portion of the total cost attributable to its interest. At the expiration of the lease, and in certain other circumstances, PGE has an option to repurchase the Boardman Assets.
As the regulatory requirements are clarified by the relevant agencies and the related costs more closely estimated, the Company will further evaluate the economic prudence of these expenditures. In doing so, the Company will also consider additional costs such as taxes, emission fees and other costs that may be imposed under any future laws related to climate change, as well as the Companys ability to recover these costs through the ratemaking process. Such additional costs, combined with any expenditures for controls, could constitute an investment in excess of what the plant can economically support. The ultimate impact that the above regulatory requirements and emission controls will have on future operations, costs, or generating capacity of the Companys thermal generating plants is not yet determinable and will be evaluated through the IRP process. PGE will seek recovery of its costs through the ratemaking process.
PGEs access to short-term debt markets, including revolving credit from banks, provides necessary liquidity to support the Companys current operating activities, including the purchase of electricity and fuel for the generation of electricity. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers and maturities of long-term debt. PGEs liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposits related to wholesale market activities, which can vary depending upon the Companys forward positions and the corresponding price curves.
As of December 31, 2008, PGE had negative working capital of $279 million compared to working capital of $147 million as of December 31, 2007. This decrease in working capital is primarily driven by an increase in the net liabilities from price risk management activities of $350 million during 2008, which are classified as current in PGEs consolidated balance sheets. The regulatory asset related to price risk management is classified as noncurrent in PGEs consolidated balance sheets, impacting the Companys working capital. These derivative instruments are recorded at their estimated fair value (mark-to-market), as discussed in Note 4, Fair Value of Financial Instruments, in the Notes to Consolidated Financial Statements. During 2008, the commodities market experienced significant volatility which resulted in, among other things, decreased market prices for purchased power and natural gas in the second half of the year. Pursuant to regulatory accounting under SFAS 71, the mark-to-market of PGEs derivative instruments is deferred and, accordingly, the Companys net regulatory asset related to price risk management increased $350 million, with no impact to the statement of income.
PGE has an unsecured $370 million revolving credit facility (Credit Facility) with a group of banks that supplements operating cash flow and provides a primary source of liquidity. The Credit Facility is for general corporate purposes and the issuance of standby letters of credit, as well as for supporting the Companys commercial paper program, under which it may issue commercial paper for terms of up to 270 days. The commercial paper program requires the Company to maintain unused revolving credit capacity at least equal to the amount of commercial paper issued. In July 2012, $10 million of the Credit Facility matures, with the remaining $360 million maturing in July 2013.
In December 2008, PGE entered into an unsecured $125 million revolving credit facility (Short-term Credit Facility) with a separate group of banks on substantially the same terms as the Credit Facility discussed above, although no letters of credit may be issued under the Short-term Credit Facility. The Short-term Credit Facility, which matures in December 2009, is for general corporate purposes, including back-up for the issuance of commercial paper.
As of December 31, 2008, PGE had $65 million of commercial paper outstanding and borrowings of $131 million under the Credit Facility, the total of which is classified as Short-term debt on the consolidated balance sheet. The Company also had issued $133 million in letters of credit. As of February 20, 2009, PGE had $53 million of commercial paper outstanding and borrowings of $61 million under the Credit Facility and had issued $153 million in Letters of Credit. As of February 20, 2009, PGE had an aggregate of $228 million unused available credit under its credit facilities.
The following summarizes PGEs cash flows for the periods presented (in millions):
Cash Flows from Operating Activities - The $161 million decrease in cash provided by operating activities in 2008 compared to 2007 was primarily attributable to the net effect of the following:
A significant portion of cash provided by operations consists of the recovery in customer prices of non-cash charges for depreciation and amortization. The $27 million increase in these charges in 2008 was due primarily to the authorized recovery of both Port Westward and Biglow Canyon Phase I, which were placed in service in June and December 2007, respectively, and accelerated depreciation of existing meters which are being replaced as part of PGEs smart meter project. The Company estimates that recovery of depreciation and amortization charges will be approximately $209 million in 2009. Combined with all other sources, cash provided by operations is estimated to be approximately $470 million for 2009, which reflects the return of approximately $120 million of margin deposits held by certain wholesale customers and brokers as of December 31, 2008. The estimated return of margin deposits is primarily based on the timing of contracts settling coupled with projected future energy prices. The remaining $141 million expected cash flows from operations in 2009 is based on normal operations, net of amount expected to be refunded to customers pursuant to the Trojan order.
Cash Flows from Investing Activities - Cash flows from investing activities consist primarily of new construction and improvements to PGEs distribution, transmission, and generation facilities. The $69 million decrease in cash used in investing activities was primarily attributable to the net effect of:
The Company plans $722 million in total capital expenditures in 2009 related to Phases II and III of Biglow Canyon, hydro relicensing, ongoing capital expenditures related to upgrades to and replacement of transmission, distribution and generation infrastructure, and the smart meter project.
Cash Flows from Financing Activities - Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Cash flows from financing activities decreased $32 million in 2008 compared to 2007. During 2008, net cash provided by financing activities consisted of short-term borrowings of $203 million and the issuance of long-term debt of $50 million, partially offset by the repayment of long-term debt of $56 million and the payments of dividends of $60 million. During 2007, net cash provided by financing activities primarily consisted of the issuance of long-term debt of $381 million, partially offset by net repayment of short-term debt of $81 million, the repayment of long-term debt of $71 million, and the payment of dividends of $58 million.
Dividends on Common Stock
The following table indicates common stock dividends declared in 2008:
While the Company expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Companys Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deem relevant and may include, but are not limited to, PGEs results of operation and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.
On February 19, 2009, the Board of Directors declared a dividend of $0.245 per share of common stock to stockholders of record on March 25, 2009, payable on or before April 15, 2009.
Debt and Equity Financings
PGE has two unsecured revolving credit facilities with groups of banks which provide an aggregate maximum amount available to the Company of $495 million. The credit facilities are currently scheduled to terminate as follows: $125 million in December 2009, $10 million in July 2012 and $360 million in July 2013. These credit facilities supplement operating cash flow and provide a primary source of liquidity. As of December 31, 2008, PGE had $196 million outstanding under the credit facilities, consisting of borrowings and outstanding commercial paper, and had issued $133 million in letters of credit. PGE has approval from the FERC to issue short-term debt up to a total of $550 million through February 6, 2010.
In January 2009, PGE issued $130 million of First Mortgage Bonds in two series. One series is for $67 million to mature January 15, 2016 at a fixed rate of 6.80%. The second series is for $63 million to mature on January 15, 2014 at a fixed rate of 6.50%. As of December 31, 2008, total long-term debt outstanding was $1,306 million. As of February 20, 2009, the total long-term debt outstanding was $1,436 million, which includes the issuance of $130 million of First Mortgage Bonds in January 2009.
PGEs ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, and alternatives available to investors. The Companys ability to obtain and renew such financing depends on its credit ratings, as well as on credit markets, both generally and for electric utilities in particular. Management believes that, as of February 25, 2009, the availability of the credit facilities, the expected ability to issue long-term debt and equity securities, and cash generated from operations would provide sufficient liquidity to meet the Companys anticipated capital and operating requirements. However, the Companys ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions. The Company anticipates issuing a total of approximately $675 million of debt in 2009 - 2010, of which $130 million was issued in January 2009, and $175 million to $200 million of equity in 2009. In
addition, the interest rate and interest period on $142 million of Pollution Control Bonds expire May 1, 2009, which will require PGE to remarket these bonds at current market rates or replace them with other debt instruments. PGE has approval from the OPUC to issue up to 12.5 million shares of common stock.
PGEs financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Companys financial obligations. The Company attempts to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGEs common equity ratios were 47.3% and 50.0% as of December 31, 2008 and 2007, respectively.
Credit Ratings and Debt Covenants
In January 2009, S&P affirmed its corporate investment grade credit rating and revised its outlook on PGE from stable to negative. The outlook revision reflects the possibility that in 2009 PGEs debt balances may increase and credit metrics may weaken to levels that would not be commensurate with expectations for the Companys current BBB+ corporate rating. In November 2008, Moodys revised its outlook on PGE from stable to positive. PGEs secured and unsecured debt is rated investment grade by Moodys and S&P, with current credit ratings and outlook as follows:
Should Moodys and/or S&P reduce their credit rating on PGEs unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale, commodity and related transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. These deposits, which are classified as Margin deposits in PGEs consolidated balance sheet, are based on the contract terms and commodity prices and can vary from period to period. As of December 31, 2008, PGE had posted approximately $308 million of collateral with these counterparties, consisting of $189 million in cash and $119 million in letters of credit, $18 million of which is affiliated with master netting agreements. Based on the Companys energy portfolio, estimates of current energy market prices, and the level of collateral outstanding as of December 31, 2008, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $151 million and decreases to approximately $46 million by December 31, 2009. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $215 million and decreases to approximately $77 million by December 31, 2009.
PGEs financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade.
The issuance of additional First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Companys Amended and Restated Articles of Incorporation and the
Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that as of December 31, 2008, and after considering the issuance of the $130 million of FMBs in January 2009, it could issue up to approximately $598 million of First Mortgage Bonds under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust. Any issuances would be subject to market conditions and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust on the basis of property additions, bond credits, and/or deposits of cash.
PGEs credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the agreements, to 65% of total capitalization (debt ratio). As of December 31, 2008, the Companys debt ratio, as calculated under the credit agreements, was 52.7%.
Contractual Obligations and Commercial Commitments
The following indicates PGEs contractual obligations as of December 31, 2008 (in millions):
Other Financial Obligations
PGE has entered into long-term power purchase contracts with certain public utility districts in the state of Washington under which it has acquired a percentage of the output (Allocation) of four hydroelectric projects (the Rocky Reach, Priest Rapids, Wanapum and Wells hydroelectric projects). The Company is required to pay its proportionate share of the operating and debt service costs of the projects whether or not they are operable. The contracts further provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of both the output and the operating and debt service costs of the defaulting
purchaser. For the Rocky Reach, Wanapum and Wells projects, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchasers percentage Allocation. For the Priest Rapids project, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt.
Off-Balance Sheet Arrangements
PGE has no off-balance sheet arrangements that have, or are likely to have, a material current or future effect on its consolidated financial condition, revenues or expenses, results of operation, liquidity, capital expenditures or capital resources.
Critical Accounting Policies
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires that management apply accounting policies and make estimates and assumptions that affect amounts reported in the consolidated financial statements. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and that require the use of estimates, assumptions, and judgments to determine matters that are inherently uncertain.
As a regulated utility, PGE prepares its consolidated financial statements in accordance with the provisions of SFAS 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). The application of SFAS 71 results in differences in the timing and recognition of certain revenues and expenses in comparison with businesses in other industries.
PGE is subject to jurisdiction of the OPUC, which reviews and approves the Companys retail rates, ensuring that they provide the Company an opportunity to earn a fair return on its investment. The Companys rates, as authorized by the OPUC, are based on the cost of service and are designed to recover operating expenses and capital costs associated with generation, transmission and distribution assets used to provide regulated service to customers. Although changes in such rates are subject to a formal ratemaking process, it is expected that the OPUC will continue to recognize all prudently-incurred costs and authorize rates that allow for their recovery.
If future recovery of costs ceases to be probable, however, PGE would be required to write off its regulatory assets and liabilities. In addition, if PGE determines that all or a portion of its utility operations no longer meet the criteria for continued application of SFAS 71, the Company would be required to adopt the provisions of SFAS 101, Revenue Recognition in Financial Statements, which would require the Company to write off those regulatory assets and liabilities related to operations that no longer meet requirements of SFAS 71. Discontinued application of SFAS 71 could have a material impact on the Companys results of operation and financial position.
Asset Retirement Obligations
SFAS 143, Accounting for Asset Retirement Obligations, as interpreted by FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations-an interpretation of FASB Statement No. 143, requires the recognition of asset retirement obligations (AROs), measured at estimated fair value, for legal obligations related to dismantlement and restoration costs associated with the
retirement of tangible long-lived assets in the period in which the liability is incurred. Upon initial recognition of AROs that are measurable, the probability-weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. Capitalized asset retirement costs are depreciated over the life of the related asset, with accretion of the ARO liability classified as an operating expense on the statement of income. On the statement of income, AROs related to electric utility plant are included in depreciation and amortization expense, with those related to other property included in other income (expense). Accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from accumulated depreciation to regulatory liabilities on the consolidated balance sheets.
Retail revenue is billed monthly and is based on meter readings taken throughout the month. At the end of each reporting period, PGE estimates the revenue earned from the last meter read date through the last day of the month, which has not been billed as of the last day of the month. Such amount is classified as Unbilled revenues in the Companys consolidated balance sheets. Unbilled revenues is calculated based on each months actual net retail system load, the number of days from the meter read date through the last day of the month, and current retail customer prices.
The Company has unresolved legal and regulatory issues for which there is inherent uncertainty with respect to the ultimate outcome of the respective matter. Contingencies are evaluated based on SFAS 5, Accounting for Contingencies, using the best information available. In accordance with SFAS 5, a material loss contingency is accrued and disclosed when it is probable that an asset has been impaired or a liability incurred and the amount of the loss can be reasonably estimated. If a range of probable loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency is disclosed to the effect that it cannot be reasonably estimated. Material loss contingencies are disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. Reserves established reflect managements assessment of inherent risks, credit worthiness, and complexities involved in the collection process. No assurance can be given for the ultimate outcome of any particular contingency.
Price Risk Management
PGE engages in price risk management activities in its electric business, utilizing derivative instruments such as electricity forward, swap, and option contracts and natural gas forward, swap, option, and futures contracts to protect the Company against variability in expected future cash flows due to associated price risk and to minimize net power costs for retail customers. Derivative contracts are accounted for in accordance with SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended.
Marking a contract to market consists of reevaluating the market value at the end of each reporting period for the entire term of the contract and recording any change in value (difference between the contract price and current market price) in either earnings or other comprehensive income for the
period. Valuation of these financial instruments reflects managements best estimates of market prices, including closing New York Mercantile Exchange (NYMEX) and over-the-counter quotations, time value of money, and volatility factors underlying the commitments.
Determining the fair value of these contracts requires the use of prices at which a buyer or seller could currently contract to purchase or sell a commodity at a future date (termed forward prices). Forward price curves are used to determine the current fair market price of a commodity to be delivered in the future. PGEs forward price curves are created by utilizing actively quoted market indicators received from electronic and telephone brokers, industry publications, NYMEX, and other sources, and are validated using independent publications. Estimates used in creating forward price curves can change with market conditions and can be materially affected by unpredictable factors such as weather and the economy. The difference between PGEs forward price curves and four independently published price curves averages 1%. The difference at any single location, delivery date and commodity is less than 5%.
For purchases and sales of forward physical or financial contracts, the mark-to-market value is the present value of the difference between PGEs contracted price and the forward price multiplied by the total quantity of the contract. For option contracts, a theoretical value is computed using standard financial models that utilize price volatility, price correlation, time to expiration, interest rate and price curves. The mark-to-market of these options includes the premium paid or received as a component of the theoretical value.
Pension expense is dependent on several assumptions used in the actuarial valuation of the plan. Primary assumptions include the discount rate, the expected return on plan assets, mortality rates, and wage escalation. These assumptions are evaluated by PGE, reviewed annually with the plan actuaries and trust investment consultants, and updated in light of market changes, trends, and future expectations. Significant differences between assumptions and actual experience can have a material impact on the valuation of the pension benefit plan obligation and net periodic pension cost.
PGEs pension discount rate is based on assumptions regarding rates of return on long-term high quality bonds. Assumptions regarding the expected rate of return on plan assets are based on historical and projected average rates of return for current asset classes in the plan investment portfolio. The expected rate of return reflects expected future returns for the portfolio, and was used in determining net periodic pension expense for the year.
Changes in actuarial assumptions can also have a material effect on net periodic pension expense. A 0.25% reduction in the expected long-term rate of return on plan assets would have increased 2008 pension expense by approximately $1.3 million. A 0.25% reduction in the discount rate would not have had a material effect on net periodic pension expense.
PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. Any variations in the Companys market risk or credit risk may affect its future financial position, results of operation or cash flows, as discussed below.
Risk Management Committee
PGE has a Risk Management Committee (RMC) which is responsible for providing oversight of the adequacy and effectiveness of corporate policies, guidelines, and procedures for market and credit risk management related to the Companys energy portfolio management activities. The RMC, which provides quarterly reports to the Audit Committee of PGEs Board of Directors, consists of officers and Company representatives with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, power operations, and generation operations. The RMC reviews and recommends for adoption policies and procedures, establishes risk limits subject to PGE Board approval, and monitors compliance with policies, procedures, and limits on a regular basis through reports and meetings.
Commodity Price Risk
PGEs primary business is to provide electricity to its retail customers. The Company participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. The Company uses power purchase contracts to supplement its thermal, hydroelectric, and wind generation and to respond to fluctuations in the demand for electricity and variability in generating plant operations. The Company also enters into contracts for the purchase of fuel for the Companys natural gas and coal fired generating units. These contracts for the purchase of power and fuel expose the Company to market risk. The Company uses instruments such as forward contracts, which may involve physical delivery of an energy commodity; swap agreements, which may require payments to, or receipt of payments from, counterparties based on the differential between a fixed and variable price for the commodity; and options and futures contracts to mitigate risk that arises from market fluctuations of commodity prices. PGE does not engage in trading activities.
Gains and losses from instruments that reduce commodity price risks are recognized when settled in purchased power and fuel expense, or in wholesale revenue. Valuation of these financial instruments reflects managements best estimates of market prices, including closing NYMEX and over-the-counter quotations, time value of money, and volatility factors underlying the commitments.
PGE actively manages its risk to ensure compliance with its risk management policies. The Company monitors open commodity positions in its energy portfolio that extend over the next 24 months using a value at risk methodology, which measures the potential impact of market movements over a one-day holding period using a variance/covariance approach at a 95% confidence interval. The portfolio is modeled using net open power and natural gas positions, with power averaged over peak and off-peak periods by month, and includes all financial and physical positions for the next 24 months, including estimates of retail load and plant generation. The risk factors include commodity prices for power and natural gas at various locations and do not include volumetric variability. Based on this methodology,
the average, high, and low value at risk on the Companys energy portfolio in 2008 were $4.8 million, $7.0 million, and $2.2 million, respectively, and in 2007 were $4.7 million, $7.6 million, and $1.6 million, respectively.
PGEs energy portfolio activities are subject to regulation, with related costs covered in retail prices approved by the OPUC. The timing differences between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in prices are deferred as regulatory assets and regulatory liabilities to reflect the effects of regulation under SFAS 71. As contracts are settled, these deferrals reverse. In PGEs value at risk methodology, no amounts are included for potential deferrals under SFAS 71.
Foreign Currency Exchange Rate Risk
PGE is exposed to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars in its energy portfolio. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE monitors its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy.
As of December 31, 2008, a 10% change in the value of the Canadian dollar would result in an immaterial change in pre-tax income for transactions that will settle over the next 12 months.
Interest Rate Risk
To meet short-term cash requirements, PGE has established a program under which it may from time to time issue commercial paper for terms of up to 270 days; such issuances are supported by the Companys unsecured revolving credit facilities. Although any borrowings under the commercial paper program subject the Company to fluctuations in interest rates, reflecting current market conditions, individual instruments carry a fixed rate during their respective terms. As of December 31, 2008, PGE has $196 million of borrowings and outstanding commercial paper, classified as Short-term debt in the Companys consolidated balance sheet.
PGE currently has no financial instruments to mitigate risk related to changes in short-term interest rates, including those on commercial paper; however, it will consider such instruments in the future as necessary.
As of December 31, 2008, the total fair value and carrying amounts by maturity date of PGEs long-term debt are as follows (in millions):
Interest rates on $142 million of Pollution Control Revenue Bonds are fixed until May 1, 2009. Pursuant to the terms of the bond agreements, PGE is required to redeem the entire principal amount of these bonds on or before May 1, 2009. The Company has the option to remarket the bonds and establish new terms concerning the interest rates, all subject to market conditions at the time of remarketing.
As of December 31, 2008, a 1% increase in the current interest rates would result in an approximate $1.4 million increase in annual interest expense.
PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. PGE manages the risk of counterparty default according to its credit policies by performing financial credit reviews, setting limits and monitoring exposures, and requiring collateral (in the form of cash, letters of credit, and guarantees) when needed. The Company also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under multiple agreements with counterparties. Despite such mitigation efforts, defaults by counterparties may periodically occur. Based upon periodic review and evaluation, allowances are recorded to reflect credit risk related to wholesale accounts receivable.
The large number and diversified base of residential, commercial, and industrial customers, combined with the Companys ability to discontinue service, contribute to reduce credit risk with respect to trade accounts receivable from retail electricity sales. Estimated provisions for uncollectible accounts receivable related to retail electricity sales are provided for such risk.
The following table presents PGEs credit exposure for commodity activities and their subsequent maturity as of December 31, 2008. The table reflects credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities (dollars in millions):
Investment grade includes those counterparties with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moodys) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. Non-investment grade includes those counterparties with below investment grade credit ratings on senior unsecured debt. For non-rated counterparties, PGE performs credit analysis to determine an internal credit rating that approximates investment or non-investment grade. Included in this analysis is a review of counterparty financial statements, specific business environment, access to capital, and indicators from debt and capital markets. The credit exposure includes activity for electricity and natural gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit and may represent prepayment or credit exposure assurance.
Omitted from the market risk exposures above are long-term power purchase contracts with certain public utility districts in the state of Washington and with the city of Portland, Oregon. These contracts provide PGE with a percentage share of hydro facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2018. Management believes that circumstances that could result in the nonperformance by these counterparties are remote.
The following financial statements and report are included in Item 8:
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of
Portland General Electric Company
We have audited the accompanying consolidated balance sheets of Portland General Electric Company and subsidiaries (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of income, shareholders equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. We also have audited the Companys internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Companys management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Managements Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Companys internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A companys internal control over financial reporting is a process designed by, or under the supervision of, the companys principal executive and principal financial officers, or persons performing similar functions, and effected by the companys board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud
may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Portland General Electric Company and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ Deloitte & Touche LLP
February 24, 2009
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in millions, except per share amounts)
See accompanying notes to consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, continued
(In millions, except share amounts)
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
(Dollars in millions)
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes