Portland General Electric Co 10-K 2008
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended December 31, 2007
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) (zip code)
Registrants telephone number, including area code: (503) 464-8000
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
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. x
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
The aggregate market value of the voting stock held by non-affiliates of Portland General Electric Company, computed by reference to the price at which the common stock was last sold, as of the last business day of Portland General Electric Companys most recently completed second fiscal quarter was approximately $1,715,275,306. The number of shares of Portland General Electric Companys common stock outstanding at February 15, 2008 was 62,529,787 shares.
Documents Incorporated by Reference
TABLE OF CONTENTS
The following abbreviations or acronyms used in the text and notes to the consolidated financial statements are defined below:
Portland General Electric Company (PGE, or the Company), incorporated in 1930, is a publicly owned, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. PGE also sells electricity and natural gas in the wholesale market to utilities and energy marketers in the western United States. PGE operates as a cost-based, regulated electric utility, for which revenue requirements are determined based upon the cost to serve customers, including a reasonable rate of return to the Company, and is obligated to provide full (bundled) service to all of its customers. The Company continues to operate as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis.
In 1997, Portland General Corporation, the former parent of PGE, merged with Enron Corp., 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, filed for 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, the 42.8 million shares of PGE common stock held by Enron Corp. were cancelled, PGE issued 62.5 million shares of new common stock, and PGE and Enron entered into a separation agreement. Following issuance of the new PGE common stock, PGE ceased to be a subsidiary of Enron. Approximately 27 million shares of the new PGE common stock were initially issued to the Debtors creditors holding allowed claims, and approximately 35.5 million shares were issued to a Disputed Claims Reserve (DCR). On June 18, 2007, the Disputed Claims Reserve sold substantially all of its remaining holdings of PGE stock in a public offering. PGEs common stock is listed on the New York Stock Exchange under the ticker symbol POR.
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 2007 its service area population was approximately 1.6 million, comprising about 43% of the states population. The Company added approximately 11,000 retail customers during 2007, and at December 31, 2007 served approximately 804,000 retail customers.
As of December 31, 2007, PGE had 2,705 employees. A total of 868 employees are covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 837 employees for a five-year period effective from March 1, 2004 through February 28, 2009. In addition, 31 employees (18 at Coyote Springs and 13 at Port Westward) are covered under a five-year agreement that extends from August 2, 2006 through August 1, 2011.
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 or 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 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.
The Company is a licensee and a public utility, as those terms are defined in the Federal Power Act, and is subject to regulation by the Federal Energy Regulatory Commission (FERC) as to accounting policies and practices, licensing of hydroelectric projects, transmission services, wholesale sales, issuance of short-term debt, and other matters. The Energy Policy Act of 2005 (EPAct 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. Such standards, the majority of which apply to PGE, became effective on June 18, 2007. PGE has submitted mitigation plans related to certain standards to the Western Electricity Coordinating Council (WECC), with review and approval pending.
Wholesale - PGE has authority under its FERC tariff to charge market-based rates for wholesale energy sales. In June 2007, the FERC issued Order 697, Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, which changed the re-authorization requirements for continued use of market-based rates and requires the filing of updated market studies on a regional schedule. PGEs current authorization, which was due to expire in May 2008, will remain in effect until June 2010, when the Company, as part of the western region, will file for re-authorization.
Transmission - FERC Order 890, Preventing Undue Discrimination and Preference in Transmission Services, which became effective in July 2007, requires regional coordination of transmission planning. The order requires greater specificity and more transparency in the Open Access Transmission Tariff (OATT). PGE submitted a compliance filing to incorporate into its OATT the non-rate terms and conditions contained in the order and will submit additional filings to incorporate other provisions of the order. FERC Order 693, Mandatory Reliability Standards for the Bulk-Power System, issued in March 2007, approved mandatory reliability standards developed by the North American Electric Reliability Corporation, which is responsible for the enforcement of such standards.
As a major transmitting utility, PGE has participated in several transmission planning efforts in support of the coordinated expansion and enhanced operation of the regional transmission system. The Company will continue to monitor and engage in these efforts although there remains considerable uncertainty regarding their further development.
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. PGEs 79% interest in the pipeline that provides natural gas to its Beaver and Port Westward plants is subject to this authority.
Nuclear - The Nuclear Regulatory Commission (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 the NRC and Energy Facility Siting Council (EFSC) 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 December 2004 pursuant to an NRC-approved License Termination Plan, with the plants Facility Operating License terminated by the NRC in May 2005. Spent fuel storage activities will continue to be subject to NRC regulation until all nuclear fuel is removed from the site, decontamination is completed, and the storage installation is fully decommissioned. The Oregon Department of Energy also monitors Trojan. For further information, see Note 13, Trojan Nuclear Plant, in the Notes to Consolidated Financial Statements.
State of Oregon Regulation
PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC), which approves the Companys retail prices through general rate proceedings and supplemental tariffs and establishes conditions of utility service. Under Oregon law, the OPUC is required to ensure that the prices and terms of service are fair, non-discriminatory, and provide PGE an opportunity to earn a fair return on its investment. In addition, the OPUC regulates the issuance of stock and long-term debt, prescribes the system of accounts to be kept by Oregon utilities, and reviews applications to sell utility assets and engage in transactions with affiliated companies. Construction of new generating facilities in Oregon requires a permit from the states EFSC.
General Rate Case - PGE periodically evaluates the need to change its overall general retail electric price structure to sufficiently cover its operating costs and provide a reasonable rate of return. The Companys most recent comprehensive general rate case, approved by the OPUC on January 12, 2007, resulted in an overall price increase of approximately 1.3%. The increase represented the combined effect of a 1.4% decrease related to general costs, which became effective on January 17, 2007, and a 2.8% increase related to cost recovery of Port Westward, which became effective on June 15, 2007. The change in retail prices was based upon a 50% equity capital structure, a 10.1% return on equity, and an overall rate of return of 8.29%. The OPUC had previously approved a 5.1% increase effective January 1, 2007 for projected increased power costs under the Resource Valuation Mechanism.
The Company filed a general rate case on late February 27, 2008 with the OPUC, based on a forecasted 2009 test year, with new prices expected to be effective beginning in January 2009. For further information, see the Overview section of Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation.
Power Costs - In its general rate order, the OPUC also approved a process by which PGE can continue to adjust prices to reflect power cost forecasts for future years. An Annual Power Cost Update Tariff, which replaced the former Resource Valuation Mechanism, provides for rate adjustments to reflect updated forecasts of net variable power costs (NVPC) for future calendar years. In addition, a new Power Cost Adjustment Mechanism (PCAM) was approved by the OPUC, effective January 17, 2007. Under the PCAM, PGE can adjust future prices to reflect a portion of the difference between each years forecasted NVPC included in prices (the baseline), and actual NVPC. Under the PCAM, PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and that included in base prices by application of an asymmetrical deadband within which PGE absorbs cost increases or decreases, with a 90/10 sharing of costs and benefits between customers and the Company outside of the deadband. A refund will occur only to the extent that it results in PGEs actual return on equity (ROE) for that year being no less than 100 basis points above the Companys last authorized ROE. A collection will occur only to the extent that it results in PGEs actual ROE for that year being no greater than 100 basis points below the Companys last authorized ROE.
For 2007, the deadband ranged from $11.7 million below, to $23.4 million above, the baseline. PGEs actual NVPC as determined under the PCAM for 2007 were less than the established baseline by $29.4 million. Accordingly, an estimated refund to customers of $16 million was recorded as a regulatory liability and is reflected as an increase to Purchased power and fuel expenses. Any regulatory asset or liability arising from application of the PCAM is subject to the results of a regulated earnings test, with final determination of any customer refund or collection made by the OPUC through a public filing and review. For 2008, the deadband will range from $14 million below, to $28 million above, baseline NVPC.
Retail Customer Choice Program - Implemented in 2002 as part of Oregons electricity restructuring law, Oregons customer choice program, along with related regulations and PGEs tariff, 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 a transition adjustment for customers that choose to purchase energy at market prices from investor-owned utilities or from ESSs. Such transition adjustments reflect the above-market or below-market cost, respectively, 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 operations of the Company.
In 2007, the three ESSs registered to transact business with PGE served a total of 30 customers with a total average load of approximately 250 MWa, representing approximately 19% of PGEs non-residential load and 12% of the Companys 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 31 commercial and industrial customers were receiving service from PGE under market-based pricing options at the end of 2007.
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. Approximately 60,000 customers have chosen renewable energy options and approximately 1,900 customers have chosen the time-of-use option.
Public Purpose Charge - The restructuring law also provides for a Public Purpose Charge to fund cost-effective conservation measures, new renewable energy resources, and weatherization measures for low-income housing. This charge, equal to 3% of retail revenues, has been extended to 2026 as part of Oregons Renewable Energy Standards legislation that was passed in 2007. The Company remits amounts collected from retail customers to the Energy Trust of Oregon (ETO) and other agencies for administration of these programs.
Regulatory Accounting - 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, or separable portions thereof. These assessments consider both the current and anticipated future rate environment and related accounting guidance, as outlined in SFAS 101, Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS No. 71, and Emerging Issues Task Force Issue No. (EITF) 97-4, Deregulation of the Pricing of Electricity - Issues Related to the Application of SFAS No. 71 and SFAS No. 101.
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 alternative suppliers (ESSs), in accordance with Oregons electricity restructuring law.
The following table summarizes PGEs revenues for the years indicated (dollars in millions):
PGE serves a diverse retail customer base. Residential customers comprise approximately 88% of the Companys total customers, with the remainder comprised of commercial and industrial customers. Total retail revenues for 2007 were fairly evenly divided between residential (49%) and commercial and industrial (51%) customer classes. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating season. Commercial and industrial customer classes are not dominated by any single industry. While the 20 largest customers constitute about 9% 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 3% of PGEs total retail load or 2% of total retail revenues.
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 power purchases and sales 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 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.
Most 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 (termed book outs) 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 Operating Revenues
Other operating revenues include sales of natural gas in excess of generating plant requirements and revenues from transmission services, pole contact rentals, and certain other electric services to customers.
For further information, including year-to-year comparisons of revenues, energy sales, and number of customers, see Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation.
Power and Fuel Supply
PGE relies upon its existing base of generating resources, as well as short- and long-term power contracts, to meet its customers energy needs. At December 31, 2007, PGEs total firm resource capacity, including short-term purchase agreements, was approximately 4,627 MW (net of short-term sales agreements of 757 MW).
The Pacific Northwest peak usage season historically occurs in the winter, when residential and commercial heating and lighting demand is highest. PGEs all-time high net system load peak (4,073 MW) occurred in December 1998. The Companys all-time summer peak (3,706 MW), driven by unusually warm weather and increased air conditioning demand, occurred in July 2006.
PGEs current generating portfolio consists of thermal (primarily coal and natural gas), hydro, and wind resources that together provide 2,449 MW of total net capability. See Item 2. - Properties for a full listing of PGEs generating facilities.
The Companys thermal generation facilities continued to supply reliable power during 2007. In June 2007, Port Westward, a new 406 MW natural gas fired generating plant, was placed in service at a total cost of $280 million, including allowance for funds used during construction (AFDC).
The Companys lowest cost generating resources are its FERC licensed hydroelectric projects. Northwest hydro conditions have a significant impact on the regions power supply, with water conditions significantly impacting PGEs cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases. Current forecasts indicate near normal hydro conditions for 2008.
Biglow Canyon Wind Farm (Biglow Canyon), located in Sherman County, Oregon, is PGEs newest and largest renewable energy project. Phase I of Biglow Canyon, comprised of 76 wind turbines with a total capacity of 125 MW, was completed and placed in service in mid-December 2007 at a total cost of approximately $255 million (including AFDC). Phases II and III of the project are in the advanced planning stages, with an estimated total cost of $700 million to $800 million, including approximately $50 million of AFDC. Phase II is expected to be completed by the end of 2009 and Phase III is expected to be completed by the end of 2010. When completed, the three-phase project is expected to have a total installed capacity of 400 to 450 MW.
PGE supplements its own generation with short- and long-term wholesale contracts as needed to meet its retail load requirements and provide the most economic mix on a variable cost basis. PGE also has firm contracts, ranging from one to thirty years, to purchase up to 975 MWa of power from counterparties, including Pacific Northwest utilities and the Confederated Tribes of the Warm Springs Reservation of Oregon. The 30-year agreement is for 27 MWa of wind capacity with an independent power producer. In addition, PGE has an exchange contract with a summer-peaking California utility to help meet the Companys winter-peaking requirements, and an exchange contract with another Northwest utility to help meet the Companys summer-peaking requirements. These resources, along
with short-term contracts, provide the Company with sufficient firm capacity to serve its peak loads. For further information, see Power and Fuel Supply in Item 7. - Managements Discussion and Analysis of Financial Condition and Results of Operation.
Mid-Columbia Hydro Matters - The Company has long-term power purchase contracts with certain public utility districts in the State of Washington related to four hydroelectric projects on the mid-Columbia River. The contracts provide approximately 567 MW of firm capacity, and expire between 2009 and 2018. In 2001, PGE executed new agreements with Grant County Public Utility District (Grant), operator of the Priest Rapids and Wanapum projects, for periods corresponding to Grants new license term, to be determined by the FERC. The Priest Rapids agreement became effective in November 2005 and the Wanapum agreement will become effective November 1, 2009. Both contracts, approved by the FERC, extend through the life of Grants new license, which is expected to be approximately 50 years. Under the terms of the agreements, Grant will annually determine the output required for its purposes, while PGE will be required to purchase approximately 25% of the output in excess of Grants requirements over the term of the new license, for which PGE will pay a proportional share of the projects debt service and operating costs. PGEs share in the projects is expected to steadily decline as Grants needs increase, with the Companys share in the two projects reduced from the current 256 MW to an estimated 149 MW in 2010. Also under the agreements, PGE is to purchase an additional 50 MWa annually during the period 2006-2011.
For further information regarding PGEs power purchase contracts from mid-Columbia projects, see Note 9, Commitments and Guarantees, in the Notes to Consolidated Financial Statements.
PGE contracts for natural gas and coal supplies used to fuel the Companys thermal generating plants. PGE also uses forward, swap, option, and futures contracts to manage its exposure to volatility in natural gas prices. The Company acquires coal and natural gas as follows:
Currently, PGE transports gas on the Kelso-Beaver Pipeline for its own use under a firm transportation service agreement, with capacity offered on an interruptible basis to the extent not utilized by the Company.
Firm gas supplies for Beaver and Port Westward may be purchased up to 72 months in advance, based on anticipated operation of the plants. PGE has access to 87,000 Dth/day of firm gas transportation capacity to serve the two plants. In addition, PGE has contractual access, through April 2017, to natural gas storage in Mist, Oregon, from which it can draw in the event that gas supplies are interrupted or if economic factors require its use. PGE believes that sufficient market supplies of gas are available to fully meet anticipated requirements of Beaver and Port Westward for 2008.
Wholesale power market products, along with PGEs base of thermal, hydroelectric and wind generating capacity, currently provide the Company with the flexibility to respond to seasonal fluctuations in the demand for electricity from its retail and wholesale customers. Although surplus generation has diminished in recent years due to economic and population growth in the western United States, the recent construction of new generating plants has increased the regions capacity to meet its power needs. PGE anticipates that generating capacity within the WECC, as well as an active wholesale market, will continue to provide sufficient energy to supplement the Companys generation and purchases under current short- and long-term power contracts. To meet anticipated future requirements and help assure continued system reliability, PGEs integrated resource planning process utilizes input from several sources, including long-term forecasts 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 a resource action plan that, when considered with the Companys existing portfolio, provides 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 that covers the years 2008 through 2015. It includes additional renewable and demand-side resources, energy efficiency programs, power purchase agreements of varying terms, and the acquisition of additional peaking capacity. The plan was developed over an 18-month period that included significant research and discussion with customer groups, independent consultants, and regulators.
The IRP Action Plan proposes the following:
Review of the IRP by stakeholders and the OPUC staff is continuing and will be completed when the OPUC determines the Action Plan appears reasonable and issues an acknowledgement order, which is expected in March 2008. The Company expects to issue a Request For Proposal for energy related resources shortly after acknowledgement of the IRP.
PGE operates in a state recognized for environmental leadership. The Companys policy of environmental stewardship seeks to minimize environmental 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, and waste disposal. The 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 generating facilities and the accumulation, cleanup, and disposal of toxic and hazardous wastes.
Greenhouse gas emissions and their potential impacts on climate change and global warming have recently received increased public attention, with several legislative efforts initiated to establish mandatory control of emissions from thermal electricity generating plants. 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. Any future laws that impose mandatory reductions in carbon dioxide emissions could have a material impact on electric utilities that rely on coal as a fuel resource. PGEs ownership shares of the Boardman and Colstrip coal plants comprise approximately one-fourth of the Companys net generation capability.
Renewable Energy Standards
Renewable Energy Standards adopted by the 2007 Oregon legislature require that PGE and other large electricity providers serve at least 5% of their retail load within the state from renewable resources by the year 2011, increasing to 25% by 2025. Additional interim steps in the standard include meeting 15% of retail load by 2015 and 20% by 2020. Biglow Canyon, which is expected to have a total installed capacity of 400 to 450 MW when all three phases are completed by the end of 2010, represents a significant step toward the Companys achievement of these goals.
Air Quality Standards
PGEs operations, principally its fossil-fuel generation plants, are subject to the federal Clean Air Act (CAA). Primary pollutants addressed by the CAA that affect PGE are 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 exceed federal standards.
PGE manages its 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 sufficient to operate Boardman at 60% to 67% of capacity. PGE has acquired additional emissions allowances, which, in combination with the allowance awards, are expected to allow PGE to meet the SO2 emission requirements for the Boardman plant at forecasted capacity for at least the next ten years.
The federal government and the states in which PGE operates have adopted the following regulations concerning mercury emissions:
In accordance with new federal regional haze rules aimed at visibility impairment in several federally protected areas, the DEQ is conducting an assessment of emission sources pursuant to a Regional Haze Best Available Retrofit Technology (BART) process. Several other states are conducting a similar process. Those sources determined to cause, or contribute to, visibility impairment at protected areas will be subject to a BART Determination.
In response to the EPAs regional haze rules, the Company volunteered to participate in a DEQ pilot project to analyze information about air emissions from Boardman. An exemption modeling analysis for identified sources, which began in September 2006, has indicated that the Boardman and Beaver generating plants may cause or contribute to visibility impairment in several federally protected areas. In November 2007, the Company submitted a BART Determination to the DEQ for Boardman that stated that the BART for Boardman is a combination of New Low NO x Burners, Modified Over Fire Air System, Selective Non-Catalytic Reduction (SNCR), and Semi-dry Flue Gas Desulphurization, and that mercury emission regulations should be addressed through a Mercury Sorbent Injection System. The cost for these controls is estimated to be in the range of $300 million to $400 million (100% of total costs). While the Company believes that these controls meet BART requirements, it is possible that the regulatory agencies could require Selective Catalytic Reduction rather than SNCR, which would increase the estimated cost to a range of $470 million to $620 million (100% of total costs). The Company has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change. Final approval of the plan is expected to occur in the second half of 2009.
As the regulatory requirements are clarified by the relevant agencies and the related costs more closely estimated, PGE will further evaluate the economic prudency of these expenditures. In doing so, the Company will also consider additional costs, including taxes, emission fees and other costs that may be imposed under any future laws related to climate change. Such additional costs, as well as the requirement to install Selective Catalytic Reduction controls, could require an investment in excess of what the plant can economically support.
The ultimate impact that the above regulatory requirements and air emission controls will have on future operations, costs, or generating capacity of the Companys thermal generating plants is not yet determinable. PGE will seek to recover its share of any associated costs through the ratemaking process.
Restoration of Salmon Runs
Populations of most salmon species in the Pacific Northwest have declined significantly over the last several decades. Many of these distinct populations of salmon 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 salmon 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 reductions at times in hydroelectric generation capability and the seasonal shifting of other generation from the fall and winter periods to the spring and summer periods.
PGE is implementing a series of salmon protection measures on the Clackamas, Deschutes, and Willamette rivers that were prescribed by the United States Fish and Wildlife Service and the National Marine Fisheries Service under their authority granted in the ESA and are contained in PGEs FERC operating licenses.
ESA consultations on PGEs Clackamas River project, completed in 2003, will be in effect until a new license is granted by the FERC. A settlement agreement related to the license application for the Companys four hydroelectric projects on the Clackamas River was submitted to the FERC in March 2006 for review and approval. Pending issuance of the new license, which is expected to occur in 2009, the project will continue to operate under annual licenses issued by the FERC.
In accordance with a 2002 agreement with state and federal agencies, environmental groups, and others, PGE is proceeding with the decommissioning of the Companys Bull Run hydroelectric project, which includes the Marmot and Little Sandy dams, located in the Sandy River basin. The Marmot Dam was removed in July 2007, with removal of the Little Sandy Dam planned for 2008.
As required under the 50-year license that the FERC issued to PGE in 2004 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 and allow 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 cost is expected to be approximately $80 million, including AFDC.
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 (PCBs), 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), also referred to as Superfund. CERCLA can assert joint and several liability for investigation and remediation costs regardless of fault or legality of original conduct. PGE is currently listed by the EPA as a Potentially Responsible Party (PRP) at two Superfund sites discussed below. Other hazardous waste spills are considered minor, with clean-ups conducted on a regular basis.
Nuclear Fuel Disposal
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-approved 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 after 2017. For further information concerning PGEs nuclear fuel disposal, see Note 13, Trojan Nuclear Plant, in the Notes to the Consolidated Financial Statements.
PGE is currently involved in two matters, known as Portland Harbor and Harbor Oil, both of which have been included by the EPA on the federal National Priority List as federal Superfund Sites pursuant to CERCLA.
In 2000, PGE, along with sixty-eight other PRPs on the Portland Harbor Initial General Notice List, received a Notice of Potential Liability from the EPA with respect to the Portland Harbor Superfund Site. A 1997 investigation of a portion of the Willamette River by the EPA, known as Portland Harbor, revealed significant contamination of sediments within the harbor. In January 2008, PGE received a request from the EPA to provide additional information concerning its properties in or near the Portland Harbor Superfund Site. Sufficient information is currently not available to determine either the total cost of the investigation and remediation of the Portland Harbor or the liability of the PRPs, including PGE.
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 Superfund Site, located in north Portland. Harbor Oil is the location of a company, Harbor Oil, Inc., that PGE and other entities used to process used oil from power plants and electrical distribution systems from at least 1990 until 2003. Sufficient information is currently not available to determine either the total cost of the investigation and remediation of the Harbor Oil site or the liability of the PRPs, including PGE.
For further information regarding these two matters, see Environmental Matters in Note 14, Contingencies, in the Notes to Consolidated Financial Statements.
Certain risks and uncertainties that may affect PGEs business, financial condition, results of operation and cash flows, or that may cause the Companys actual results to vary from the forward-looking statements contained in the Annual Report on Form 10-K, include those set forth below.
PGE is subject to the risk that the OPUC will not allow sufficient recovery of the Companys costs and thus not provide a reasonable rate of return to shareholders.
The prices that the OPUC allows PGE to charge for its retail services is 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. Further, the regulatory process does not provide assurance that PGE will be able to achieve earnings levels authorized.
The OPUC order in the Companys recent comprehensive general rate case, issued in January 2007, approved the use of a PCAM by which PGE can adjust future prices to reflect a portion of the difference between each years forecasted and actual NVPC. However, use of the approved cost sharing (deadband) methodology will require that PGE absorb some power cost increases before the Company is allowed to recover any amount from customers. Accordingly, future application of the PCAM is expected to only partially mitigate the potentially adverse financial impact of unplanned generating plant outages, severe weather, reduced hydro availability, and volatile wholesale energy prices.
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 the Trojan Nuclear Plant, which was closed in 1993. For further information, see Trojan Investment Recovery within Legal Matters of Note 14, Contingencies, in the Notes to Consolidated Financial Statements. The Company cannot predict the ultimate outcome of this matter. However, while management believes that it will not have a material adverse impact on the financial condition of the Company, it may have a material adverse impact on results of operations and cash flows for future reporting periods.
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. Particularly for residential customers, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Severe weather can also disrupt energy delivery and damage the Companys 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.
Unplanned 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.
Unplanned outages at the Companys generating plants could result in replacement power costs greater than those power costs included in customer prices, and any inability to recover such costs in future rates could have a negative impact on the Companys results of operations. As indicated above, application of the Companys PCAM can be expected to mitigate adverse financial impacts of future unplanned outages at the Companys generating plants.
Weather conditions that reduce stream flows could adversely affect the Companys 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 will require increased generation from the Companys higher cost thermal plants and/or power purchases in the wholesale market, the adverse financial effects of which are not expected to be fully mitigated by the Companys PCAM.
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 customers can also affect PGEs variable power costs. Further, disruption in wholesale markets may 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 also affect the market value of derivative instruments and unrealized gains and losses, as well as cash requirements to purchase electricity. Although the Companys PCAM can be expected to partially mitigate the financial effects of adverse wholesale market conditions, cost sharing features of the mechanism do not provide for full recovery in customer prices.
Market risk related to adverse fluctuations in the price of natural gas purchased as fuel for electricity generation can also impact the Companys 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 may incur greater costs than originally estimated. The Company may not be able to fully recover these increased costs through ratemaking.
Sustained downturns in the economy in its service territory could reduce demand for electricity and adversely affect the Companys results of operations.
Current and projected slowing of the Oregon and national economies could result in reduced demand for electricity that could decrease earnings and cash flow. Economic conditions can also impact the Companys ability to collect accounts receivable.
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 operations.
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 the Boardman coal plant. Additional emissions controls may be required at PGEs Boardman coal plant, although specific measures will depend on the outcome of the regulators reviews. For further information regarding the total costs and the Companys portion, see Environmental Matters in Item 1. - Business.
In addition, PGE may 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, injunctive relief, and the closure of plants. On January 15, 2008, PGE received a notice of intent to sue from a coalition of environmental groups alleging violations of the Clean Air Act and the Oregon State Implementation Plan relating to Boardman. The Company has not yet fully evaluated the claims referenced in the notice and cannot determine at this time its estimated exposure, if any. If the plaintiffs file their complaint and articulate their claims in greater detail, PGE will be better able to assess the likelihood, if any, that the claims will have a material adverse effect on the Company.
Montana regulators have adopted strict requirements related to mercury emissions that could impact the operations of Colstrip, in which PGE has a 20% ownership interest in units 3 and 4.
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.
Adverse changes in the Companys credit ratings may negatively affect its access to the capital markets and cost of funds.
Access to capital markets is important to PGEs ability to operate. Increased scrutiny of the energy industry and the impacts of regulation, as well as changes in the Companys financial performance, could result in credit agencies re-examining its credit rating. A ratings downgrade could increase the interest rates and fees on PGEs revolving credit facility, 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 principle source of short-term borrowings, could be restricted, resulting in higher interest costs. The Companys secured and unsecured debt is currently rated at investment grade by Moodys Investors Service and Standard and Poors. Should Moodys and/or Standard and Poors 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.
Failure of the Companys wholesale suppliers to perform their contractual obligations could adversely affect the Companys ability to deliver electricity and increase the Companys costs.
The Company 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 contractual agreements expire, PGE may be unable to continue to purchase natural gas, coal or electricity on terms and conditions equivalent to those of current agreements. Cost and availability of fuel supplies, primarily 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, may be subject to risks that result in disallowance of certain costs for recovery in prices, reduced plant efficiency, or higher operating costs.
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, may 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, if construction projects are not completed according to specifications, reduced plant efficiency and higher operating costs could result. Equipment failure, the ability of generating plants to operate as intended, and other factors can result in plant performance that falls below expected levels.
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 operations.
A portion of PGEs total energy requirement is comprised of generation from hydroelectric projects on the Columbia, Clackamas, Deschutes, Willamette, and Sandy rivers. Operations of these projects are 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 species 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.
Legislative efforts to reduce carbon emissions, in response to concerns related to climate change and global warming, could lead to increased capital and operating costs and have an adverse impact on the Companys operations and operating results.
The outcome of legislative efforts regarding carbon dioxide emissions, whether at the federal, regional, or state level, or the timing of any such laws or regulations that may be enacted, could have a material adverse affect 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 Company would seek to recover through the ratemaking process any capital and operating costs of additional emission control equipment or emission reduction measures, such as the cost of sequestration or purchasing allowances, or offset credits that may be required.
PGE is subject to various legal and regulatory proceedings, the outcome of which is uncertain, and resolution adverse to PGE could adversely affect the Companys cash flows, financial condition or results of operations.
From time to time in the normal course of its business, PGE is subject to various regulatory proceedings, lawsuits, claims and other matters, which may 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 the Company 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 PGEs cash flows and results of operations. Similarly, the terms of resolution could require the Company to change its business practices and procedures, which could also have an adverse affect on PGEs cash flows, financial position or results of operations.
Certain legal and regulatory proceedings, such as the proceedings related to refunds on wholesale market transactions in the Pacific Northwest described in Note 14, Contingencies, in the Notes to Consolidated Financial Statements and in Item 3. - Legal Proceedings, may have an adverse affect on results of operations and cash flows for future reporting periods.
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 laws. Regulation affects almost every aspect of the Companys business. Changes to these 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 can cause delays in or affect business planning and transactions and can substantially increase the Companys costs.
PGE has an aging workforce with a significant number of employees approaching retirement age.
The Company anticipates higher than previous averages of retirement rates over the next ten years and may 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 Companys ability to provide quality service to its customers and meet regulatory requirements will be tested and could affect operating results.
Conditions that may be imposed in connection with hydroelectric license renewals may 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 may 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.
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 physical 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 under the tariff against customer claims related to service failures beyond the Companys reasonable control. To the extent reasonably possible, the Company utilizes insurance as a means to mitigate the risk of physical loss of or damage to the Companys property resulting from natural disasters. However, such insurance may be subject to certain coverage restrictions and deductibles.
PGE is subject to political processes that may adversely affect its business.
Customer groups in certain geographic areas and certain governmental entities could attempt to acquire PGE facilities and equipment in the Companys allocated service territory through the use of public ownership initiatives, utilizing initiative petition and condemnation processes.
The Companys principal plants, generating facilities and hydro storage reservoirs 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 on the map below:
The following are generating facilities owned by PGE:
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 2009.
In October 2002, PGE entered into an agreement with state and federal agencies, conservation groups, and others regarding removal of the Companys 22 MW Bull Run hydroelectric project located in the Sandy River basin. The Marmot Dam was removed in July 2007, reducing the projects capability to 15 MW, with removal of the Little Sandy Dam planned for 2008. The FERC issued a surrender order in 2004 and an annual operating license in early 2005 that allows PGE to operate the project until the removal of Little Sandy Dam. PGE has fully recovered its remaining plant investment and is recovering approximately $17 million in estimated decommissioning costs over a ten-year period ending in 2011. Total decommissioning costs increased to an estimated $24 million at December 31, 2007, with the incremental costs expected to be recovered in future prices charged to customers.
PGE owns and/or has contractual access to transmission lines that deliver electricity from its Oregon plants to its distribution system in its service territory and also to the Northwest grid. The Company also has ownership in, and contractual access to, transmission lines that deliver electricity from the Colstrip plant in Montana to PGE. In addition, PGE has contractual access to approximately 20% of the Pacific Northwest Intertie, a 4,800 MW transmission facility between John Day, in northern Oregon, and Malin, in southern Oregon near the California border. This line is used primarily for interstate purchases and sales of electricity among utilities, including PGE.
Citizens Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen ONeill v. Public Utility Commission of Oregon, Marion County Oregon Circuit Court, the Court of Appeals of the State of Oregon, the Oregon Supreme Court.
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, citing an opinion issued by the Oregon Department of Justice that current law gave the OPUC authority to allow recovery of, and a return on, its Trojan investment and future decommissioning costs. The Declaratory Ruling was appealed to the Marion County Circuit Court, which upheld the OPUCs Declaratory Ruling in November 1994. 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 Utility Reform Project (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.
In August 1998, PGE 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. The URP filed a Petition for Review with the Oregon Supreme Court seeking review of that portion of the 1998 Decision relating to PGEs recovery of its undepreciated investment in Trojan.
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 and requested a hearing 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 URPs challenges and approving PGEs application for the accounting and ratemaking elements of the Settlement. URP appealed the Settlement Order to the Marion County Circuit Court.
On November 19, 2002, the Oregon Supreme Court dismissed PGEs and URPs Petitions for Review of the 1998 Decision. As a result, the 1998 Decision stands and the remand of the 1995 Order to the OPUC (1998 Remand) became effective.
In regards to the URPs appeal of the March 2002 Settlement Order, on November 7, 2003, the Marion County Circuit Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds (2003 Remand). The opinion does not specify the amount or timeframe of any reductions or refunds. On February 9, 2004, PGE appealed the 2003 Remand to the Oregon Court of Appeals. The OPUC has also appealed.
On March 3, 2004, the OPUC re-opened Dockets DR 10, UE 88, and UM 989 and issued a notice of a consolidated procedural conference before an administrative law judge. On October 18, 2004, the OPUC affirmed the order (Scoping Order) issued by the administrative law judge defining the scope of the proceedings necessary to comply with the orders remanding this matter to the OPUC. The URP and Class Action Plaintiffs (see Dreyer below) filed an application with the OPUC for reconsideration of the Scoping Order, which the OPUC denied. On April 18, 2005, URP and Linda K. Williams filed a complaint in Marion County Circuit Court challenging the OPUCs affirmation of the Scoping Order. On September 21, 2005, the Marion County Circuit Court granted the OPUCs motion to dismiss the complaint.
The OPUC combined the 1998 Remand and the 2003 Remand into one proceeding and is considering the matter in phases. The first phase addresses what rates would have been if the OPUC had interpreted the law to prohibit a return on the Trojan investment. The subsequent phases will address reconciling the results of the first phase with actual rates, and adjusting rates to the extent necessary. A decision is pending in the first phase of the proceeding. On November 15, 2006, PGE filed a motion with the OPUC to Consolidate Phases and Re-Open the Record.
On February 16, 2007, the Oregon Court of Appeals declined to reverse or abate the 2003 Remand and ordered the parties to file revised briefs with the Court of Appeals.
In Order No. 07-157 (the Order) entered on April 19, 2007, the OPUC denied PGEs motion with the OPUC to Consolidate Phases and Re-Open the Record. In addition, the Order abated the Phase I proceeding pending a decision by the Oregon Court of Appeals of the 2003 Remand, and ordered that a second phase of the joint remand proceedings be immediately commenced to investigate the OPUCs delegated authority to engage in retroactive ratemaking. The Order further stated that parties not now participating in the joint remand proceedings will be allowed to intervene and participate in the second phase. Pursuant to the Order, final briefs were submitted on July 20, 2007 and oral argument was held on August 9, 2007, with a decision by the OPUC pending.
On October 10, 2007, the Oregon Court of Appeals issued an opinion that reversed a March 2002 OPUC Order (the 2002 Order) approving the 2000 settlement agreements and remanded the 2002 Order to the OPUC for reconsideration. The Oregon Court of Appeals also vacated the 2003 Remand.
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, 2001 (Current Class)
and the Morgan case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2001, 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. PGE filed for an interlocutory appeal, which was rejected on February 1, 2005. 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 responds to the 2003 Remand.
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 ordered by the Circuit Court in October of 2006. A hearing on that motion is scheduled for April 2008. On January 14, 2008, the class action plaintiffs filed a motion asking the OPUC to issue an order on the OPUC remedial authority prior to addressing the other issues and the Utility Reform Project requested permission to address all issues it previously raised on appeal to the Circuit Court and on cross-appeal to the Court of Appeals in URP, et al. v. PUC, with an opportunity to present new evidence with full evidentiary hearings. On February 13, 2008, the OPUC issued an order denying this motion. In the order, the OPUC expressed its desire to avoid future piecemeal litigation by resolving all of these issues in one comprehensive order, including the issue of the OPUCs remedial authority. The OPUC further stated that it has come to the preliminary conclusion that the OPUC has refund authority under limited circumstances. The OPUC emphasized that this is a preliminary determination and stated that it has not yet determined whether it is necessary to exercise that authority in this case and that it cannot make such a determination until it has decided all phases of the proceedings. On February 22, 2008, the Administrative Law Judge issued a Ruling and Notice of Conference, which established the scope for further proceedings prior to issuance of the OPUC order. The ruling also includes notice of a conference scheduled for March 12, 2008 to establish a procedural schedule for the remainder of this phase of the proceeding.
Wah Chang, a division of TDY Industries, Inc. v. Avista Corporation, Avista Energy, Inc., Avista Power, LLC, Dynegy Power Marketing, Inc., El Paso Electric Company, IDACORP, Inc., Idaho Power Company, IDACORP Energy L.P., Portland General Electric Company, Powerex Corporation, Puget Energy, Inc., Puget Sound Energy, Inc., Sempra Energy, Sempra Energy Resources, Sempra Energy Trading Corp., Williams Power Company, Inc., United States District Court for the District of Oregon, Case No. 04-CV-00619-AS.
On May 5, 2004, Wah Chang, a division of TDY Industries, (Wah Chang) filed a complaint in the U.S. District Court for the District of Oregon against PGE and fifteen other companies (Wah Chang Defendants) alleging that practices among the Wah Chang Defendants and/or Enron and others
involving the generation, purchase, sale and transmission of electric energy, beginning in 1998 and continuing through 2001, were designed to communicate false or misleading information to participants in the energy market with the purpose of causing a shortage or appearance of a shortage in the generation of electricity, the appearance of congestion in the transmission of electricity, illegally raising the price of electricity, and fraudulently concealing illegal activities, all in violation of Federal and state antitrust statutes, the Racketeer Influenced and Corrupt Organization Act and for wrongful interference with their purchase contracts with PacifiCorp. No specific facts as to PGEs activities are alleged. Wah Chang seeks compensatory ($30 million) and treble damages.
On February 11, 2005, the Court entered an order dismissing the case based on federal preemption of state law claims, the exclusive jurisdiction of the FERC over electricity markets, and the filed rate doctrine that holds that rates approved by a governing regulatory agency are reasonable and unassailable in judicial proceedings brought by ratepayers. On March 10, 2005, Wah Chang filed a notice of appeal in the Ninth Circuit Court of Appeals, with oral argument held on April 10, 2007.
On November 20, 2007, the Ninth Circuit affirmed the trial courts dismissal of the claims based on the filed rate doctrine. On January 15, 2008, the Ninth Circuit denied Wah Changs petition for rehearing.
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. (Northwest Refund case)
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 declined to reach the merits of the FERCs ultimate decision to deny refunds. Two requests for rehearing have been filed with the court, with a decision now pending.
The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq. (California Refund case), approved by the FERC on May 17, 2007, resolves all 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, but does not settle potential claims from other market participants relating to transactions in the Pacific Northwest.
In a separate action, on March 20, 2002, the California Attorney General filed a complaint (the Lockyer case) with the FERC against various sellers in the wholesale power market, alleging that the FERCs authorization of market-based rates violated the Federal Power Act (FPA), and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to re-file their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERCs decision to the Ninth Circuit. On September 8, 2004, the Court issued an opinion upholding the FERCs authority to approve market-based tariffs, but also holding that the FERC had the authority to order refunds, if quarterly filing of market-based sales transactions had not been properly made. The Court required the FERC, upon remand, to reconsider whether refunds should be ordered. Petitions for rehearing at the Ninth Circuit and for U.S. Supreme Court review have been denied and the case has been remanded to the FERC.
On December 10, 2007, certain California parties filed with the FERC a Motion to hold the Lockyer case remand proceedings in abeyance until the court issues mandates in the California Refund case and Northwest Refund case. In their Motion, the California parties argue that all three cases include similar parties and similar issues, particularly the impact of alleged market manipulation in western energy markets during the 2000-2001 time period. They assert that these cases should be considered together by FERC and that they will file a motion to consolidate all three cases upon remand of the two that remain pending before the Ninth Circuit. The Company and other parties filed answers contesting the California parties characterization of the three cases as inextricably linked and arguing that it is premature to discuss consolidation. Consolidation of the Lockyer case with the Northwest Refund case and the California Refund case could increase the Companys potential liability by extending the period for which other parties are requesting refunds back to May 1, 2000 or earlier.
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 does not believe any of these other matters will have a material adverse effect on the Companys financial position, results of operations or cash flows.
PGE common stock is traded on the New York Stock Exchange (NYSE) under the ticker symbol POR. At February 15, 2008, there were 1,335 holders of record of PGEs common stock. Quarterly stock prices since the April 3, 2006 issuance of new PGE common stock are indicated in the table below.
PGE expects to pay regular quarterly dividends on its common stock. However, the declaration of such dividends is at the discretion of the Companys Board of Directors and is not guaranteed. The amount of common dividends will depend upon PGEs results of operations and financial condition, future capital expenditures and investments, any applicable regulatory and contractual restrictions, and other factors that the Board of Directors considers relevant.
As required by Section 303A.12 of the NYSE Listed Company Manual, the Chief Executive Officer of the Company certified to the NYSE on May 3, 2007 that she was not aware of any violation by the Company of the NYSEs corporate governance listing standards.
* Not meaningful as PGE was a wholly-owned subsidiary of Enron.
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, assumptions, business prospects, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events 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 identify 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, 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.
Customers - As of December 31, 2007, the Company served approximately 804,000 retail customers, a 1.4% increase from the end of 2006. The number of residential and commercial customers both increased during 2007, with total retail energy deliveries up 1.0% for the year. This growth was the result of continued economic expansion, as Oregons non-farm employment (seasonally adjusted) grew 1.4% in 2007 and the states 5.3% unemployment rate (seasonally adjusted) was down slightly from 2006.
The Company expects weather adjusted retail loads to increase 1.9% in 2008, with higher commercial demand and increased deliveries to industrial customers, including new solar panel manufacturers, expected to more than offset slower growth in the housing market and lower residential use resulting from conservation and energy efficiency efforts. Customer increases and demand growth will require continued investment in generation, transmission and distribution facilities to meet increased energy requirements.
PGE continues its focus on customer service and recognizes the importance of reliability, restoration response, safety, and reasonable prices in maintaining overall customer satisfaction. As the Company effectively maintains and improves its transmission, distribution, and customer service systems, it continues to place a top priority on meeting regulatory standards for safety and constantly strives to exceed service quality standards related to outage frequency and duration. The Company continues to rank high in surveys of customer satisfaction.
PGE is currently engaged in three major efforts that are expected to benefit customers. First, the Company has a customer focus initiative that seeks to meet rising customer expectations for service and reliability. Second, the Company has signed contracts with vendors for the purchase and installation of an Advanced Metering Infrastructure (AMI) system. Subject to Board of Directors and regulatory approvals, PGE will deploy AMI for residential and commercial customers between 2008 and 2010, with the expectation of achieving operational savings through increased efficiencies while also providing new services for customers. Third, the Company has undertaken an initiative to improve its ability to serve increasing numbers of customers who do business with PGE through the internet.
PGE periodically evaluates the need to change its overall general retail electric price structure to sufficiently cover its operating costs and provide a reasonable rate of return. PGE plans to file new tariffs with the OPUC on February 27, 2008, based on a forecasted 2009 test year, seeking an increase in electricity prices effective January 1, 2009. The proposed 8.9% increase in prices is a result of increased generation costs based on higher natural gas and coal prices; increased purchased power costs; and higher general (non-power) costs, including the rising cost of materials and supplies, government compliance, hydro relicensing improvements, and labor and healthcare benefits. The
revenue requirements include a return on common equity of 10.75%, based on an expected capital structure of 50% equity and 50% debt, and an overall weighted average cost of capital of 8.66%. Review of PGEs filing by the OPUC, including a detailed analysis of the Companys projected costs and proposed price structure, is expected to take nine to ten months and will include input from stakeholders.
In May 2007, Residential Exchange Program (REP) payments to the regions investor-owned utilities, including PGE, were suspended as a result of a decision by the U.S. Ninth Circuit Court of Appeals. This program, administered by the Bonneville Power Administration (BPA), provides residential and small farm customers with the benefits of federal power. The removal of exchange program credits from PGE customers bills has resulted in an approximate 14% average price increase for the Companys residential and small farm customers. In February 2008, the BPA issued its initial proposal to re-establish REP payments to investor-owned utilities. For further information, see Results of Operations in this Item 7.
Power Supply - PGE utilizes its own generating resources, along with wholesale market purchases, to meet the energy and capacity needs of its customers. In June 2007, the Company added the 406 MW capacity Port Westward plant to its base of generating resources, reducing its dependence on the wholesale energy market. With the completion of the 125 MW Phase I of Biglow Canyon in late 2007, the Company has a more diverse generation portfolio powered by coal, natural gas, hydro and wind and has further reduced its dependence on purchased power. In addition, PGE has implemented a generation excellence program aimed at ensuring cost-effective and reliable plant operations.
PGE supplements its own generation with short- and long-term wholesale contracts as needed to meet its retail load requirements and provide the most economic mix on a variable cost basis. Factors that can affect the availability and price of purchased power and fuel include weather conditions in the Northwest and Southwest, the performance of major generating facilities in both regions, regional hydro conditions, and prices of natural gas and coal used to fuel thermal generating plants. Market prices of natural gas can also be affected by destructive storms and extreme weather in other regions of the United States. Prices of purchased power, coal, and natural gas trended upward during 2007, due in part to the effect of higher crude oil prices, with the increased coal and natural gas prices resulting in higher overall generation costs.
PGEs 2007 IRP, filed with the OPUC in June 2007, describes the Companys energy and capacity supply strategy to meet the long-term electric energy needs of its customers, with emphasis on supply reliability and price stability. The result of a planning process utilizing input from various stakeholders, the IRP includes additional renewable and demand-side resources, energy efficiency measures, demand-side resources, power purchase agreements of varying terms, and the acquisition of additional peaking capacity. Once the OPUC has officially acknowledged the plan, the Company will issue Requests for Proposals to acquire sufficient resources, including power contracts and asset acquisitions, to meet the future energy and capacity needs of its customers, as outlined in the plan. For further information, see Integrated Resource Plan under Power and Fuel Supply included in Item 1. - Business.
New Renewable Energy Standards adopted by the 2007 Oregon legislature require that PGE and other large electricity providers in Oregon serve at least 25% of their retail load within the state from renewable resources by the year 2025, with interim requirements of 5% by 2011, 15% by 2015, and 20% by 2020. Biglow Canyon, which is expected to have a total installed capacity of 400 to 450 MW when all three phases are completed by the end of 2010, represents a significant step toward the Companys achievement of these goals.
Legal, Regulatory, and Environmental Matters - PGE is a party in several legal and regulatory proceedings that could have a material impact on the Companys results of operations and cash flows for future periods, including:
For further information regarding these and other matters, see Note 14, Contingencies, in the Notes to Consolidated Financial Statements.
PGE is subject to state and federal environmental laws and regulations that establish air quality standards and regulate allowed emissions from thermal generating plants. Such laws and regulations, as well as federal regional haze rules that establish goals to protect visibility and remedy existing impairments resulting from man-made pollution, may affect the Companys operations. While PGE anticipates that it will be able to comply with these restrictions and those imposed under the Clean Air Mercury Rule, such rules will require added costs for additional emission control equipment. In November 2007, the Company submitted to the Oregon DEQ its BART plan for implementing controls to meet the requirements. Final approval of the plan is expected to occur in the second half of 2009. For further information, see Air Quality Standards within Capital Requirements of the Capital Resources and Liquidity section of this Item 7.
The Company has begun construction of a Selective Water Withdrawal structure at its Pelton Round Butte Hydroelectric Project in an effort to restore fish passage on the upper Deschutes River. During 2007, decommissioning of the Bull Run system began with the removal of the Marmot Dam, allowing fish passage on the Sandy River.
In addition, increasing local, national and international concerns regarding global warming and climate change may result in future laws or regulations that require additional pollution control equipment or significant emissions fees or taxes. For further information regarding estimated future capital expenditures related to emission control laws and regulations, see Capital Requirements in Capital Resources and Liquidity in this Item 7.
Financing - PGE maintains adequate liquidity through both its $400 million credit facility and access to the commercial paper market. The Company issued a total of $375 million of First Mortgage Bonds in 2007 to help provide sufficient liquidity to fund ongoing operations and construction projects. Increased capital expenditures expected over the next several years include those related to Phases II and III of Biglow Canyon, hydro relicensing, the AMI project, and requirements of environmental regulations. The Companys ability to execute its capital investment plan will depend on continued strength in the economy and access to capital markets. In anticipation of additional capital needs, the Company recently received authorization from the FERC to increase its short-term borrowing to a total of $550 million and has received approval from the OPUC to issue an additional $250 million of First Mortgage Bonds.
PGE strives to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50% in order to maintain acceptable credit ratings and allow access to long-term capital at reasonable rates. PGEs common equity ratio at December 31, 2007 was 50%.
For a discussion of new accounting standards that have been issued but not yet adopted by the Company, see New Accounting Standards within Note 1, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements.
Results of Operations
See Consolidated Statements of Income in Item 8. - Financial Statements and Supplementary Data, for Operating expense detail. The following tables contain certain financial and operating information for the periods presented:
2007 Compared to 2006
PGEs net income was $145 million, or $2.33 per diluted share, for the year ended December 31, 2007 compared to $71 million, or $1.14 per diluted share, for the year ended December 31, 2006. The improved results were primarily attributable to increased energy deliveries, increased generation from the return of Boardman to full operation, and the addition of Port Westward. Results for 2006 included a $32 million after-tax impact of incremental power costs required to replace the output of Boardman during its extended repair outage. Results for 2007 include a positive $16 million after-tax impact of the deferral of a portion of the Boardman replacement power costs (including accrued interest) for potential future recovery, as approved by the OPUC.
Also contributing to the increase in earnings was a $35 million after-tax impact from SB 408, with an estimated collection from customers recorded in 2007 compared to a refund recorded in 2006. This positive impact in 2007 reflects in part the so-called double whammy effect of the law that results in unusual outcomes in certain situations. As the provisions of SB 408 apply to PGE, if the Company records higher operating income as compared to its latest rate case, customers would be 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 15, Utility Rate Treatment of Income Taxes, in the Notes to Consolidated Financial Statements.
Total revenues in 2007 increased $223 million, or 15%, from 2006 as a result of the following 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 Electricity Service Supplier (ESS). Reduced revenues from these customers reflect the lower energy sales as well as transition adjustment credits, reflecting the difference between the cost and market value of PGEs power supply portfolio, as provided by Oregons electricity restructuring law.
On a weather adjusted basis, retail energy deliveries to PGE and ESS customers increased 1.1% in 2007, with deliveries to residential, commercial, and industrial customers increasing by 0.7%, 1.0%, and 2.2%, respectively. Increased residential sales resulted primarily from an increase of 10,000 in the average number of customers served during the year. Higher commercial and industrial sales resulted from a 1,500 increase in the average number of customers served. These increases were partially offset by a slowing economy and conservation efforts. PGE forecasts an approximate 1.9% increase in total weather adjusted energy deliveries to PGE and ESS customers in 2008.
The following price adjustments, as approved by the OPUC, became effective on January 1, 2008:
The above items, combined with other miscellaneous tariff changes totaling an approximate 0.5% increase, will result in an overall increase of approximately 0.8% in average prices for 2008.
Pending regulatory matters that could have an effect on customer prices and future revenues include the following:
BPA has also determined that actual REP payments made from 2002 through May 2007 under certain settlement agreements exceeded those which should have been made under terms of traditional REP agreements covering the period 2002 through 2011. In its initial proposal BPA stated that such agreements would have utilized a calculation method that would have resulted in lower payments than those actually made by BPA. The BPA proposal includes recovery of $620 million of such overpayment ($64 million from PGE customers) over the period of 2009 through 2028. The recovery will reduce future REP payments to investor-owned utilities.
Purchased power and fuel expenses for 2007 increased $116 million, or 15%, from 2006. The following table indicates PGEs total system load (including both retail and wholesale) for the last two years.
The average variable power cost of the above total system loads was $39.19 per MWh in 2007 and $33.65 per MWh in 2006. Averages exclude the effect of amounts related to regulatory power cost deferrals, unrealized gains on derivative instruments, and wholesale credit provisions.
The increase in Purchased power and fuel expense was due primarily to the following factors:
Partially offsetting the above increases were:
Generation activities - In 2007, PGE generated 56% of its retail load requirement compared to 37% in 2006. Short- and long-term purchases were utilized to meet the remaining load. The Company met 46% of its retail load requirement from thermal generation in 2007 compared to 27% in 2006. PGE- owned hydro generation met 10% of PGEs retail load requirement in both 2007 and 2006.
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. PGE has long-term agreements to purchase power generated from hydro facilities on the mid-Columbia River. Energy received under these agreements increased 3% in 2007.
Current forecasts indicate that regional hydro conditions in 2008 will be near normal levels. Volumetric water supply forecasts for the Pacific Northwest region, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies as of February 14, 2008 indicate the April-to-September 2008 runoff forecast compared to the actual runoffs for 2007 and 2006, as follows:
Production, distribution, administrative and other expenses increased $30 million, or 10%, in 2007 compared to 2006, due to the following factors:
Depreciation and amortization expenses 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:
Income taxes increased $33 million, or 87%, in 2007, due primarily to higher taxable income for the year.
Other income increased $2 million, or 11%, 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 during the year.
2006 Compared to 2005
PGEs net income was $71 million, or $1.14 per diluted share, for the year ended December 31, 2006 compared to $64 million, or $1.02 per diluted share, for the year ended December 31, 2005. The improved results were primarily attributable to higher energy sales, resulting from both an increase in customers served and weather conditions, and increased hydro availability, resulting from improved stream flows. Results for 2006 also included a $26 million after-tax reserve for a potential refund obligation to customers, reflecting the Companys estimate of the impact of SB 408. In addition, 2006 results reflect a $4 million after-tax decrease in earnings related to the higher cost of incremental replacement power during the extended, unplanned repair outage at Boardman. Results for 2005 include a $6 million after-tax provision related to the refund to customers of previously collected local income taxes.
Total revenues increased $74 million, or 5%, in 2006 from 2005 as a result of the following factors:
Weather adjusted retail energy deliveries to PGE customers, including those purchasing energy from an ESS, increased 2.7% in 2006 compared to 2005, with deliveries to residential, commercial and industrial customers increasing by 2.4%, 3.0% and 2.6%, respectively.
Purchased power and fuel expenses increased $92 million, or 14%, in 2006 from 2005 as a result of the following factors:
The following table indicates PGEs total system load (including both retail and wholesale) for the years 2006 and 2005.
The average variable power cost of the above total system loads was $33.65 per MWh in 2006 and 31.34 per MWh in 2005. Averages exclude the effect of amounts related to regulatory power cost deferrals, unrealized gains on derivative instruments, and wholesale credit provisions.
Generation activities - In 2006, PGE generated 37% of its retail load requirement compared to 42% in 2005. Short- and long-term purchases were utilized to meet the remaining load. The Company met 27% of its retail load requirement from thermal generation and 10% from hydro generation in 2006 compared to 34% and 8%, respectively, in 2005.
A 17% reduction in thermal production, related primarily to Boardmans outage from late October 2005 through June 2006, resulted in increased reliance on higher cost purchases in the wholesale market.
Partially offsetting the decrease in thermal production was a 28% increase in Company-owned hydro production, resulting from increased stream flows. Energy received under long-term agreements to purchase power from hydro facilities on the mid-Columbia River increased 13% in 2006 compared to 2005.
Production, distribution, administrative and other expenses increased $8 million, or 3%, in 2006 compared to 2005 primarily due to increased expenses related to maintenance and repair activities at PGEs thermal generating plants, storm-related service restoration costs, and increased tree trimming costs. Such increases were partially offset by reduced administrative and other expenses, related primarily to the settlement of certain asserted claims in 2005.
Depreciation and amortization expenses decreased $14 million, or 6%, in 2006 compared to 2005 due primarily to the net effect of the following factors:
Income taxes decreased $8 million, or 17%, primarily due to lower taxable income and a reduction in state income taxes resulting from apportionment rule changes.
Other income increased $13 million in 2006 compared to 2005 due to the net effect of the following factors:
Interest expense increased $1 million, or 1%, in 2006 compared to 2005, primarily due to a higher level of outstanding long-term debt resulting from the issuance of additional First Mortgage Bonds during 2006.
Capital Resources and Liquidity
The following table presents PGEs projected primary cash requirements, excluding AFDC, for the years indicated (in millions):
Biglow Canyon - In accordance with PGEs plan to acquire additional wind generation, as outlined in its IRP, the Company is proceeding with construction of Biglow Canyon, located in Sherman County, Oregon.
Phase I of the project, with an installed capacity of 125 MW and a cost of $255 million (including AFDC), has been completed. Phases II and III of the project are currently in the advanced planning stages. In the second quarter of 2007, PGE paid $17 million to a vendor towards wind turbines for Phases II and III. The payment is non-refundable if PGE and the vendor do not execute a definitive agreement after good faith efforts to negotiate and execute such an agreement within a specified time period. The payment will be returned to PGE if the vendor fails to negotiate the definitive agreement in good faith. The estimated total cost of Phases II and III is $700 million to $800 million, including approximately $50 million AFDC, with Phase II expected to be completed by the end of 2009 and Phase III expected to be completed by the end of 2010. The cost of the project could vary depending upon the fluctuations of foreign currencies against the U.S. dollar. Total installed capacity of all three phases is expected to be between 400 and 450 MW.
Hydro relicensing - As required under the 50-year license that the FERC issued to PGE in 2004 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.
Advanced Metering Infrastructure - PGE plans to install, subject to OPUC approval, over 800,000 new customer meters that would enable daily, two-way remote communications with the Company. AMI, at an estimated capital cost of $130 million to $135 million, is expected to provide improved services, operational efficiencies, and a reduction in future expenses.
Air Quality Standards - In accordance with new federal regional haze rules aimed at visibility impairment in several federally protected areas, the DEQ is conducting an assessment of emission sources pursuant to a BART process. Several other states are conducting a similar process. Those sources determined to cause, or contribute to, visibility impairment at protected areas will be subject to a BART Determination.
In addition, the federal government and the states in which PGE operates have adopted the following regulations concerning mercury emissions:
In response to the EPAs regional haze rules, the Company volunteered to participate in a DEQ pilot project to analyze information about air emissions from Boardman. An exemption modeling analysis for identified sources, which began in September 2006, has indicated that the Boardman and Beaver generating plants may cause or contribute to visibility impairment in several federally protected areas. In November 2007, the Company submitted a BART Determination to the DEQ for Boardman that stated the BART for Boardman is a combination of New Low NOx Burners, Modified Over Fire Air System, SNCR, and Semi-dry Flue Gas Desulphurization, and that mercury emission regulations should be addressed through a Mercury Sorbent Injection System. The total cost for these controls is estimated to be in the range of $300 million to $400 million (100% of total costs). While the Company believes that these controls meet BART requirements, the regulatory agencies could require Selective Catalytic Reduction rather than SNCR, which would increase the total estimated cost to a range of $470 million to $620 million (100% of total costs). The Company has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change. Final approval of the plan is expected to occur in the second half of 2009.
As the regulatory requirements are clarified by the relevant agencies and the related costs more closely estimated, the Company will further evaluate the economic prudency 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. Such additional costs, as well as the requirement to install Selective Catalytic Reduction controls, could require an investment in excess of what the plant can economically support.
The ultimate impact that the above regulatory requirements and air emission controls will have on future operations, costs, or generating capacity of the Companys thermal generating plants is not yet determinable. PGE will seek to recover its share of any associated costs through the ratemaking process.
On January 15, 2008, PGE received a notice of intent to sue from a coalition of environmental groups. The notice alleges violations of the Clean Air Act and the Oregon State Implementation Plan relating to the Boardman generation facility. The Company has not yet fully evaluated the claims referenced in the notice and cannot determine at this time its estimated exposure, if any. If the plaintiffs file their complaint and articulate their claims in greater detail, PGE will be better able to assess the likelihood, if any, that the claims will have a material adverse effect on the Company.
Transmission improvements - PGE and seven other utilities have initiated WECC Coordinated Planning and Technical Studies related to eight significant new high voltage transmission projects currently under consideration in the northwestern United States. The sponsors anticipate completion of the WECC Phase I Rating Studies by August 2008. The Southern Crossing Project, proposed by PGE, would expand the Companys transmission system across the Oregon Cascades with the construction of a new 500 kV transmission line. The project is designed to integrate existing Boardman and Coyote Springs generation resources, integrate up to 750 MW of proposed wind generation resources, and provide additional transmission capacity for future needs.
PGEs access to short-term debt markets provides sufficient liquidity to support current operating activities, including the purchase of electricity to meet load requirements and fuel for the Companys thermal generating plants. Long-term capital requirements are driven largely by expenditures for distribution, transmission, and generation facilities to support both new and existing customers, as well as debt retirement. PGEs liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposits related to wholesale trading activities, which can vary depending upon the Companys forward positions and the corresponding price curves.
PGE has performed an assessment of its investments held in trusts, which will be used to satisfy future obligations under the Companys pension and postretirement benefit plans and to satisfy future obligations to decommission its Trojan nuclear plant. The Company has determined that a decline in the fair value of its investments that may have subprime-related exposures would not be material.
The following summarizes PGEs cash flows for the periods presented (in millions):
Cash Flows from Operating Activities - The $238 million increase in cash provided by operating activities in 2007 compared to 2006 was primarily attributable to:
A significant portion of cash provided by operations consists of the recovery in revenue requirements of non-cash charges for depreciation and amortization related to utility plant. The $38 million reduction of these charges in 2007 was due primarily to reduced depreciation rates and authorized recovery of Trojan decommissioning costs, as approved by the OPUC in PGEs general rate case. The Company estimates recovery of depreciation and amortization charges to be approximately $210 million in 2008. Combined with all other sources, cash provided by operations is estimated to be approximately $380 million during 2008.
Cash Flows from Investing Activities - Cash flows from investing activities consist of new construction and improvements to PGEs distribution, transmission, and generation facilities. The $71 million increase in cash used in investing activities was primarily attributable to the net effect of:
The Company plans $428 million in total capital expenditures in 2008 related to Phases II and III of Biglow Canyon, hydro relicensing, ongoing capital expenditures and AMI.
Cash Flows from Financing Activities - Cash flows from financing activities provide supplemental cash for both operating and capital requirements. Cash provided by financing activities in 2007 was primarily attributable to the net effect of the following:
PGE has received approval from the FERC to increase its short-term borrowings up to a total of $550 million through February 6, 2010, and has received approval from the OPUC to issue an additional $250 million in long-term debt.
Dividends on Common Stock
The following table indicates common stock dividends declared in 2007:
PGE expects to pay regular quarterly dividends on its common stock; however, the declaration of such dividends is at the discretion of the Companys Board of Directors and is not guaranteed. The amount of common dividends is dependent upon PGEs results of operations and financial condition, future capital expenditures and investments, any applicable regulatory and contractual restrictions, and other factors that the Board of Directors considers relevant. On February 20, 2008, the Board of Directors declared a dividend of $0.235 per share of common stock to stockholders of record on March 25, 2008, payable on or before April 15, 2008.
Debt and Equity Financings
PGE has a $400 million five-year revolving credit facility with a group of commercial and investment banks that supplements operating cash flow and provides a primary source of liquidity. The facility, which expires in 2012 and is unsecured, is used as backup for commercial paper borrowings and is available for general corporate purposes, with the maximum amount available to PGE for borrowings and/or the issuance of standby letters of credit.
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 bank credit markets, both generally and for electric utilities in particular. Management believes that the availability of the credit facility and the expected ability to issue long-term debt and equity securities provide sufficient liquidity to meet the Companys anticipated capital and operating requirements. The Company anticipates issuing a total of approximately $300 million debt and $200 million equity in 2008 and 2009.
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 50% and 53% at December 31, 2007 and December 31, 2006, respectively.
For further information regarding PGEs credit facility and debt financing activities, see Note 9, Credit Facility and Debt, in the Notes to Consolidated Financial Statements.
Credit Ratings and Debt Covenants
PGEs secured and unsecured debt is rated investment grade by Moodys Investors Service (Moodys) and Standard and Poors (S&P). PGEs current credit ratings and outlook are 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 counterparties to post additional performance assurance collateral. On December 31, 2007, PGE had posted approximately $33 million of collateral, consisting of $28 million in cash and $5 million in letters of credit, none of which is affiliated with master netting agreements. Based on the Companys energy portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of
December 31, 2007, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $55 million and decreases to approximately $8 million by December 31, 2008. The approximate amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $83 million and decreases to approximately $8 million by December 31, 2008.
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 on December 31, 2007 it could issue up to approximately $601 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 facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the facility, to 65% of total capitalization. At December 31, 2007, the Companys consolidated indebtedness to total capitalization ratio, as calculated under the facility, was 50%.
Contractual Obligations and Commercial Commitments
The following indicates PGEs contractual obligations as of December 31, 2007 (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 PGE 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.
For details of annual costs by project, including debt service, see Note 9, Commitments and Guarantees, in the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
PGE is not engaged in any off-balance sheet arrangements through unconsolidated limited purpose entities.
Critical Accounting Policies and Estimates
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. 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. Under the authority of the FERC and the OPUC, the Company has recorded certain regulatory assets and liabilities at December 31, 2007 in the amount of $304 million and $574 million, respectively, and regulatory assets and liabilities of $351 million and $523 million, respectively, at December 31, 2006. For further information, see Note 1, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements.
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, 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 operations and financial position.
Asset Retirement Obligations
SFAS 143, as interpreted by FASB Interpretation No. 47, 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 Utility plant are included in Depreciation and Amortization expense, with those related to Other property included in Other Income (Deductions). In accordance with requirements of SFAS 143, 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.
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 under SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended.
In its January 2007 general rate order, the OPUC approved a new PCAM by which PGE can adjust future rates to reflect a portion of the difference between each years forecasted and actual NVPC. Effective December 2006, PGE began to apply SFAS 71 to all derivative instruments to reflect the effects of regulation. As a result, a regulatory asset or regulatory liability is recorded to offset changes in fair value of instruments not included in the Resource Valuation Mechanism (RVM). Prior to December 2006, changes in fair value for these instruments were not offset by a regulatory asset or regulatory liability unless those contracts were previously included in rates under the RVM or were expected to be included in future rates under the RVM. Effective January 17, 2007, a new Annual Power Cost Update Tariff replaced the RVM.
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 is the difference between the premium paid or received and 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. At December 31, 2007, the plans assets were comprised of approximately 67% equity securities and 33% debt securities.
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 2007 pension expense by approximately $1.2 million. A 0.25% reduction in the discount rate would have increased 2007 pension expense by approximately $1.5 million.
PGE is exposed to various forms of market risk (including changes in commodity prices, foreign currency exchange rates, and interest rates), as well as to credit risk. These changes may affect the Companys future financial results, as discussed below.
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. In early 2005, PGE discontinued its trading activities for non-retail purposes, with existing trading transactions settled by December 31, 2005. The Company uses purchased power contracts to supplement its thermal, hydroelectric, and wind generation to respond to fluctuations in the demand for electricity and variability in generating plant operations. In meeting these needs, PGE is exposed to market risk arising from the need to purchase power and to purchase fuel for its natural gas and coal fired generating units. 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.
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 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 2007 were $4.7 million, $7.6 million, and $1.6 million, respectively, and in 2006 were $5.7 million, $9.9 million, and $3.3 million, respectively.
PGEs energy portfolio activities are subject to regulation and related costs are recovered 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 faces exposure 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.
At December 31, 2007, 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 $400 million five-year unsecured revolving credit facility. 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. PGE had no short-term debt outstanding at December 31, 2007.
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.
The total fair value and carrying amounts (including current maturities) of PGEs long-term debt are as follows (in millions):
For detail of debt by category, see Note 7, Credit Facility and Debt, in the Notes to Consolidated Financial Statements.
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 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 reduced 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. At December 31, 2007, the likelihood of significant losses associated with credit risk in trade accounts receivable is considered to be remote.
The following table presents PGEs credit exposure for commodity activities and their subsequent maturity as of December 31, 2007. 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. As of December 31, 2007, there was no posted collateral subject to be returned to a counterparty that is affiliated with master netting agreements.
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.
Risk Management Committee
PGE has a Risk Management Committee (RMC) which is responsible for providing oversight of the adequacy and effectiveness of the 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.
For further information on price risk management activities, see Note 10, Price Risk Management, in the Notes to Consolidated Financial Statements.
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, 2007 and 2006, 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, 2007. Our audits also included the financial statement schedule listed in Item 15(a). We also have audited the Companys internal control over financial reporting as of December 31, 2007, 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 and financial statement schedules, 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 the financial statement schedule 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, 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 the Portland General Electric Company and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As discussed in Notes 1 and 2 to the consolidate financial statements, on December 31, 2006 the Company changed its method of accounting for defined benefit and other postretirement plans upon the adoption of Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.
/s/ Deloitte & Touche LLP
February 27, 2008
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in millions, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
(Dollars in millions)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
Nature of Operations
Portland General Electric Company (PGE, or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power marketers located throughout the western United States. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGEs corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. PGEs service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. At the end of 2007, PGEs service area population was approximately 1.6 million, comprising about 43% of the states population. The Company served approximately 804,000 retail customers at December 31, 2007.
Note 1 - Summary of Significant Accounting Policies
The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries. The Companys ownership share of direct expenses and costs related to jointly-owned generating plants are also included in the consolidated financial statements. Intercompany balances and transactions have been eliminated.
Basis of Accounting
PGE and its subsidiaries financial statements conform to accounting principles generally accepted in the United States. In addition, PGEs accounting policies are in accordance with the requirements and the rate making practices of regulatory authorities having jurisdiction.
Use of Estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of contingent liabilities, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Contingencies are evaluated based on Statement of Financial Accounting Standards No. (SFAS) 5, Accounting for Contingencies, using the best information available. 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 possible 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 the probable loss cannot be reasonably estimated. A material loss contingency will be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. Gain contingencies are recognized upon realization and are disclosed when material.
Certain amounts in prior year financial statements have been reclassified for comparative purposes. Specifically, Allowance for equity funds used during construction and Senate Bill 408 deferrals,
previously classified within Other non-cash income and expenses, net on the Consolidated Statements of Cash Flows, are now reported separately. These reclassifications had no effect on PGEs previously reported consolidated financial position, results of operations, or cash flows.
Retail revenues are recognized when monthly billings are made for energy sold to customers and delivered to those customers that purchase their energy from Energy Service Suppliers (ESSs). In addition, estimated unbilled revenues are accrued for services provided to retail customers from the meter read date to month-end. Unbilled revenues are calculated based upon each months actual net system load, the number of days from meter-reading date to month-end, and current retail customer prices. Estimated provisions for uncollectible accounts receivable related to retail electricity sales, charged to Administrative and other expense, are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on managements assessment of the probable collection of customer accounts, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors.
Wholesale revenues are recognized as energy is delivered to the Companys wholesale customers (primarily utilities and energy marketers) during the month. Provisions related to wholesale accounts receivable and unsettled positions, charged to Purchased power and fuel expense, are based on a periodic review and evaluation that includes counterparty non-performance risk and contractual rights of offset when applicable. Actual amounts written off are charged to the allowance for uncollectible accounts.
In certain situations, PGE defers the recognition of revenues until the period in which the related costs are incurred, in accordance with the provisions of SFAS 71, Accounting for the Effects of Certain Types of Regulation.
In addition to power purchases and certain price risk management activities (described under Price Risk Management in this Note), certain other activities are reflected in Purchased power and fuel expense. These consist of: 1) amounts related to certain power cost adjustments and deferrals; 2) amounts recorded under PGEs long-term power exchange contracts that help meet seasonal peaking requirements (for further information, see Purchased Power in Note 9, Commitments and Guarantees); and, 3) provisions related to wholesale accounts receivable and unsettled positions (described under Revenue Recognition in this Note).
Price Risk Management
PGE engages in price risk management activities in its electric business, utilizing derivative instruments such as forward, swap, and option contracts for electricity and natural gas, and futures contracts for natural gas. Under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (as amended), derivative instruments are recorded on the Consolidated Balance Sheets as Assets and Liabilities from price risk management activities measured at fair value, unless they qualify for the normal purchases and normal sales exception, with changes in fair value recognized currently in earnings unless hedge accounting applies.
Certain electricity forward contracts that were entered into in anticipation of serving the Companys regulated retail load meet the requirements for treatment under the normal purchases and normal sales exception under SFAS 133, as amended by SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. Other activities consist of certain electricity forwards and natural gas forwards and swaps that qualify as cash flow hedges of forecasted transactions, and electricity
options, certain electricity forwards, certain natural gas swaps and forward contracts for acquiring Canadian dollars. Such activities are utilized to protect against variability in expected future cash flows due to associated price risk and to minimize net power costs for retail customers.
The Public Utility Commission of Oregon (OPUC), which regulates PGEs retail electricity business, recognizes derivative contracts only at the time of settlement. Contracts that qualify for the normal purchases and normal sales exception are not required to be recorded at fair value. Unrealized gains and losses from contracts that qualify as cash flow hedges are recorded net in Other comprehensive income (OCI) and contracts designated as non-hedges are recorded net in Purchased power and fuel expense on the Statements of Income. The timing difference between the recognition of unrealized gains and losses on derivative instruments and their realization and subsequent recovery in rates is recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS 71.
Prior to December 2006, PGE recorded a regulatory asset or regulatory liability under SFAS 71 to offset unrealized gains and losses on certain contracts recorded prior to settlement to the extent that such contracts were included in the Companys Resource Valuation Mechanism (RVM). The regulatory asset or regulatory liability is reflected within Regulatory assets or Regulatory liabilities, respectively, on the Consolidated Balance Sheets. Upon settlement, the regulatory asset or regulatory liability is reversed. In its January 17, 2007 general rate order, the OPUC approved a new Power Cost Adjustment Mechanism (PCAM) by which PGE can adjust future rates to reflect a portion of the difference between each years forecasted and actual net variable power costs (NVPC). As a result, a regulatory asset or regulatory liability is recorded to offset changes in fair value of derivative instruments not included in the RVM. Effective with the January 17, 2007 order, a new Annual Power Cost Update Tariff replaced the RVM.
Sales and purchases involving electricity derivative activities that are physically settled are recorded in Revenues and Purchased power and fuel expense, respectively. Electricity derivative activities that are booked out (not physically settled) are recorded on a net basis in Purchased power and fuel expense, pursuant to the requirements of Emerging Issues Task Force Issue No. (EITF) 03-11, Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes as Defined in Issue 02-3. For further information, see Note 10.
Stock-based compensation is accounted for in accordance with SFAS 123 (revised 2004), Share-based Payments (SFAS 123R), which requires the measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, based on the estimated fair value of the awards. Under SFAS 123R, the fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period. PGE attributes the value of stock-based compensation to expense on a straight-line basis. For further information, see Note 5.
Counterparty and Customer Deposits
In the course of its wholesale activities, PGE both receives and deposits performance assurance cash collateral, with required amounts based upon provisions contained in certain wholesale power agreements with counterparties. Amounts deposited with counterparties under such agreements are reflected as margin deposits and classified in Other current assets in the Consolidated Balance Sheets and were $28 million and $46 million at December 31, 2007 and 2006, respectively. Amounts received from counterparties under such agreements are reflected as customer deposits and are classified in Other current liabilities in the Consolidated Balance Sheets and were $8 million and $5 million at December 31, 2007 and 2006, respectively, which includes certain retail and transmission customer deposits received.
Capitalization of Property, Plant and Equipment
Additions to utility plant are capitalized at their original cost, consistent with accounting and regulatory guidelines. Costs include direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and allowance for funds used during construction. Plant replacements are capitalized, with minor items charged to expense as incurred. The costs to purchase/develop software applications are capitalized in accordance with American Institute of Certified Public Accountants Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. Costs of relicensing the Companys hydroelectric projects are capitalized and amortized over the related license period.
Utility plant consists of the following (in millions):
Depreciation and Amortization of Property, Plant and Equipment
Depreciation is computed using the straight-line method, based upon original cost and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was approximately 3.9% in 2007, 4.3% in 2006, and 4.4% in 2005. Estimated asset retirement removal costs included in depreciation expense were $43 million, $68 million, and $64 million in 2007, 2006, and 2005, respectively. The reductions in 2007 are related to PGEs most recent depreciation study, as described below.
Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of Asset Retirement Obligations (AROs) and asset retirement removal costs. The studies are conducted every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. The results of the most recent depreciation study, filed in November 2005, were incorporated into customer rates that became effective on January 17, 2007.
Thermal production plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the forecasted retirement date. These dates range from 2020 to 2042. Depreciation is provided on the Companys other classes of plant in service over their estimated average service lives, which are as follows: Hydro, 88 years; Wind, 27 years; Transmission, 48 years; Distribution, 38 years; and General, 14 years.
The original cost of depreciable property units, net of any related salvage value, is charged to accumulated depreciation when property is retired and removed from service. Cost of removal expenditures are charged to asset retirement obligations for assets with AROs and to accumulated asset retirement removal costs, included in Regulatory liabilities, for assets without AROs. For further information, see Note 12.
Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro relicensing costs, which are amortized over the applicable license term. Amortization expense for 2007, 2006, and 2005, was $15 million, $15 million, and $13 million, respectively. Accumulated amortization was $96 million and $82 million at December 31, 2007 and December 31, 2006, respectively.
Major Maintenance Expenses
Costs of periodic major maintenance inspections and overhauls at the Companys generating plants are charged to operating expense as incurred. Due to the variability of major maintenance expenses at the Coyote Springs combustion turbine generating plant, PGEs retail customer prices include the recovery of an annual amount, as authorized by the OPUC. Differences between amounts authorized in prices and actual Coyote Springs maintenance expenses are deferred as regulatory assets or regulatory liabilities pursuant to SFAS 71.
Allocations and Loadings
PGE utilizes a series of cost distributions and loadings to allocate certain administrative and overhead costs between capital and operating accounts, based primarily on construction activities of the Company.
Allowance for Funds Used During Construction (AFDC)
AFDC represents the pre-tax cost of borrowed funds used for construction purposes and a reasonable rate for equity funds. It is capitalized as part of the cost of plant and is credited to income but does not represent current cash earnings. The average rate used by PGE in 2007 was 8%, while the rates for 2006 and 2005 were 9%. AFDC from borrowed funds was $10 million in 2007, $8 million in 2006, and $4 million in 2005 and is reflected in the Consolidated Statements of Income as a reduction to interest expense. AFDC from equity funds was $16 million in 2007, $16 million in 2006, and $8 million in 2005 and is reflected as a component of Other income (deductions).
Debt Issuance Costs
Underwriting, legal, and other direct costs related to the issuance of debt securities are deferred and amortized to interest expense equitably over the life of the security. Unamortized debt issuance costs at December 31, 2007 and 2006 were $16 million and $15 million, respectively, and are included within Other noncurrent assets on the Consolidated Balance Sheets.
PGE files consolidated federal and state income tax returns. The Companys policy is to collect for tax liabilities from subsidiaries that generate taxable income and to reimburse subsidiaries for tax benefits utilized in its tax return. Deferred income taxes are recorded for temporary differences between financial and income tax reporting. Investment tax credits utilized have been deferred and are being amortized to income over a period which will end in 2011, which corresponds with the lives of the related properties. Interest and penalties related to any future income tax deficiencies will be recorded within Interest expense and Other income (deductions), respectively, in the Consolidated Statements of Income.
Cash and Cash Equivalents
Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents. Cash equivalents consist of money market funds and total $59 million and zero at December 31, 2007 and 2006.
Non-Qualified Benefit Plan Trust
The non-qualified benefit plan trust is comprised of insurance contracts and investments in money market, bond, and other equity investments. The cash surrender value of insurance contracts is reported as an asset at the end of the reporting period, with changes in such values between reporting periods recognized as income or expense of the period. For further information, see Note 2. The cash surrender values of insurance contracts, the majority of which are held in the trust, were $22 million and $23 million at December 31, 2007 and 2006, respectively. The investments in marketable securities are classified as trading and recorded at fair value on the Consolidated Balance Sheets. Realized and unrealized gains and losses on these investments are determined using average cost and are included in Other income (deductions) on the Consolidated Statements of Income. Investments in marketable securities and cash totaled $47 million at December 31, 2007 and 2006.
Accumulated Other Comprehensive Income
SFAS 130, Reporting Comprehensive Income, establishes standards for the reporting of comprehensive income and its components. Accumulated other comprehensive income (AOCI) is comprised of the difference between the pension and other postretirement plans obligations recognized in earnings to date, and the funded position at December 31, 2007 and 2006. With the adoption of SFAS 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS 158) on December 31, 2006, PGE recorded an initial adjustment to reflect the provisions of SFAS 158.
PGEs inventories are recorded at cost, which includes the purchase price (less discounts), applicable taxes, transportation and handling, etc. The average cost method is utilized to price inventory as fuel is burned at the generating plants and as materials and supplies are issued for operations, maintenance and capital activities. General storeroom operation costs, including procurement, management, and storage, are recorded in the unallocated stores account and distributed equitably as materials and supplies are issued.
Inventories consist of the following (in millions):
Asset Retirement Obligations
Asset retirement obligations are accounted for in accordance with SFAS 143, Accounting for Asset Retirement Obligations, which requires that the fair value of a liability for an ARO be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Because of the long lead time involved until future decommissioning activities occur, the Company uses present value techniques as quoted market prices and a market-risk premium are not available. The present value of estimated future removal expenditures, which is revised periodically, is recorded as an ARO on the Consolidated Balance Sheets, with actual expenditures charged to the ARO as incurred. For further information, see Notes 12 and 13.
Regulatory Assets and Liabilities
As a rate-regulated enterprise, the Company applies SFAS 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Accounting under SFAS 71 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprises cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers.
As of December 31, 2007, the majority of PGEs regulatory assets and liabilities are reflected in customer rates and are amortized over the period in which they are included in billings to customers. Items not currently reflected in rates are pending before the regulatory body as discussed below. Based on such rates, PGE estimates that it will collect substantially all of is regulatory assets, and refund its regulatory liabilities (excluding those related to asset retirement obligations and removal costs), within the next 12 years.
Regulatory assets and liabilities consist of the following (in millions):
Circumstances that could result in the discontinuance of SFAS 71 include (1) increased competition that restricts the Companys ability to establish prices to recover specific costs, and (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of SFAS 71 to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that the Companys regulatory assets are probable of future recovery.
Income taxes recoverable - The amount represents tax benefits previously flowed to customers through rates for temporary differences between book and tax reporting. The balance is reduced as temporary differences reverse and the increase in current tax expense is recovered in customer rates. PGE expects recovery over the next 17 years.
Pension and other postretirement plans - On December 31, 2006, PGE adopted SFAS 158, which requires that the funded status of pension and other postretirement plans be recognized, with the resulting adjustment recorded to the ending balance of AOCI on the Consolidated Balance Sheets. Postretirement costs are covered in rates charged to customers. The OPUC issued an accounting order that authorizes PGE to record a regulatory asset equal to the pre-tax charge against AOCI that would otherwise be required by recognition of the pension funded status under SFAS 158. As pension expense is recognized in future years, the regulatory asset will be reduced. PGE expects recovery over the average service life of its employees. For further information, see Note 2.
Price risk management - SFAS 133 requires that unrealized gains and losses on derivative instruments that do not qualify for the normal purchase and normal sale exception be recorded in earnings or OCI in the current period. To reflect the effects of regulation under SFAS 71, timing differences between the recognition of unrealized gains and losses on derivative instruments and their realization and subsequent recovery in rates are recorded as regulatory assets or regulatory liabilities. Amounts recorded by PGE at December 31, 2007 and 2006 offset the effects of such gains and losses, which are caused by changes in fair values of related energy contracts. Recorded amounts are reversed as such contracts are settled. PGE expects recovery over the next 4 years. For further information, see Note 10.
Boardman power cost deferral - In October 2005, the Boardman Coal Plant (Boardman) was taken out of service for repair of the plants steam turbine rotor and remained out of service during the first half of 2006 for additional repairs. PGE incurred significant incremental power costs during this period to replace the plants generation. In November 2005, PGE filed with the OPUC an application to defer for later ratemaking treatment excess power costs associated with Boardmans turbine rotor repair outage. Based upon prior OPUC actions, the stated position of the OPUC staff in the proceeding, and considering both applicable accounting guidance and the impact of SB 408 on any benefit received by the Company, PGE recorded a deferral in the amount of $6 million at December 31, 2006. On February 12, 2007, the OPUC issued an order granting a portion of PGEs request and authorizing the Company to defer $26.4 million, subject to a prudency review process. PGE recorded the deferral of $20.4 million in the first quarter 2007. On October 9, 2007, PGE filed a request with the OPUC to amortize the deferral of $26.4 million of replacement power costs, plus interest until the amortization period begins (accrued interest is $5.0 million as of December 31, 2007), associated with the outage of Boardman from November 18, 2005 through February 5, 2006. In its filing, the Company proposed that the amortization be offset with certain credits due to customers, with no price impact anticipated. PGEs request is subject to both a prudency review with respect to the outage and to a regulated earnings test.
Debt reacquisition costs - As authorized by the OPUC, costs related to the reacquisition of debt securities, including unamortized debt issuance costs related to such debt securities, are deferred and amortized to interest expense equitably over the life of the replacement or retired issue as applicable. PGE expects recovery over the next 25 years.
Trojan decommissioning costs - PGEs retail prices include recovery of costs to decommission Trojan. These amounts represent the estimated present value of future decommissioning expenditures to be recovered from customers. For further information, see Note 13.
SB 408 - This Oregon 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 investor-owned utilities or their consolidated group. The Company has established a regulatory liability for future refunds to customers related to the 2006 reporting year. PGE filed its report on October 15, 2007 with the OPUC reflecting the amount of taxes paid by the Company, as well as the amount of taxes authorized to be collected in rates. The report is being reviewed as part of a formal process, with the OPUC expected to issue an order in April 2008. The Company has reached agreement with OPUC Staff and certain interveners that the appropriate refund due customers is $37.2 million plus accrued interest, based on the OPUCs administrative rules that govern the calculation of the refund amount. This regulatory liability includes $17 million paid to Enron Corp. for net current taxes payable for the first quarter of 2006 when PGE was included in its former parents consolidated group for filing consolidated federal and state income tax returns. Under OPUC rules, refunds to customers for the 2006 reporting year will begin on June 1, 2008. For 2007, a regulatory asset was established for collection from customers. For further information, see Note 15.
Residential Exchange Program - The Residential Exchange Program, which is administered by the Bonneville Power Administration (BPA), provides access to the benefits of federal power to residential and small farm customers of the regions investor-owned utilities. In 2000, PGE entered into a settlement agreement with the BPA related to the Residential Exchange Program covering the period October 1, 2001 through September 30, 2011. The benefits that PGE receives under the agreement with the BPA are passed through directly to residential and small farm customers in the form of monthly billing credits. Based upon decisions in the U.S. Ninth Circuit Court of Appeals, the BPA, on May 21, 2007, notified PGE and six other investor-owned utilities that it was immediately suspending the Residential Exchange Program payments. In its notice, the BPA indicated that the suspension will continue at least until any petitions for rehearing on the decisions are finally resolved. The $9 million regulatory asset represents Residential Exchange Program credits that were passed through to eligible customers but not received from the BPA.
Regulatory restructuring costs - The OPUC authorized PGE to defer certain costs related to implementation of Oregons electricity restructuring law. Of the $24 million total implementation costs, $7 million was fully recovered over a five-year period that ended December 31, 2007, and $17 million is being recovered over a five-year period that began on January 1, 2004, with a remaining balance of $5 million at December 31, 2007.
Beaver 8 - In December 2004, the OPUC issued an order that adopted a stipulation in which parties agreed that PGE may recover from customers approximately $14 million associated with a 24.7 MW combustion turbine (referred to as Beaver 8) installed at the Companys Beaver generating plant site in 2001. Of this amount, $10 million (plus accrued interest) was deferred for recovery from customers over a five-year period beginning January 1, 2005, with the remaining $4 million to be recovered through depreciation charges included in general prices.
Accumulated asset retirement removal costs - Asset retirement removal costs that do not qualify as AROs are a component of depreciation expense allowed in customer rates. Accumulated asset retirement removal costs are recorded as a regulatory liability as they are collected in rates, and are reduced by actual removal costs as incurred, in accordance with SFAS 143 and SFAS 71. This amount is also included as a reduction to PGEs rate base for ratemaking purposes.
Asset retirement obligations - SFAS 143 requires the recognition of 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. Pursuant to regulation, AROs of rate-regulated long-lived assets are included as an allowable cost in rates charged to customers. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability under SFAS 71. Asset retirement obligations are included in PGEs rate base for ratemaking purposes. For further information, see Note 13.
Trojan ISFSI pollution control tax credits - In December 2004, PGE received final certification from the Oregon Environmental Quality Commission (OEQC) related to $21.1 million in Oregon pollution control tax credits that were generated from PGEs investment in an Independent Spent Fuel Storage Installation (ISFSI) at Trojan. OEQC rules require that the tax credits be spread over a ten-year period, beginning in 2004. The OPUC approved the deferral of the tax credits for future ratemaking treatment.
Power Cost Adjustment Mechanism (PCAM) - A new PCAM was approved by the OPUC, effective January 17, 2007. Under the PCAM, PGE can adjust future prices to reflect a portion of the difference between each years forecasted NVPC included in prices (the baseline), and actual NVPC. Under the PCAM, PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and that included in base prices by application of an asymmetrical deadband within which PGE absorbs cost increases or decreases, with a 90/10 sharing of costs and benefits between customers and the Company outside of the deadband. For 2007, the deadband ranged from $11.7 million below, to $23.4 million above, the baseline. PGEs actual NVPC as determined under the PCAM for 2007 were less than the established baseline by $29.4 million, thus an estimated refund to customers of $16.5 million, including accrued interest, was recorded as a regulatory liability and is reflected as an increase to Purchased power and fuel expense. A final determination of any customer refund or collection will be determined by the OPUC through a public filing and review.
New Accounting Standards
SFAS 157, Fair Value Measurements (SFAS 157), was issued in September 2006 and is effective for fiscal years beginning after November 15, 2007. (In February 2008, the FASB deferred the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis). SFAS 157 provides enhanced guidance for the use of fair value to measure assets and liabilities. It also requires expanded disclosure regarding the extent to which fair value is used for such measurements, information used to measure fair value, and the effect of fair value measurements on earnings. Provisions of SFAS 157 apply whenever other accounting standards require (or permit) assets or liabilities to be measured at fair value, but does not expand the use of fair value in any new circumstances. PGE believes that the adoption of SFAS 157 will not have a material impact on its consolidated financial position or consolidated results of operations.
SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159), was issued in February 2007 and is effective for fiscal years beginning after November 15, 2007. SFAS 159 provides entities the option to report most financial assets and liabilities at fair value, with changes in
fair value recorded in earnings. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. PGE believes that the adoption of SFAS 159 will not have a material impact on its consolidated financial position or consolidated results of operations.
FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (FSP FIN 39-1) was issued April 30, 2007 and modifies FIN 39, Offsetting of Amounts Related to Certain Contracts, and permits reporting entities to offset the receivable or payable recognized for derivative instruments that have been offset under a master netting arrangement. FSP FIN 39-1 requires financial statement disclosure of a reporting entitys accounting policy (to offset or not to offset) as well as amounts recognized for the right to reclaim cash collateral, or the obligation to return cash collateral, that have been offset against net derivative positions. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying FSP FIN 39-1 shall be presented as a change in accounting principle through retrospective application for all financial statements presented unless it is impracticable to do so. PGE is in the process of determining the impact the application of FSP FIN 39-1 will have on its consolidated financial position, but believes the adoption of FSP FIN 39-1 will not have a material impact on its consolidated results of operations.
EITF 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11) was ratified by the Emerging Issues Task Force at its June 27, 2007 meeting. EITF 06-11 clarifies how an entity should (1) recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares and (2) charged to retained earnings under SFAS 123R. EITF 06-11 applies prospectively to the income tax benefits that result from dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years. PGE believes the adoption of EITF 06-11 will not have a material impact on its consolidated financial position or consolidated results of operations.
Note 2 - Employee Benefits
Pension and Other Postretirement Plans
Defined Benefit Pension Plan - PGE sponsors a non-contributory defined benefit pension plan, of which substantially all members are current or former PGE employees. The assets of the pension plan are held in a trust. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate.
PGE made no contributions to the pension plan in 2006 and 2007 and does not currently expect to make any contribution in 2008. The measurement date for the pension plan is December 31.
Non-Qualified Benefit Plans - The Non-Qualified Benefit Plans in the accompanying table consist primarily of obligations for a Supplemental Executive Retirement Plan (SERP). The SERP was closed to new participants in 1997. Investments in a non-qualified benefit plan trust, consisting of trust owned life insurance policies (TOLI) and marketable securities, are intended to be the primary source for funding these plans. Trust assets of $25 million as of December 31, 2007 and 2006 are included in the accompanying table for informational purposes only and are not considered segregated and restricted as defined by SFAS 158. The investments in marketable securities, consisting of money market, bond, and equity mutual funds, are classified as trading and recorded at fair value. The measurement date for the non-qualified plans is December 31.
Other Benefits - PGE also participates in non-contributory postretirement health and life insurance plans (Other Benefits in the table). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGEs obligation by establishing a maximum benefit per employee. Contributions made to a voluntary employees beneficiary association trust are used to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers. Post-retirement benefit plan calculations include several assumptions which are reviewed annually with PGEs consulting actuaries and trust investment consultants and updated as appropriate.
PGE has also established Health Retirement Accounts (HRAs) for its employees. Contributions are made to trust accounts to provide for claims by retirees for qualified medical costs. The 2004 bargaining unit agreement provides that participants accounts are credited with 58% of the value of the employees accumulated sick time as of April 30, 2004 and 100% of their earned time off accumulated at the time of retirement. Between July 1, 2007 and June 30, 2008, the Company will make additional contributions to the trust of $0.25 per compensable hour for each participant, increasing to $0.50 per compensable hour through February 28, 2009. The Company also grants a fixed dollar amount for all active non-bargaining employees, which will become available for qualified medical expenses upon their retirement.
No contributions were made to the postretirement or non-bargaining HRA plans in 2007. Contributions totaling $1 million were made to the bargaining unit HRA in 2007, with similar contributions expected in 2008. No contributions are currently expected to be made to the other postretirement plans in 2008. The measurement date for the postretirement plans is December 31.
The following table provides a reconciliation of changes in the Plans benefit obligations and fair value of assets, a statement of the funded status, and components of net periodic benefit cost (dollars in millions):