DCL-05-027, PG&E Corporation 2004 Annual Report

PG&E Corporation 2004 Annual Report

ML050900062
Person / Time
Site:	Diablo Canyon, Humboldt Bay
Issue date:	03/22/2005
From:	Jacobs D Pacific Gas & Electric Co
To:	Document Control Desk, NRC/FSME
References
DCL-05-027, HBL-05-011, OL-DPR-80, OL-DPR-82, OP-DPR-07
Download: ML050900062 (158)

Text

Pacific Gas and Electric Company Donna Jacobs Diablo Canyon Power Plant Vice President P.0. Box 56 Nuclear Services Avila Beach, CA 93424 805.545.4600 Fax: 805.545.4234 March 22, 2005 PG&E Letter DCL-05-027 HBL-05-011 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units I and 2 Docket No. 50-133, OP-DPR-7 Humboldt Bay Unit 3 PG&E Corporation 2004 Annual Report

Dear Commissioners and Staff:

Pursuant to 10 CFR 50.71(b) and 10 CFR 140.15(b)(1), enclosed is one hard copy of the PG&E Corporation 2004 Annual Report and one diskette containing an Adobe Acrobat file titled "PG&ECorporation_2004_AnnualReport.pdf." Internet download, viewing, or copies of the complete PG&E Corporation 2004 Annual Report is available at:

http:/Iwww.pgecorp.com/investors/pdfs/2004Annual Report.pdf Sincerely, Donr Jacobs ddm Enclosure cc: Marna N. Colcun Ira P. Dinitz John B. Hickman Bruce S. Mallett David L. Prouix Girija S. Shukla David Sokolsky Diablo Distribution PG FossilGen HBPP Humboldt Distribution AoISS 1 A member of the STARS (Strategic Teaming and Resource Sharing) Alliance CalLaway

• Comanche Peak

• Diablo Canyon . Palo Verde

• South Texas Project

• Wolf Creek

Enclosure PG&E Letter DCL-04-027 HBL-04-01 1 PG&E Corporation 2004 Annual Report

1. PG&E Corporation 2004 Annual Report (hard copy)

2. PG&E Corporation_2004_Annual Report.pdf file (1.44 Mb Diskette)

. 1 M PG&E CORPORATI ON ANNUAL REPORT

DEAR FELLOW SHAREHOLDER, PG&E Corporation is stronger than at any time in the last decade. We're now using this strong position to implement our vision of industry leadership in delivering value to our customers and shareholders.

In this letter, we summarize the results of 2004 Our reported consolidated net income for and our current business position. We describe 2004 was substantially higher than earnings from our vision of industry leadership in delivering operations. This reflected two large one-time, value to our customers. And we outline the steps non-cash gains, totaling $8.52 per share, related to we are taking to accomplish that objective and, Pacific Gas and Electric Company's Chapter 11 with it, provide value to our shareholders. exit, as well as the Corporation's exit from the national wholesale energy business. As a result, 2004 RESULTS L ast year, PG&E Corporation's earnings consolidated net income reported in accordance with generally accepted accounting principles from operations, which excludes certain (GAAP) was $10.57 per share.

income and expenses considered by management to be non-operating, were $2.12 per diluted share, an increase of 43 percent over 2003.

The Financial Highlights table on page 29 Today, our core utility business is revitalized, of this report reconciles our non-GAAP earnings with a solid balance sheet, healthy cash flows from operations with GAAP consolidated and sound credit - all reinforced by landmark net income. regulatory compacts whose longevity, clarity and stability set the stage for strong and growing "Today, our core financial performance in 2005 and beyond.

utility business is DELIVERING VALUE revitalized, with a TO SHAREHOLDERS n addition to solid earnings, our business is solid balance sheet, generating substantial cash. We intend to use healthy cash flows these funds for three purposes: paying a regular common stock dividend, repurchasing PG&E and sound credit." Corporation stock and making continued new Based on agreements reached in 2003 and investments in our core utility business.

implemented in 2004, Pacific Gas and Electric In February 2005, the Board of Directors Company's credit rating was returned to invest- declared a quarterly common stock dividend of ment grade, its balance sheet was refinanced $0.30 per share to be paid in April 2005.

at historically low interest rates, all creditor In 2004, we also repurchased approximately claims were resolved in full and the company $380 million of common stock, after finalizing exited Chapter 11. an agreement that resolved outstanding issues Pacific Gas and Electric Company has reached with our former national energy business and its authorized capital structure of 52 percent freed about $350 million of previously restricted equity, on which it is authorized to earn a return cash. Our intention is to repurchase an additional of 11.22 percent. Recently the company's invest- $1.6 billion of stock by the end of 2005.

ment-grade credit rating was raised again. These steps to return value to shareholders helped drive a nearly 20 percent increase in the price of PG&E Corporation shares over the course of last year.

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DELIVERING VALUE TO CUSTOMERS After the challenges of natural gas industry e lowered electric rates in 2004 by restructuring in the 1980s, electric industry about $800 million. restructuring in the 1990s, and the energy crisis We invested about $1.6 billion in the infra- beginning in the year 2000, we're thrilled structure of our utility business to serve our to be operating from a position of stability customers better and to provide service to new and strength. Even more, we're firm in our customers, and we announced our intention to commitment that "stable" and "strong" will not invest at least $10 billion over the next five years, be euphemisms for stationary or static.

including approximately $2.0 billion in 2005.

2005 AND BEYOND - A VISION We also implemented a settlement with regulators and consumer advocates to establish our base utility rates and revenues through 2006, O:

OF INDUSTRY LEADERSHIP ur team is energized around a vision to lead the industry. And PG&E's current including formulaic increases to cover inflation strong and stable position has given us the best and growth in our customer base. platform in years to implement this vision.

In the long term, Pacific Gas and Electric In 2005 - and for the next several years - our Company's investment-grade credit rating, strong team's energies are focused on finding and balance sheet and improved regulatory stability implementing ways to deliver our products and assure customers that their utility has the finan- services better, faster and more cost-effectively.

cial wherewithal to maintain cost-effective access We believe the bar for providing value and to capital and credit markets. In practical terms, good service is higher than ever. Moreover, it's that means customers can count on us to be able going to continue to be raised. Customers and to buy power and fund critical infrastructure regulators are increasingly measuring our investments when and where needed. performance against other leading utilities - and even service leaders in other industries - and they're expecting us to stay ahead of the curve.

That's the reason we've placed the California energy customer firmly at the center of our strat-egy for achieving our vision to lead the industry.

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And it's the reason that last year we launched to be better, while preserving those elements that an intensive, multi-year effort to transform our will continue to be fundamental to our success.

operations and our culture to achieve our vision. In practical terms, customers can expect us to:

Our goal is to use our strong platform to

• Serve them in ways that are better, faster and identify and implement changes necessary more cost-effective.

• Provide them easier access to time- and "Our team is energized money-saving information.

around a vision to *Invest in infrastructure to safeguard and improve reliability.

lead the industry. *Deliver new products and solutions that our PG&E's current strong customers say they want.

and stable position And to provide industry-leading customer service, our employee team members will have:

has given us the best *Learning opportunities to support new platform in years to systems and tools to satisfy customers.

• Simplified work processes.

implement this vision." *More effective information technologies.

to enhance service in ways that customers of *More standardization of systems and assets.

Pacific Gas and Electric Company will value most. *Participation in building a performance We're already rethinking and improving culture.

operating models in many areas of the business. In some areas this undertaking will be about We're identifying smart new investments in infra- building on our strengths. For example, structure and technology. And we're taking stock customers rate the service at PG&E's call centers of our culture to strengthen areas where we want among the best in the business. In other areas it will mean identifying and adopting the most effective business processes from our industry, or from others.

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To drive success, we've made this effort heavily Good opportunities exist for additional research and benchmarking driven. We're involv- investments that will benefit our customers, such ing thousands of our team members, because as new power generation to help ensure a they understand where customers would like to stable supply of utility-owned capacity to meet see us perform better. customers' future demand.

Through this effort, we expect to achieve cost-savings that benefit our customers, even as we "Our energies are are creating further savings and making improve- focused on delivering ments through additional capital investments.

our products and This undertaking will be a major task for the next three to five years. In fact, it's among the services better, hardest tasks a company can tackle. But it's also a faster and more critical one. And now is the right time to begin.

Providing better, faster and more cost-cost-effectively."

effective service to our customers will help meet Opportunities also exist for investments in their needs, as well as the energy policy goals electric distribution and transmission to alleviate of our regulators, and at the same time enhance system bottlenecks and create access to renewable our ability to provide shareholders a good return power sources in remote locations, as well as on their investment. investments in such technologies as advanced Our goal is to grow earnings per share from metering infrastructure, which could allow operations by 4 to 6 percent annually for 2005 us to provide new pricing and service options through 2009. A big driver of this will be rate that our customers have said they would value.

base growth resulting from additional investment Incremental investments in these areas could in Pacific Gas and Electric Company. Our total up to $2.0 billion between 2005 and 2009, current forecast anticipates a base level of capital depending on utility needs.

expenditures averaging approximately $2.0 billion per year over the next five years.

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As this transformation of the way we do as Chairman of the Boards of PG&E Corporation business moves forward in 2005; it coincides and Pacific Gas and Electric Company through with our celebration of the 100th anniversary the end of 2005, when he will retire from the of Pacific Gas and Electric Company's company and the Boards. Chris Johns became incorporation, and the start of the second century Senior rice President, Chief Financial Officer for PG&E'ers. and Controller.

T2 CHANGES TO OUR BOARDS THANK YOU AND SENIOR MANAGEMENT hank you to our shareholders for your E n 2005, we will say thanks and farewell to confidence and investment in PG&E David Lawrence, who has served on our Corporation and its future. Your company is Boards of Directors since 1995. We're grateful strong. It's energized. And it's moving toward an for David's counsel and contributions during ambitious vision.

the past 10 years. Thank you also to our team of 20,000 men and We've also welcomed Barbara Rambo as a women whose hard work and dedication on the new member to our Boards. Barbara is the job have kept our company delivering service and Chief Executive Officer of Nietech Corporation value to our customers and shareholders.

and has more than 25 years of experience in the banking industry. She brings talent that further Sincerely, strengthens our Boards.

In December 2004, we announced a transition He'0s in PG&E Corporation's executive leadership. ROBERT D. GLYNN, JR. PETER A. DARBEE Our Board believes that the company's strong Chairman of the Board President and CEO PG&E Corporation PG&E Corporation financial position and positive outlook made this February 24, 2005 February 24, 2005 the right time for the next chief executive to begin leading the company.

Effective January 1, 2005, Peter Darbee became President and CEO. Bob Glynn, Jr., continues 7

PG&E has emerged from the energy crisis on a solid financial footing and is currently enjoying a stable business and regulatory environment. With this strong foundation in place, we have begun a process to transform the way we work, the way we interact with each other, and the way we serve and think about our customers. We are conducting a "stem-to-stern" analysis of our operational processes, benchmarking them against

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other companies to gauge where we stand and learn from the best practices of others.

A cross-functional team within PG&E is spearheading the redesign of processes, and senior management is engaged in face-to-face dialogue with employees throughout the company to listen closely to those who interact directly with our customers.

In that process, we're being reminded that we have much to

be proud of, and also that we always have opportunities to improve. Our customers and employees tell us they want ideas put into action, and that is what we intend to do.

More than ever, we are determined to tear down the "silos" within the organization and work together in cross-functional teams with a focus on serving customers better, faster and more cost-effectively.

We are energized and committed to change. We have a plan to achieve our objectives through a highly structured, disciplined approach. And we are measuring progress to be certain we are on track. In the pages that follow, some of the PG&E people leading this charge talk about programs being implemented to create cost-efficient service, satisfied customers and shareholder value now and into the future.

ur goal is to be first class in the eyes of our customers. As part of that effort, PG&E is taking a closer look at what customer satisfaction means by examining all the elements that feed into that equation. Driving this initiative is a view that our customers are "Essential in this people whose loyalty and satisfaction we have to compete for and win.

Doing that takes more than just the friendly voice of a service effort is the rep on the phone; it takes all 20,000 employees from all parts of the organization functioning seamlessly.

engagement of our Using consumer and employee opinion surveys, focus groups, 20,000 dedicated metrics and industry benchmarking, we are working continuously to gauge customer satisfaction and pinpoint areas where we can employees, improve. Then, we're translating that research into action, and we're measuring our progress.

united around In parts of our operations such as our customer call centers, a shared vision, where we rank in the industry's top quartile for customer service, and the California Gas Transmission pipeline, where our customers rate values and culture."

us highly in terms of satisfaction, we are evaluating the drivers of their success in order to replicate them across our entire enterprise.

Essential in this effort is the engagement of our 20,000 dedicated employees, united around a shared vision, values and culture. They know better than anyone where the greatest opportunities lie to make changes that our customers will value. By stepping up employee communications and committing to open and honest dialogue between senior management and our people in the field, we are tapping into that resource, and ensuring that thousands of PG&E'ers have a voice in the process and a stake in its success.

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E G&E isexpanding the use of automated technologies to help provide customers with better, faster and more cost-effective service - and the feedback we are getting in response is very positive.

Over the past year, we have made significant progress in increasing online service capability on our website. Our residential customers can now schedule gas appliance appointments, start and stop their service, and submit energy efficiency rebates online. Customers also can sign up for paperless billing, and are doing so at the rate of more than 20,000 a month. Since PG&E sends out over 5 million bills a month, this option is more than just a customer convenience. The savings in paper and postage will help cut costs and support the environment -

"Customers benefits that ultimately flow through to our customers.

Our call centers, which fielded more than 17 million customer calls can sign up for in 2004, now offer voice recognition to navigate through the service menu, so customers can easily communicate routine requests without paperless billing, having to speak with a service agent. We also have streamlined and and are doing so enhanced our automated outage communications system to provide customers with faster and more accurate outage information, as well at the rate of more as helpful services such as wake-up calls when their power is out.

Another technology initiative currently being evaluated by the than 20,000 a California Public Utilities Commission (CPUC) is an advanced month." metering infrastructure (AMI) system that would provide new pricing options and cost-effective remote meter reading. Other utilities have implemented AMI successfully, and their experience shows that remote meter reading offers many operational advantages, including eliminating the need to estimate bills when meters are inaccessible, pinpointing the location of power outages for faster response, and ending customer inconveniences associated with manual meter reading, such as the need to tie up dogs and unlock gates. If approved by the CPUC, a systemwide implementation of AMI would represent a more than $1 billion investment to better serve our customers.

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ne of our top responsibilities is planning and procuring I cost-effective, reliable energy resources to make certain that California has the power it needs tomorrow. Deregulation shifted this responsibility from the utilities to the market in the 1990s. That has changed again. We're back in the business of identifying how much "We're back in electricity our customers will need in the future and executing a strategy to deliver it. the business of At PG&E, we are implementing a resource plan that gives preference to reducing demand by helping customers use energy identifying how more efficiently through education, technical assistance and financial much electricity our incentives. This strategy helps to contain costs for our customers, mitigates the need for new power plants, and is better for the customers will need environment. PG&E's customer energy efficiency programs have helped keep electricity usage per capita flat in our territory for the last in the future and 15 years, compared to overall growth of 13 percent in the U.S. over the same period. Over the last 10 years, our energy efficiency executing a strategy programs have helped customers save enough energy to avoid the to deliver it."

need to build more than 1,000 megawatts of new generation capacity - the equivalent of two large power plants. Furthermore, we are targeting additional customer energy savings of 2,200 megawatts through energy efficiency programs over the next 10 years.

Even with effective programs to save energy, California will need new power plants operating toward the end of this decade. That means we have to start now. PG&E is actively gathering bids for new supply. We'll choose the options that make the most sense for our customers and for the environment. New plants could be owned and operated by PG&E, or by others with whom we would contract for the power. Some of the plants will be highly efficient, low-emitting, natural gas-fueled resources. But a substantial part of our future supply will come from renewable sources such as biomass, geothermal, wind and solar technologies. The new plants will add to a generating portfolio that already has one of the lowest rates of air emissions, including greenhouse gases, in the country.

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"Standardization of processes n today's world, even a momentary interruption in service can and equipment have big impacts on a business or an individual. That means ensuring a reliable flow of energy to our customers is more critical has important than ever. In order to keep pace with the inevitable impacts of demand growth and age on our infrastructure, we are aggressively ramifications in searching for new ways to maintain and improve our transmission and distribution system - and to do so in the most cost-effective the field, enabling ways for our customers.

employees to work In addition to ongoing preventive measures such as the replace-ment of power poles and gas pipelines, PG&E is continuing to make more efficiently substantial infrastructure investments. The tremendous growth occurring in California's Central Valley, a part of our territory that and improve the had been largely rural, has created a need to install an unprecedented overall quality of amount of new electric transmission and distribution capacity on an accelerated schedule. Our capital investment in infrastructure was service." $1.6 billion in 2004, and we expect it to average at least $2 billion per year through 2009. The vast majority of these investments are in our gas and electric distribution and electric transmission systems.

One way that we are managing costs while strengthening reliability is by standardizing equipment and work methods across our service territory as a means to increase efficiency, improve productivity, streamline procurement of goods and services, and enhance customer satisfaction. Fewer types of assets will require us to keep fewer spare parts in inventory. Standardization of both processes and equipment also has important ramifications in the field, enabling employees to work more efficiently and improve the overall quality of service.

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ver the past 20 years, Diablo Canyon Power Plant has 0 built a reputation as a leader in operational excellence among nuclear power facilities. PG&E is committed to sustaining that leadership in the decades ahead. Toward that end, we have begun a

$1 billion program to ensure the facility continues to perform strongly in the future and remains a valuable contributor to California's energy supply. Between now and 2010, we will make significant "The stewardship new investments in Diablo's steam generators, turbines and other major pieces of equipment. of nuclear power Wre are also investing today in the next generation of employees who will operate Diablo Canyon. We have launched an aggressive demands that recruiting and training program to bring in individuals with strong safety and security educational backgrounds, problem-solving skills and leadership abilities to operate Diablo Canyon in accordance with the high be factored into performance standards to which we hold ourselves. We're preparing these new team members to lead Diablo Canyon forward as members every decision."

of the current team begin to retire.

Essential to that preparation is instilling new team members with principles developed over 20 years of excellence in nuclear power operations - the foremost of which is that safety and security always come first. Indeed, the stewardship of nuclear power demands that safety and security be factored into every decision. Diablo Canyon's culture emphasizes mitigating risk, planning work and refueling out-ages with a heavy focus on preventive measures to keep equipment operating smoothly, and paying attention to even the smallest details.

This is an ongoing challenge, and we always see opportunities to improve. Our long-term plan is focused on delivering operational results, using metrics to drive performance and establish priorities to reduce downtime, improve efficiency and uphold the public trust.

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s the world becomes more focused on reducing the Aenvironmental impact of burning fossil fuels, natural gas is seen as a bridge to the future. It burns cleaner, transports easily and does not have to be stored on site. Over the last five years, 95 percent of the new power generation capacity built in the U.S. was natural gas-fired. PG&E's high-pressure, natural gas pipelines are the backbone of California's gas transmission infrastructure and are primed to capture that business.

"Efforts to As one of the industry's largest storage providers, PG&E's California Gas Transmission (CGT) operation is well positioned to accommodate manage costs and offer electric generation and industrial customers the flexibility they seek. Our gas storage facilities enable our customer needs customers to purchase gas when prices are favorable and store it for have earned use at a time when prices increase. This allows customers to better manage their costs even as gas prices fluctuate. PG&E is also CGT top rankings structured to offer its transmission customers flexibility that allows them to share their right to use transmission capacity with other from its customers entities when they are not using the capacity.

on satisfaction." Such efforts to accommodate customer needs, even to the extent of seeking regulatory changes when necessary, have earned CGT top rankings from its customers on satisfaction. Key to that success is listening and responding to feedback from customers with greater efficiency, reliability and security - including establishing an electronic contracting system to eliminate paperwork and speed transactions, or creating a GPS (global positioning system) database of our whole pipeline system to prioritize pipe replacements to meet the highest public safety standards. For manufacturers weighing the viability of locating operations in California, we seek to provide the cost and service advantages that make a decisive difference.

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-f ith the average age of workers in our industry approaching v w 44, and over one-third of that workforce reaching retirement eligibility in the next five years, PG&E is competing with other utility companies and other employers in general for top talent.

To identify the technical and leadership skills needed today and in the future, PG&E is listening closely to customers and employees, and is benchmarking other western utilities. Increasingly, we are "A measure of relying on metrics to provide accurate and timely profiles of employee demographics in each of our business units, and to help prioritize the success of our recruitment and training goals so we have the right people with the right skills in the right place as employees retire. This is especially internship program important for positions such as linemen, where a lengthy apprentice- is that more than ship is the best way to pass on knowledge acquired through years on the job. Presently we're training over 750 active apprentices, almost 75 percent of the half of whom are training to become electrical line workers.

Our recruiting strategy for entry management positions begins interns offered with identifying colleges that draw the right caliber of students and full-time jobs at conducting in-depth interviews with candidates to make sure their interests and skills match specific needs within PG&E. The company's PG&E accept."

internship program gives both the intern and PG&E an opportunity to determine whether the "fit" is right. A measure of the success of our internship program is that more than 75 percent of the interns offered full-time jobs at PG&E accept - a retention level we are committed to maintaining through mentorship programs and career growth opportunities.

We also have intensified our efforts to "on-board" those newly hired through our New Employee Orientation program. All new employees participate in this program in their first 30 days to introduce them to PG&E's vision, goals, values, culture and organizational structure, and to give them an understanding of the business opportunities and challenges facing the company and its 20,000 employees.

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"In 2004, PG&E employees and retirees P G&E has a long tradition of supporting community needs, and we have not wavered in that commitment. With our solid demonstrated financial footing, we now are in a position to raise our level of philanthropy. The core of this effort is a goal to provide corporate their personal gifts of at least $60 million over five years starting in 2005.

Our shareholder-funded contributions program combines PG&E's commitment by values and expertise with the energy of our employees to address the needs of local communities. We focus on four core areas: education, donating $2.6 the environment, emergency preparedness and economic develop-million through ment. Wherever possible, we try to combine these interests in projects we fund. An example is a major commitment to purchase and install the company- solar equipment for public schools along with the distribution of teaching materials on solar energy, allowing school districts to lower sponsored their electric bills, enrich curriculum and teach children about Campaign for renewable energy.

Another way that PG&E serves local communities is by supporting the Community." organizations that assist underserved populations, particularly low-income people, minorities and the disabled. Through our five-year commitment, we are targeting at least 60 percent of total giving to nonprofit groups that assist these communities.

Above and beyond the more than 900 local nonprofits supported through contributions, our giving program is energized by the community spirit of our employees, who generously donate their time and money to a multitude of worthy causes. In 2004, PG&E employees and retirees demonstrated their personal commitment by volunteering in more than 20 company-sponsored community projects and donating $2.6 million (22 percent higher than in 2003) to 3,000 nonprofit organizations through the company-sponsored Campaign for the Community.

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P G&E strives to be an environmental leader in the industry and

- in the communities we serve. In policy and practice, we are com-mitted to running our business in a responsible and environmentally "PG&E has agreed sensitive manner and to helping customers conserve energy through education and rebates. to donate or PG&E has been at the forefront of many innovative initiatives over the years. Recent examples include adopting an Environmental create conservation Justice Policy to ensure that we are good neighbors to residents easements to around our facilities and becoming a charter member of the California Climate Action Registry, a state-sponsored voluntary registry formed protect 140,000 to inventory and reduce greenhouse gas emissions. In 2004, our leadership in developing our carbon dioxide emission inventory acres of mountain earned us the Registry's Climate Action Champion Award.

watershed land In 2004, PG&E, in partnership with the California Public Utilities Commission, launched the Pacific Forest and Watershed Lands associated with our Stewardship Council. PG&E has agreed to donate or create conserva-tion easements to protect 140,000 acres of mountain watershed land hydro facilities."

associated with our hydro facilities. These watershed lands, home to many rare and endangered plants and animals including one of the highest concentrations of nesting bald eagles in the lower 48 states, have been in the PG&E family since the beginning of our hydro business in the mid-1800s. PG&E has also set aside $70 million to support future environmental land enhancements and $30 million for programs providing wilderness experiences for disadvantaged urban youth and to acquire and maintain urban parks and recreation areas.

The Stewardship Council, with a Board of Directors representing 18 different government agencies, industry groups, conservation organizations and other interests, will administer the funds to ensure that these lands will be managed in perpetuity with regard to the ecosystem and public enjoyment.

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FINANCIAL HIGHLIGHTS PG&E CORPORATION (unaudited, in millions, except share and per share amounts) 2004 2003 Operating Revenues S 11,080 $ 10,435 Net Income Earnings from operations") $ 901 $ 611 2

Headroom( ) - 677 Items impacting comparability(3' 2,919 (499)

NEGT 684 (369)

Reported consolidated net income S 4,504 $ 420 4

Income Per Common Share, diluted( )

Earnings from operations") S 2.12 S 1.48 2

Headroom Q) - 1.64 Items impacting comparability(3 ) 6.85 (1.21)

NEGT S 1.60 $ (0.89)

Reported consolidated net income per common share S 10.57 $ 1.02 Dividends Per Common Share S - $ -

Total Assets at December 31 S 34,540 S 30,175 Number of common shareholders at December 31 104,703 111,423 Number of common shares outstanding at December 310) 418,616,141 416,520,282

°) Earnings from operations does not meet the guidelines of accounting principles generally accepted in the United States of America, or GAAP. It should not be considered an alternative to net income. It reflects net income of PG&E Corporation, on a stand-alone basis, and the Utility, but excludes the results of NEGT, headroom and certain income and expenses, or items impacting comparability, in order to provide a measure that allows investors to compare the core underlying financial performance of the business from one period to another, exclusive of items that manage-ment believes do not reflect the normal course of operations.

As a result of California Public Utilities Commission, or the CPUC, decisions approving the December 19, 2003 settlement agreement, or Settle-ment Agreement, entered into among PG&E Corporation, the Utility, and the CPUC to resolve the Utility's Chapter 11 proceeding, and implementing various ratemaking mechanisms, the Utility no longer records frozen electric rates and surcharges, or headroom, directly to earnings as it had in 2003. Instead, the Utility collects cost-of-service based electric rates that are the sum of specific revenue requirements.

Items impacting comparability represent items that management does not believe are reflective of normal, core operations. Items impacting compa-rability for 2004 include the Utility's recognition of a gain of approximately $120 million (50.28 per share), after-tax, related to the prior year impact and regulatory asset recognition resulting from the CPUC decision approving the 2003 GRC, a fourth quarter CPUC decision granting recovery of approximately $30 million (SO.07 per share), after-tax, of previously incurred costs related to the implementation of electric industry restructuring filed by the Utility with the CPUC on April 16, 2004, and a gain of approximately S2,950 million ($6.92 per share), after-tax, related to the establishment of regulatory assets contemplated in the Settlement Agreement. In addition, the Utility recognized $17 million ($0.04 per share), after-tax, in charges related to obligations to invest in clean energy technology and donate land, included in the Settlement Agreement.

The effect of recognizing the impacts of the Settlement Agreement, cost recoveries and GRC was partially offset by the net effect of incremen-tal interest costs of 567 million (50.15 per share), after-tax, from the increased amount and cost of debt resulting from the California energy crisis and the Utility's Chapter 11 filing; increased costs ofS 13 million ($0.03 per share), after-tax, related to the Utility's and NEGT's Chapter 11 filings and generally consisting of external legal consulting fees, financial advisory fees and other related costs; approximately $30 million (50.07 per share),

after-tax, associated with the early redemption of PG&E Corporation's $600 million 6X% Senior Secured Notes on November 15, 2004; and $54 million ($0.13 per share), after-tax, related to the change in the estimated market value of non-cumulative dividend participation rights included within the Holding Company's $280 million principal amount of 9.5% Convertible Subordinated Notes.

In 2003, items impacting comparability include the net effect of incremental interest costs of $370 million ($0.90 per share), after-tax, from the increased amount and cost of debt resulting from the California energy crisis and the Utility's Chapter 11 filing-, increased costs of5123 million (50.30 per share), after-tax, related to the Utility's and NEGT's Chapter 11 filings and generally consisting of external legal consulting and financial advisory fees; and $6 million ($0.01 per share) of other costs associated with the prior year impacts of regulatory rulings in 2003.

(4 Reflects adoption of the 'Tivo-Class" method of calculating earnings per share for all periods presented.

(5) Common shares outstanding include 24,665,500 shares at December 31, 2004 and 23,815,500 shares at December 31, 2003, held by a wholly owned subsidiary of PG&E Corporation. These shares are treated as treasury stock in the Consolidated Financial Statements.

29

SELECTED FINANCIAL DATA (in millions, except per share amounts) 2004 2003 2002 2 I00 2000 PG&E Corporation(')

For the Year Operating revenues $11,080 $10,435 $10,505 S10,450 $ 9,623 Operating income (loss) 7,118 2,343 3,954 2,613 (5,077)

Income (loss) from continuing operations 3,820 791 1,723 1,021 (3,435)

Earnings (loss) per common share from continuing operations, basic 9.16 1.96 4.53 2.81 (9.49)

Earnings (loss) per common share from continuing operations, diluted 8.97 1.92 4.49 2.80 (9.49)

Dividends declared per common share - - - - 1.20 At Year-End Book value per common shared2> $ 20.90 S 10.16 $ 8.92 S 11.91 $ 8.76 Common stock price per share 33.28 27.77 13.90 19.24 20.00 Total assets 34,540 30,175 36,081 38,529 38,786 Long-term debt (excluding current portion) 7,323 3,314 3,715 3,923 3,346 Rate reduction bonds (excluding current portion) 580 870 1,160 1,450 1,740 Financial debt subject to compromise - 5,603 5,605 5,651 -

Preferred stock of subsidiary with mandatory redemption provisions 122 137 137 137 137 Pacific Gas and Electric Company"l For the Year Operating revenues $11,080 $10,438 $10,514 S10,462 $ 9,637 Operating income (loss) 7,144 2,339 3,913 2,478 (5,201)

Income available for (loss allocated to) common stock 3,961 901 1,794 990 (3,508)

At Year-End Total assets $34,302 $29,066 $27,593 $28,105 $24,622 Long-term debt (excluding current portion) 7,043 2,431 2,739 3,019 3,342 Rate reduction bonds (excluding current portion) 580 870 1,160 1,450 1,740 Financial debt subject to compromise - 5,603 5,605 5,651 -

Preferred stock with mandatory redemption provisions 122 137 137 137 137

(') Operating income (loss) and income (loss) from continuing operations reflect the write-off of generation-related regulatory assets and under-collected electricity purchase costs in 2000 and the recognition of regulatory assets in 2004 provided under the December 19,2003 settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC to resolve the Utility's Chapter 11 proceeding. Matters relating to certain data, including discontinued operations, and the cumulative effect of changes in accounting principles, are discussed in M'anagement's Dis-cussion and Analysis and in the Notes to the Consolidated Financial Statements.

(2) Book value per common shares includes the effect of participating securities. The dilutive effect of outstanding stock options and restricted stock are further disclosed in the Notes to the Consolidated Financial Statements.

30

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Utility's electricity distribution, natural gas distribution and nat-ural gas transportation and storage services in California, PG&E Corporation, incorporated in California in 1995, is an among other matters. The CPUC is also responsible for setting energy-based holding company that conducts its business princi-service levels and certain operating practices and for reviewing pally through Pacific Gas and Electric Company, or the Utility, a the Utility's capital and operating costs. In certain cases, the public utility operating in northern and central California. The CPUC prescribes specific accounting treatment for capital and Utility engages primarily in the businesses of electricity and nat-operating costs. The FERC has jurisdiction to set the rates, ural gas distribution, electricity generation, procurement and terms and conditions of service for the Utility's electricity trans-transmission, and natural gas procurement, transportation and mission operations and wholesale electricity sales.

storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, CPUC and FERC decisions have a significant impact on the incorporated in California in 1905, is the predecessor of PG&E amount of operating and capital costs the Utility incurs and the Corporation. Both PG&E Corporation and the Utility are head- amount the Utility is authorized to recover from customers for quartered in San Francisco, California. Through October 29, these costs through the authorization of "revenue require-2004, PG&E Corporation also owned National Energy & Gas ments." Revenue requirements are designed to allow the Utility Transmission, Inc., or NEGT, formerly known as PG&E an opportunity to recover its reasonable costs of providing util-National Energy Group, Inc., which engaged in electricity gen- ity services, including a return of, and a fair rate of return on, eration and natural gas transportation in the United States, or its investment in utility facilities, or rate base.

U.S, and which is accounted for as discontinued operations.

FACTORS AFFECTING 2004 RESULTS OF This is a combined annual report of PG&E Corporation and OPERATION AND FINANCIAL CONDITION the Utility and includes separate Consolidated Financial State-ments for each of these two entities. PG&E Corporation's During 2004, several events had a significant impact on PG&E Consolidated Financial Statements include the accounts of Corporation's and the Utility's results of operation and financial PG&E Corporation, the Utility and other wholly owned and condition, including:

controlled subsidiaries. The Utility's Consolidated Financial

• The Utility's reorganization under Chapter 11 of the U.S Statements include the accounts of the Utility and its wholly Bankruptcy Code, or Chapter 11, on April 12, 2004, the owned and controlled subsidiaries. This combined Management's effective date of its plan of reorganization, and the associated Discussion and Analysis of Financial Condition and Results of

$7.8 billion exit financing; Operations, or AID&A, should be read in conjunction with the Consolidated Financial Statements and Notes to the Consoli-

• The return to cost-of-service ratemaking for the Utility's elec-dated Financial Statements included in this annual report. tricity distribution and generation operations; The Utility served approximately 4.9 million electricity dis-

• The CPUC's authorization of a majority of the Utility's base tribution customers and approximately 4.1 million natural gas revenue requirements in the Utility's 2003 General Rate Case, distribution customers at December 31, 2004. The Utility had or GRC; and approximately $34.3 billion in assets at December 31, 2004 and

• The elimination of PG&E Corporation's equity ownership generated revenues of approximately $11.1 billion in 2004. Its in NEGT.

revenues are generated mainly through the sale and delivery of electricity and natural gas.

The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC. The CPUC has juris-diction to set the rates, terms and conditions of service for the 31

The Utility's Plan of finance the plan of reorganization. Upon the Effective Date, the Reorganization and Settlement Agreement Utility paid all valid claims, deposited funds into escrow The Utility's plan of reorganization under Chapter 11 became accounts for the payment of disputed claims upon resolution, effective on April 12, 2004, or the Effective Date. The plan of and reinstated certain obligations. The Utility expects to fund reorganization incorporated the terms of the settlement agree- its operating and capital expenditures substantially from ment approved by the CPUC on December 18, 2003, and internally generated funds. In addition, available credit facilities entered into among the CPUC, the Utility and PG&E Corpo- are considered adequate to meet these operating requirements ration on December 19, 2003, to resolve the Utility's and seasonal fluctuation in working capital.

Chapter 11 proceeding, or the Settlement Agreement. At Federal and state court appeals of the bankruptcy court's March 31, 2004, the Utility recorded approximately $4.9 billion December 22, 2003 order confirming the plan of reorganization of regulatory assets established under the Settlement Agreement and the CPUC's approval of the Settlement Agreement remain (including a $2.2 billion, after-tax, regulatory asset ($3.7 billion, pending. PG&E Corporation and the Utility believe these pre-tax) referred to in this annual report as the Settlement Reg- appeals and petitions are without merit. Under applicable fed-ulatory Asset) and a related pre-tax gain of approximately $4.9 eral precedent, once the plan of reorganization has been billion on recognition of these regulatory assets. The Settle- "substantially consummated," any pending appeals of the con-ment Agreement authorizes the Utility to earn an 11.22% rate firmation order should be dismissed. If, notwithstanding this of return on equity on its rate base, including these regulatory federal precedent, the bankruptcy court's confirmation order or assets. As described below, because the Utility refinanced the the Settlement Agreement is subsequently overturned or modi-remaining unamortized after-tax balance of the Settlement Reg- fied, PG&E Corporation and the Utility's financial condition ulatory Asset through the issuance of approximately $ 1.9 billion and results of operations could be materially adversely affected.

of energy recovery bonds, the Utility will no longer earn this See Note 2 of the Notes to the Consolidated Financial State-11.22% rate of return on the Settlement Regulatory Asset as it ments for further discussion.

is no longer a part of rate base.

The Settlement Agreement has a term of nine years that Transition from Frozen Rates to Cost of Service Ratemaking began on the Effective Date. Although the Utility's operations BeginningJanuary 1, 1998, electricity rates were frozen as are no longer subject to the oversight of the bankruptcy court, required by the California electric industry restructuring law. In the bankruptcy court retains jurisdiction to hear and determine 2001, in response to the California energy crisis, the CPUC disputes arising in connection with the interpretation, imple- increased frozen rates by imposing fixed surcharges. As a result mentation or enforcement of (1) the Settlement Agreement, of the Settlement Agreement and various CPUC decisions, the (2) the plan of reorganization, and (3) the bankruptcy court's Utility's electricity rates as ofJanuary 1, 2004, are no longer December 22, 2003 order confirming the plan of reorganization. frozen and are determined based on its costs of service, includ-In addition, the bankruptcy court retains jurisdiction to resolve ing periodic adjustments to rates to reflect changes in sales or remaining disputed claims held in escrow of approximately $1.7 demand compared to forecast sales or demand. The Utility's billion at December 31, 2004. See Note 2 of the Notes to the electricity and natural gas distribution rates in 2004 reflected the Consolidated Financial Statements for further discussion. sum of individual revenue requirement components including:

In March 2004, in anticipation of its emergence from Chap-

• Base revenue requirements to recover its basic business and ter 11, the Utility issued $6.7 billion in first mortgage bonds, or operational costs for electricity and natural gas distribution First Mortgage Bonds, and, together with its consolidated sub- operations and for electricity generation operations as set by sidiaries, obtained $2.9 billion in credit facilities, in order to the CPUC in the Utility's 2003 GRC;

• The allowed rates of return as set in the Utility's annual cost of capital proceedings at the CPUC; 32

• Revenue requirements for the recovery of the regulatory authorized for 2004, 2005 and 2006, is based on the 2003 assets (including an 11.22% return on equity) provided under authorized amount, as increased each year to reflect the annual the Settlement Agreement; changes in the Consumer Price Index, or CPI, subject to certain minimum and maximum adjustments. These adjustments are

• Revenue requirements for recovery of electricity and natural called "attrition adjustments." Base revenue requirements in gas procurement costs as authorized by the CPUC; 2004, including attrition adjustments totaled approximately $4.4

• Revenue requirements authorized by the FERC in the Util- billion. See "Regulatory Matters" below for further detail of the ity's transmission owner rate cases and to recover charges terms of the 2003 GRC.

imposed on the Utility for services provided by the California The impact of the approval of the GRC on the Utility's Independent System Operator, or ISO; and results of operations and financial condition is discussed below

• The revenue requirements of the California Department of under "Results of Operations" and "Regulatory Matters."

'Water Resources, or DWR, to meet the DIR's obligations under its long-term electricity procurement contracts entered Elimination of Equity Ownership in NEGT into during the energy crisis when the California investor- On October 29, 2004, NTEGT's plan of reorganization became owned electric utilities were unable to procure electricity. effective, at which time NTEGT emerged from Chapter 11 and Changes in any individual revenue requirement will affect PG&E Corporation's equity ownership in NTEGT was can-customers' electricity rates and the Utility's revenues. As a celled. As a result, during the fourth quarter of 2004 PG&E result, the Utility's net income is more predictable under cost- Corporation recognized a one-time non-cash gain on the dis-of-serice ratemaking than under the previous rate freeze. posal of NTEGT of approximately $684 million, as discussed below in the "Results of Operations" section.

In December 2004, the CPUC approved the Utility's first annual electricity rate true-up to adjust rates to reflect over- and FACTORS THAT MAY AFFECT FUTURE RESULTS under-collections in the Utility's major electricity balancing OF OPERATION AND FINANCIAL CONDITION accounts (including electricity procurement), and consolidate various other 2005 electricity revenue requirement changes In addition to future CPUC and FERC decisions that will affect authorized by the CPUC and the FERC. These rate changes, the rates that the Utility can charge for its services and that will implemented on January 1, 2005, contemplated an increase in determine the amount of costs the Utility can recover through electricity revenues of approximately $274 million as compared rates, the following significant factors are expected to affect the to 2004 revenues at previously adopted rates. On February 7, Utility's future results of operations and financial condition:

2005, the Utility requested the CPUC to approve a rate

• The issuance of energy recovery bonds in the aggregate decrease, to be effective on March 1, 2005 of approximately $73 amount of up to $3.0 billion; million, as compared to January 1, 2005 rates, to reflect the issuance of energy recovery bonds discussed below.

• The amount and cost of the long-term electricity resource com-mitments the Utility is required to make in connection with its 2003 GRC long-term electricity procurement plan which may involve sub-stantial capital expenditures in new generation resources; On May 27, 2004, the CPUC issued a decision in the Utility's 2003 GRC that determined the amount the Utility can collect

• The level of operating expenses; from customers, or base revenue requirements, to recover its

• The performance of distribution, generation, transmission basic business and operational costs for electricity and natural and natural gas transportation operating assets; and gas distribution operations and for electricity generation opera-tions for 2003 through 2006. The CPUC authorized base revenue requirements of approximately $4.3 billion for 2003, an increase of approximately $326 million over the previously authorized amounts. The amount of base revenue requirements 33

• The success of the Utility's strategy to achieve cost efficien- Utility's recovery through rates of the tax payments that will be cies and operational excellence and to invest in needed due as the Utility collects the DRC over the term of the first infrastructure to serve the Utility's customers, resulting in series of ERBs to pay principal. The Utility anticipates that it improved customer service, rate base growth and future earn- will use the proceeds from the second series of ERBs to repay ings under cost-of-service rate making. outstanding debt, or repurchase common stock from, PG&E Corporation or make additional needed investments in the Util-Issuance of Energy Recovery Bonds ity's rate base. Until taxes are fully paid, the Utility will In connection with the Settlement Agreement, PG&E Corpo- compensate customers, computed at the Utility's authorized rate ration and the Utility agreed to seek to refinance the remaining of return on rate base, for the use of the proceeds. This credit, unamortized balance of the Settlement Regulatory Asset and along with energy supplier refunds received after the second related federal income and state franchise taxes, in an aggregate series of ERBs is issued, other credits and costs related to the principal amount of up to $3.0 billion in two separate series up ERBs, will be reflected in rates. It is estimated that providing to one year apart, to be secured by a dedicated rate component, this "carrying cost credit" to customers could result in a or DRC, to be collected from electricity customers as a nonby- decrease of up to $60 million in the Utility's 2006 net income.

passable charge. On February 10, 2005, PG&E Energy The actual impact on 2006 net income will depend on the prin-Recovery Funding LLC, or PERF, a limited liability company cipal amount of the second series of ERBs issued, which, in which is wholly owned and consolidated by the Utility (but turn, depends on the timing and amount of refunds the Utility legally separate from the Utility), issued approximately $1.9 bil- receives from energy suppliers through the related FERC pro-lion of energy recovery bonds, or ERBs. The Utility, as servicer, ceedings. The carrying cost credit and the resulting impact on will collect and remit DRC charges to PERF to enable PERF net income will decline as the taxes are paid, reaching zero in to pay the principal and interest on the ERBs. The proceeds of 2012 when the ERBs and related taxes are paid in full. See Note the ERBs were paid by PERF to the Utility and will be used by 2 of the Notes to the Consolidated Financial Statements for the Utility to refinance the remaining unamortized after-tax further discussion.

balance of the Settlement Regulatory Asset through the redemption and repurchase of higher cost equity and debt. Electricity Procurement Costs and Long-Term Electricity Procurement Plan As a result of the issuance of the first series of ERBs, the Util-As a regulated utility, the Utility is obligated to procure elec-ity's 2005 net income will be reduced by approximately $100 tricity to meet the needs of its customers. The amount of million as compared to 2004 due to the elimination of the 11.22%

electricity needed to meet the demands of customers, plus return on common equity that the Utility earned on the Settle-applicable reserve margins, that is not satisfied from the Utility's ment Regulatory Asset and charged to customers during 2004.

own generation facilities, the Utility's electricity purchase con-In January 2005, the equity component of the Utility's capi- tracts, or from the DIWR's electricity purchase contracts tal structure reached 52%, the target specified in the Settlement allocated to the Utility's customers, is referred to as the Utility's Agreement. The Utility anticipates that it will use surplus cash residual net open position. Electricity procurement costs signif-to pay dividends to, or repurchase common stock from, PG&E icantly impacted the Utility's results of operations and financial Corporation. As discussed below, under "Liquidity," the Boards condition during the California energy crisis. California legisla-of Directors of the Utility and PG&E Corporation each have tion has been enacted which allows the Utility to recover its declared a common stock dividend and have authorized sub- reasonably incurred wholesale electricity procurement costs and stantial share repurchases. includes a mandatory rate adjustment provision that requires the CPUC to adjust rates on a timely basis to ensure that the The proceeds of the second series of ERBs, anticipated to be Utility recovers its costs. Accordingly, during 2004, electricity issued in November 2005 in an aggregate amount of up to procurement costs did not have the same impact on the Utility's

$1.1 billion will be paid by PERF to the Utility to pre-fund the results of operations that they had during the California energy crisis. The level of electricity procurement costs and revenues continue to have an impact on cash flows.

34

In December 2004, the CPUC issued a final decision which and maintenance expenses. If the Utility's operating expenses approved, with certain modifications, each California investor- exceed the amount of the authorized revenue requirement, the owned electric utility's long-term electricity procurement plan, Utility's results of operations and ability to earn its authorized or LTPP, in order to authorize each utility to plan for and pro- rate of return may be affected.

cure the resources necessary to provide reliable service to their customers for the ten-year period 2005-2014. The utilities are Distribution, Generation, Transmission required to solicit bids from providers of all potential sources And Natural Gas Transportation Operating Assets of new generation (e.g. conventional or renewable resources to The Utility's distribution, generation, transmission and natural be provided under utility owned turnkey developments, or gas transportation operating assets generally consist of long-lived under third party power purchase agreements) through a sin- assets with significant construction and maintenance costs. A sig-gle, open, transparent and competitive request for offers, or nificant outage at any of these facilities may have a material RFO, process, although a utility can tailor a RFO to meet spe- impact on the Utility's operations. Costs associated with replace-cific resource needs.

ment electricity and natural gas or use of alternative facilities The decision notes that there is a great degree of uncertainty during these outages could have an adverse impact on PG&E as to the amount of load the existing utilities will be responsible Corporation's and the Utility's results of operations and liquidity.

for serving in the future. Among other provisions, the decision:

The Utility's annual capital expenditures are expected to

• Permits the utilities to recover their net stranded costs of all average approximately $2.0 billion annually over the next five new fossil-fuel and renewable generation resources from all years from 2005 through 2009 and are estimated to result in customers, including departing customers, for a period of 10 rate base growth of approximately 4.5%. As discussed below years or the life of the power purchase agreement, whichever under "Capital Expenditures," the Utility could make additional is less; capital expenditures that would further increase rate base growth to 6.5% from 2005 through 2009.

• Extends the mandatory rate adjustment mechanism for whole-sale electric procurement costs under California law, which STRATEGY TO ACHIEVE COST EFFICIENCIES othenvise would end on January 1, 2006, to the length of a AND OPERATIONAL EXCELLENCE AND TO resource commitment or 10 years, whichever is longer; INVEST IN NEEDED UTILITY INFRASTRUCTURE

• Prohibits the utilities from recovering initial capital costs in With its exit from Chapter 11 and the return to cost-of-service excess of their final bid price for utility-owned generation ratemaking for electric distribution and generation operations, resources; and the Utility aims to earn no less than its authorized rate of

• Recognizes that the full cost (or debt equivalence) of power return, generate strong cash flow, ensure adequate liquidity, and purchase agreements should be considered when evaluating strengthen its credit rating. To achieve these goals, the Utility's energy contracts. strategy is to:

For more information, see "Regulatory MIatters" below.

• Achieve operational excellence and improved customer service;

• Generate cost and operating efficiencies; and Operating Expenses

• Invest in transmission and distribution infrastructure needed to Operating expenses are a key factor in determining whether the serve its customers (i.e., to extend the life of existing infrastruc-Utility earns the rate of return authorized by the CPUC. Many ture, to replace existing infrastructure, and to add new of the Utility's costs, including electricity procurement costs, infrastructure to meet load growth) as well as to invest in discussed above, are subject to ratemaking mechanisms that are needed new generation resources, as authorized by the CPUC.

intended to provide the Utility the opportunity to fully recover these costs. In the Utility's GRC, the CPUC authorizes the Utility to collect a fixed revenue requirement from customers that is intended to enable the Utility to recover its operating 35

It is expected that the Utility would use cash in excess of OPERATING ENVIRONMENT amounts needed for operations, debt service and base capital

• Unanticipated changes in operating expenses or capital expen-expenditures, to pay regular quarterly dividends, to make incre-ditures, which may affect the Utility's ability to earn its mental capital expenditures needed to serve its customers, and to authorized rate of return; repurchase its common stock. In turn, it is expected that PG&E Corporation would use the cash received from the Utility in the

• The level and volatility of wholesale electricity and natural gas form of dividends or share repurchases to pay regular dividends prices and supplies, the Utility's ability to manage and to, or repurchase common stock from, its shareholders. respond to the levels and volatility successfully and the extent to which the Utility is able to timely recover increased costs related to such volatility; FORWARD-LOOKING STATEMENTS

• Weather, storms, earthquakes, fires, floods, other natural dis-This combined Annual Report and the letter to shareholders asters, explosions, accidents, mechanical breakdowns and that accompanies it contain fonvard-looking statements that are other events or hazards that affect demand, result in power necessarily subject to various risks and uncertainties the realiza- outages, reduce generating output, or cause damage to the tion or resolution of which are outside of management's Utility's assets or operations or those of third parties on which control. These statements are based on current expectations and the Utility relies; projections about future events, and assumptions regarding these events and management's knowledge of facts at the time

• Unanticipated population growth or decline, changes in mar-the statements were made. These forward-looking statements ket demand and demographic patterns, and general economic are identified by words such as "assume," "expect," "intend," and financial market conditions, including unanticipated "plan," "project," "believe," "estimate," "predict," "anticipate," changes in interest or inflation rates, and the extent to which "may," "might," "will," "should," "would," "could," "goal," the Utility is able to timely recover its costs in the face of "potential" and similar expressions. Although PG&E Corpora- such events; tion and the Utility are not able to predict all the factors that

• The operation of the Utility's Diablo Canyon nuclear power may affect future results, some of the factors that could cause plant, or Diablo Canyon, which exposes the Utility to poten-future results to differ materially from those expressed or tially significant environmental costs and capital expenditure implied by the forward-looking statements, or from historical outlays and, to the extent the Utility is unable to increase its results, include:

spent fuel storage capacity by 2007 or find an alternative depos-itory, the risk that the Utility may be required to close Diablo APPEALS OF THE UTILITY'S Canyon and purchase electricity from more expensive sources; PLAN OF REORGANIZATION AND SETTLEMENT AGREEMENT

• Actions of credit rating agencies;

• The timing and resolution of the petitions for review that were

• Significant changes in the Utility's relationship with its filed in the California Court of Appeal for the first Appellate employees, the availability of qualified personnel and the District, or the California Court of Appeal, seeking review of potential adverse effects if labor disputes were to occur; and the CPUC's approval of the Settlement Agreement; and

• Acts of terrorism.

• The timing and resolution of the pending appeals of the con-firmation order. LEGISLATIVE AND REGULATORY ENVIRONMENT AND PENDING LITIGATION

• The impact of current and future ratemaking actions of the CPUC, including the risk of material differences between fore-casted costs used to determine rates and actual costs incurred; 36

• Whether the assumptions and forecasts underlying the Util-

• Whether the Utility is required to incur material costs or cap-ity's CPUC-approved long-term electricity procurement plan ital expenditures or curtail or cease operations at affected prove to be accurate, the terms and conditions of the genera- facilities to comply with existing and future environmental tion or procurement commitments the Utility enters into in laws, regulations and policies; and connection with its plan, the extent to which the Utility is

• The outcome of pending litigation.

able to recover the costs it incurs in connection with these commitments and the extent to which a failure to perform by COMPETITION AND BYPASS any of the counterparties to the Utility's electricity purchase contracts or the DIVIR contracts allocated to the Utility's cus-

• Increased competition as a result of the takeover by condem-tomers affects the Utility's ability to meet its obligations or to nation of the Utility's distribution assets, duplication of the recover its costs; Utility's distribution assets or service by local public utilities, and other forms of competition that may result in stranded

• Prevailing governmental policies and legislative or regulatory investment capital, decreased customer growth, loss of cus-actions generally, including those of the California legislature, tomer load and additional barriers to cost recovery; and the U.S. Congress, the CPUC, the FERC, and the Nuclear Regulatory Commission, or the NRC, with regard to the

• The extent to which the Utility's distribution customers Utility's allowed rates of return, industry and rate structure, switch between purchasing electricity from the Utility and recovery of investments and costs, acquisitions and disposal of from alternate energy service providers as direct access cus-assets and facilities, treatment of affiliate contracts and rela- tomers, the extent to which cities, counties and others in the tionships, and operation and construction of facilities; Utility's service territory begin directly serving the Utility's customers, and the extent to which the Utility's customers

• The extent to which the CPUC or the FERC delays or denies become self-generators, results in stranded generating asset recovery of the Utility's costs, including electricity purchase costs and non-recoverable procurement costs.

costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other rea- See the section below entitled "Risk Factors" for a further sons resulting in write-offs of regulatory balancing accounts; discussion of the more significant risks that could affect the out-come of these forward-looking statements and PG&E

• How the CPUC administers the capital structure, stand-alone Corporation's and the Utility's future results of operations and dividend and first priority conditions of the CPUC's decisions financial condition.

permitting the establishment of holding companies for the California investor-own ed electric utilities;

• The terms under which the CPUC authorizes the Utility to issue debt and equity in the future, and in particular the extent to which the conditions adopted by the CPUC, such as those contained in the CPUC's general financing authoriza-tion decision issued on October 28, 2004 (under which the Utility is authorized to issue debt and preferred stock in the future within certain amounts and for specific purposes) limit the Utility's ability to issue debt in the future;

• Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses; 37

RESULTS OF OPERATIONS The table below details certain items from the accompanying Consolidated Statements of Operations for 2004, 2003 and 2002.

Year ended December 31, (inmillions) 2004 2003 2002 Utility Electric operating revenues $ 7,867 $ 7,582 S 8,178 Natural gas operating revenues 3,213 2,856 2,336 Total operating revenues 11,080 10,438 10,514 Cost of electricity 2,770 2,319 1,482 Cost of natural gas 1,724 1,467 954 Operating and maintenance 2,842 2,935 2,817 Recognition of regulatory assets (4,900) - -

Depreciation, amortization and decommissioning 1,494 1,218 1,193 Reorganization professional fees and expenses 6 160 155 Total operating expenses 3,936 8,099 6,601 Operating income 7,144 2,339 3,913 Interest income 50 53 74 Interest expense (667) (953) (988)

Other expense, net') (5) (9) (27)

Income before income taxes 6,522 1,430 2,972 Income tax provision 2,561 528 1,178 Income before cumulative effect of a change in accounting principle 3,961 902 1,794 Cumulative effect of a change in accounting principle - (1) -

Income available for common stock S 3,961 $ 901 S 1,794 5

PG&E Corporation, Eliminations and Other(M)()

Operating revenues S - $ (3) S (9)

Operating expenses 26 (7) (50)

Operating income (loss) (26) 4 41 Interest income 13 9 6 Interest expense (130) (194) (236)

Other income (expense), net") (93) - 77 Income (loss) before income taxes (236) (181) (112)

Income tax benefit (95) (70) (41)

Income (loss) from continuing operations (141) (111) (71)

Discontinued operations 684 (365) (2,536)

Cumulative effect of changes in accounting principles - (5) (61)

Net income (loss) S 543 S (481) $ (2,668)

Consolidated Total()

Operating revenues $11,080 S 10,435 $10,505 Operating expenses 3,962 8,092 6,551 Operating income 7,118 2,343 3,954 Interest income 63 62 80 Interest expense (797) (1,147) (1,224)

Other income (expenses), net"' (98) (9) 50 Income before income taxes 6,286 1,249 2,860 Income tax provision 2,466 458 1,137 Income from continuing operations 3,820 791 1,723 Discontinued operations 684 (365) (2,536)

Cumulative effect of changes in accounting principles - (6) (61)

Net income (loss) $ 4,504 $ 420 S (874)

(° Includes preferred dividend requirement as other expense.

I) PG&E Corporation eliminates all intercompany transactions in consolidation.

M) Operating results of NEGT are reflected as discontinued operations. See Note 5 of the Notes to the Consolidated Financial Statements for further discussion.

38

UTILITY From mid-January 2001 through December 2002, the DWR was responsible for procuring electricity required to cover the As discussed above under "Overview," as ofJanuary 1, 2004, the Utility's net open position. The Utility resumed purchasing Utility no longer collects frozen electricity rates. Instead, the Util-electricity on the open market in January 2003 to satisfy its ity's electric rates are designed to fully recover the Utility's costs of residual net open position, but still relies on electricity provided service, including wholesale electricity procurement costs.

under DXVR contracts for a material portion of its customers' California legislation has been enacted which allows the demand. Revenues collected on behalf of the DWR and the Utility to recover its reasonably incurred wholesale electricity DWVR's related costs are not included in the Utility's Consoli-procurement costs and includes a mandatory rate adjustment dated Statements of Operations, reflecting the Utility's role as a provision which requires the CPUC to adjust rates on a timely billing and collection agent for the DWR's sales to the Utility's basis to ensure that the Utility recovers its costs. Accordingly, customers. Previously, under the frozen rate structure, increases with the implementation of new CPUC-approved electricity in the revenues passed through to the DWR decreased the Util-balancing accounts and cost of service ratemaking in 2004, elec- ity's revenues. Starting in 2004, the Utility's electric operating tricity procurement costs and items such as changes in sales revenues are based on an aggregation of individual rate compo-volumes have not had the same impact on the Utility's results of nents, including base revenue requirements, and electricity operations that they had during the California energy crisis procurement costs, among others. Changes in the DVR's rev-when rates were frozen. The level of the Utility's electricity enue requirements will not affect the Utility's revenues.

procurement costs continue to have an impact on cash flows. Although the Utility is permitted to pass through the DWR charges to customers, any changes in the amount of DWR Due to the recognition of the Settlement Regulatory Asset charges that the Utility's customers are required to pay can and generation-related regulatory assets provided under the affect regulatory willingness to increase overall rates to permit Settlement Agreement, net income for 2004 reflects a one-time the Utility to recover its own costs. As overall rates rise or non-cash gain of approximately $2.9 billion, after tax. In addi-decline, there may be changes regarding the risk of regulatory tion, as a result of receiving a CPUC decision in the Utility's disallowance of costs.

2003 GRQ, the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recov- The Utility is required to dispatch, or schedule, all of the ery of retained generation assets and unfunded taxes, electricity resources within its portfolio, including electricity depreciation and decommissioning. provided under the DWR allocated contracts, in the most cost-effective way. This requirement, in certain cases, requires the The following presents the Utility's operating results for Utility to schedule more electricity than is necessary to meet its 2004, 2003, and 2002.

retail load and to sell this additional electricity on the open market. The Utility typically schedules excess electricity when Electric Operating Revenues the expected sales proceeds exceed the variable costs to operate Beginning January 1, 1998, electricity rates were frozen as a generation facility or buy electricity under an optional con-required by the California electric industry restructuring law. In tract. Proceeds from the sale of surplus electricity are allocated 2001, in response to the California energy crisis, the CPUC between the Utility and the DINrR based on the percentage of increased frozen rates by imposing fixed surcharges which the volume supplied by each entity to the Utility's total load. The Utility collected through December 31, 2003. As a result of the Utility's net proceeds from the sale of surplus electricity after Settlement Agreement and various CPUC decisions, the Util- deducting the portion allocated to the DWVR are recorded as a ity's electricity rates as of January 1, 2004, are no longer frozen reduction to the cost of electricity.

and are determined based on its costs of service.

As a result of the return to cost-of-service ratemaking in 2004, the Utility records its electric distribution revenues under revenue requirements approved by the 2003 GRC. Differences between the authorized revenue requirements and amounts col-lected by the Utility from customers in rates are tracked in regulatory balancing accounts and are reflected in miscellaneous revenues in the table below.

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The following table shows a breakdown of the Utility's

• Surcharge revenues decreased by approximately $900 million electric operating revenues. compared to 2002, reflecting the impact of a variety of factors including an increase in pass-through revenue to the DINR (in millions) 2004 2003 2002 and the Utility's obligation under the Settlement Agreement Electric revenues $ 9,600 $10,043 $10,203 to refund surcharge revenues in excess of $875 million.

DWVVR pass-through revenue (1,933) (2,243) (2,056)

Partially offsetting this decrease was an increase of approxi-Subtotal 7,667 7,800 8,147 Miscellaneous 200 (218) 31 mately $270 million for electric distribution operations as a result of the 2003 GRC.

Total electric operating revenues $ 7,867 $ 7,582 $ 8,178 Total electricity sales (in Kwhy') 83,096 80,152 75,968 Cost of Electricity (e) Includes DIVR electricity sales. The Utility's cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities, The Utility's electric operating revenues increased in 2004 but it excludes costs to operate its owned generation facilities, by approximately $285 million, or approximately 4%, compared which are included in operating and maintenance expense.

to 2003 due to the following factors: Electricity purchase costs and the cost of fuel used by owned generation facilities are passed through in rates to customers.

• The CPUC authorization for the Utility to collect the rev- The following table shows a breakdown of the Utility's cost of enue requirements associated with the Settlement Regulatory electricity and the total amount and average cost of purchased Asset and the other regulatory assets provided under the Set- power, excluding in each case both the cost and volume of elec-tlement Agreement resulted in an electric operating revenue tricity provided by the DXVR to the Utility's customers:

increase of approximately $490 million during 2004, com-pared to 2003; (in millions) 2004 2003 2002

• The approval of the Utility's 2003 GRC in May 2004 resulted Cost of purchased power S 2,816 S 2,449 $ 1,980 in an electric operating revenue increase of approximately Proceeds from surplus sales allocated to the Utility (192) (247) -

$100 million. The GRC determines the amount the Utility Fuel used in own generation 146 117 97 can collect from its customers, or base revenue requirements Adjustments to purchased power (see the "Regulatory Matters" section of this MD&A); accruals - - (595)

• Electric transmission revenues increased by approximately Total net cost of electricity $ 2,770 $ 2,319 $ 1,482

$400 million in 2004 compared to 2003 primarily due to an Average cost of purchased increase in recoverable reliability must run, or RMR, costs power per kVh S 0.082 S 0.076 $ 0.081 and an increase in at-risk transmission access revenues; and Total purchased power (GWh) 34,525 32,249 24,552

• The remaining increases in the Utility's electric operating rev-enues were due to increases of approximately $170 million in the Utility's authorized revenue requirements for procure- In 2004, the Utility's cost of electricity increased approxi-ment and miscellaneous other electric revenues in 2004 mately $451 million, or 19%, as compared to 2003 mainly due compared to 2003. to the following factors:

Partially offsetting the increase in electric operating rev-

• The increase in total purchased power of 2,276 Gigawatt enues was the absence of surcharge revenues in 2004 as a result hours, or GNN'h, and the increase in the average cost of pur-of the return to cost of service ratemaking in 2004. The Utility chased power of $0.006 per kNVh in 2004 as compared to collected $875 million in surcharge revenues in 2003. 2003 resulted in an increase of approximately $367 million in the cost of purchased power; and In 2003, the Utility's electric operating revenues decreased approximately $596 million, or 7%, compared to 2002.

• The cost of electricity increased by approximately $84 million in 2004 as compared to 2003 as a result of a decrease in the proceeds from surplus sales allocated to the Utility in 2004 and an increase in the amount of fuel used in the Utility's owned generation.

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In 2003, the Utility's cost of electricity increased approxi- mately 35% of its total natural gas deliveries, *whilenoncore cus-mately $837 million, or 56%, compared to 2002 mainly due to tomers comprised less than I % of the Utility's total customers and the following factors: approximately 65% of its total natural gas deliveries.

• The Utility's total volume of electricity purchased in 2003 The Utility's transportation system transports gas through-increased 31 % due to the fact that the Utility resumed buying out California to the Utility's distribution system, which, in and selling electricity on the open mark-et beginning in the turn, delivers gas to end-use customers. Utility transportation first quarter of 2003 to meet its residual net open position in and distribution services for all customers have historically been accordance with its CPUC-approved electricity procurement bundled or sold together at a combined rate.

plan. The increase in total purchased power of 7,697 GMVh, The following table shows a breakdown of the Utility's which was partially offset by a decrease in the average cost of natural gas operating revenues:

purchased power of $0.005 per k-Wh resulted in an increase of approximately $469 million in the cost of purchased power in (in millions) 2004 2003 2002 2003 compared to 2002; Bundled natural gas revenues $2,943 S2,572 $2,020

• In AMarch 2002, the Utility recorded a net reduction of Transportation service-only revenues 270 284 316 approximately $595 million to the cost of electricity as a result Total natural gas operating revenues $3,213 $2,856 $2,336 of FERC and CPUC decisions that allowed the Utility to reverse previously accrued ISO charges and to adjust for the Average bundled revenue per AIcf of naturalgassold $10.51 S 9.22 $ 7.16 amount previously accrued as payable to the DWR for the DXVR's 2001 revenue requirement. There was no comparable Total bundled natural gas sales (in millions of lcf) 280 279 282 reduction in 2003; and

• As the Utility resumed procuring power on behalf of its cus-tomers, it wvas sometimes required to dispatch more electricity The Utility's natural gas operating revenues increased than was necessary to meet its retail load, and to sell this addi- approximately $357 million, or 13%, for the year ended Decem-tional electricity on the open market. Proceeds from surplus ber 31, 2004, compared to 2003. The increase in natural gas electricity sales, offset by an increase in the amount of fuel used operating revenues was primarily due to the following factors:

in the Utility's owned generation reduced the total cost of elec-

• Bundled natural gas revenues (excluding the effects of the tricity by approximately $227 million in 2003 compared to 2002.

2003 GRC decision discussed below) increased by approxi-The Utility's cost of electricity in 2005 will depend upon mately $250 million, or 10%, in 2004 compared to 2003, electricity prices and the amount of the Utility's residual net mainly due to a higher cost of natural gas which the Utility is open position (see the "Risk Factors" section of this MD&A). permitted by the CPUC to pass on to its customers through higher rates. The average bundled revenue per thousand Natural Gas Operating Revenues cubic feet, or Mcf, of natural gas sold in 2004 (excluding the The Utility sells natural gas and provides natural gas transporta- effects of the 2003 GRC decision discussed below) increased tion services to its customers. The Utility's natural gas customers by approximately $0.86, or 9%, as compared to 2003; and consist of two categories: core and noncore customers. The core

• The approval of the 2003 GRC resulted in an increase in nat-customer class is comprised mainly of residential and smaller com- ural gas revenues of approximately $121 million (consisting of mercial natural gas customers. The noncore customer class is a 2004 portion of $69 million and a 2003 portion of $52 mil-comprised of industrial and larger commercial natural gas cus- lion) in 2004 compared to 2003 (see the "Regulatory Matters" tomers. The Utility provides natural gas delivery services to all section of this MID&A).

core and noncore customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from In 2003, the Utility's total natural gas operating revenues alternate energy service providers or can elect to have the Utility increased approximately $520 million, or 22%, compared to provide both delivery service and natural gas supply. When the 2002. The Utility's bundled natural gas revenues increased by Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. In 2004, core customers represented over 99% of the Utility's total customers and approxi-41

approximately $552 million, or 27%, in 2003 compared to 2002

• The Utility's cost of natural gas sold increased by approxi-mainly due to a higher average cost of natural gas, which the mately $483 million, or 57%, in 2003 compared to 2002 Utility is permitted by the CPUC to pass on to its customers mainly due to an increase in the average cost of natural gas in through higher rates. The average bundled revenue per Mcf of 2003 of $1.77 per Mcf, or 59%; and natural gas sold in 2003 increased $2.06, or 29%, compared to

• The Utility's cost of natural gas transportation increased by 2002. This increase in bundled natural gas revenues was par-approximately $30 million, or 30%, in 2003 compared to tially offset by a decrease in transportation service-only 2002 mainly due to pipeline transportation charges paid to El revenues of approximately $32 million, or 10%, in 2003 com-Paso Natural Gas Company, or El Paso. The Utility, along pared to 2002. The decrease in transportation service-only with other California utilities, was ordered by the CPUC in revenues was primarily due to a decrease in demand for natural July 2002 to enter into new long-term contracts to purchase gas transportation services by certain non-core customers, firm transportation services on the El Paso pipeline, under mainly natural gas-fired electric generators in California. An which the Utility pays a fixed amount to secure capacity on increase in electricity available from hydroelectric facilities and the El Paso pipeline.

the greater efficiency of generation facilities that commenced operations in 2003 resulted in reduced demand for natural gas The Utility's cost of natural gas sold in 2005 will be prima-transportation services. rily affected by the prevailing costs of natural gas, which are determined by North American regions that supply the Utility.

The Utility's natural gas revenues in 2005 X ill increase due to an increase in natural gas distribution revenue requirements Operating and Maintenance that were approved in the 2003 GRC decision, and will be fur-ther impacted by changes in the cost of natural gas. Operating and maintenance expenses consist mainly of the Util-ity's costs to operate and maintain its electricity and natural gas Cost of Natural Gas facilities, customer accounts and service expenses, public purpose program expenses, and administrative and general expenses.

The Utility's cost of natural gas includes the purchase cost of natural gas and transportation costs on interstate pipelines, but During 2004, the Utility's operating and maintenance excludes the costs associated with the Utility's intrastate expenses decreased by approximately $93 million, or 3 %, com-pipeline, which are included in operating and maintenance pared to 2003. This decrease is primarily due to the expense. The following table shows a breakdown of the Utility's establishment of a regulatory asset of approximately $50 million cost of natural gas: in 2004 related to distribution-related electric industry restruc-turing costs incurred during the period from 1999 through (in rnillions) 2004 2003 2002 2002 that were previously not considered probable of recovery.

Cost of natural gas sold S1,591 $1,336 $ 853 During 2004, the CPUC adopted a proposed settlement agree-Cost of natural gas transportation 133 131 101 ment that permits recovery of a portion of these costs (see the Total cost of natural gas $1,724 $1,467 $ 954 "Regulatory Matters" section of this MD&A).

Average cost per Mcf of natural gas sold S 5.68 $ 4.79 $ 3.02 In 2003, the Utility's operating and maintenance expenses increased by approximately $118 million, or 4%, compared to Total natural gas sold (in millions of Acf) 280 279 282 2002 mainly due to a reversal of a liability of approximately $65 million for surcharge revenues in excess of ongoing procurement In 2004 the Utility's total cost of natural gas increased costs and surcharge revenue collections at the end of 2002. The approximately $257 million, or 18%, as compared to 2003, pri- remainder of the increase was mainly due to wage increases in marily due to an increase in the average market price of natural 2003 and increases in employee benefit plan-related expenses gas purchased of approximately $0.89 per Mcf. due to a 15% decrease in returns on plan investments and a decrease in the discount rates used to calculate the present value In 2003, the Utility's total cost of natural gas increased by of the Utility's benefit obligations from 6.75% to 6.25%.

approximately $513 million, or 54%, compared to 2002 mainly due to the following factors: Recognition of Regulatory Assets In light of the satisfaction of various conditions to the imple-mentation of the Utility's plan of reorganization, the Utility recorded the regulatory assets provided for under the 42

Settlement Agreement in the first quarter of 2004. This 2004 from 2003 and approximately $21 million, or 28%, in 2003 resulted in the recognition of a one-time non-cash, pre-tax gain from 2002. Both decreases were mainly due to lower average of $3.7 billion for the Settlement Regulatory Asset and $1.2 bil- interest rates earned on the Utility's short-term investments.

lion for the Utility retained generation regulatory assets, for a total after-tax gain of $2.9 billion. See the "Overview" section Interest Expense of this MD&A and Note 2 of the Notes to the Consolidated In 2004, the Utility's interest expense decreased by approxi-Financial Statements for further discussion. mately $286 million, or 30%, compared to 2003 mainly due to a lower average amount of unpaid debt accruing interest and a Depreciation, Amortization and Decommissioning lower weighted average interest rate on debt outstanding during The Utility charges the original cost of retired plant and removal 2004 compared to 2003. As a result of this interest savings, the costs less salvage value to accumulated depreciation upon retire- CPUC reduced the Utility's authorized cost of capital revenue ment of plant in service for its lines of business that apply SEAS requirement in 2004 (see the "Regulatory Matters" section of No. 71, "Accounting for the Effects of Certain Types of Regula- this MD&A).

tion," as amended, or SFAS No. 71, which includes electricity In 2003, the Utility's interest expense decreased by approxi-and natural gas distribution, electricity generation and transmis-mately $35 million, or 4%, compared to 2002 mainly due to the sion, and natural gas transportation and storage.

reduction in the amount of rate reduction bonds outstanding, In 2004, the Utility's depreciation, amortization and decom- reflecting the declining principal balance of the rate reduction missioning expenses increased by approximately $276 million, bonds and a lower amount of unpaid debts accruing interest. See or 23%, compared to 2003, primarily as a result of the amorti- Note 3 of the Notes to the Consolidated Financial Statements zation of the Settlement Regulatory Asset and an increase in the for further discussion. This decrease was partially offset by the Utility's plant assets. accrual of $38 million in interest payable to the DWR in 2003.

In 2003, the Utility's depreciation, amortization and decom-Income Tax Expense missioning expenses increased by approximately $25 million, or 2%, compared to 2002 mainly due to an increase in the Utility's In 2004, the Utility's income tax expense increased by approxi-plant assets. mately $2.0 billion, or 387%, as compared to 2003, mainly due to an increase in pre-tax income of approximately $5.1 billion Reorganization Fees and Expenses for the year ended December 31, 2004, primarily as a result of the recognition of regulatory assets associated with the Settle-In accordance with the American Institute of Certified Public ment Agreement, as compared to the same period in 2003. This Accountants' Statement of Position 90-7, "Financial Reporting increase w as partially offset by the recognition of tax regulatory by Entities in Reorganization Under the Bankruptcy Code," or assets established upon receipt of the Utility's 2003 GRC deci-SOP 90-7, the Utility reports reorganization fees and expenses sion. The effective tax rate for the year ended December 31, separately on its Consolidated Statements of Operations. These 2004 increased by 2.9 percentage points. This increase is due costs mainly include professional fees for services in connection mainly to increases in the effect of regulatory treatment of with the Utility's Chapter 11 proceedings and totaled approxi-depreciation differences and lower tax credit amortization in mately $6 million in 2004, $160 million in 2003 and $155 2004.

million in 2002. The Utility discontinued reporting in accor-dance with SOP 90-7 upon its emergence from Chapter 11 on In 2003, the Utility's income tax expense decreased by approx-April 12, 2004. imately $650 million, or 55%, as compared to 2002, mainly due to a decrease in pre-tax income of approximately $1.5 billion for Interest Income the year ended December 31, 2003. In 2003 the effective tax rate In accordance \vith SOP 90-7, the Utility reports reorganization decreased by 2.9 percentage points from 2002. The decrease is interest income separately on its Consolidated Statements of due mainly to the effect of regulatory treatment of depreciation Operations. Reorganization interest income mainly includes differences.

interest earned on cash accumulated during the Utility's Chapter 11 proceedings. Interest income, including reorganization inter-est income, decreased by approximately $3 million, or 6%, in 43

PG&E CORPORATION, deferred charges and unamortized loan fees during 2003, ELIMINATIONS AND OTHERS compared to 2002. During the third quarter of 2003, PG&E Corporation wrote off approximately $89 million as described Operating Revenues and Expenses above, while during the third quarter of 2002, PG&E Corpora-PG&E Corporation's revenues consist mainly of billings to its tion wrote off $153 million of unamortized loan fees and affiliates for services rendered, all of which are eliminated in discounts when it repaid principal and modified a loan under consolidation. PG&E Corporation's operating expenses consist PG&E Corporation's credit agreement.

mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation's operat- Other Income (Expense) ing expenses are allocated to affiliates. These allocations are PG&E Corporation's other expense increased by approximately made without mark-up. Operating expenses allocated to affili- $93 million in 2004 compared to 2003. The increase was prima-ates are eliminated in consolidation. rily due to a pre-tax charge to earnings, related to the change in market value of non-cumulative dividend participation rights The increase in operating expenses was primarily due to the included within PG&E Corporation's $280 million of 9.50%

absence of entries in 2004 to eliminate the cost of natural gas Convertible Subordinated Notes due 2010, or Convertible Sub-and electricity expenses provided by NEGT to the Utility after ordinated Notes.

PG&E Corporation's deconsolidation of NEGT effective July 7, 2003. A reduction in general and administrative expenses In 2003, PG&E Corporation's other income decreased by in 2004 compared to 2003 partly offset this increase. approximately $77 million, compared to 2002, due to the third quarter of 2002 change in the market value of NEGT warrants.

In 2003, the increase in operating expenses of approximately In 2001, PG&E Corporation granted to affiliates of lenders

$43 million compared to the same period in 2002, w.as primarily through which it was refinancing debt, warrants to purchase up attributable to increased employee compensation plan expenses, to 2 % or 3% of NEGT's outstanding common stock (depending partly offset by a decrease in consulting services and outside on how long the loans were outstanding). These warrants were attorney fees related to the Utility's plan of reorganization.

originally recorded at their fair value of approximately $151 mil-lion. The fair value of the warrants was marked to market at the Interest Expense end of each reporting period. Changes in fair value of the war-PG&E Corporation's interest expense is not allocated to its rants were recorded as other non-operating expense or income.

affiliates. In 2004, PG&E Corporation's interest expense In the third quarter of 2002, approximately $71 million was decreased by approximately $64 million, or 33%, compared to recorded in other non-operating income to reflect the reduction 2003 due to a reduction in principal debt amount outstanding to zero of the fair value of the 3% warrants. The 3% warrants and lower interest rates in 2004 compared to 2003, as well as a were exercised during the first quarter of 2003.

write-off of approximately $89 million of unamortized loan fees, loan discount, and prepayment fees associated with the repay- Discontinued Operations ment in July 2003 of approximately $735 million of principal Effective July 8, 2003 (the date NTEGT filed a voluntary peti-and interest under PG&E Corporation's then existing credit tion for relief under Chapter 11), NTEGT and its subsidiaries agreement. This decrease in interest expense was partly offset were no longer consolidated by PG&E Corporation in its Con-by a redemption premium of approximately $51 million and a solidated Financial Statements. Under accounting principles charge due to the write-off of approximately $15 million of generally accepted in the United States of America, or GAAP, unamortized loan fees associated with the redemption of PG&E consolidation is generally required for entities owning more Corporation's $600 million of 6 7/8% Senior Secured Notes than 50% of the outstanding voting stock of an investee, except due 2008, or Senior Secured Notes, on November 15, 2004.

when control is not held by the majority owner. Legal reorgani-In 2003, PG&E Corporation's interest expense decreased by zation and bankruptcy represent conditions that can preclude approximately $42 million, or 18%, compared to 2002. The consolidation in instances where control rests with an entity decrease was mainly due to a decrease in amortization of other than the majority owner. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives who previously served on the NEGT Board of Directors resigned on July 7, 2003, and were replaced with Board members who are 44

not affiliated with PG&E Corporation. As a result, PG&E LIQUIDITY AND Corporation no longer retained significant influence over the FINANCIAL RESOURCES ongoing operations of NTEGT.

Accordingly, PG&E Corporation has reflected the loss from OVERVIEW operations of NTEGT through July 7, 2003 as discontinued oper- The level of PG&E Corporation and the Utility's current ations in its Consolidated Statements of Operations. In addition, assets and current liabilities is subject to fluctuation as a result PG&E Corporation's negative investment in NTEGT of approxi- of seasonal demand for electricity and natural gas, energy com-mately $1.2 billion was reflected as a single amount, under the modity costs, and the timing and effect of regulatory decisions cost method, within the December 31, 2003 Consolidated Bal- and financings, among other factors. The Utility will use the ance Sheet of PG&E Corporation. This negative investment proceeds of the issuance of the ERBs it received from PERF, represents the losses of NTEGT recognized by PG&E Corpora- the issuer of the ERBs, to refinance the remaining unamortized tion in excess of its investment in and advances to NEGT. balance of the Settlement Regulatory Asset through the On October 29, 2004, NEGT's plan of reorganization redemption and repurchase of higher cost equity and debt. The became effective, at which time NTEGT emerged from Utility plans to use a portion of the ERB proceeds to defease Chapter 11 and PG&E Corporation's equity ownrership in $600 million of Floating Rate First Mortgage Bonds by the end NTEGT was cancelled. On the effective date, PG&E Corpora- of February 2005, retire $300 million of short-term debt, and tion reversed its negative investment in NEGT and also reversed repurchase approximately $960 million of its common stock net deferred income tax assets of approximately $428 million and from PG&E Corporation.

a charge of approximately $120 million ($77 million, after tax), In January 2005, the equity component of the Utility's capi-in accumulated other comprehensive income, related to NEGT. tal structure reached 52%, the target specified in the Settlement The resulting net gain has been offset by the $30 million pay- Agreement. As discussed below, on February 16, 2005, the ment made by PG&E Corporation to NEGT pursuant to the Boards of Directors of the Utility and PG&E Corporation each parties' settlement of certain tax-related litigation and other declared a common stock dividend. In addition, PG&E Corpo-adjustments to NEGT-related liabilities. A summary of the ration anticipates that it will repurchase shares of its common effect on the quarter and year ended December 31, 2004 earn- stock of up to $1.05 billion, increased from a previous authori-ings from discontinued operations is as follows: zation of up to $975 million.

(in millions) LIQUIDITY Investment in NEGT $1,208 Accumulated other comprehensive income (120) PG&E Corporation and the Utility intend to retain sufficient cash Cash paid pursuant to settlement of tax related litigation (30) for operating needs and to manage debt levels to maintain access Tax effect (374) to credit. Available cash, combined with cash from operations and Gain on disposal of NLEGT, net of tax $ 684 cash generated from refinancing of the Settlement Regulatory Asset will be used for planned capital expenditures and repayment of existing long-term debt. Surplus cash either will be returned to At December 31, 2004, PG&E Corporation's Consolidated investors through dividend payments and/or share repurchases or Balance Sheet includes approximately $138 million in income utilized to fund incremental capital investments.

tax liabilities (including $86 million in current income taxes PG&E Corporation and the Utility seek to manage their liq-payable) and approximately $25 million of other net liabilities uidity and capital resources within the following parameters related to NTGT. Until PG&E Corporation reaches final set-and assumptions:

tlement of these obligations, it will continue to disclose fluctuations in these estimated liabilities in discontinued opera-

• PG&E Corporation and the Utility target cash balances, tions. Beginning on the effective date of NEGT's plan of which, together with credit facilities, accommodates normal reorganization, PG&E Corporation no longer includes NTEGT and unforeseen demands on its liquidity. Currently, PG&E or its subsidiaries in its consolidated income tax returns. Corporation and the Utility have credit facilities totaling

$200 million and $1.5 billion, respectively; PG&E Corporation recorded losses from discontinued oper-ations of approximately $365 million in 2003 and approximately

$2.5 billion in 2002.

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• The Utility seeks to maintain or strengthen its credit ratings PG&E Corporation and the Utility primarily invest their cash to provide efficient access to financial and trade credit and to - in money market funds and in short-term obligations of the ensure adequate liquidity. The Utility's issuer credit ratings, as U.S. Government and its agencies.

of February 16, 2005, are BBB from Standard & Poor's, or S&P, and Baa3 from Moody's Investors Service, or Moody's. DIVIDENDS The Utility's secured debt ratings are currently BBB from PG&E Corporation and the Utility did not declare or pay a S&P and Baa2 from Moody's; dividend during the Utility's Chapter I1 proceeding as the Util-

• The Utility seeks to manage its operating expenses and capital ity was prohibited from paying any common or preferred stock expenditures to earn not less than its 11.22% authorized rate dividends without bankruptcy court approval and certain of return on the equity portion of its authorized rate base covenants in PG&E Corporation's Senior Secured Notes assets. Under the Settlement Agreement, the Utility's author- restricted the circumstances in which such a dividend could be ized return on equity floor of 11.22% and allowed equity ratio declared or paid. With the Utility's emergence from Chapter 11 of 52% cannot be reduced until its long-term issuer credit on April 12, 2004, the Utility resumed the payment of preferred ratings are at least A- from S&P or A3 from Mloody's; stock dividends.

• The Utility estimates average capital expenditures of approxi- On February 16, 2005, the Board of Directors of the Utility mately $2.0 billion annually over the next five years declared a cash dividend of $117 million on the Utility's com-(excluding additional potential capital expenditures as dis- mon stock for the first quarter of 2005. The dividend was paid cussed below under "Capital Expenditures"); to PG&E Corporation and PG&E Holdings LLC, a wholly owned subsidiary of the Utility that holds approximately 6% of

• The Utility assumes that the second series of ERBs in the the Utility's common stock, on February 17, 2005. Also, on approximate amount of up to $1.1 billion will be issued in February 16, 2005, the Board of Directors of PG&E Corpora-November 2005; tion declared a cash dividend of $0.30 per share on PG&E

• The Utility assumes that its total natural gas and electric rate Corporation's common stock for the first quarter of 2005, base will grow at the rate of 4.5%-6.5% per year over the payable on April 15, 2005, to shareholders of record on next five years, depending on the level of capital spending for March 31, 2005. These actions are consistent with the dividend infrastructure needs. Rate base is expected to reach approxi- policy and target dividend payout ratio range (the proportion of mately $15.3 billion in 2005 and $16.0 billion in 2006; and earnings paid out as dividends) adopted by both Boards in October 2004. PG&E Corporation's and the Utility's dividend

• The Utility remains under cost-of-service regulation by the policies contemplate a target dividend payout ratio range of CPUC and, with respect to electricity transmission, the 50-70% and PG&E Corporation's policy targets an initial FERC, and the CPUC authorizes sufficient revenues for the annual cash dividend of $1.20 per share ($0.30 quarterly).

Utility to recover its energy procurement and base expenses.

PG&E Corporation's and the Utility's dividend policies are At December 31, 2004, PG&E Corporation and its sub-designed to meet the following three objectives:

sidiaries had consolidated cash and cash equivalents of approximately $ 1.0 billion, and restricted cash of approximately

• Comparability Pay a dividend competitive with the securities

$2.0 billion. PG&E Corporation and the Utility maintain sepa- of comparable companies based on payout ratio and, with rate bank accounts. At December 31, 2004, PG&E Corporation respect to PG&E Corporation, yield (i.e., dividend divided by on a stand-alone basis had cash and cash equivalents of approxi- share price);

mately $189 million. At December 31, 2004, the Utility had Flexibiity:

F Allow sufficient cash to pay a dividend and to fund cash and cash equivalents of approximately $783 million, and

- investments while avoiding the necessity to issue new equity restricted cash of approximately $2.0 billion. The Utility's unless PG&E Corporation's or the Utility's capital expendi-restricted cash includes amounts deposited in escrow related to ture requirements are growing rapidly and PG&E the remaining disputed Chapter 11 claims, collateral required Corporation or the Utility can issue equity at reasonable cost by the ISO and deposits under certain third party agreements.

and terms; and

• Sustainability: Avoid reduction or suspension of the dividend despite fluctuations in financial performance except in extreme and unforeseen circumstances.

46

The target dividend payout ratio range was based on an UTILITY analysis of dividend payout ratios of comparable companies. The initial dividend target was chosen in recognition of the Utility's Operating Activities current credit rating and the potential capital investments that The Utility's cash flows from operating activities consist of sales the Utility may make in the future to provide electricity resource to its customers and payments of operating expenses, other than adequacy in compliance with future regulatory requirements and expenses such as depreciation that do not require the use of an approved LTPP. cash. Cash flows from operating activities are also impacted by Each Board of Directors retains authority to change its corn- collections of accounts receivable and payments of liabilities mon stock dividend policy and its dividend payout ratio at any previously recorded.

time, especially if unexpected events occur that would change The Utility's cash flows from operating activities for 2004, the Board's views as to the prudent level of cash conservation. 2003 and 2002 were as follows:

STOCK REPURCHASES (in millions) 2004 2003 2002 During the fourth quarter of 2004, 1,863,600 shares of PG&E Net income $3,982 $ 923 $1,819 Corporation common stock were repurchased through transac- Non-cash (income) expenses:

Depreciation, amortization and tions with brokers and dealers on the New York Stock decommissioning 1,494 1,218 1,193 Exchange and/or the Pacific Exchange for an aggregate pur- Gain on establishment of chase price of approximately $60 million. Of this amount, regulatory asset, net (2,904) 850,000 shares are held by Elm Power Corporation, a wholly Net reversal of ISO accrual (970) owned subsidiary of PG&E Corporation. Change in accounts receivable (85) (590) 212 Change in accrued taxes 52 48 (345)

In addition, on December 15, 2004, PG&E Corporation Other uses of cash:

entered into accelerated share repurchase arrangements with Payments authorized by the Goldman, Sachs & Co., or GS&Co., under which PG&E Cor- bankruptcy court on amounts classified as liabilities subject poration repurchased 9,769,600 shares of its common stock for to compromise (1,022) (87) (1,442) an aggregate of purchase price of approximately $318 million.

Other changes in operating assets The repurchased shares were retired. PG&E Corporation will and liabilities 454 458 667 pay GS&Co. approximately $14 million on February 22, 2005,

• Net cash provided by operating to settle its obligations to pay GS&Co. a price adjustment based activities S1,971 S 1,970 $1,134 on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement.

On December 15, 2004, the Board of Directors of the Util- In 2004, net cash provided by operating activities approxi-ity authorized the repurchase of up to $800 million (which has mated 2003 levels. This is mainly due to the following factors:

been increased to $1.8 billion following the receipt of proceeds Net income increased approximately $431 million, excluding from the issuance of ERBs) of the Utility's common stock from the one-time non-cash gain, after-tax, of approximately $2.9 PG&E Corporation, with such repurchases to be effective from billion related to the recognition of the regulatory assets time to time, but no later than December 31, 2006. Based on established under the Settlement Agreement and including the expected receipt of funds, on December 15, 2004, PG&E $276 million for the impact of depreciation, amortization, and Corporation's Board of Directors authorized the repurchase of decommissioning which are also non-cash items; up to $975 million of its outstanding common stocL

• Accounts receivable increased approximately $505 million pri-On February 16, 2005, the Board of Directors of PG&E marily due to there being no similar settlement in 2004 for Corporation increased this authorization to $1.05 billion with the 2003 DWR settlement discussed below; and such repurchases to be effected from time to time, but no later thanJune 30, 2006. PG&E Corporation expects to enter into a

• Payments authorized by the bankruptcy court on amounts replacement accelerated share repurchase arrangement by early classified as liabilities subject to compromise increased March 2005 to repurchase an aggregate of $1.05 billion of its approximately $935 million due to payment of all allowed outstanding shares. The repurchased shares will be retired at creditor claims on the Effective Date.

that time.

47

In 2003, net cash provided by operating activities increased In 2004, net cash used by investing activities increased by by approximately $836 million compared to 2002, even though approximately $1.6 billion as compared to 2003. This increase net income decreased by $896 million in 2003. This is mainly was mainly due to an increase in restricted cash of approxi-due to the following factors: mately $1.7 billion in 2004 reflecting a deposit of funds into an escrow account to pay disputed Chapter I1 claims when

• Payments on amounts classified as liabilities subject to com-resolved. This was partially offset by a decrease of $139 million promise decreased by approximately $1.4 billion in 2003, in capital expenditures in 2004 compared to 2003 primarily due compared to 2002 due to significant pre-petition and post-to delays in electric transmission line capacity projects.

petition payments made in 2002 under bankruptcy court-approved settlements; In 2003, net cash used by investing activities increased by approximately $254 million compared to 2002. This increase was

• This was partially offset by an increase in accounts receivable mainly due to an increase in capital expenditures related to elec-of approximately $802 million. This increase was mainly due tricity transmission network upgrades and new electricity capacity to the settlement in 2003 of an amount payable to the DWR and transmission development projects in 2003 and other invest-that was recorded as an offset to the Utility's customer ing activities during 2003. Cash flows from other investing accounts receivable balance in 2002. Amounts payable to the activities related mainly to nuclear decommissioning funding and DWVR are offset against amounts receivable from the Utility's the change in nuclear fuel inventory during the period.

customers for energy supplied by the DWR reflecting the Utility's role as a billing and collection agent for the DIVR's Financing Activities sales to the Utility's customers; During its Chapter 11 proceeding, the Utility's financing activi-

• During 2002, the Utility overpaid income taxes resulting in an ties were limited to repayment of secured debt obligations as increase of $393 million of accrued taxes; and authorized by the bankruptcy court. During this period, the

• Net income in 2002 included a non-cash reduction of approx- Utility did not have access to the capital markets. In imately $970 million to cost of electricity related to the March 2004, in anticipation of its emergence from Chapter 11, reversal of ISO charges. the Utility issued significant amounts of debt in order to finance its payments to be made in connection with the imple-Investing Activities mentation of the plan of reorganization on the Effective Date.

The Utility also established a working capital facility and an The Utility's investing activities consist of construction of accounts receivable financing facility for the purposes of fund-new and replacement facilities necessary to deliver safe and reli-ing its operating expenses and seasonal fluctuations in working able electricity and natural gas services to its customers. Cash capital and providing letters of credit.

flows from operating activities have been sufficient to fund the Utility's capital expenditure requirements during 2004, 2003 The Utility's cash flows from financing activities for 2004, and 2002. Year to year variances depend upon the amount and 2003 and 2002 were as follows:

type of construction activities, which can be influenced by storm and other damage. (in millions) 2004 2003 2002 Net proceeds from long-term The Utility's cash flows from investing activities for 2004, Adebtissued S 7,742 $ - $ -

2003 and 2002 were as follows:

Net proceeds under credit facilities and short-term borrowings 300 - -

(in millions) 2004 2003 2002 Rate reduction bonds matured (290) (290) (290)

Capital expenditures S(1,559) S(1,698) $(1,546) Long-term debt, matured, redeemed or Net proceeds from sale of assets 35 49 11 repurchased (8,402) (281) (333)

Increase in restricted cash (1,710) - -

Preferred dividends paid (90) - -

Other investing activities, net (178) (114) 26 Preferred stock redeemed (15) - -

Net cash used by investing Net cash used by financing activities $ (755) $ (571) $ (623) activities S(3,412) $(1,763) $(1,509) 48

In 2004, net cash used by financing activities increased by PG&E Funding, LLC pays the principal and interest on the approximately $184 million as compared to 2003. This was rate reduction bonds from a specific rate element in Utility cus-mainly due to the following factors: tomers' bills. See Note 4 of the Notes to the Consolidated Financial Statements for further discussion. The Utility remits In March 2004 the Utility consummated a public offering of the collection of these billings to PG&E Funding, LLC on a

$6.7 billion in First Mortgage Bonds. On the Effective Date, daily basis.

the Utility entered into pollution control bond bridge loans in the amount of $454 million and borrowed $350 million under PG&E CORPORATION the accounts receivable financing facility. In June 2004, the Utility entered into four separate loan agreements with the As of December 31, 2004, PG&E Corporation had stand-alone California Pollution Control Financing Authority, which issued cash and cash equivalents of approximately $189 million.

$345 million aggregate principal amount of its Pollution Con- PG&E Corporation's sources of funds are dividends and share trol Refunding Revenue Bonds. See Note 3 of the Notes to the repurchases from the Utility, issuance of its common stock and Consolidated Financial Statements for further discussion; external financing. The Utility did not pay any dividends to, nor repurchase shares from, PG&E Corporation during 2004,

• Partially offsetting these proceeds are issuance costs of 2003, or 2002.

approximately $107 million associated with the $6.7 billion in First Mortgage Bonds, working capital facilities, bridge loans Operating Activities and other exit financing activities; PG&E Corporation's consolidated cash flows from operating

• In November 2004, the Utility borrowed $300 million under activities consist mainly of billings to the Utility for services its $850 million credit facility; the $300 million was repaid on rendered and payments for employee compensation and goods February 11, 2005; and services provided by others to PG&E Corporation. PG&E

• Approximately $290 million of rate reduction bonds matured Corporation also incurs interest costs associated with its debt.

during 2004; PG&E Corporation's consolidated cash flows from operating

• The amount of long-term debt, matured, redeemed or repur- activities for 2004, 2003 and 2002 were as follows:

chased includes $310 million paid in Aarch 2004 upon (in millions) 2004 2003 2002 maturity of secured debt, $6.9 billion of long-term debt paid on the Effective Date, $350 million borrowed on the Effective Net income (loss) $4,504 S 420 $ (874)

Date under the accounts receivable financing facility and Gain on disposal of NEGT (net of income taxes ofS374 million) (684) - -

repaid in May 2004, and $345 million of pollution control Loss from discontinued operations - 365 2,536 bond-related bridge loans that were repaid in June 2004; Cumulative effect of changes in accounting principles - 6 61

• In October 2004, $500 million of Floating Rate First Mort-gage Bonds were redeemed; Neet income from continuing operations 3,820 791 1,723 Non-cash (income) expenses:

• Approximately $90 million of preferred stock dividends were Depreciation, amortization and paid during 2004; and decommissioning 1,497 1,222 1,196 Deferred income taxes and tax

• Approximately $15 million of preferred stock with mandatory credits-net 611 190 (281) redemption provisions was redeemed during 2004. Recognition of regulatory asset, net of tax (2,904)

In 2003, net cash used by financing activities decreased by Other deferred charges and approximately $52 million compared to 2002. With bankruptcy noncurrent liabilities (519) 857 921 court approval, the Utility repaid approximately $281 million in Loss from retirement of long-principal on its mortgage bonds that matured in August 2003, term debt 65 89 153 Gain of sale of assets (19) (29) -

which was a decrease of approximately $52 million from 2002.

Tax benefit from employee stock plans 41 - -

PG&E Funding, LLC, a wholly owned subsidiary of the Other changes in operating assets and liabilities: (242) (618) (2,898)

Utility, also repaid approximately $290 million in principal on its rate reduction bonds in 2003 and 2002. PG&E Funding, Net cash provided by LLC was not included in the Utility's Chapter 11 proceeding. operating activities S2,350 $ 2,502 $ 814 49

In 2004 the net cash provided by operating activities PG&E Corporation's cash flows from financing activities for decreased by $152 million, compared to 2003 due to 2004 pay- 2004, 2003 and 2002 were as follows:

ments totaling approximately $85 million for PG&E Corporation's senior executive retention program and $30 (in millions) 2004 2003 2002 million pursuant to a settlement of certain tax-related litigation Net borrowings under credit facilities between PG&E Corporation and NEGT. There were no simi- and short-term borrowings $ 300 $ - $ -

lar payments in the prior year. Net proceeds from long-term debt issued 7,742 581 847 Long-term debt matured, redeemed In 2003, PG&E Corporation's consolidated cash flows pro- or repurchased (9,054) (1,068) (1,241) vided by operating activities increased by approximately $1.7 Rate reduction bonds matured (290) (290) (290) billion compared to 2002, mainly due to an increase in the Util- Preferred stock with mandatory ity's net cash provided from operating activities, partially offset by redemption provisions redeemed (15) - -

Common stock issued 162 166 217 a decrease in net cash provided from NEGT's operating activities Common stock repurchased (378) - -

as a result of realized losses generated through July 7, 2003. Preferred dividends paid (90) - -

Other, net (1) (4) -

Investing Activities Net cash used by financing activities S(1,624) $ (615) $(467)

PG&E Corporation, on a stand-alone basis, did not have any material investing activities in the years ended December 31,'

2004, 2003 and 2002. In 2004, PG&E Corporation's consolidated net cash used by financing activities increased by approximately $1,009 million, Financing Activities compared to 2003. The increase is primarily due to the PG&E Corporation's cash flows from financing activities con- November 15, 2004 redemption of PG&E Corporation's Senior sist mainly of cash generated from debt refinancing and the Secured Notes for which PG&E Corporation paid approxi-issuance of common stock mately $664.5 million which included a redemption premium of approximately $50.7 million and $13.8 million of interest accrued since the last interest payment date. During November and December of 2004, PG&E Corporation repur-chased 10,783,200 shares of PG&E Corporation common stock at a cost of approximately $350 million and 850,000 shares repurchased through Elm Power Corporation, PG&E Corpora-tion's subsidiary, at a value of $28 million.

- In 2003, net cash used by financing activities increased by

$148 million compared to 2002 mainly due to a decrease in common stock issued for 401(k) plan stock purchases and stock option and warrant exercises and a decrease in net proceeds from

'long-term debt issued. In 2002, PG&E Corporation refinanced a credit facility, which was further amended to increase the size of the facility in October 2002 to a total of $720 million. In addition, in June 2002, PG&E Corporation issued $280 million of Convertible Subordinated Notes. In July 2003, PG&E Cor-poration issued $600 million of Senior Secured Notes.

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CONTRACTUAL COMMITMENTS The following table provides information about the Utility's and arrangements (such as long-term debt, preferred stock and cer-PG&E Corporation's contractual obligations and commitments tain forms of regulatory financing), purchases of transportation at December 3 1, 2004. PG&E Corporation and the Utility capacity, natural gas and electricity to support customer demand enter into contractual obligations in connection with business and the purchase of fuel and transportation to support the activities. These obligations primarily relate to financing Utility's generation activities.

Payment due by period Less than Alore than (in millions) Total One Year 1-3 years 3-5 Years 5 years Contractual Commitments:

Utility Purchase obligations:

Power purchase agreements">:

Qualifying facilities S18,733 $1,566 $3,144 $2,899 $11,124 Irrigation district and water agencies 573 77 113 114 269 Other power purchase agreements 295 94 140 39 22 Natural gas supply and transportation 960 829 131 Nuclear fuel 290 46 109 82 53 Preferred dividends and redemption requirements(2' 165 15 83 67 Employee benefits:

Pension3' 40 20 20 Postretirement benefits other than pension") 130 65 65 Other commitments'4) 132 109 21 2 Operating leases 73 14 27 18 14 21,391 2,835 3,853 3,221 11,482 Long-term debt's): , r Fixed rate obligations 11,831 295 929 1,155 9,452 Variable rate obligations 2,257 805 1,452 Other long-term liabilities reflected on the Utility's balance sheet under GAAP:

Rate reduction bonds 870 290 580 Capital lease 10 2 4 4 -

PG&E Corporation Purchase obligations:

Purchase agreements-natural gas supply 5 ) 176 - 2 22 152 Long-term debt(s:

Convertible subordinated notes 426 27 53 53 293 Other long-term debt 1 Operating leases 19 3 6 5 5 (1' This table does not include DWVR allocated contracts because the DWR is currently legally and financially responsible for these contracts or pay-ments the Utility could be required to pay the ISO under the terms of a transmission control agreement which is discussed below.

(2) Preferred dividend and redemption requirement estimates beyond 5 years do not include non-redeemable preferred stock dividend payments as these continue in perpetuity. -

(3) Contribution estimates include amounts required to fund a voluntary retirement program of approximately $20 million annually in 2005 and 2006.

PG&E Corporation's and the Utility's funding policy is to contribute tax deductible amounts, consistent with applicable regulatory decisions (induding the 2003 GRC), sufficient to meet minimum funding requirements. Contribution estimates after 2006 will be driven by GRC decisions.

(4) Includes commitments for capital infusion agreements for limited partnership interests in the aggregate amount of approximately $11 million, con-tracts to retrofit generation equipment at the Utility's facilities in the aggregate amount of approximately $38 million, load-control and self-generation CPUC initiatives in the aggregate amount of approximately $73 million, contracts for local and long-distance telecommunications in the aggregate amount of approximately $10 million and capital expenditures for which the Utility has contractual obligations or firm commitments.

(5) Includes interest payments over life of debt. See Note 3 of the Notes to the Consolidated Financial Statements for further discussion.

(6) See Note 12 of the Notes to the Consolidated Financial Statements for further discussion of assigned natural gas capacity contracts.

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Contractual Commitments ity sources, approximately 20% of the Utility's 2003 electricity sources, and approximately 25% of the Utility's 2002 electricity UTILITY sources. No single qualifying facility accounted for more than The Utility's contractual commitments include power purchase 5% of the Utility's 2004, 2003 or 2002 electricity sources.

agreements (including agreements with qualifying facilities, irriga- There are proceedings pending at the CPUC that may tion districts and water agencies and renewable energy providers), impact both the amount of payments to qualifying facilities and natural gas supply and transportation agreements, nuclear fuel the number of qualifying facilities holding power purchase agreements, operating leases and other commitments. agreements with the Utility. The CPUC will address whether certain payments for short-term power deliveries required by Power Pu'rchase Agreements the power purchase agreements comply with the pricing Qualifying FacilityPower PurchaseAgreements -The Utility is requirements of the PURPA. The CPUC is also considering required by CPUC decisions to purchase energy and capacity whether to require the California investor-owned electric utili-from independent power producers that are qualifying facilities ties to enter into new power purchase agreements with existing under the Public Utility Regulatory Policies Act of 1978, or qualifying facilities with expiring power purchase agreements PURPA. To implement PURPA, the CPUC required California and with newly-constructed qualifying facilities. PG&E Corpo-investor-owned electric utilities to enter into long-term power ration and the Utility are unable to estimate the outcome of purchase agreements with qualifying facilities and approved the these proceedings.

applicable terms, conditions, prices and eligibility requirements.

In a proceeding pending at the CPUC, the Utility has These agreements require the Utility to pay for energy and requested refunds in excess of $500 million for overpayments capacity. Energy payments are based on the qualifying facility's from June 2000 through Alarch 2001 that were made to qualify-actual electrical output and CPUC-approved energy prices, ing facilities pursuant to CPUC orders at approved rates. The while capacity payments are based on the qualifying facility's net after-tax amount of any qualifying facilities refunds, which total available capacity and contractual capacity commitment.

the Utility actually realizes in cash, claim offsets or other cred-Capacity payments may be adjusted if the qualifying facility fails its, would be credited to customers, either as a reduction to the to meet or exceeds performance requirements specified in the principal amount of the second series of ERBs anticipated to be applicable power purchase agreement.

issued in November 2005, or if refunds are received after the As of December 31, 2004, the Utility had agreements with second series of ERBs is issued, as a credit to the balancing 300 qualifying facilities for approximately 4,300 megawatts, or account that tracks recovery of the customer costs and benefits M\IN, that are in operation. Agreements for approximately 3,950 related to the ERBs. PG&E Corporation and the Utility are AIXV expire at various dates between 2005 and 2028. Qualifying unable to estimate the outcome of this proceeding.

facility power purchase agreements for approximately 350 ?,"Nr IrrigationDistrictsand WaterAgencies -The Utility has con-have no specific expiration dates and will terminate only when tracts with various irrigation districts and water agencies to the owner of the qualifying facility exercises its termination purchase hydroelectric power. Under these contracts, the Util-option. The Utility also has power purchase agreements with ity must make specified semi-annual minimum payments based approximately 50 inoperative qualifying facilities. The total of.

on the irrigation districts' and water agencies' debt service approximately 4,300 MW consists of approximately 2,600 MW requirements, regardless if any hydroelectric power is supplied, from cogeneration projects, 700 AMWV from wind projects and

-and variable payments for operation and maintenance costs 1,000 IMWIr from projects with other fuel sources, including bio-incurred by the suppliers. These contracts expire on various mass, waste-to-energy, geothermal, solar and hydroelectric.

dates from 2005 to 203 1. The Utility's irrigation district and OnJanuary 22, 2004, the CPUC ordered the California water agency contracts accounted for approximately 5% of the investor-owned electric utilities to allow owners of qualifying Utility's 2004 electricity sources, approximately 5% of the Util-facilities with certain power purchase agreements expiring ity's 2003 electricity sources and approximately 4% of the before the end of 2005 to extend these contracts for five years Utility's 2002 electricity sources.

vith modified pricing terms. As of December 31, 2004, thirteen qualifying facilities had entered into such five-year contract Other Power Purchase Agreements extensions. Qualifying facility power purchase agreements Electricity Purchasesto Satisfy the ResidualNet Open Position-accounted for approximately 23% of the Utility's 2004 electric- In 2004 the Utility continued buying electricity to meet its residual net open position. During 2004, more than 10,000 52

Gigawatt hours, or GNh, of energy was bought and sold in the contracts that will help the Utility meet its goals. The Utility wholesale market to manage the 2004 residual net open posi- also is conducting negotiations with several renewable energy tion. Most of the Utility's contracts entered into in 2004 had providers pursuant to a request for offers made by the Utility in terms of less than one year. In 2004, the Utility both submitted July 2004 that should result in the Utility entering into a num-and requested bids in competitive solicitations to meet interme- ber of new renewable contracts in 2005. In January 2005, the diate and long-term needs and anticipates procuring electricity California Senate introduced a bill proposing to require the under contracts with multi-year terms beginning in 2005. goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal bermet by 2010. The Util-Reneurable Energy Requirement - California law requires that, ity estimates that the accelerated goal would require the Utility beginning in 2003, each California retail seller of electricity, to increase the amount of its annual renewable energy pur-except for municipal utilities, must increase its purchases of chaises to approximately 800-900 GWh. Based on the medium renewable energy (such as biomass, wind, solar and geothermal load scenario in the Utility's long-term electricity procurement energy) by at least I % of its retail sales per year, the annual plan, the Utility believes that it can meet the accelerated goal.

procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail Annual Receipts and Payments - The payments made under sales by the end of 2017. The Utility was excused from meeting qualifying facility, irrigation district, water agency and bilateral its annual procurement target under the current law in 2003 agreements during 2002 through 2004 were as follows:

and 2004 due to its Chapter 11 proceeding. With its exit from Chapter 11, as of January 1, 2005, the Utility is no longer (in millions) 2004 20X)3 2002 exempt from complying with its annual procurement target. To Qualifying facility energy payments $1,002 $ 994 51,051 meet the 20% goal by the end of 2017, the Utility estimates Qualifying facility capacity payments 487 499 506 that it will need to purchase 700-800 GIN'h of electricity from Irrigation district and water renewable resources each year. During 2003 and 2004, the Util- agency payments 61 62 57 Other power purchase ity entered into several new renewable power purchase agreement payments 834 513 196 At December 31, 2004, the undiscounted future expected power purchase agreement payments were as follows:

Irrigation District &

Qualifying Facility WVater Agency Other Operations & Debt (in millions) Energy Capacity Maintenance Service Energy Capacity Total 2005 $ 1,060 $ 506 S 51 $ 26 $ 53. $ 41 $ 1,737 2006 1,082 506 31 26 39 36 1,720 2007 1,070 486 30 26 29 36 1,677 2008 1,040 476 33 26 15 9 1,599 2009 947 436 31 24 10 5 1,453 Thereafter 7,633 3,491 152 117 18 4 11,415 Total $12,832 $5,901 $328 $245 $164 $131 $19,601 Natural Gas Supply and Transportation Agreements letter of credit and a pledge of its core natural gas customer The Utility purchases natural gas directly from producers and accounts receivable. In connection with its emergence from marketers in both Canada and the United States to serve its Chapter 11, the Utility received investment grade issuer credit core customers. The contract lengths and natural gas sources of ratings from Moody's and S&P. As a result of these credit rating the Utility's portfolio of natural gas procurement contracts has upgrades, the Utility has obtained unsecured credit lines from fluctuated, generally based on market conditions. the majority of its gas supply counterparties.

During the period that the Utility was in Chapter 11, the Utility used several different credit arrangements to purchase natural gas, including a $10 million cash collateralized standby 53

At December 31, 2004, the Utility's obligations for natural Reliability Must Run Agreements gas purchases and gas transportation services were as follows: The ISO has entered into reliability must run, or RIMR, agree-ments with various power plant owners, including the Utility, (inmillions) that require designated units in certain power plants, known as 2005 $ 829 RAIR plants, to remain available to generate electricity upon the 2006 124 ISO's demand when needed for local transmission system relia-2007 7 bility. At December 31, 2004, as a party to the Transmission 2008 Control Agreement, or the TCA, the Utility estimated that it 2009 -

Thereafter could be obligated to pay the ISO approximately $570 million in costs incurred under these RMR agreements during the period Total $960 January 1, 2005 to December 31, 2006. Of this amount, the Utility estimates that it would receive approximately $42 million under its RMR agreements during the same period. These costs Payments for natural gas purchases and gas transportation and revenues are subject to applicable ratemaking mechanisms.

services amounted to approximately $1.8 billion in 2004, $1.5 billion in 2003, and $898 million in 2002. In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision addressing subsidiaries of Mirant Nuclear Fuel Agreements Corporation. The decision approved rates and a ratemaking The Utility has purchase agreements for nuclear fuel. These methodology that, if affirmed by the FERC, will require the agreements have terms ranging from two to eight years and are Mirant subsidiaries that are parties to three RMR agreements intended to ensure long-term fuel supply. Deliveries under 9 of with the ISO to refund to the ISO, and the ISO to refund to the 11 contracts in place at the end of 2003 were completed by the Utility, excess payments of approximately $360 million, 2004. New contracts for deliveries in 2005 to 2012 are under including interest, for the availability of Mirant's RMR plants negotiation. In most cases, the Utility's nuclear fuel contracts are under these agreements. On July 14, 2003, Mirant filed a peti-requirements-based. The Utility relies on large, well-established tionfor reorganization under Chapter 11 and on December 15, international producers of nuclear fuel in order to diversify its -2003, the Utility filed claims in Mfirant's Chapter 11 sources and provide security of supply. Pricing terms also are proceeding, including a claim for an RAIR refund. On Janu-diversified, ranging from fixed prices to market-based prices to ary 14, 2005, the Utility entered into a settlement with Mirant base prices that are escalated using published indices. and its subsidiaries that own RMR units that will resolve the Utility's claim through September 30, 2004. The settlement At December 31, 2004, the undiscounted obligations under agreement is subject to approval by the FERC, the bankruptcy nuclear fuel agreements were as follows: court overseeing the Chapter 11 cases filed by Mirant and these subsidiaries, and, to the extent deemed necessary by the Utility, (in millions) by the bankruptcy court that retains jurisdiction over the Util-2005 546 ity's Chapter 11 case. Under the settlement, Mirant will transfer 2006 54 to the Utility Mirant's interest in and equipment for the par-2007 55 tially built Contra Costa Unit 8 power plant. If Contra Costa 2008 50 Unit 8 is not transferred to the Utility as a result of various 2009 .32 Thereafter - 53 1contingencies described in the settlement, Mirant will pay the Utility at least $70 million in lieu of the plant assets. In addi-Total  : $290 tion, under the settlement, the Utility will enter into a contract that gives the Utility the right to dispatch power from certain RMR units owned b1y Mirant subsidiaries from 2006-2012, and Payments for nuclear fuel amounted to approximately $119 the Utility will receive approximately $60 million of allowed million in 2004, $57 million in 2003 and $70 million in 2002.

claims, credits, offsets, or cash from Mirant or its subsidiaries.

The Utility is unable to predict whether and when the FERC or the bankruptcy courts will approve the settlement. Although the settlement resolves issues concerning any refund that might be owed by Mirant, it does not address the underlying merits of the RAIR case, which will still be decided by the FERC.

54

In November 2001, after the ALJ issued the initial decision In addition, PG&E Funding, LLC must make scheduled pay-in Alirant's rate case, two complaints were filed at the FERC ments on its rate reduction bonds. The balance owed on these against other RMR plant owners, including the Utility, alleging bonds at December 31, 2004 was approximately $870 million.

that the ratemaking methodology approved in the ALJ's initial Annual principal payments on the rate reduction bonds total decision should be applied to the other RMIR agreements. The approximately $290 million. The rate reduction bonds are complainants asked the FERC to take no action until after the expected to be fully retired by the end of 2007.

FERC issues its final decision in Mirant's rate case. If the FERC A detailed description of these commitments is included in adopts the ALJ's decision in the Mirant rate case and applies the Note 3 and Note 4 of the Notes to the Consolidated ratemaking methodology to the Utility's RMIR plants, the Utility Financial Statements.

could be required to refund payments it received from the ISO for the availability of the Utility's RMNIR plants. The Utility has responded to the complaint asserting that the methodology approved in the ALJ's decision should not apply to the Utility.

CAPITAL EXPENDITURES The FERC has not yet acted on these complaints. On The Utility's investment in plant and equipment totaled approx-December 23, 2004, the Utility filed a settlement with all the imately $1.6 billion in 2004, $1.7 billion in 2003 and $1.5 complainants that, if approved by FERC, will result in the with- billion in 2002. The Utility's annual capital expenditures are drawal of the complaint with no decision by the FERC on its expected to increase to an average of approximately $2.0 billion merits. If the case is not dismissed, the Utility believes the ulti- annually over the next five years. These expenditures are neces-mate outcome of this matter will not have an adverse material sary to replace aging and obsolete equipment and accommodate effect on the Utility's results of operations or financial condition. anticipated electricity and natural gas load growth of approxi-mately 2 % and 1.2 % per year, respectively. Capital expenditures Other Commitments and Operating Leases for which contracts or firm commitments exist have, in addition The Utility has other commitments relating to operating to being included in estimated capital expenditures, been leases, capital infusion agreements, equipment replacements, included in the 'Contractual Commitments" table above, which the self-generation incentive program exchange agreements details the Utility's contractual obligations and commitments at and telecommunication contracts. At December 31, 2004, the December 31, 2004. The estimate of capital expenditures over future minimum payments related to other commitments the next five years includes the following significant capital were as follows: expenditure projects:

• New customer connections and expansion of the existing (in millions) electricity and natural gas distribution systems anticipated to 2005 $123 average approximately $400 million annually over the next 2006 i 31 five years; 2007 17 2008 14

• Replacements and upgrades to portions of the Utility's 2009 6 electricity distribution system anticipated to average approxi-Thereafter 14 mately $400 million annually over the next five years; Total $205

• Replacement of natural gas distribution pipelines expected to average approximately $70 million annually over the next Payments for other commitments amounted to approxi- five years; mately $111 million in 2004, $74 million in 2003, and $34

• Replacements and capacity expansion of the electricity trans-million in 2002. mission system expected to average approximately $400 million annually over the next five years; Financing Commitments

• Replacements and upgrades to the Utility's natural gas trans-The Utility's current commitments under financing arrange-portation facilities expected to average approximately $120 ments include obligations to repay First Mortgage Bonds, million annually over the next five years; pollution control bond-related agreements, credit facilities and reimbursement agreements associated with letters of credit.

55

• Replacements and upgrades of existing facilities at the Utility's

• Implementation of electric distribution reliability and tech-Diablo Canyon power plant, including the turbine and steam nology driven service enhancements such as advanced generator replacement projects, potential investments in a metering; and new combined cycle generation unit in Contra Costa County

• Reliability and service enhancements of the Utility's gas that may be acquired pursuant to a settlement agreement with distribution infrastructure to provide access to new natural Mlirant, and replacements, upgrades and relicensing of the gas sources.

Utility's hydroelectric generation facilities. All of these gener-ation-related projects are expected to average approximately The Utility has estimated that if these additional capital

$3 70 million annually over the next five years; and expenditures related to new generation, electric transmission and distribution and gas distribution are made, the Utility's total

• Investment in common plant, including computers, vehicles, weighted average rate base would grow by approximately 6.5%

facilities and communications equipment, expected to average over the five-year period.

approximately $200 million annually over the next five years.

The Utility retains the ability to delay or defer substantial Advanced Metering Improvements amounts of these planned expenditures in light of changing eco- The CPUC is assessing the viability of implementing an nomic conditions and changing technology. It is also possible advanced metering infrastructure for residential and small com-that these projects may be replaced by other projects. Consis-. mercial customers. This infrastructure would enable the tent with past practice, the Utility expects that any capital California investor-owned electric utilities to measure usage of expenditures will be included in its rate base and recoverable in electricity on a time-of-use basis and to charge demand respon-rates. Based on the estimate of average capital expenditures of sive rates. The goal of demand responsive rates is to encourage approximately $2.0 billion annually over the next five years, the customers to reduce energy consumption during peak demand Utility's average annual rate base would grow by approximately periods and reduce peak period procurement costs. Advanced 4.5% per year over the five-year period. meters can record usage in time intervals and be read remotely.

The Utility's residual net open position is expected to The Utility is implementing demand responsive tariffs for large increase over time. To meet this need, the Utility will need to industrial customers who already have advanced metering sys-enter into contracts with third-party generators for additional tems in place, and has just completed the second year of a supplies of electricity, develop or otherwise acquire additional statewide pilot program designed to test whether and how generation facilities or satisfy its residual net open position much residential and small commercial customers will respond through a combination of the two. The discussion above does to demand responsive rates. The Utility expects to provide not include any capital expenditures for new generation facili- information to the CPUC in the first quarter of 2005 regarding ties aside from the Contra Costa project described above. The the results of this pilot program. If the CPUC determines that discussion above also does not include any capital expenditures it would be cost-effective to install advanced metering on a necessary to implement advanced metering improvements. large-scale and authorizes the Utility to proceed with large scale development of advanced metering for residential and small The estimate of capital expenditures discussed above does commercial customers, the Utility expects that it would incur not include up to $2.0 billion in additional potential expendi- substantial costs to convert its meters, build the meter reading tures over the 2005 through 2009 period for: network, and build the data storage and processing facilities to

• New generation facilities to comply with the Utility's long- bill its customers. The Utility would expect to recover through term electricity procurement plan as approved by the CPUC. rates the capital investments and any ongoing operating costs To meet future resource needs, the Utility will need to enter associated with implementing the advanced metering improve-into contracts with third-party generators for additional sup- ments. The total deployment of an advanced metering plies of electricity, develop or otherwise acquire additional infrastructure to all of the Utility's electricity and natural gas generation facilities; customers using equipment and technology currently available may cost more than $1.0 billion, based on a five-year installa-

• Electric transmission projects to accommodate system expan- ' tion schedule starting in 2006.

sions approved by the ISO, interconnections and upgrades triggered by new generation, costs to extend the life of or replace transmission equipment; 56

OFF-BALANCE- cated that it would consider later allowances claimed by sellers SHEET ARRANGEMENTS for natural gas costs above the natural gas prices in the refund methodology. The FERC directed the ISO and the PX (which For financing and other business purposes, PG&E Corporation operates solely to reconcile remaining refund amounts owed) to and the Utility utilize certain arrangements that are not make compliance filings establishing refund amounts. The ISO reflected in their Consolidated Balance Sheets. Such has indicated that it plans to make its compliance filing during arrangements do not represent a significant part of either the first half of 2005 with the PX to follow. In October 2003, PG&E Corporation's or the Utility's activities or a significant the FERC affirmed its March 2003 decision and various parties ongoing source of financing. These arrangements are used to appealed to the Ninth Circuit. Briefs have been submitted enable PG&E Corporation or the Utility to obtain financing or concerning which power suppliers are subject to refunds, the execute commercial transactions on favorable terms. For further appropriate time period for which refunds can be ordered, and information related to letter of credit agreements, the credit which transactions are subject to refunds. These matters will be facilities, aspects of PG&E Corporation's accelerated share argued before the Ninth Circuit on April 12 and 13, 2005, and repurchase program and PG&E Corporation's guarantee related a decision is expected in the following months.

to certain NEGT indemnity obligations, see Notes 3, 6 and 12 of the Notes to the Consolidated Financial Statements. The final refunds will not be determined until the FERC Amounts due under these contracts are contingent upon terms issues a final decision in the Refund Proceeding, following the contained in these agreements and are not included in the table ISO and PX compliance filings and the resolution of the of contractual commitments above. appeals of the FERC's orders. In addition, future refunds could increase or decrease as a result of retroactive adjustments pro-posed by the ISO, which incorporate revised data provided by CONTINGENCIES the Utility and other entities.

PG&E Corporation and the Utility have significant contingen-In the FERC's separate proceedings to investigate whether cies that are discussed below and in Note 12 to the Notes to the tariff violations occurred in the period before October 2, 2000, Consolidated Financial Statements.

the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the FERC Proceedings tariffs in force at that time were violated or subject to manipula-tion. In September 2004, the Ninth Circuit found that the Various entities, including the Utility and the state of California FERC has the authority to provide refunds for tariff violations are seeking up to $8.9 billion in refunds for electricity over-involving inadequate transaction reporting for sales into the charges on behalf of California electricity purchasers for the California spot markets throughout the period before period May 2000 to June 2001 through a proceeding pending at October 2, 2000. The FERC has not yet acted on this finding the FERC. This proceeding, the Refund Proceeding, com-and it is uncertain how it will be applied by the FERC.

menced on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. OnJuly 25, 2001, the The Utility recorded approximately $1.8 billion of claims FERC held that refunds would be available for certain over- filed by various electricity generators in its Chapter 11 proceed-charges, and established a process to determine the refunds but ing as liabilities subject to compromise. This amount is subject asserted that it could not order market-wide refunds for periods to a pre-petition offset of approximately $200 million, reducing before October 2, 2000. In December 2002, a FERC ALJ the net liability recorded to approximately $1.6 billion. Under a issued an initial decision in the Refund Proceeding finding that bankruptcy court order, the aggregate allowable amount of ISO, power suppliers overcharged the utilities, the state of California PX and generator claims was limited to approximately $1.6 bil-and other buyers approximately $1.8 billion from October 2, lion. The Utility currently estimates that the claims would have 2000 to June 20, 2001, but that California buyers still owe the been reduced to approximately $1.0 billion based on the refund power suppliers approximately $3.0 billion, leaving approxi- methodology recommended in the FERC ALJ's initial decision.

mately $1.2 billion in net unpaid bills. The revised methodology adopted by the FERC's March 2003 decision could further reduce the amount by several hundred In March 2003, the FERC confirmed most of the ALJ's find-million dollars, offset by the amount of any additional fuel ings in the Refund Proceeding, but partially modified the cost allowance for suppliers.

refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indi-57

The Utility has entered into settlements with various power 2003 General Rate Case suppliers resolving the Utility's claims against these power sup-In May 2004, the CPUC issued a decision in the Utility's pliers. As discussed in Note 1 of the Notes to the Consolidated 2003 GRC. The decision approved the July 2003 and Financial Statements, as of December 31, 2004, the Utility has September 2003 settlement agreements reached among the recorded offsets to the Settlement Regulatory Asset of approxi- Utility and various consumer groups to set the Utility's 2003 mately $309 million, pre-tax ($183 million, after-tax) in base revenue requirements at approximately-connection with settlements. The final net after-tax amount of, any amounts received by the Utility under future settlements * $2.5 billion for electricity distribution operations, representing a $236 million increase over the previously authorized amount; with energy suppliers will be credited to customers, either as a reduction to the principal amount of the second series of ERBs, * $912 million for electricity generation operations, represent-anticipated to be issued in November 2005, or if refunds are : ing a $38 million increase over the previously authorized received after the second series of ERBs is issued, as a credit to

• amount; and the balancing account that tracks recovery of the customer costs

• $927 million for natural gas distribution operations, and benefits related to the ERBs. representing a $52 million increase over the previously As discussed in Note 13 of the Notes to the Consolidated authorized amount.

Financial Statements, in January 2005, the Utility and other As part of the GRC, the CPUC approved the following min-parties entered into a settlement agreement with Mirant Corpo- imum and maximum yearly adjustments to the Utility's 2003 ration and its subsidiaries, to resolve Mirant's liability for FERC base revenue requirements, or attrition adjustments, for 2004, refunds, penalties and civil liabilities arising out of the 2005, and 2006 based on the change in the CPI:

California energy crisis. The settlement agreement is subject to approval by the FERC, the bankruptcy court overseeing 2004 2005 2006 Mirant's bankruptcy proceedings, and to the extent deemed Electricity and necessary by the Utility, the bankruptcy court that retains juris- Natural Gas diction over the Utility's Chapter 11 case. Although settlement Distribution discussions with a number of other major sellers and other Minimum 2.00% 2.25% 3.00%

market participants are continuing, the Utility cannot predict Multiplier Change in CPI Change in CPI Change in CPI+1%

whether these settlement negotiations will be successful. Maximum 3.00% 3.25% 4.00%

Electricity Generation Minimum 1.50% 1.50%o 2.50%

REGULATORY MATTERS Multiplier Change in CPI Change in CPI Change in CPI+l%

Maximum 3.00% 3.00% 4.00%

This section of MD&A discusses significant regulatory issues pending before the CPUC, the FERC, or the NRC, the resolu-In addition, under the GRC decision, if the Utility forecasts tion of which may affect the Utility's and PG&E Corporation's a second refueling outage at Diablo Canyon in any one year, the results of operations or financial condition.

electricity generation revenue requirement would be increased by $32 million per refueling outage, adjusted for changes in the ELECTRICITY AND CPI in the manner described in the decision. Currently, the NATURAL GAS DISTRIBUTION only forecasted second refueling outage during the period 2004 AND ELECTRICITY GENERATION to 2006 occurred in 2004.

The Utility's primary base revenue requirement proceeding is As a result of the approval of the 2003 GRC, during the the general rate case filed with the CPUC. In the general rate second quarter of 2004, the Utility recorded various regulatory case, the CPUC authorizes the amount the Utility can collect- assets and liabilities associated with revenue requirement from customers to recover its basic business and operational increases, recovery of retained generation assets and unfunded costs for electricity and natural gas distribution and electricity. taxes, depreciation, and decommissioning. During the third generation operations. The general rate case typically sets the and fourth quarters of 2004, the Utility recorded electricity annual revenue requirement levels for a three-year rate period. and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 58

GRC. The net increase in revenue requirements and revenues voted to approve certain storm response improvement initia-related to the 2003 GRC on the Utility's 2004 results of opera- tives as well as a reliability performance incentive mechanism tions, on a pre-tax basis, is as follows: for the years 2005 through 2007. Under the performance incentive mechanism the Utility could receive up to $24 million Revenue each year depending on the extent to which the Utility exceeds requirement the reliability performance improvement targets, but could be increase Recognized Recognized required to pay a penalty of up to $24 million a year depending (in millions) 2003 2004 in 2003 in 2004 on the extent to which it fails to meet the targets. The decision Electricity revenue $273 $277 $268 $282 does not provide the Utility with additional revenues to meet Natural gas revenue 52 50 - 102 Electricity attrition - 100 - 100 the reliability standards, but does include a margin of error Natural gas attrition - 19 - 19 around the targets in order to mitigate potential penalties.

Regulatory assets, net (17) 158 - 141 PG&E Corporation and the Utility are unable to predict Total 5308 $604 $268 $644 whether or not the Utility will incur a reward or penalty related to the performance incentive mechanism.

In addition, on November 9, 2004, The Utility Reform Net-Because the Utility collected revenue subject to refund for work, a consumer group, or TURN, filed a motion in the 2003 electricity distribution and generation in 2003, but not for natu-GRC seeking an investigation into the Utility's billing and col-ral gas distribution, the impact of the 2003 GRC decision on lection practices alleging that the Utility's failure to issue timely the Utility's 2004 results of operations is different for each area.

bills and reliance on estimated billing constituted "billing For electricity distribution and generation, the Utility col- errors". under the Utility's tariffs. In the case of "billing errors,"

lected electricity revenue and surcharges subject to refund the Utility is prohibited under its tariffs from billing customers under the frozen rate structure in 2003. The amount of elec- for more than three months usage. The Utility responded to tricity revenue to be refunded in 2003 incorporated the impact TURN's motion on December 30, 2004. On January 13, 2005, of the electric portion of the GRC settlement, therefore this the CPUC adopted a resolution approving tariff changes stating was recognized in net income in 2003. In 2004, the Utility that "billing error" includes failure to issue a bill and issuance of recorded its electricity distribution and generation base revenue an estimated bill, under certain circumstances. The resolution requirements under a cost-of-service ratemaking structure. stated that the tariff changes approved by the resolution "are Because the 2003 refund obligation already incorporated the consistent with existing CPUC policy, tariffs, and require-impact of the GRC that related to fiscal 2003, the Utility ments." On February 17, 2005, the Utility filed an application recorded the increase related to 2004 in its 2004 results of oper- for rehearing of this resolution with the CPUC on the basis ations of approximately $382 million, including attrition. that the resolution's characterization of the revised "billing error" definition as consistent with "existing CPUC policy, tar-For natural gas distribution, since the CPUC issued a final iffs, and requirements," is contrary to both the plain language decision on the Utility's 2003 GRC in 2004, the Utility of the Utility's prior tariffs and the CPUC's own policies and recorded both the 2003 revenue requirement increase and the requirements interpreting the Utility's prior tariffs. Although 2004 revenue requirement increase in its 2004 results of opera-PG&E Corporation and the Utility are unable to predict tions of approximately $121 million, including attrition.

whether TURN's motion for an investigation will be granted, In addition, as a result of the GRC decision, the Utility has PG&E Corporation and the Utility believe that the ultimate recorded various regulatory assets and liabilities associated with outcome of this matter will not have a material adverse effect the recovery of retained generation assets, unfunded taxes, on PG&E Corporation's or the Utility's results of operations or depreciation, and decommissioning. The net impact of these financial condition.

items resulted in after-tax earnings of approximately $84 million recorded in the Utility's 2004 results of operations. These assets 2007 General Rate Case and liabilities are reflected in the Utility's current rates and will The Utility's next GRC will be the 2007 GRC. The 2007 GRC be amortized over their respective collection periods. will set the base revenue requirements for the years 2007.

Another phase of the GRC was established to address the through 2009. The Utility plans to file its application for the Utility's response to the December 2002 storm and the Util- 2007 GRC with the CPUC during the fourth quarter of 2005 ity's reliability performance. In October 2004, the CPUC 59

with a final decision expected from the CPUC by the end of December 2004, the CPUC issued a final decision approving a 2006. PG&E Corporation and the Utility are unable to predict return on common equity, or ROE, for the Utility of 11.22%

what amount of revenue requirements the CPUC will authorize for 2004 and 2005, which is consistent with the Settlement Agree-for the 2007 through 2009 period, when a final decision in this ment. The Settlement Agreement provides that from January 1, proceeding will be received, or the impact it will have on their 2004 until certain credit ratings are achieved, the Utility's author-financial condition or results of operations. ized ROE will be no less than 11.22 % per year. The Settlement Agreement also provides that the authorized equity ratio of the Cost of CapitaI Proceedings Utility's capital structure for ratemaking purposes will not be The CPUC determines the rate of return that the Utility may less than 52%, except that for 2004 and 2005 it may not be less earn on its electricity and natural gas distribution, natural gas than 48.6%. The decision authorizes the following cost of transmission and storage, and electricity generation assets. In capital for 2004 and 2005:

2004 2005 Capital Weighted Capital Weighted Cost Structure Cost Cost Structure Cost Long-term debt 5.90% 48.2% 2.84% 6.10% 45.5% 2.78%

Preferred stock 6.76% - 2.8% 0.19% 6.42% 2.5% 0.16%

Common equity 11.22% 49.0% 5.50% 11.22% 52.0% 5.83%

Return on rate base 8.53% 1 8.77%

The Utility's annual revenue requirement for 2004 decreased semi-annually and adjust retail electricity rates or order refunds, by approximately $105 million compared to the CPUC last as appropriate, when the forecast aggregate over-collections or authorized revenue requirement, as a result of interest savings under-collections exceed 5% of the utility's prior year electricity associated with the Utility's Chapter 11 exit financing. This procurement revenues, excluding amounts collected for the decision did not have an impact on the Utility's financial results DIR. The Utility's ERRA trigger threshold for 2004 is $191 for 2004 because the Utility has adjusted its operating revenues million. As of December 31, 2004, the ERRA had an under-for the difference between its last authorized rate of return on collected balance of approximately $75 million, which is below rate base of 9.24% in 2003 and the lower rate of return on rate the 5% trigger for mandatory adjustment of rates. The CPUC base of 8.53% in 2004 that has now been approved. approved an ERRA revenue requirement of $2.189 billion for 2004. In its 2005 ERRA application filed in June 2004, the Util-Electricity Generation Resources ity requested a forecast revenue requirement of $2.140 billion California legislation has been. enacted which allows the Utility and the authority to amortize routine over and under-collections to recover its reasonably incurred wholesale electricity procure- in the ERRA annually to coincide with January 1 rate changes.

ment costs and includes a mandatory rate adjustment provision In December, 2004, the CPUC approved the Utility's Annual that requires the CPUC to adjust rates on a timely basis to Electric True-up filing, under which the under-collections and ensure that the Utility recovers its costs. over-collections in the Utility's electric-related balancing accounts, including the under-collection in the ERRA, are Procurement Cost BalancingAccount authorized to be recovered in the Utility's 2005 electric rates. A and AMandatozy Rate Adjustments final decision on the 2005 ERRA application is expected in the Effective January 1, 2003, as authorized by California law, the first quarter of 2005.

Utility established a balancing account, the Energy Resource The CPUC performs periodic compliance reviews of the Recovery Account, or ERRA, designed to track and allow procurement activities recorded in ERRA to ensure that the recovery of the difference between the authorized revenue Utility's procurement activities are in compliance with its requirement and actual costs incurred under the Utility's approved procurement plan. If the CPUC determines that the authorized procurement plans, excluding the costs associated Utility's procurement activities were not in compliance with its with the DWR allocated contracts and certain other items. The approved procurement plan, some of the Utility's procurement CPUC must review the revenues and costs associated with an costs could be disallowed. Procurement activities related to investor-owned utility's electricity procurement plan at least DINWR allocated contracts could be disallowed up to a maximum of two times the Utility's administration costs associated with 60

procurement, or $36 million for 2004. The Utility and the CPUC requires the utilities to use an independent evaluator to CPUC's Office of Ratepayer Advocates, or the ORA, have review the RFO process. Before the CPUC decision was issued, agreed that there should be no disallow ances in the Utility's the CPUC had approved the Utility's solicitation of offers for ERRA proceeding reviewing procurement activities during the utility-owned generation development and for generation to be period from January 1, 2003 through December 31, 2003, and provided under long-term power. purchase agreements for have jointly recommended that the CPUC close the record approximately 1,200 M1V of peaking resources by 2008 and an period. PG&E Corporation and the Utility are unable to pre- additional 1,000 AMW of load-following resources by 2010. The dict whether a disallowance will result or the size of any Utility issued two RFOs in November 2004 for these resources.

potential disallowance. In addition, it is uncertain whether the .In order to incorporate elements of the CPUC's Decem-CPUC will modify or eliminate the maximum disallowance for ber 2004 decision, the Utility notified bidders on January 7, future years. 2005 that it was deferring its RFOs to evaluate how to incorpo-rate new RFO requirements adopted by the CPUC. The Utility New Long-Termi Generation Resource Commitments expects to issue updated RFOs in March 2005 and request ini-As discussed in the "Overview" section above, in December 2004, tial bids to be submitted in April 2005. It is anticipated that the CPUC issued a final decision which approved, with certain contracts for the winning bidders would be submitted to the modifications, each investor-owned electric utility's LTPP in CPUC for approval in the second half of 2005. Completed order to authorize each utility to plan for and procure the projects could result in rate base additions in 2008.

resources necessary to provide reliable service to their customers To help assure recovery of the Utility's cost of new long-for the ten-year period 2005-2014. The decision recognizes that term resource commitments, the CPUC adopted a each utility will have capacity needs over the ten-year period, non-bypassable charge to be collected from all customers on especially in 2011 when most of the electricity purchase contracts whose behalf the Utility makes these new commitments, includ-entered into by the DWR expire. In January 2005, several parties ing those who subsequently receive generation from other submitted applications for rehearing of the December 2004 load-serving entities.

CPUC decision. The Utility is unable to predict how or when the CPUC will respond to those applications. In addition, in its decision approving the LTPP, the CPUC recognized that credit rating agencies will consider obligations

- In the LTPP filing the Utility assumed, under a medium under long-term procurement contracts to have debt-like char-load scenario, that:

acteristics that will adversely affect the Utility's credit ratios,

• By 2014, its procurement responsibility would be reduced by which may, in turn, adversely affect the resulting credit ratings.

approximately 4,000 megawatts, or MWV; and The CPUC has agreed that it will consider the debt equiva-lence impact of procurement contracts on credit ratings in

• Power plants currently providing 2,000 MW of generation to future cost of capital proceedings. The Utility is required to the Utility would retire within the next five or six years.

employ S&P's method for assessing the debt equivalence of In addition, the LTPP reflects that all California investor-

• power purchase agreements when evaluating bids in an all-owned electric utilities are required to achieve an electricity source solicitation, except that the debt equivalence factor planning reserve margin of 15% to 17% in excess of peak should be 20% instead of 30%. As the Utility enters into con-capacity electricity requirements byJune 1, 2006. tracts with counterparties, the Utility will be exposed to the risk that counterparties will fail to perform and associated business The CPUC may require the Utility, or the Utility may elect, credit risks.

to satisfy all or a part of the resources necessary to meet their customers' energy needs by developing or acquiring additional The CPUC also determined that for utility-owned genera-generation facilities or by entering into long-term power pur- tion resources, the utilities are prohibited from recovering chase agreements. The December 2004 CPUC decision initial capital costs in excess of their final bid price. If final proj-requires the utilities to solicit bids from providers of all poten- ect costs are less than the final bid price, the savings would be tial sources of new generation (e.g., conventional or renewable shared with customers, while any cost overruns would be resources to be provided under utility owned projects or. absorbed by the utilities. Costs of future plant additions and turnkey developments, or buyouts, or under third party power annual operating and maintenance costs and similar costs purchase agreements) through a single, open, transparent and incurred by a utility would be eligible for cost-of service competitive request for offers, or RFO, process, although a util- ratemaking treatment.

ity can tailor a RFO to meet specific resource needs. The 61

If the Utility is not able to recover a material part of the cost procurement recovery mechanism described below, the collec-of developing or acquiring additional generation facilities in tion of DIN'R revenue requirements, or any adjustments thereto, rates in a timely manner, PG&E Corporation's and the Utility's should not affect the Utility's results of operations.

financial condition and results of operations would be materially Electric Restructuring Costs Account Application adversely affected.

On April 16, 2004, the Utility filed an updated Electric Renewable Energy Restructuring Costs Account application for recovery of distri-California law requires that, beginning in 2003, each California bution related electric industry restructuring related revenue retail seller of electricity, except for municipal utilities, must requirements totaling $117 million for the period 1999 through increase its purchases of renewable energy (such as biomass, 2002. The Utility requested that the $117 million revenue wind, solar and geothermal energy) by at least 1% of its retail requirement increase become effective January 1, 2005, and be sales per year, the annual procurement target, so that the recovered through future rates charged to customers. Revenue amount of electricity purchased from renewable resources requirements associated with these ongoing activities in 2003 equals at least 20% of its total retail sales by the end of 2017. In and afterwards are included in the 2003 GRC.

January 2005, the California Senate introduced a bill proposing On December 2, 2004, the CPUC adopted a proposed set-to require the goal to be met by the end of 2010 instead of tlement agreement to resolve issues in this proceeding filed by 2017. The CPUC also has suggested that the 20% goal be met the Utility, ORA, Aglet Consumer Alliance, and TURNT. Under by 2010. The Utility estimates that the accelerated goal would the settlement agreement, the Utility is authorized to collect require the Utility to increase the amount of its annual renew- $80 million in revenue requirements to recover the distribution able energy purchases to approximately 800-900 GXlh. Based related electric industry restructuring costs through rates on the medium load scenario in the Utility's long-term electric- charged to certain of the Utility's customers beginning ity procurement plan, the Utility believes that it can meet the January 1, 2005. Additionally, beginningJanuary 1, 2007, the accelerated goal. Utility is required to remove from rate base all remaining net D"R Allocated Contracts plant in service associated with the Utility's capital plant at issue in this application, projected to be approximately $30 million at The Utility acts as a billing agent for the collection of the the end of 2006. During the fourth quarter of 2004, the Utility DWR's revenue requirements from the Utility's customers. The recorded a net pre-tax regulatory asset of approximately $50 DIVR's revenue requirements consist of a power charge to pay million, resulting in an increase of approximately $30 million in for the DWVR's costs of purchasing electricity under its contracts after-tax net income.

and a bond charge to pay for the DWR's costs associated with its

$11.3 billion bond offering completed in November 2002. In FERC Transmission Rate Cases December 2004, the CPUC issued a decision on the permanent The Utility's electric transmission revenues and wholesale and cost allocation methodology for the DWR's power charge rev- retail transmission rates are subject to authorization by the enue requirements in 2004 and subsequent years, am6ng the FERC. InJanuary and October 2003, the Utility filed applica-three California investor-owned electric utilities. The Utility's tions with the FERC requesting authority to recover its annual customers' share of 2004 DWR power charge revenue require- electricity transmission retail revenue requirements for 2003 ment is approximately $1.7 billion after consideration of the and 2004. During the third quarter of 2004, the FERC issued DAVR power charge adjustment to implement this decision. The final orders on these applications, which did not have a material Utility's customers' share of 2004 DWVR bond charge revenue impact on the Utility's 2004 results of operations. The current requirement is approximately $369 million. InJanuary 2005, the approved rates will remain in effect until the Utility's next rate CPUC granted limited rehearing of its permanent cost alloca- application. The Utility expects to file its next transmission tion decision to address how to calculate the above-market costs owner rate case requesting approval of 2006 retail electric trans-of the DWR power contracts. A final decision on DWR perma- mission revenue requirements in August 2005.

nent cost allocation is expected in the first quarter of 2005. The Diablo Canyon Steam Generator Replacement Projects Utility cannot predict the final outcome of this matter. As a result of the transition from frozen rates and the electricity The Utility established a steam generated replacement project

'to replace turbines and steam generators and other equipment

- at the two nuclear operating units at the Diablo Canyon nuclear 62

power plant. The Utility plans to replace Unit 2's steam genera- Spent Nuclear Fuel Storage Proceedings tors in 2008 and replace Unit l's steam generators in 2009. Under the Nuclear Waste Policy Act of 1982, the Department Because the fabrication of new steam generators requires a long of Energy, or the DOE, is responsible for the permanent stor-lead-time, in August 2004 the Utility entered into contracts age and disposal of spent nuclear fuel. The Utility has signed a with Westinghouse Electric Company LLC, or Westinghouse, contract with the DOE to provide for the disposal of spent for the design, fabrication and delivery of eight steam genera- nuclear fuel and high-level radioactive waste from the Utility's tors. Under the contracts, the Utility must pay Westinghouse nuclear power facilities. Under the Utility's contract with the for all work done and pro-rated profit up to the time the con- DOE, if the DOE completes a storage facility by 2010, the ear-tracts are completed or cancelled. The contracts require liest that Diablo Canyon's spent fuel would be accepted for progress payments in line with actual expenditures for materials storage or disposal would be 2018. At the projected level of and work completed over the life of the contracts. The Utility is operation for Diablo Canyon, the Utility's current facilities are currently in negotiation for an installation contract for the new able to store on-site all spent fuel produced through approxi-steam generators. The negotiation is expected to be completed mately 2007. The NRC granted authorization in March 2004 by the end of February 2005. On January 25, 2005, a CPUC to build an on-site dry cask storage facility to store spent fuel administrative law judge issued a proposed decision that would through approximately 2021 for Unit l and to 2024 for Unit 2.

find the steam generator replacement project to be cost-effec- However, several intervenors in that proceeding filed an appeal tive and would authorize the Utility to recover the projected of the NRC's decision with the U.S. Court of Appeals for the

$706 million capital cost of the project in rates with no after- Ninth Circuit, or Ninth Circuit. Oral arguments on that appeal the-fact reasonableness review if the total costs do not exceed are expected in the first quarter of 2005 with a decision antici-

$706 million, and established a maximum project cost of $815 pated in the second half of 2005. Construction of the on-site million. If the project costs exceed $706 million, or if the dry cask storage facility is expected to start in the second quar-CPUC has reason to believe that the costs may be unreasonable ter of 2005 after grading permits are obtained from the County regardless of the amount, the CPUC may conduct a reasonable- of San Luis Obispo. To provide another storage alternative in ness review of all costs. The proposed decision recommends the event construction of the dry cask storage facility is delayed, that the Utility would be allowed to recover the revenue the Utility has also requested that the NRC approve another requirements related to the project in rates beginning on storage option to install a temporary storage rack in each unit's January 1 of the year following the commencement of commer- existing spent fuel storage pool that would increase the on-site cial operations of each unit. The CPUC may act on the storage capability to permit the Utility to operate Unit I until proposed decision at its meeting to be held on February 25, 2005. 2010 and Unit 2 until 2011. If the Utility is unsuccessful in per-Assuming the CPUC approves the proposed decision, the Util- mitting and constructing the on-site dry cask storage facility, ity would make the capital expenditures required to maintain a and is otherwise unable to increase its on-site storage capacity, 2008/2009 implementation schedule. It is expected that the it is possible that the operation of Diablo Canyon may have to CPUC will issue a final decision on whether to approve the be curtailed or halted as early as 2007 and until such time as project in September 2005, after considering the environmental additional spent fuel can be safely stored.

impact review for the project. Expenditures on the project of approximately $25 million are expected to be incurred through Annual Earnings Assessment Proceeding for Energy February 2005 when the CPUC's decision on cost effectiveness Efficiency Program Activities and Public Purpose Programs is expected and these are expected to grow to approximately $70 In May 2004, 2003, 2002, 2001, and 2000, the Utility filed its million in September 2005 when the CPUC's final decision annual applications with the CPUC claiming incentives totaling approving the project is expected. If the CPUC approves the approximately $110 million for past energy efficiency and pub-project, the Utility estimates it would spend an additional $10 lic purpose program activities. These applications remain million in the last quarter of 2005. If the CPUC does not subject to verification and approval by the CPUC. PG&E Cor-approve the projects, then the Utility will terminate the con-poration and the Utility are unable to predict the ultimate tracts and seek to recover the project costs that it incurred outcome of this proceeding.

before termination from customers through the abandoned project process.

63

NATURAL GAS SUPPLY operational balancing agreements to connect all new upstream AND TRANSPORTATION gas pipelines that interconnect with the pipeline systems of San Diego Gas and Electric and Southern California Gas Company.

In December 2004, the CPUC issued a final decision approving the Gas Accord III Settlement Agreement that sets the Utility's gas transmission and storage rates and market structure for a RISK MANAGEMENT ACTIVITIES three-year term, commencingJanuary 1, 2005. The decision extends the terms of a settlement agreement originally reached The Utility and PG&E Corporation, mainly through its owner-in 1997 called the Gas Accord. The CPUC has approved previ- ship of the Utility, are exposed to market risk, which is the risk ous extensions of the Gas Accord. Under the terms of the that changes in market conditions will adversely affect net recent decision, the Utility's revenue requirement has been set income or cash flows. PG&E Corporation and the Utility face at $427.4 million for 2005, $435.5 million for 2006, and $443.7 market risk associated with their operations, financing arrange-million for 2007. This is compared to an authorized revenue ments, the marketplace for electricity, natural gas, electricity requirement for 2004 of $416.9 million, adjusted for the transmussion, natural gas transportation and storage, other goods CPUC's final decision in the cost of capital proceeding as dis- and services, and other aspects of their business. PG&E Corpo-cussed above. Under the Gas Accord, the Utility's gas ration and the Utility categorize market risks as price risk, transmission and storage facilities are operated on an open- interest rate risk and credit risk. The Utility actively manages access basis, thus allowing all eligible shippers to subscribe to market risks through risk management programs that are gas transmission and storage services. In addition, the Utility designed to support business objectives, reduce costs, discourage assumes risk of not recovering its full natural gas transportation unauthorized risk-taking, reduce earnings volatility and manage and storage costs since the Utility does not have a balancing cash flows. The Utility uses derivative instruments only for non-account for over-collections or under-collections of natural gas trading purposes (i.e., risk mitigation) and not for speculative transportation or storage revenues. purposes. The Utility's risk management activities include the use of energy and financial instruments, including forward The original Gas Accord market structure included an contracts, futures, swaps, options, and other instruments and incentive mechanism for recovery of core procurement costs, or agreements, most of which are accounted for as derivative the CPIM, which is used to determine the reasonableness of the instruments. Some contracts are accounted for as leases.

Utility's costs of purchasing natural gas for its customers. Under the CPIJI, costs that fall within a market-based tolerance band, The Utility estimates fair value of derivative instruments which is currently 99% to 102% of the benchmark, are using the midpoint of quoted bid and asked forward prices, considered reasonable and fully recoverable in customers' rates. including quotes from customers, brokers, electronic exchanges One-half of the costs above 102% of the benchmark are recov- and public indices, supplemented by online price information erable in the Utility's customers' rates, and the Utility's from news services. 'When market data is not available, the customers receive three-fourths of the savings when the costs Utility uses models to estimate fair value.

are below 99% of the benchmark.

PRICE RISK In 2004, the CPUC ordered the Utility and other California natural gas utilities to submit proposals addressing how Califor-Convertible Subordinated Notes nia's long-term natural gas needs should be met through contracts with interstate pipelines, new liquefied natural gas PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Subordinated Notes that are scheduled to facilities, storage facilities and in-state production of natural mature onJune 30, 2010. These Convertible Subordinated gas. Proposals w ere submitted in February 2004. The CPUC Notes may be converted (at the option of the holder) at any issued a decision in September 2004, which authorizes the utili-time prior to maturity into 18,558,655 shares of common stock ties to expand their portfolios to access gas from multiple gas of PG&E Corporation, at a conversion price of $15.09 per producing basins, to negotiate reduced capacity, and to termi- ,

share. The conversion price is subject to adjustment should a nate expiring contracts. The decision also established a significant change occur in the number of PG&E Corporation's pre-approval process for utility interstate and Canadian pipeline outstanding common shares. To date, the conversion price has capacity contracts. The second phase of this proceeding will not required adjustment. In addition, the terms of the Convert-establish a process to consider the adoption of standardized ible Subordinated Notes entitle the note holders to participate in any dividends declared and paid on PG&E Corporation's common shares based on their equity conversion value.

64

In accordance with SFAS No. 133. "Accounting for Deriva- the CPUC approved, with certain modifications, the Utility's tive Instruments and Hedging Activities," or SFAS No. 133, the LTPP for the 2005 through 2014 period. The LTPP is detailed dividend participation rights component is considered to be an in the preceding "Regulatory Matters" section of this MD&A.

embedded derivative instrument and, therefore, must be bifuir-The Settlement Agreement provides that the Utility will cated from the Convertible Subordinated Notes and marked to recover its reasonable costs of providing utility service, includ-market on PG&E Corporation's Consolidated Statements of ing power procurement costs. In addition, California law Operations as a non-operating expense (in Other expense, net),

requires that the CPUC review revenues and expenses associ-and reflected at fair value on PG&E Corporation's Consoli-ated with a CPUC-approved procurement plan at least dated Balance Sheets as $76 million of non-current liability (in semi-annually through 2006 and adjust retail electricity rates, or Non-current liabilities-other) and $15 million of current lia-order refunds when there is an under or over-collection exceed-bility (in Current liabilities-other). At December 31, 2004, the ing 5% of the Utility's prior year electricity procurement total estimated fair value of the dividend participation rights revenues, excluding the revenue collected on behalf of the component on a pre-tax basis was approximately $91 million.

DWVR. In addition, the CPUC has established a maximum pro-curement disallowance of approximately $36 million for the Electricity Utility's administration of the DXVR contracts and least-cost The Utility relies on electricity from a diverse mix of resources, dispatch. Adverse market price changes are not expected to including third-party contracts, amounts allocated under DWVR impact the Utility's net income, while these cost recovery regu-contracts and its own electricity generation facilities. In addi- latory mechanisms remain in place. However, the Utility is at tion, the Utility purchases and sells electricity on the spot risk to the extent that the CPUC may in the future disallow market and the short-term forward market (contracts with transactions. Additionally, market price changes could impact delivery times ranging from one hour ahead to one year ahead). the timing of the Utility's cash flows.

It is estimated that the residual net open position (the amount of electricity needed to meet the demands of customers, Nuclear Fuel plus applicable reserve margins, that is not satisfied from the The Utility purchases nuclear fuel for Diablo Canyon Utility's own generation facilities, purchase contracts or DWR through contracts with terms ranging from two to five years.

contracts allocated to the Utility's customers) will change over These long-term nuclear fuel agreements are with large, well-time for a number of reasons, including: established international producers in order to diversify its commitments and provide security of supply.

• Periodic expirations of existing electricity purchase contracts, or entering into new electricity purchase contracts; Nuclear fuel purchases are subject to tariffs of up to 8% on

• Fluctuation in the output of hydroelectric and other renew- imports from certain countries. The Utility's nuclear fuel costs able power facilities owned or under contract; have not increased based on the imposed tariffs because the terms of the Utility's existing long-term contracts do not

• Changes in the Utility's customers' electricity demands due to include these costs. However, these contracts expired at the end customer and economic growth and weather, and implemen-of 2004, and prices under new contracts may be higher as a tation of new energy efficiency and demand response result of such tariffs. In addition, because of an increase in U.S.

programs, community choice aggregation, and a core/noncore demand for uranium compared with the domestic supply, ura-retail market structure; nium prices have been trending higher in 2005.

• Planning reserve and operating requirements; As the Utility replaces existing contracts ending in 2004,

• The reallocation of the DWR power purchase contracts new higher priced uranium contracts wvill raise nuclear fuel among California investor-owned electric utilities; and costs. The Utility is expected to partially offset these higher

• The acquisition, retirement or closure of Utility prices by executing a portfolio of near- and long-term contracts generation facilities. for nuclear fuel components. These costs are recovered in ERRA (see the "Electricity Resources" section of this MD&A);

In addition, unexpected outages at the Utility's generation therefore, the changes in nuclear fuel prices are not expected to facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DINWR allocated contracts, materially impact net income.

would immediately increase the Utility's residual net open posi-tion. The Utility expects to satisfy at least some of the residual net open position through new contracts. In December 2004, 65

Natural Gas The Utility uses value-at-risk to measure the expected maxi-The Utility generally enters into physical and financial natural mum change over a one-day period in the 18-month forward gas commodity contracts from one to 30 months in length to value of its transportation and storage portfolio. This calcula-fulfill the needs of its retail core customers. Changes in temper- tion is based on a 95% confidence level, which means that ature cause natural gas demand to vary daily, monthly and there is a 5% probability that the portfolio will incur a change seasonally. Consequently, significant volumes of gas may be in value in one day at least as large as the reported value-at-purchased in the monthly and, to a lesser extent, daily spot mar- risk. For example, if the value-at-risk is calculated at $5 ket. The Utility's cost of natural gas purchased for its core million, there is a 95% probability that if prices moved against customers includes the commodity cost, the cost of Canadian current positions, the change in the value of the portfolio and intestate transportation and gas storage costs. resulting from a one-day price movement would not exceed $5 million. The value-at-risk provides an indication of the Utility's Under the CPINI, the Utility's purchase costs for a twelve exposure to potential market conditions that could impact month period are compared to an aggregate market-based revenues based on one-day price changes. It is also a way to benchmark based on a weighted average of published monthly measure the effectiveness of hedge strategies on a portfolio.

and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a The Utility's value-at-risk for its transportation and storage tolerance band, which is 99% to 102% of the benchmark, are portfolio was approximately $4 million at December 31, 2004 considered reasonable and are fully recovered in customers' and approximately $4 million at December 31, 2003. A compar-rates. One-half of the costs above 102% of the benchmark are ison of daily values-at-risk is included in order to provide recoverable in customers' rates, and the Utility's customers context around the one-day amounts. The Utility's high, low receive, in their rates, three-fourths of any savings resulting and average transportation and storage value-at-risk during from the Utility's cost of natural gas that is less than 99% of the 2004 were approximately $6 million, $2 million and $4 million, benchmark The shareholder award is capped at the lower of respectively. The Utility's high, low and average transportation 1.5% of total natural gas commodity costs or $25 million. and storage value-at-risk during 2003 were approximately $13 AWhile this cost recovery mechanism remains in place, changes million, $2 million and $5 million, respectively.

in the price of natural gas are not expected to materially impact Value-at-risk has several limitations as a measure of portfolio net income. ' risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, mismatch of Transportation and Storage one-day liquidation period assumed in the value-at-risk The Utility currently faces price and volumetric risk for the methodology as compared to the longer tenn holding period of portion of intrastate natural gas transportation capacity that is the storage and transportation portfolio, and inadequate indica-not contracted under fixed reservation charges used by core tion of the exposure of a portfolio to extreme price movements.

customers. Non-core customers contract with the Utility for In addition, value-at-risk does not measure intra-day risk from natural gas transportation and storage, along with natural gas position changes nor does it measure volumetric uncertainty in' parking and lending (market center) services. The Utility is at the demand for pipeline services.

risk for any natural gas transportation and storage revenue Due to the limitations of value-at-risk, the Utility enhanced volatility. Transportation is sold at competitive market-based the calculation methodology during the fourth quarter of 2004 rates within a cost-of-service tariff framework There are signif-to 1) capture uncertainty with respect to demand (volumetric icant seasonal and annual variations in the demand for natural uncertainty) for pipeline services, 2) reflect the market condi-gas transportation and storage services. The Utility sells most of tions in which the pipeline operates by increasing the holding its pipeline capacity based on the volume of natural gas that is period to 12 months, and 3) include the uncertainty associated transported by its customers. As a result, the Utility's natural with the option exposure in the pipeline portfolio.

gas transportation revenues fluctuate.

The calculation of value-at-risk under this methodology is based on a 99% confidence level, which means that there is a 1% probability that the portfolio will incur a change in value at least as large as the modified value-at-risk. This value-at-risk measure provides an indication of the Utility's exposure to potential market conditions that could impact revenues based 66

on changes in market prices and demand for pipeline services The Utility manages credit risk for its wholesale customers over the 12-month holding period. The value-at-risk calculated and counterparties by assigning credit limits based on an evalu-under this methodology was approximately $35 million at ation of their financial condition, net worth, credit rating and December 31, 2004. other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit The Utility will calculate value-at-risk using the enhanced analysis is performed at least annually.

methodology on a prospective basis only, beginningJanuary 1, 2005. For comparative purposes in 2005, the Utility will con- Credit exposure for the Utility's wholesale customers and tinue to report value-at-risk under the methodology formerly counterparties is calculated daily. If exposure exceeds the estab-used in addition to value-at-risk calculated under the enhanced lished limits, the Utility takes immediate action to reduce the methodology. exposure or obtain additional collateral, or both. Further, the Utility relies heavily on master agreements that require security, INTEREST RATE RISK referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eli-Interest rate risk is the risk that changes in interest rates could gible securities if current net receivables and replacement cost adversely affect earnings or cash flows. Specific interest rate exposure exceed contractually specified limits.

risks for PG&E Corporation and the Utility include the risk of increasing interest rates on variable rate obligations. The Utility calculates gross credit exposure for each of its wholesale customers and counterparties as the current mark-to-Interest rate risk sensitivity analysis is used to measure inter- market value of the contract (i.e., the amount that would be lost est rate risk by computing estimated changes in cash flows as a if the counterparty defaulted today), plus or minus any out-result of assumed changes in market interest rates. At Decem- - standing net receivables or payables, before the application of ber 31, 2004, if interest rates changed by 1% for all current credit collateral. During 2004, the Utility recognized no mate-variable rate debt held by PG&E Corporation and the Utility, rial losses due to contract defaults or bankruptcies. At the change would affect net income by an immaterial amount, December 31, 2004, there were three counterparties that repre-based on net variable rate debt and other interest rate-sensitive sented greater than 10% of the Utility's net wholesale credit instruments outstanding. exposure. Of these three counterparties, two were investment grade representing a total of approximately 47% of the Utility's CREDIT RISK net wholesale credit exposure and one wvas below investment Credit risk is the risk of loss that PG&E Corporation and the grade representing approximately 17% of the Utility's net Utility would incur if customers or counterparties failed to per- wholesale credit exposure.

form their contractual obligations. The Utility conducts business with wholesale counterparties PG&E Corporation had gross accounts receivable of mainly in the energy industry, including other California approximately $2.2 billion at December 31, 2004 and approxi- investor-owned electric utilities, municipal utilities, energy trading mately $2.5 billion at December 31, 2003. The majority of the companies, financial institutions, and oil and natural gas pro-accounts receivable were associated with the Utlity's residential duction companies located in the United States and Canada.

and small commercial customers. Based upon historical experi- This concentration of counterparties may impact the Utility's ence and evaluation of then-current factors, allowances for overall exposure to credit risk because counterparties may be doubtful accounts of approximately $93 million at Decem-~ similarly affected by economic or regulatory changes, or other ber 31, 2004 and approximately $68 million at December 31, changes in conditions. Credit losses experienced as a result of 2003 were recorded against those accounts receivable. In accor- electrical and gas procurement activities are expected to be dance with tariffs, credit risk exposure is limited by requiring recoverable from customers and are therefore, not expected to deposits from new customers and from those customers whose have a material impact on earnings.

past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receiv-ables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered likely.

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CRITICAL ACCOUNTING POLICIES recovered or reflected in future rates, the revenues or costs would be charged to income in the period in which they were The preparation of Consolidated Financial Statements in accor-incurred. If it is determined that a regulatory asset is no longer dance with GAAP involves the use of estimates and assumptions probable of recovery in rates, then SPAS No. 71 requires that it that affect the recorded amounts of assets and liabilities as of be written off at that time. At December 31, 2004, PG&E Cor-the date of the financial statements and the reported amounts poration and the Utility reported regulatory assets (including of revenues and expenses during the reporting period. The current regulatory balancing accounts receivable) of approxi-accounting policies described below are considered to be critical mately $7.5 billion and regulatory liabilities (including current accounting policies, due, in part, to their complexity and balancing accounts payable) of approximately $4.4 billion.

because their application is relevant and material to the finan-cial position and results of operations of PG&E Corporation UNBILLED REVENUES and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ sub- The Utility records revenue as electricity and natural gas are stantially from these estimates. These policies and their key delivered. A portion of the revenue recognized has not yet been characteristics are outlined below. billed. Unbilled revenues are determined by factoring an estimate of the electricity and natural gas load delivered with REGULATORY ASSETS AND LIABILITIES recent historical usage and rate patterns. At December 31, 2004, the Utility had recorded approximately $550 million in PG&E Corporation and the Utility account for the financial unbilled revenues.

effects of regulation in accordance with SPAS No. 71. SPAS No. 71 applies to regulated entities whose rates are designed to ENVIRONMENTAL REMEDIATION LIABILITIES recover the cost of providing service. SFAS No. 71 applies to all of the Utility's operations except for the operations of a natural Given the complexities of the legal and regulatory environment gas pipeline. During the first quarter of 200.4, the Utility began regarding environmental laws, the process of estimating environ-reapplying SFAS No. 71 to its generation operations. mental remediation liabilities is a subjective one. The Utility records a liability associated with environmental remediation Under SPAS No. 71, regulatory assets represent capital-activities when it is determined that remediation is probable, as ized costs that otherwise would be charged to expense under defined in SFAS No. 5, and the cost can be estimated in a reason-GAAP. These costs are later recovered through regulated able manner. The liability can be based on many factors, including rates. Regulatory liabilities are created by rate actions of a site investigations, remediation, operations, maintenance, regulator that will later be credited to customers through the monitoring and closure. This liability is recorded at the'lower ratemaking process. Regulatory assets and liabilities are range of estimated costs, unless a more objective estimate can be recorded when it is probable, as defined in SPAS No. 5, achieved. The recorded liability is re-examined every quarter.

"Accounting for Contingencies," or SFAS No. 5, that these items will be recovered or reflected in future rates. Determin- At December 31, 2004, the Utility's accrual for undis-ing probability requires significant judgment on the part of counted environmental liability was approximately $327 management and includes, but is not limited to, consideration million. The Utility's undiscounted future costs could increase of testimony presented in regulatory hearings, CPUC and to as much as $480 million if other potentially responsible par-FERC administrative law judge proposed decisions, final reg- ties are not able to contribute to the settlement of these costs ulatory orders and the strength or status of applications for. or the extent of contamination or necessary remediation is regulatory rehearings or state court appeals. The Utility also greater than anticipated.

maintains regulatory balancing accounts, which are comprised The accrual for undiscounted environmental liability is of sales and cost balancing accounts. These balancing representative of future events that are likely to occur. In deter-accounts are used to record the differences between revenues mining maximum undiscounted future costs, events that are and costs that can be recovered through rates.

possible but not likely are included in the estimation.

If the Utility determined that it could not apply SFAS No. 71 to its operations or, if under SFAS No. 71 it could not ASSET RETIREMENT OBLIGATIONS conclude that it is probable that revenues or costs would be The Utility accounts for its nuclear generation and certain fossil generation facilities under SPAS No. 143, "Accounting for Asset Retirement Obligations," or SFAS No. 143. SPAS No. 143 68

requires that an asset retirement obligation be recorded at fair differences in actual experience, plan changes or significant value in the period in which it is incurred if a reasonable esti- changes in assumptions may materially affect the recorded pen-mate of fair value can be made. In the same period, the sion and other benefit obligations and future plan expenses.

associated asset retirement costs are capitalized as part of the In accordance with accounting rules, changes in benefit obli-carrying amount of the related long-lived asset. Rate-regulated gations associated with these assumptions may not be entities may recognize regulatory assets or liabilities as a result recognized as costs on the income statement. Differences of timing differences between the recognition of costs as

between actuarial assumptions and actual plan results are recorded in accordance with SFAS No. 143 and costs recovered deferred and are amortized into cost only when the accumu-through the ratemaking process.

lated differences exceed 10% of the greater of the projected There are uncertainties regarding the ultimate cost associ- benefit obligation or the market-value of the related plan assets.

ated with retiring the assets the Utility has accounted for in If necessary, the excess is amortized over the average remaining accordance with SFAS No. 143. These include, but are not lim- service period of active employees. As such, significant portions ited to changes in assumed dates of decommissioning, of benefit costs recorded in any period may not reflect the regulatory requirements, technology, cost of labor, materials, .actual level of cash benefits provided to plan participants.

and equipment. At December 31, 2004, the Utility's estimated PG&E Corporation's and the Utility's recorded pension cost of retiring these assets is approximately $1.3 billion. expense totaled $182 million in 2004, $212 million in 2003 and

$43 million in 2002, in accordance with the provisions of PENSION AND OTHER SPAS 87. PG&E Corporation's and the Utility's recorded POSTRETIREMENT PLANS expense for other postretirement and benefit obligations totaled

$78 million in 2004, $76 million in 2003 and $50 million in Certain employees and retirees of PG&E Corporation and its 2002, in accordance with the provisions of SFAS 106. Under subsidiaries participate in qualified and non-qualified SFAS No. 71, regulatory adjustments have been recorded in the non-contributory defined benefit pension plans. Certain retired Consolidated Statements of Operations and Consolidated Bal-employees and their eligible dependents of PG&E Corporation ance Sheets of the Utility to reflect the difference between and its subsidiaries also participate in contributory medical Utility pension expense or income for accounting purposes and plans, and certain retired employees participate in life insurance Utility pension expense or income for ratemaking, which is plans (referred to collectively as other benefits). Amounts that based on a funding approach. The CPUC has authorized the PG&E Corporation and the Utility recognize as costs and obli-Utility to recover the costs associated with its other benefits for gations to provide pension benefits under SFAS No. 87, 1993 and beyond. Recovery is based on the lesser of the "Employers' Accounting for Pensions," and other benefits amounts collected in rates or the annual contributions on a tax-under SFAS No. 106, "Employers Accounting for Postretire-

'deductible basis to the appropriate trusts.

ment Benefits other than Pensions," are based on a variety of factors. These factors include the provisions of the plans, PG&E Corporation's and the Utility's funding policy is to employee demographics and various actuarial calculations, contribute tax deductible amounts, consistent with applicable assumptions and accounting mechanisms. Because of the com- regulatory decisions (including the 2003 GRC), sufficient to plexity of these calculations, the long-term nature of these meet minimum funding requirements. Based upon current obligations and the importance of the assumptions utilized, assumptions and available information, PG&E Corporation and PG&E Corporation's and the Utility's estimate of these costs the Utility have not identified any minimum funding require-and obligations is a critical accounting estimate. ments related to its pension plans, excluding amounts required to fund a voluntary retirement program of approximately $20 Actuarial assumptions used in determining pension obliga-.

million annually in 2005 and 2006. PG&E Corporation and the tions include the discount rate, the average rate of future Utility have estimated funding requirements related to their compensation increases and the expected return on plan assets.

postretirement benefit plans at approximately $65 million annu-Actuarial assumptions used in determining other benefit obliga-ally in 2005 and 2006. Contribution estimates for the Utility's tions include the discount rate, the average rate of future pension and postretirement benefit plans after 2006 will be compensation increases, the expected return on plan assets and driven by future GRC decisions.

the assumed health care cost trend rate. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe the assumptions used are appropriate, significant 69

Pension and other benefit funds are held in external trusts. The following reflects the sensitivity of postretirement Trust assets, including accumulated earnings, must be used benefit costs and accumulated benefit obligation to changes in exclusively for pension and other benefit payments. Consistent certain actuarial assumptions:

with the trusts' investment policies, assets are invested in U.S.

equities, non-U.S. equities and fixed income securities. Invest- Increase in Increase in ment securities are exposed to various risks, including interest 2004 Accumulated Post- Benefit rate, credit and overall market volatility risks. As a result of Increase retirement Obligation at these risks, it is reasonably possible that the market values of (decrease) in Benefit December 3 1, investment securities could increase or decrease in the'near (in millions) assumption Cost 2004 term. Increases or decreases in mark-et values could materially Health care cost trend rate 0.5% $5 $37 affect the current value of the trusts and, as a result, the future Discount rate (0.5)% 2 84 level of pension and other benefit expense.

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then apply- ACCOUNTING PRONOUNCEMENTS ing these returns to the target asset allocations of the employee ISSUED BUT NOT YET ADOPTED benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income projected returns were based on his- Share-Based Payment Transactions torical returns for the broad U.S. bond market. Equity returns In December 2004, the Financial Accounting Standards Board, were based primarily on historical returns of the S&P 500 or FASB, issued Statement No. 123 (revised December 2004),

Index. For the Utility Retirement Plan, the assumed return of "Share-Based Payment," or SFAS No. 123R. SFAS No. 123R 8.1% compares to a ten-year actual return of 9.5%. requires that the cost resulting from all share-based payment The rate used to discount pension and other post-retirement transactions be recognized in the financial statements and estab-benefit plan liabilities was based on a yield curve developed lishes a fair-value measurement objective in determining the from the Mloody's AA Corporate Bond Index at December 31, value of such a cost. SFAS No. 123R will be effective for the 2004. This yield curve has discount rates that vary based on the third quarter of 2005. PG&E Corporation and the Utility are maturity of the obligations. The estimated future cash flows for currently evaluating the impact of SPAS No. 123R on their the pension and other post retirement obligations were matched Consolidated Financial Statements.

to the corresponding rates on the yield curve to derive a weighted average discount rate. Inventory Costs In December 2004, the FASB issued Statement No. 151, The following reflects the sensitivity of pension costs and

'Inventory Costs an amendment of ARB No. 43, Chapter 4", or projected benefit obligation to changes in certain actuarial SPAS No. 151. The guidance clarifies that the allocation of assumptions:

fixed production overhead to inventory is based on normal capacity. Abnormal amounts of idle facility, excess freight, han-Increase in Projected dling costs and spoilage should be recognized as a current Increase in Benefit period charge. SFAS No. 151 will be effective January 1, 2006.

Increase 2004 Obligation at The adoption of SFAS No. 151 is not expected to have a mate-(decrease) in Pension December 3 1, (in millions) rial effect on the financial position or results of operations of assumption Cost 2004 either PG&E Corporation or'the Utility.

Discount rate (0.5)% $40 $584 Rate of return on plan assets (0.5)% 32 Rate of increase in compensation 0.5% 25 124 70

TAXATION MATTERS nized additional income tax benefits for financial reporting pur-poses with respect to the losses of NEGT and its subsidiaries The IRS has completed its audit of PG&E Corporation's 1997 even though it must continue to include NEGT and its sub-and 1998 consolidated federal income tax returns and has sidiaries in its consolidated income tax returns. After its assessed additional federal income taxes of approximately $79 equity ownership in NEGT was cancelled on the effective date million (including interest). PG&E Corporation has filed of NEGT's plan of reorganization, PG&E Corporation no protests contesting certain adjustments made by the IRS in that longer includes NEGT or its subsidiaries in its consolidated audit and currently is discussing these adjustments with the IRS' income tax returns. In addition, any remaining deferred tax Appeals Office. PG&E Corporation does not expect final reso-assets related to NEGT or its subsidiaries, were reversed as dis-lution of these appeals to have a material impact on its financial continued operations in the Consolidated Statements of position or results of operations.

Operations at the time PG&E Corporation's equity interest in In the fourth quarter of 2003, PG&E Corporation made an NEGT was cancelled. See Note 5 of the Notes to the Consoli-advance payment to the IRS of $75 million relating to the 1999 dated Financial Statements for further discussion.

and 2000 audit. The IRS completed its audit of PG&E Corpo-In addition to the reversal of deferred tax assets referred to ration's 1999 and 2000 consolidated federal income tax returns above, and based on preliminary information provided by during the third quarter of 2004. As a result of the completion NEGT, PG&E Corporation anticipates paying approximately of this audit, PG&E Corporation received a refund from the

$86 million of consolidated federal tax obligations. This IRS of $14 million in January of 2005.

includes federal income taxes on NEGT activities through the The IRS is auditing PG&E Corporation's 2001 and 2002 effective date of NEGT's plan of reorganization.

consolidated federal income tax returns. In September 2004, the PG&E Corporation and NEGT have entered into a separate IRS issued notices of proposed adjustments that propose to agreement under which they have agreed to take certain actions disallow $104 million of synthetic fuel credits claimed on these and cooperate with each other with respect to certain tax mat-tax returns. In addition, the IRS has proposed to disallow aban-ters, including future tax returns and audits.

donment losses deducted on the 2002 tax return related to certain NEGT assets. These assets were transferred to NEGT For the year ended December 31, 2003, PG&E Corporation lenders in the third quarter of 2004. In addition, the IRS has increased its valuation allowances against certain state deferred challenged other deductions related to NEGT prior to its tax assets related to NEGT or its subsidiaries due to the uncer-Chapter I1 filing. PG&E Corporation is disputing the IRS's tainty of their realization. During this period, valuation proposed adjustments and will contest these disallowances if the allowances of approximately $24 million were recorded in dis-IRS continues to assert its current position. continued operations, and approximately $5 million wias recorded in accumulated other comprehensive loss. No valua-PG&E Corporation has accrued $52 million associated with tion allowances were recorded in the three-month period ended NEGT related tax liabilities. In addition, PG&E Corporation December 31, 2003 or during 2004.

has accrued a $41 million liability to cover potential tax obliga-tions relating to non-NEGT issues raised in outstanding tax At December 31, 2003, PG&E Corporation had $420 mil-audits. The Utility has accrued $62 million to cover potential lion of California net operating loss, or NOL. The California tax obligations for outstanding tax audits. Considering these NOLs were fully utilized in 2004.

reserves, PG&E Corporation does not expect the resolution of these matters to have a material impact on its financial position or result of operations. ADDITIONAL SECURITY MEASURES All IRS audits of PG&E Corporation's federal income tax Various federal regulatory agencies have issued guidance and returns prior to 1997 have been closed. the NRC has issued orders regarding additional security meas-ures to be taken at various facilities, including generation Prior to July 8, 2003, the date that NEGT filed for bank-facilities, transmission substations and natural gas transportation ruptcy protection, PG&E Corporation recognized federal income tax benefits related to the losses of NEGT and its subsidiaries. However, after July 7, 2003, under the cost method of accounting PG&E Corporation has not recog-71

facilities. The guidance and the orders require additional capital their formations, but that the CPUC's decision interpreting the investment and increased operating costs. However, neither capital requirements condition was not ripe for review. On Sep-PG&E Corporation nor the Utility believes that these costs will tember 1, 2004, the California Supreme Court denied PG&E have a material impact on its respective consolidated financial Corporation's petition seeking review of the California Court of position or results of operations. Appeal's finding that the CPUC had limited jurisdiction.

Pursuant to the terms of the Settlement Agreement, the CPUC agreed that, once the CPUC approval of the Settlement ENVIRONMENTAL Agreement is no longer subject to appeal, it will release all AND LEGAL MATTERS claims against PG&E Corporation and the Utility related to PG&E Corporation and the Utility are subject to laws and reg- past holding company actions during the California energy ulations established both to maintain and improve the quality of crisis. Nevertheless, as now interpreted by the CPUC, when-the environment. Where PG&E Corporation's and the Utility's ever the Utility's financial health is impaired in the future, properties contain hazardous substances, these laws and regula- PG&E Corporation could be required to infuse the Utility with tions may require PG&E Corporation and the Utility to all types of capital necessary to fulfill its obligation to serve or remove those substances or to remedy effects on the environ- to operate in a prudent and efficient manner. These obligations, ment. Also, in the normal course of business, PG&E if ultimately upheld by the courts, could materially restrict Corporation and the Utility are named as parties in a number of PG&E Corporation's ability to meet other obligations.

claims and lawsuits. See Note 12 of the Notes to the Consoli-dated Financial Statements for further discussion. Adverse resolution of pending litigation could have a material adverse effect on PG&E Corporation's financial condition and results of operation.

RISK FACTORS PG&E Corporation has been named in lawsuits filed by the California Attorney General and the City and County of San RISKS RELATED TO PG&E CORPORATION Francisco, or CCSF, alleging unfair or fraudulent business acts or practices in violation of California Business and Professions PG&E Corporation could be required to contribute capital to Section 17200, or Section 17200, based on alleged violations of the Utility or be denied distributions from the Utility to the conditions established in the CPUC's holding company deci-extent required by the CPUC's determination of the Utility's sions caused by PG&E Corporation's alleged failure to provide financial condition. adequate financial support to the Utility during the California energy crisis. The plaintiffs alleged that the transfer of money In approving the formation as the holding company of the Utility, from the Utility to PG&E Corporation in the form of divi-the CPUC imposed certain conditions, including an obligation by dends and share repurchases violated Section 17200. These PG&E Corporation's Board of Directors to give "first priority" to lawsuits have been consolidated and are pending in the San the capital requirements of the Utility, as determined to be neces-Francisco Superior Court, or Superior Court. The Attorney sary and prudent to meet the Utility's obligation to serve and to General and CCSF seek significant damages, penalties or equi-operate in a prudent and efficient manner. The CPUC later issued table relief. On October 8, 2003, the U.S. District Court for the decisions in which it adopted an expansive interpretation of PG&E Northern District of California, or the District Court, held that Corporation's obligations under this condition, including the the claims for damages were property of the Utility's bank-requirement that PG&E Corporation, as well as each of the hold-ruptcy estate, thus removing the damages claims from the ing companies of the other major California investor-owned lawsuits. The Attorney General and CCSF have appealed that electric utilities, "infuse the utility with all types of capital necessary decision to the U.S. Court of Appeals for the Ninth Circuit, or for the utility to fulfill its obligation to serve." PG&E Corporation the Ninth Circuit, where it is currently pending. Oral argument and the other holding companies of the other major California on the appeal will be held on February 18, 2005. It is uncertain investor-owned electric utilities appealed these decisions. On when a decision will be issued.

May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding OnJanuary 21, 2005, the Superior Court issued a tentative companies to enforce the conditions imposed by the CPUC on ruling rejecting the standard advocated by the Attorney General and CCSF to calculate the number of violations that plaintiffs allege have been committed for purposes of determining the 72

amount of potential civil penalties at issue. Under PG&E Corporation's and the Utility's financial viability Section 17200, a penalty of up to $2,500 can be imposed for depends upon the Utility's ability to recover its costs in a each violation. The Superior Court found that the appropriate timely manner from the Utility's customers through standard was each transfer of money from the Utility to PG&E regulated rates and otherwise execute its business strategy.

Corporation that plaintiffs allege violated Section 17200. The Utility is a regulated entity subject to CPUC jurisdiction Comments on the ruling are scheduled to be discussed at a case in almost all aspects of its business, including the rates, terms management conference to be held on February 25, 2005. and conditions of its services, procurement of electricity and PG&E Corporation believes that the plaintiffs' allegations are natural gas for its customers, issuance of securities, dispositions without merit. However, there can be no assurance that PG&E of utility assets and facilities and aspects of the siting and opera-Corporation will prevail in these lawsuits. tion of its electricity and natural gas distribution systems.

Executing the Utility's business strategy depends on periodic RISKS RELATED TO THE UTILITY CPUC approvals of these and related matters. The Utility's ongoing financial viability depends on its ability to recover from If either or both of the CPUC's approval of the Settlement its customers in a timely manner the Utility's costs, including Agreement and the confirmation order are overturned or the costs of electricity and natural gas purchased by it for its modified on appeal, PG&E Corporation's and the Utility's customers, in the Utility's CPUC-approved rates and its ability financial condition and results of operations could be to pass through to its customers in rates the Utility's FERC-materially adversely affected. authorized revenue requirements.

On December 18, 2003, the CPUC approved the Settlement The Utility's financial viability also depends on its ability to Agreement and, on December 22, 2003, the bankruptcy court recover in rates an adequate return on its capital structure, confirmed the Utility's plan of reorganization, which fully including long-term debt arid equity. During the California incorporates the Settlement Agreement as a material and inte-energy crisis, the high price the Utility had to pay for electricity gral part of the plan. On March 16, 2004, the CPUC denied on the wholesale market, coupled with its inability to fully applications that had been filed by several parties seeking recover its costs in retail rates, caused the Utility's costs to sig-rehearing of the CPUC's decision approving the Settlement nificantly exceed its revenues and ultimately caused the Utility Agreement. On April 15, 2004, two of these parties, CCSF and to file a petition under Chapter 11. Even though the Settlement Aglet Consumer Alliance, or Aglet, filed petitions for review of Agreement and current regulatory mechanisms contemplate the CPUC's decisions with the California Court of Appeal.

that the CPUC will give the Utility the opportunity to recover Three California state senators have filed a brief in support of its reasonable and prudent future costs in its rates, there can be the CCSF and Aglet petitions. The California Court of Appeal no assurance that the CPUC will find that all of the Utility's has not yet acted on the petitions.

costs are reasonable and prudent or will not otherwise take or In addition, appeals of the confirmation order were filed in fail to take actions to the Utility's detriment.

the District Court by the two CPUC commissioners who did In addition, there can be no assurance that the bankruptcy not vote to approve the Settlement Agreement, or the dissent-court or other courts will implement and enforce the terms of ing commissioners, and a municipality. OnJuly 15, 2004, the the Settlement Agreement and the Utility's plan of reorganiza-District Court dismissed the appeals filed by the dissenting tion in a manner that would produce the economic results that commissioners. The dissenting commissioners have appealed PG&E Corporation and the Utility intend or anticipate. Fur-the District Court's order with the Ninth Circuit. The munici-ther, there can be no assurance that FERC-authorized tariffs pality's appeal remains pending at the District Court.

,will be adequate to cover the related costs. If the Utility is If the bankruptcy court's confirmation of the Utility's plan of unable to recover any material amount of its costs through its reorganization or the Settlement Agreement is overturned or rates in a timely manner, PG&E Corporation's and the Utility's modified on appeal, PG&E Corporation's and the Utility's financial condition and results of operations would be materially financial condition and results of operations, and the Utility's adversely affected.

ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected.

73

The Utility may be unable to purchase electricity in the from recovering costs in excess of the Utility's projection of its wholesale market or to increase its generating capacity in initial capital costs included in the Utility's bid for Utility-a manner that the CPUC will find reasonable or in owned generation. If the Utility is not able to recover a material amounts sufficient to satisfy the Utility's obligation to meet part of the cost of developing or acquiring additional generation the electricity needs of its customers and the CPUC's facilities in the Utility's rates in a timely manner, PG&E Cor-electricity resource adequacy requirements. poration's and the Utility's financial condition and results of The Utility's residual net open position (i.e., that portion of the operations would be materially adversely affected.

Utility's electricity customers' demand not satisfied by electric-ity that the Utility generates or has under contract, or by The Utility's financial condition and results of operations electricity provided under the DWR allocated contracts) is could be materially adversely affected if it is unable to expected to grow over time, as discussed in the "Risk Manage- successfully manage the risks inherent in operating the ment" section of this MD&A above. In addition, unexpected Utility's facilities.

outages at the Utility's Diablo Canyon power plant or any of its The Utility owns and operates extensive electricity and natural other significant generation facilities, or a failure to perform by gas facilities that are interconnected to the U.S. western elec-any of the counterparties to the Utility's electricity purchase tricity grid and numerous interstate and continental natural gas contracts or the DWR allocated contracts, would immediately pipelines. The operation of the Utility's facilities and the facili-increase the Utility's residual net open position. ties of third parties on which it relies involves numerous risks, including-As existing electricity purchase contracts expire, sources of electricity otherwise become unavailable or demand increases,

• Operating limitations that may be imposed by environmental the Utility will purchase electricity in the wholesale market. or other regulatory requirements; These purchases will be made under contracts priced at the

• Imposition of operational performance standards by agencies time of execution or, if made in the spot market, at the then-with regulatory oversight of the Utility's facilities; current market price of wholesale electricity. There can be no assurance that sufficient replacement electricity will be available

• Environmental and personal injury liabilities; at prices and on terms that the CPUC will find reasonable, or

• Fuel interruptions; at all. The Utility's financial condition and results of operations would be materially adversely affected if it is unable to purchase

• Blackouts; electricity in the wholesale market at prices or on terms the

• Labor disputes; CPUC finds reasonable or in quantities sufficient to satisfy the Utility's residual net open position.

• Weather, storms, earthquakes, fires, floods or other natural disa'sters; and California investor-owned electric utilities are required to achieve an electricity planning reserve margin of 15% to 17%

• Explosions, accidents, mechanical breakdowns and other in excess of peak capacity electricity requirements by June 1, events or hazards that affect demand, result in power out-2006. In order to meet electricity resource adequacy require- ages, reduce generating output or cause damage to the ments, the Utility may develop or acquire new generation Utility's assets or operations or those of third parties on facilities. The development or acquisition of additional genera- which it relies.

tion facilities would require the Utility to incur significant The occurrence of any of these events could result in lower additional capital expenditures or other costs and may require revenues or increased expenses, or both, that may not be fully the Utility to issue additional debt, which it may not be able to recovered through insurance, rates or other means in a timely issue on reasonable terms, or at all. The CPUC's December 16, manner or at all.

2004 decision approving the Utility's LTPP prohibits the Utility 74

Electricity and natural gas markets are highly volatile and equipment, as well as for related fees and permits. Moreover, insufficient regulatory responsiveness to that volatility could compliance in the future may require significant expenditures cause events similar to those that led to the filing of the relating to electric and magnetic fields. The Utility also is sub-Utility's Chapter 11 petition to occur. ject to significant liabilities related to the investigation and In the recent past, the commodity markets for electricity and remediation of environmental contamination at the Utility's cur-natural gas have been highly volatile and subject to substantial rent and former facilities, as well as at third-party owned sites.

price fluctuations. A variety of factors may contribute to com- Due to the potential for imposition of stricter standards and modity market volatility, including: greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to

• Weather; contribute to cleanup costs, conditions may change or additional

• Supply and demand; contamination may be discovered, the Utility's environmental compliance and remediation costs could increase, and the timing

• The availability of competitively priced alternative of its capital expenditures in the future may accelerate. If the energy sources; Utility is unable to recover the costs of complying with environ-

• The level of production of natural gas; mental laws in its rates in a timely manner, the Utility's financial condition and results of operations could be materially adversely

• The availability of liquified natural gas, or LNG, supplies; affected. In addition, in the event the Utility must pay materially

• The price of other fuels that are used to produce electricity, more than the amount that it currently has reserved on its bal-including crude oil and coal; ance sheet to satisfy its environmental remediation obligations and the Utility is unable to recover these costs from insurance or

• The transparency, efficiency, integrity and liquidity of through rates in a timely manner, PG&E Corporation's and the regional energy markets affecting California; Utility's financial condition and results of operations would be

• Electricity transmission or natural gas transportation materially adversely affected.

capacity constraints;

• Federal, state and local energy and environmental regulation The Utility faces the risk of unrecoverable costs if its and legislation; and customers obtain distribution and transportation services from other providers as a result of municipalization,

• Natural disasters, war, terrorism and other catastrophic events.

competition, technological change, or other forms of These factors are largely outside the Utility's control. If bypass.

wholesale electricity or natural gas prices increase signifi- The Utility's customers could bypass its distribution and trans-cantly, public pressure or other regulatory or governmental portation system by obtaining service from other sources.

influences or other factors could constrain the willingness or Forms of bypass of the Utility's electricity distribution system ability of the CPUC to authorize timely recovery of the Util- include the construction of duplicate distribution facilities to ity's costs. Moreover, the volatility of commodity markets serve specific existing or new customers, the municipalization of could cause the Utility to apply more frequently to the CPUC the Utility's distribution facilities by local governments or dis-for authority to timely recover its costs in rates. If the Utility tricts, and other forms of bypass or competition. Bypass of the is unable to recover any material amount of its costs in its Utility's system may result in stranded investment capital, loss rates in a timely manner, PG&E Corporation's and the Util- of customer growth or additional barriers to cost recovery.

ity's financial condition and results of operations would be Recently, both the Sacramento Municipal Utility District and materially adversely affected. South SanJoaquin Irrigation District have studied the feasibil-ity of condemning portions of the Utility's electric system The Utility's operations are subject to extensive within Yolo County and San Joaquin County, respectively. If environmental laws, and changes in, or liabilities under, these agencies continue their efforts, they must satisfy a number these laws could adversely affect its financial condition and of legal steps, which will likely span several years. The Utility results of operations. opposes these efforts as not being within the best interests of The Utility's operations are subject to extensive federal, state the customers within the subject areas, as well as other cus-and local environmental laws. Complying with these environ- tomers. The Utility's natural gas transportation facilities also mental laws has in the past required significant expenditures for are at risk of being bypassed by interstate pipeline companies environmental compliance, monitoring and pollution control that construct facilities in the Utility's markets or by customers 75

who build pipeline connections that bypass the Utility's natural CPUC, for the period January 1, 2006 through January 1, 2009, gas transportation and distribution system, or by customers who to permit new direct access transactions in an amount equiva-use and transport LNG. As customers and local public officials lent to the combined amount of Statewide utility load growth explore their energy options in light of the California energy and reduction in the electricity supply contract obligations of crisis, these bypass risks may be increasing and may increase the DWR. While AB 428 was not approved by the legislature, further if the Utility's rates exceed the cost of other available there can be no assurance that a similar bill will not be intro-alternatives. In addition, technological changes could result in duced and approved in future legislative sessions.

the development of economically attractive alternatives to pur-Separately, the CPUC has instituted a rulemaking imple-chasing electricity through the Utility's distribution facilities.

menting California's Assembly Bill 117, which permits Neither PG&E Corporation nor the Utility can currently pre-California cities and counties to purchase and sell electricity for dict the impact of these actions and developments on the their residents once they have registered as community choice Utility's business, although one possible outcome is a decline in a gregators. The Utility would continue to provide distribu-the demand for the services that the Utility provides, which tion, metering and billing services to the community choice would result in a corresponding decline in the Utility's revenues aggregators' customers. Once registration has occurred, and the and PG&E Corporation's consolidated revenues.

applicable community choice aggregator has received CPUC If the number of the Utility's customers declines due to approval for its implementation plan, the community choice municipalization, competition, technological changes or other aggregator would purchase electricity for all of its residents who forms of bypass, and the Utility's rates are not adjusted in a do not affirmatively elect to continue to receive electricity from timely manner to allow it to fully recover its investment in the Utility. The Utility would continue to be the electricity electricity and natural gas facilities and electricity procurement provider of last resort for all customers. If the Utility loses a costs, PG&E Corporation's and the Utility's financial condition material number of customers as a result of cities and counties and results of operations could be materially adversely affected. electing to become community choice aggregators or the CPUC once again allows customers to migrate to direct access, The Utility faces the risk of unrecoverable costs resulting the Utility's electricity purchase contracts could obligate it to from changes in the number of customers in its service purchase more electricity than the Utility's remaining customers territory for whom the Utility purchases electricity. require, the excess of which the Utility would have to sell, pos-As part of California's electricity industry restructuring, the sibly at a loss. Further, if the Utility must provide electricity to Utility's customers were given the ability to choose to purchase customers discontinuing direct access or electing to leave a electricity from alternate energy service providers and to thus community choice aggregator, the Utility may be required to become direct access customers. Customers who did not buy make unanticipated purchases of additional electricity at higher electricity from an alternate provider continued to receive elec- prices. If the Utility has excess electricity or it must make tricity procurement, transmission and distribution services, or unplanned purchases of electricity as a result of changes in the bundled service, from the Utility. Customers who chose an number of community choice aggregators' customers or direct alternate electricity provider continued to receive transmission access customers and the CPUC fails to adjust the Utility's rates and distribution services from the Utility. The CPUC sus- to reflect the impact of these actions, PG&E Corporation's and pended the right of end-user customers to become direct access the Utility's financial condition and results of operations could customers on September 20, 2001, although customers that be materially adversely affected.

were then direct access customers have been allowed to remain on direct access. During the 2003-2004 legislative session, the. The operation and decommissioning of the Utility's nuclear California legislature considered bills, including California power plants expose it to potentially significant liabilities and Assembly Bill 428, or AB 428, which would have required the capital expenditures.

CPUC to establish rules for reintroduction of direct access The operation and decommissioning of the Utility's nuclear through a phased implementation and to establish a model for power plants expose it to potentially significant liabilities and direct access transactions. AB 428 would also have required the capital expenditures, including those arising from the storage, handling and disposal of radioactive materials and uncertainties related to the regulatory, technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The Utility maintains decommissioning trusts and exter-76

nal insurance coverage to reduce the Utility's financial exposure upon the NRC's assessment of the severity of the situation.

to these risks. However, the costs or damages the Utility may Safety and security requirements promulgated by the NRC incur in connection with the operation and decommissioning of have, in the past, necessitated substantial capital expenditures at nuclear power plants could exceed the amount of the Utility's the Utility's Diablo Canyon power plant and additional signifi-insurance coverage and other amounts set aside for these poten- cant capital expenditures could be required in the future.

tial liabilities. In addition, as an operator of two operating nuclear reactor units, the Utility may be required under federal If the Utility fails to increase the spent fuel storage law to pay up to $201.2 million of liabilities arising out of each capacity at the Utility's Diablo Canyon power plant by the nuclear incident occurring not only at the Utility's Diablo spring of 2007 and there are no other available spent Canyon power plant but at any other nuclear power plant in the fuel storage or disposal alternatives, the Utility would be United States. forced to close this plant and would therefore be required to purchase electricity from more expensive sources.

In January 2004, the Utility filed an application with the CPUC seeking approval of projects to replace turbines and Under the terms of the NRC operating licenses for the Utility's steam generators and other equipment at the two nuclear oper- Diablo Canyon power plant, there must be sufficient storage ating units at the Utility's Diablo Canyon nuclear power plant capacity for the radioactive spent fuel produced by this plant.

and authorization to recover the projected $706 million capital Under current operating procedures, the Utility believes that its expenditures in rates. The Utility plans to replace Unit 2's Diablo Canyon power plant's existing spent fuel pools have suf-steam generators in 2008 and to replace Unit l's steam genera- ficient capacity to enable it to operate until the spring of 2007.

tors in 2009. OnJanuary 25, 2005, a CPUC administrative law Although the Utility is taking actions to increase the Diablo judge issued a proposed decision that would find the steam Canyon power plant's spent fuel storage capacity and exploring generator replacement project to be cost-effective and would other alternatives, there can be no assurance that the Utility can authorize the Utility to recover the projected $706 million obtain the final necessary regulatory approvals to expand spent capital cost of the project in rates with no after-the-fact reasori- fuel capacity or that other alternatives will be available or ableness review if the total costs do not exceed $706 million, implemented in time to avoid a disruption in production or and established a maximum project cost of $815 million. If the shutdown of one or both units at this plant. As the proposed project costs exceed $706 million, or if the CPUC has reason to permanent spent fuel depository at Yucca Mountain, Nevada believe that the costs may be unreasonable regardless of the will not be available by 2007, there will not be any available amount, the CPUC may conduct a reasonableness review of all third-party spent fuel storage facilities. If there is a disruption in costs. The proposed decision recommends that the Utility production or shutdown of one or both units at this plant, the would be allowed to recover the revenue requirements related Utility will need to purchase electricity from more expensive to the project in rates beginning onJanuary I of the year fol- sources.

lowing the commencement of commercial operations of each unit. The CPUC may act on the proposed decision at its meet- Acts of terrorism could materially adversely affect PG&E ing to be held on February 25, 2005. Assuming the CPUC Corporation's and the Utility's financial condition and approves the proposed decision, the Utility would make the ini- results of operations.

tial capital expenditures required to maintain a 2008/2009 The Utility's facilities, including its operating and retired implementation schedule. It is expected that the CPUC will nuclear facilities and the facilities of third parties on which we issue a final decision, including incorporation of the environ- rely, could be targets of terrorist activities. A terrorist attack on mental impact review for the projects, in September 2005. If these facilities could result in a full or partial disruption of the the Utility cannot recover any material amount of these excess Utility's ability to generate, transmit, transport or distribute costs or damages in the Utility's rates in a timely manner, electricity or natural gas or cause environmental repercussions.

PG&E Corporation's and the Utility's financial condition and Any operational disruption or environmental repercussions results of operations would be materially adversely affected. could result in a significant decrease in the Utility's revenues or significant reconstruction or remediation costs, which could In addition, the NRC has broad authority under federal law materially adversely affect PG&E Corporation's and the Util-to impose licensing and safety-related requirements upon own-ity's financial condition and results of operations.

ers and operators of nuclear power plants. In the event of -

non-compliance, the NRC has the authority to impose fines or to force a shutdown of the nuclear plant, or both, depending 77

Adverse judgments or settlements in the chromium penalties, or other amounts. As an example, the Utility is litigation cases could materially adversely affect PG&E required to reimburse the California Department of Forestry, Corporation's and the Utility's financial condition and or CDF, for fire suppression costs when a fire on wild lands is results of operations. caused by the Utility's failure to maintain a specified clearance The Utility is a named defendant in 14 civil actions currently between vegetation and overhead lines. Recently, the CDF has pending in California courts relating to alleged chromium con- demanded the Utility pay for fire suppression costs regardless of tamination. The chromium litigation complaints allege personal whether the Utility is determined to be at fault in identifying injuries, wrongful death and loss of consortium and seek and removing hazard trees.

unspecified compensatory and punitive damages based on claims arising from alleged exposure to chromium contamina- Changes in, or liabilities under, the Utility's permits, tion in the vicinity of three of the Utility's natural gas authorizations or licenses could adversely affect PG&E compressor stations. If the Utility pays a material amount in Corporation's and the Utility's financial condition and excess of the amount that it currently has reserved on its bal- results of operations.

ance sheet to satisfy chromium-related liabilities and costs, The Utility is also required to comply with the terms of various PG&E Corporation's and the Utility's financial condition and permits, authorizations and licenses. These permits, authoriza-results of operations could be materially adversely affected. tions and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from The Utility's operations are subject to a number of federal the facts assumed when they were issued. In addition, discharge and state statutes, CPUC and FERC regulations, rules and pennits and other approvals and licenses are often granted for a orders, as well as the terms of governmental permits, term that is less than the expected life of the associated facility.

authorizations and licenses. Licenses and permits may require periodic renewal, which may The Utility is obligated to comply in good faith with all appli- result in additional requirements being imposed by the granting cable statues, rules, tariffs and orders of the CPUC, the FERC agency. In connection with a license renewal, the FERC may and the NRC relating to the aspects of its electricity and natural impose new license conditions that could, among other things, gas utility operations which fall within the jurisdictional author- require increased expenditures or result in reduced electricity ity of such regulatory agencies. These include customer billing, output and/or capacity at the facility.

customer service, affiliate transactions, vegetation management, If the CPUC, the FERC, the NRC, or other regulatory and safety and inspection practices. There is a risk that the agency having jurisdiction, makes a finding that the Utility did interpretation and application of these statues, rules, tariffs and not comply with applicable rules, tariffs and orders, the Utility orders may change over time and that the Utility will be deter- could be required to make customer refunds, pay penalties, or mined to have not complied with the new interpretation incur other non-recoverable expenses, which could have a mate-exposing the Utility to potential liability for customer refunds, rial adverse effect on PG&E Corporation's and the Utility's financial condition and results of operations. Also, if the Utility is unable to obtain, renew or comply writh these governmental permits, authorizations or licenses, or the Utility is unable to recover any increased costs of complying with additional license requirements or any other associated costs in its rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations could be materially adversely affected.

78

CONSOLIDATED STATEMENTS OF OPERATIONS PG&E CORPORATION Year ended December 31, (in millions, except per share amounts) 2004 2003 2002 Operating Revenues Electric $ 7,867 $ 7,582 $ 8,178 Natural gas 3,213 2,853 2,327 Total operating revenues 11,080 10,435 10,505 Operating Expenses Cost of electricity 2,770 2,309 1,447 Cost of natural gas 1,724 1,438 895 Operating and maintenance 2,865 2,963 2,858 Recognition of regulatory assets (4,900) - -

Depreciation, amortization, and decommissioning 1,497 1,222 1,196 Reorganization professional fees and expenses 6 160 > 155 Total operating expenses 3,962 8,092 6,551 Operating Income 7,118 2,343 3,954 Reorganization interest income 8 46 71 Interest income 55 16 9 Interest expense (797) (1,147) (1,224)

Other income (expense), net (98) (9) 50 Income Before Income Taxes 6,286 1,249 2,860 Income tax provision 2,466 458 1,137 Income From Continuing Operations 3,820 791 1,723 Discontinued Operations Gain on disposal of NEGT (net of income taxes of $374 million) 684 - -

Loss from operations of NEGT (net of income tax benefit of $230 minion in 2003 and

$1,558 million in 2002) - (365) (2,536)

Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles 4,504 426 (813)

Cumulative effect of changes in accounting principles of $(5) million in 2003 and $(61) million in 2002 related to discontinued operations (net of income tax benefit of $3 million in 2003 and

$42 million in 2002). In 2003, $(1) million related to continuing operations (net of income tax benefit of51 million) - (6) (61)

Net Income (Loss) $ 4,504 $ 420 S (874)

Weighted Average Common Shares Outstanding, Basic 398 385 371 Earnings Per Common Share from Continuing Operations, Basic $ 9.16 $ 1.96 $ 4.53 Net Earnings (Loss) Per Common Share, Basic $ 10.80 $ 1.04 $ (2.30)

Earnings Per Common Share from Continuing Operations, Diluted $ 8.97 $ 1.92 $ 4.49 Net Earnings (Loss) Per Common Share, Diluted $ 10.57 $ 1.02 $ (2.27)

See accompanying Notes to the Consolidated Financial Statements.

79 I-

CONSOLIDATED BALANCE SHEETS PG&E CORPORATION Balance at December 31, (in millions) 2004 2()03 ASSETS Current Assets Cash and cash equivalents S 972 $ 3,658 Restricted cash 1 1,980 403 Accounts receivable:

Customers (net of allowance for doubtful accounts of $93 million in 2004 and S68 million in 2003) 2,085 2,424 Related parties 15 Regulatory balancing accounts 1,021 248 Inventories:

Gas stored underground 175 166 Materials and supplies 129 126 fE UI eU n o xFpense 3ou-. l --r r}o ULIi oUwIn .U so Ino Total current assets 6,408 7,148 Property, Plant and Equipment Electric 21,519 20,468 Gas 8,526 8,355 Construction work in progress 449 379 Other 15 20 Total property, plant and equipment 30,509 29,222 Accumulated depreciation (11,520) (11,115)

Net property, plant and equipment 18,989 18,107 Other Noncurrent Assets Regulatory assets 6,526 2,001 Nuclear decommissioning funds 1,629 1,478 Other 988 1,441 Total other noncurrent assets 9,143 4,920 TOTAL ASSETS $34,540 $30,175 See accompanying Notes to the Consolidated Financial Statements.

80

CONSOLIDATED BALANCE SHEETS PG&E CORPORATION Bal1.nce at December 31, (in millions, except share amounts) 2004 2003 LIABILITIES AND SHAREHOLDERS' EQUITY Liabilities Not Subject to Compromise Current Liabilities Short-term borrowings $ 300 $ -

Long-term debt, classified as current 758 310 Rate reduction bonds, classified as current 290 290 Accounts payable:

Trade creditors 762 657 Disputed claims 2,142 Regulatory balancing accounts 369 186 Other 352 402 Interest payable 461 174 Income taxes payable 185 256 Deferred income taxes 394 102 Other 905 761 Total current liabilities 6,918 3,138 Noncurrent Liabilities Long-term debt 7,323 3,314 Rate reduction bonds 580 870 Regulatory liabilities 4,035 3,979 Asset retirement obligations 1,301 1,218 Deferred income taxes 3,531 856 Deferred tax credits 121 127 Net investment in NEGT - 1,216 Preferred stock of subsidiary with mandatory redemption provisions (redeemable, 6.30% and 6.57%, outstanding 4,925,000 shares, due 2005-2009) 122 137 Other 1,690 1,501 Total noncurrent liabilities 18,703 13,218 Liabilities Subject to Compromise Financing debt - 5,603 Trade creditors - 3,715 Total liabilities subject to compromise - 9,318 Commitments and Contingencies (Notes 1, 2, 5 and 12)

Preferred Stock of Subsidiaries 286 286 Preferred Stock Preferred stock, no par value, 80,000,000 shares, $100 par value, 5,000,000 shares, none issued - -

Common Shareholders' Equity Common stock, no par value, authorized 800,000,000 shares, issued 417,014,431 common and 1,601,710 restricted shares in 2004 and 414,985,014 common and 1,535,268 restricted shares in 2003 6,518 6,468 Common stock held by subsidiary, at cost, 24,665,500 shares in 2004 and 23,815,500 shares in 2003 (718) (690)

Unearned compensation (26) (20)

Accumulated earnings (deficit) 2,863 (1,458)

Accumulated other comprehensive loss (4) , (85)

Total common shareholders' equity 8,633 4,215 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY S34,540 $30,175 See accompanying Notes to the Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS PG&E CORPORATION Year ended December 31, (in millions) 2004 2003 2002 Cash Flows From Operating Activities Net income (loss) S 4,504 $ 420 5 (874)

Gain on disposal of NEGT (net of income taxes of S374 million) (684) - -

Loss from discontinued operations - 365 2,536 Cumulative effect of changes in accounting principles - 6 61 Net income from continuing operations 3,820 791 1,723 Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, amortization and decommissioning 1,497 1,222 1,196 Recognition of regulatory assets (4,900) - -

Deferred income taxes and tax credits, net 2,607 190 (281)

Reversal of ISO accrual - - (970)

Other deferred charges and noncurrent liabilities (519) 857 921 Loss from retirement of long-term debt 65 89 153 Tax benefit from employee stock plans 41 - -

Gain on sale of assets (19) (29) -

Net effect of changes in operating assets and liabilities:

Restricted cash 494 (237) (473)

Accounts receivable (85) (605) 212 Inventories (12) (17) 62 Accounts payable 273 403 198 Accrued taxes (122) 173 (619)

Regulatory balancing accounts, net (590) (329) (23)

Other working capital 712 (90) 22 Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise (1,022) (87) (1,442)

Other, net 110 171 135 Net cash provided by operating activities 2,350 2,502 814 Cash Flows From Investing Activities Capital expenditures (1,559) (1,698) (1,547)

Net proceeds from sale of assets 35 49 11 Increase in restricted cash (1,710) - -

Other, net (178) (112) 25 Net cash used in investing activities (3,412) (1,761) (1,511)

Cash Flows From Financing Activities Net borrowings under credit facilities and short-term borrowings 300 -

Proceeds from issuance of long-term debt, net of issuance costs of $107 million in 2004 7,742 581 847 Long-term debt matured, redeemed or repurchased (9,054) (1,068) (1,241)

Rate reduction bonds matured (290) (290) (290)

Preferred stock with mandatory redemption provisions redeemed (15) - -

Common stock issued 162 166 217 Common stock repurchased (378) - -

Preferred dividends paid (90) -

Other, net (1) (4) -

Net cash used in financing activities (1,624) (615) (467)

Net change in cash and cash equivalents (2,686) 126 (1,164)

Cash and cash equivalents atJanuary 1 3,658 3,532 4,696 Cash and cash equivalents at December 31 S 972 $ 3,658 $ 3,532 Supplemental disclosures of cash flow information Cash received for:

Reorganization interest income S 16 $ 39 $ 75 Cash paid for:

Interest (net of amounts capitalized) 646 866 1,414 Income taxes paid (refunded), net 128 (9i) 971 Reorganization professional fees and expenses 61 99 99 Supplemental disclosures of noncash investing and financing activities Transfer of liabilities and other payables subject to compromise (to) from operating assets and liabilities $(2,877) $ 181 $ 419 See accompanying Notes to the Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY PG&E CORPORATION Common Reinvested Accumulated Total stock earnings other common Compre-Common Stock held by Unearned (accumulated comprehensive shareholders' hensive (in millions, except share amounts) Shares tAmount subsidiary compensation deficit) income (loss) equity income (loss)

Balance at December 31, 2001 387,898,848 $5,986 $(690) - S(1,004) $30 S4,322 Net loss - (874) - (874) $(874)

Alark-to-market adjustments for hedging transactions in accordance with SEAS No. 133 (net of income tax benefit of

$44 million) -- (139) (139) (139)

Net reclassification to earnings (net of income tax expense of $4 million) - - - - - 13 13 13 Foreign currency translation adjustment (net of income tax expense of SI million) _ _ _ -- - - -2 2 2 2 Other (net of zero income tax) 1 1 Comprehensive loss $(997)

Common stock issued 17,582,636 217 217 Common stock repurchased (6,580)

Warrants issued 71 71 Common stock warrants exercised 11,111 Balance at December 31, 2002 405,486,015 6,274 (690) _ (1,878) (93) 3,613 Net income - 420 - 420 $420 Alark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax benefit of

$10 million) _ _ - - - (8) (8) (8)

Retirement plan remeasurement (net of income tax benefit of $3 million) _ _ _ _ - (4) (4) (4)

Net reclassification to earnings (net of income tax expense of $27 million) - - - -17 17 17 Foreign currency translation adjustment (net of income tax expense of S5 million) 3 3 3 Comprehensive income S428 Common stock issued 8,796,632 166 166 Common stock warrants exercised 702,367 Common restricted stock issued 1,590,010 28 (28)

Common restricted stock cancelled (54,742) (1) I Common restricted stock amortization 7 7 I

Other Balance at December 31, 2003 416,520,282 6,468 (690) (20) (1,458) (85) 4,215 Net income - 4,504 - 4,504 S4,504 AMark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax expense of $2 million) 3 3 ' 3 NEGT losses reclassified to earnings upon elimination of equity interest by PG&E Corporation (net of income tax expense of $43 million) 77 77 77 Other 1 1 1 Comprehensive income $4,585 Common stock issued 8,410,058 162 - 162 Common stock repurchased (10,783,200) (167) (183) - (350)

Common stock held by subsidiary (28) - (28)

Common stock warrants exercised 4,003,812 Common restricted stock issued 498,910 16 (16)

Common restricted stock cancelled (33,721) (1) 9 Common restricted stock amortization 9 9

Tax benefit from employee stock plans 41 41 Other (1) (I)

Balance at December31, 2004 418,616,141 $6,518 5(718) $(26) $2,863 $(4) $8,633 See accompanying Notes to the Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF OPERATIONS PACIFIC GAS AND ELECTRIC COMPANY Year ended December 31, (in millions) 2004 2003 2002 Operating Revenues Electric S 7,867 S 7,582 $ 8,178 Natural gas 3,213 2,856 2,336 Total operating revenues 11,080 10,438 10,514 Operating Expenses Cost of electricity 2,770 2,319 1,482 Cost of natural gas 1,724 1,467 954 Operating and maintenance 2,842 2,935 2,817 Recognition of regulatory assets (4,900) - -

Depreciation, amortization and decommissioning 1,494 1,218 1,193 Reorganization professional fees and expenses 6 160 155 Total operating expenses 3,936 8,099 6,601 Operating Income 7,144 2,339 3,913 Reorganization interest income 8 46 71 Interest income 42 7 3 Interest expense (non-contractual interest expense ofS31 million in 2004, $131 million in 2003, and S149 million in 2002) (667) (953) (988)

Other income (expense), net 16 13 (2)

Income Before Income Taxes 6,543 1,452 2,997 Income tax provision 2,561 528 1,178 Net Income Before Cumulative Effect of a Change in Accounting Principle 3,982 924 1,819 Cumulative effect of a change in accounting principle (net of income tax benefit of $1 million in 2003) - (1) -

Net Income 3,982 923 1,819 Preferred dividend requirement 21 22 25 Income Available for Common Stock $ 3,961 $ 901 S 1,794 See accompanying Notes to the Consolidated Financial Statements.

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CONSOLIDATED BALANCE SHEETS PACIFIC GAS AND ELECTRIC COMPANY Balance at December 31, (in millions) 2004 2003 ASSETS Current Assets Cash and cash equivalents $ 783 $ 2,979 Restricted cash 1,980 403 Accounts receivable:

Customers (net of allowance for doubtful accounts of S93 million in 2004 and $68 million in 2003) 2,085 2,424 Related parties 2 17 Regulatory balancing accounts 1,021 248 Inventories:

Gas stored underground and fuel oil 175 166 Materials and supplies 129 126 Prepaid expenses and other 43 100 Total current assets 6,218 6,463 Property, Plant and Equipment Electric 21,519 20,468 Gas 8,526 8,355 Construction work in progress 449 379 Total property, plant and equipment 30,494 29,202 Accumulated depreciation (11,507) (11,100)

Net property, plant and equipment 18,987 18,102 Other Noncurrent Assets Regulatory assets 6,526 2,001 Nuclear decommissioning funds 1,629 1,478 Other 942 1,022 Total other noncurrent assets 9,097 4,501 TOTAL ASSETS $34,302 $29,066 I

See accompanying Notes to the Consolidated Financial Statements.

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CONSOLIDATED BALANCE SHEETS PACIFIC GAS AND ELECTRIC COMPANY Balance at December 31, (in millions, except share amounts) 2004 2003 LIABILITIES AND SHAREHOLDERS' EQUITY Liabilities Not Subject to Compromise Current Liabilities Short term borrowings $ 300 $

Long-term debt, classified as'current 757 310 Rate reduction bonds, classified as current 290 290 Accounts payable:

Trade creditors 762 657 Disputed claims 2,142 Related parties 20 224 Regulatory balancing accounts 369 186 Other 337 365 Interest payable 461 153 Income taxes payable -102 Deferred income taxes 377 86 Other 869 637 Total current liabilities 6,786 2,908 Noncurrent Liabilities Long-term debt 7,043 2,431 Rate reduction bonds 580 870 Regulatory liabilities 4,035 3,979 Asset retirement obligations 1,301 1,218 Deferred income taxes 3,629 1,334 Deferred tax credits 121 127 Preferred stock with mandatory redemption provisions (redeemable, 6.30% and 6.57%,

outstanding 4,925,000 shares due 2005-2009) 122 137 Other 1,555 1,471 Total noncurrent liabilities 18,386 11,567 Liabilities Subject to Compromise Financing debt - 5,603 Trade creditors - 3,899 Total liabilities subject to compromise - 9,502 Commitments and Contingencies (Notes 1, 2 and 12)

Shareholders' Equity Preferred stock without mandatory redemption provisions: -

Nonredeemable, 5% to 6%, outstanding 5,784,825 shares 145 145 Redeemable, 4.36% to 7.04%, outstanding 5,973,456 shares 149 149 Common stock, $5 par value, authorized 800,000,000 shares, issued 321,314,760 shares 1,606 1,606 Common stock held by subsidiary, at cost, 19,481,213 shares (475) (475)

Additional paid-in capital 2,041 1,964 Reinvested earnings 5,667 1,706 Accumulated other comprehensive loss (3) (6)

Total shareholders' equity 9,130 5,089 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $34,302 $29,066 See accompanying Notes to the Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS PACIFIC GAS AND ELECTRIC COMPANY Year ended December 31, (in millions) 2004 2003 2002 Cash Flows From Operating Activities Net income $ 3,982 $ 923 $ 1,819 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, amortization and decommissioning 1,494 1,218 1,193 Recognition of regulatory assets (4,900)

Deferred income taxes and tax credits, net 2,580 (75) 378 Reversal of ISO accrual (970)

Other deferred charges and noncurrent liabilities (391) 581 102 Gain on sale of assets (19) (29)

Cumulative effect of a change in accounting principle 1 Net effect of changes in operating assets and liabilities:

Restricted cash 133 (253) (97)

- Accounts receivable (85) (590) 212 Inventories (12) (17) 62 Accounts payable 273 507 198 Accrued taxes 52 48 (345)

Regulatory balancing accounts, net (590) (329) (23)

Other working capital 450 29 11 Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise (1,022) (87) (1,442)

Other, net 26 43 36 Net cash provided by operating activities 1,971 1,970 1,134 Cash Flows From Investing Activities Capital expenditures (1,559) (1,698) (1,546)

Net proceeds from sale of assets 35 49 11 Increase in restricted cash (1,710) - -

Other, net (178) (114) 26 Net cash used in investing activities (3,412) (1,763) (1,509)

Cash Flows From Financing Activities Net borrowings under credit facilities and short-term borrowings 300 Proceeds from issuance of long-term debt, net of issuance costs of S107 million in 2004 7,742 - -

Long-term debt matured, redeemed or repurchased (8,402) (281) (333)

Rate reduction bonds matured (290) (290) (290)

Preferred dividends paid (90) - -

Preferred stock with mandatory redemption provisions redeemed (15) - -

Net cash used in financing activities (755) (571) (623)

Net change in cash and cash equivalents (2,196) (364) (998)

Cash and cash equivalents at January 1 2,979 3,343 4,341 Cash and cash equivalents at December 31 S 783 S 2,979 $ 3,343 Supplemental disclosures of cash flow information Cash received for:

Reorganization interest income $ 16 S 39 $ 75 Cash paid for:

Interest (net of amounts capitalized) 512 773 1,105 Income taxes paid, net 109 648 1,186 Reorganization professional fees and expenses 61 99 99 Supplemental disclosures of noncash investing and financing activities Transfer of liabilities and other payables subject to compromise (to) from operating assets and liabilities $(2,877) S 181 S 419 Equity contribution for settlement of POR payable (129)

See accompanying Notes to the Consolidated Financial Statements.

87 S

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY PACIFIC GAS AND ELECTRIC COMPANY Preferred stock without Common Reinvested Accumulated manditory Additional stock earnings other Total Compre-redemption Common paid-in held by (accumulated comprehensive shareholders' hensive (in millions, except share amounts) provisions stock capital subsidiary defict) income (loss) equity income Balance at December 31, 2001 S294 SI,606 $1,964 S(475) S(989) $(2) $2,398 Net Income - - - - 1,819 - 1,819 $1,819 Foreign currency translation adjustments (net of income tax expense of $1 million) 2 Comprehensive income $1,821 Preferred stock dividend - - - - (25) - (25)

Balance at December 31, 2002 294 1,606 1,964 (475) 805 - 4,194 Net Income - - - - 923 - 923 $923 Retirement plan remeasurement (net of income tax benefit of $2 million) - - - - - (3) (3) (3)

Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax benefit of $2 million) - (3) (3) (3)

Comprehensive income $917 Preferred stock dividend - - - - (22) - (22)

Balance at December 31, 2003 294 1,606 1,964 (475) 1,706 (6) S,089 Net Income - - - - 3,982 - 3,982 $3,982 Alark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax expense ofS2 million) _ _ _ _ _ 3 3 3 Comprehensive income $3,985 Equity contribution for settlement of POR payable (net of income taxes of $52 million) - - 77 - - - 77 Preferred stock dividend - - - - (21) - (21)

Balance at December 31, 2004 $294 $1,606 S2,041 5(475) $5,667 5(3) $9,130 See accompanying Notes to the Consolidated Financial Statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: GENERAL addition, as discussed in Note 5, effectiveJuly 8, 2003, PG&E Corporation no longer consolidated the earnings and losses of ORGANIZATION AND NEGT or its subsidiaries and began accounting for its owner-BASIS OF PRESENTATION ship interest in NEGT using the cost method, under which PG&E Corporation's investment in NEGT is reflected as a PG&E Corporation, incorporated in California in 1995, is an single amount within the December 31, 2003 Consolidated energy-based holding company that conducts its business Balance Sheet of PG&E Corporation. On October 29, 2004, principally through Pacific Gas and Electric Company, or the NEGT's plan of reorganization became effective and NEGT Utility, a public utility operating in northern and central emerged from Chapter 11, at which time PG&E Corporation's California. The Utility engages primarily in the businesses of equity interest in NEGT was cancelled.

electricity and natural gas distribution, electricity generation, procurement and transmission, and natural gas procurement, This is a combined annual report of PG&E Corporation and transportation and storage. PG&E Corporation became the the Utility. Therefore, the Notes to the Consolidated Financial holding company of the Utility and its subsidiaries onJanu- Statements apply to both PG&E Corporation and the Utility.

ary 1, 1997. The Utility, incorporated in California in 1905, is PG&E Corporatibn's Consolidated Financial Statements the predecessor of PG&E Corporation. include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility's As discussed further in Note 2, on April 12, 2004, the Util-Consolidated Financial Statements include its accounts and ity's plan of reorganization under the provisions of Chapter 11 those of its wholly owned and controlled subsidiaries and vari-of the U.S. Bankruptcy Code, or Chapter 11, became effective, able interest entities for which it is subject to a majority of the at which time the Utility emerged from Chapter 11.

risk of loss or gain. All intercompany transactions have been Prior to October 29, 2004, the effective date of the plan of eliminated from the Consolidated Financial Statements.

reorganization of National Energy & Gas Transmission, Inc., or The preparation of financial statements in conformity with NEGT, formerly known as PG&E National Energy Group, accounting principles generally accepted in the United States of Inc., was the other significant subsidiary of PG&E Corporation.

America, or GAAP, requires management to make estimates and NEGT was incorporated on December 18, 1998, as a wholly assumptions. These estimates and assumptions affect the owned subsidiary of PG&E Corporation. On July 8, 2003, reported amounts of revenues, expenses, assets and liabilities NEGT filed a voluntary petition for relief under Chapter 11.

and the disclosure of contingencies and include, but are not For the reasons described below in Note 5, PG&E Corporation limited to, estimates and assumptions used in determining the considered NEGT to be an abandoned asset under Statement Utility's regulatory asset and liability balances based on proba-of Financial Accounting Standards, or SFAS, "Accounting for bility assessments of regulatory recovery, revenues earned but Impairment or Disposal of Long-Lived Assets," or SFAS not yet billed (including delayed billings), disputed claims, asset No. 144, and, as a result, the operations of NEGT prior to July 8, 2003 and for all prior periods, are reflected as discontin-ued operations in the Consolidated Financial Statements. In 89

retirement obligations, allowance for doubtful accounts receiv- related to the Utility's Chapter 11 proceeding and interest able, provisions for losses that are deemed probable from income on funds accumulated during the Chapter 11 proceed-environmental remediation liabilities, pension liabilities, mark- ings were reported separately as reorganization items.

to-market accounting under SFAS No. 133, "Accounting for The Utility discontinued the application of SOP 90-7 upon Derivative Instruments and Hedging Activities," as amended, or its emergence from Chapter 11 on April 12, 2004. The Consol-SFAS No. 133, income tax related liabilities, litigation, and the idated Financial Statements as of and for the years ending-Utility's review for impairment of long-lived assets and certain December 31, 2003 and 2002, have been presented in accor-identifiable intangibles to be held and used whenever events or dance with SOP 90-7. Although the Utility emerged from changes in circumstances indicate that the carrying amount of Chapter 11 on April 12, 2004, the bankruptcy court retained its assets might not be recoverable. As these estimates and jurisdiction, among other things, to resolve disputed claims assumptions involve judgments on a wide range of factors, made in the Chapter 11 case. Upon the effective date of the including future regulatory decisions and economic conditions Utility's plan of reorganization, $1.8 billion was deposited into that are difficult to predict, actual results could differ from these escrow, pending the resolution of disputed claims, and has been estimates. PG&E Corporation's and the Utility's Consolidated classified as restricted cash in current assets on PG&E Corpora-Financial Statements reflect all adjustments that management tion's and the Utility's December 31, 2004 Consolidated believes are necessary for the fair presentation of their financial Balance Sheets. The related remaining pre-petition disputed position and results of operations for the periods presented.

claims are subject to resolution by the bankruptcy court and are During the Utility's Chapter 11 proceeding, PG&E Corpo- classified as current liabilities on the Consolidated Balance ration's and the Utility's Consolidated Financial Statements are Sheets at December 31, 2004.

presented in accordance with the American Institute of Certi-fied Public Accountants' Statement of Position 90-7, "Financial Reclassifications Reporting by Entities in Reorganization Under the Bankruptcy Certain amounts in the 2003 and 2002 Consolidated Financial Code," or SOP 90-7. Under SOP 90-7, certain claims against Statements and Notes to the Consolidated Financial Statements the Utility existing before the Utility filed its Chapter 11 peti- have been reclassified to conform to the 2004 presentation.

tion were classified as liabilities subject to compromise on These reclassifications did not affect the consolidated net PG&E Corporation's and the Utility's Consolidated Balance income of PG&E Corporation and the Utility for the periods Sheets. Additionally, professional fees and expenses directly presented, nor did they impact revenues, operating income, cur-rent assets or liabilities, or total assets or equity.

Earnings (Loss) Per Share Earnings (loss) per share is calculated utilizing the "two-class" method by dividing earnings (loss) allocated to common share-holders by the weighted average number of common shares outstanding during the period.

90

The following is a reconciliation of PG&E Corporation's net income (loss) and weighted average common shares outstanding for calculating basic and diluted net income (loss) per share:

Year ended December 31, (in millions, except per share amounts) 2004 2003 2002 Income from continuing operations $3,820 $ 791 $1,723 Discontinued operations 684 (365) (2,536)

Net income (loss) before cumulative effect of changes in accounting principles 4,504 426 (813)

Cumulative effect of changes in accounting principles - (6) (61)

Net income (loss) for basic and diluted calculations 4,504 420 (874)

Weighted average common shares outstanding, basic 398 385 371 9.50% Convertible Subordinated Notes 19 19 9

'Weighted average common shares outstanding and participating securities, basic 417 404 380 Weighted average common shares outstanding, basic 398 385 371 Employee Stock Options, Restricted Stock and PG&E Corporation shares held by grantor trusts and accelerated share repurchase agreement(l) 7 4 2 PG&E Corporation Warrants 2 5 2 Weighted average common shares outstanding, diluted 407 394 375 9.50% Convertible Subordinated Notes 19 19 9 Weighted average common shares outstanding and participating securities, diluted 426 413 384 Earnings (Loss) Per Common Share, Basic Income from continuing operations $ 9.16 S 1.96 $ 4.53 Discontinued operations 1.64 (0.90) (6.67)

Cumulative effect of changes in accounting principles - (0.01) (0.16)

Rounding - (0.01) -

Net earnings (loss) per common share, basic $10.80 S 1.04 S (2.30)

Earnings (Loss) Per Common Share, Diluted Income from continuing operations S 8.97 S 1.92 $ 4.49 Discontinued operations 1.60 (0.88) (6.60)

Cumulative effect of changes in accounting principles - (0.01) (0.16)

Rounding - (0.01) -

Net earnings (loss) per common share, diluted S 10.57 S 1.02 $ (2.27)

' Includes approximately 222,000 shares of PG&E Corporation common stock potentially issuable in settlement of an obligation of PG&E Corporation of approximately $7.4 million under an accelerated share repurchase agreement at December 31, 2004. See Note 6 for further discussion.

On March 31, 2004, the Financial Accounting Standards PG&E Corporation currently has outstanding $280 million Board, or FASB, ratified the consensus reached by the Emerg- of 9.50% Convertible Subordinated Notes due 2010, or ing Issues Task Force, or the EITF, on EITT Issue 03-06, Convertible Subordinated Notes, that are entitled to receive "Participating Securities and the Two-Class Method under (non-cumulative) dividend payments without exercising the FASB Statement No. 128," or EITF 03-06. EITF 03-06 pro-. conversion option. These Convertible Subordinated Notes vides additional guidance related to the calculation of earnings meet the criteria of a participating security in the calculation of per share under SFAS No. 128, "Earnings per Share," or SFAS basic earnings per share using the "two-class" method of SFAS No. 128, which includes application of the "two-class" method in computing earnings per share, identification of participating securities, and requirements for the allocation of undistributed earnings (and losses) to participating securities.

91

No. 128. Therefore, EITF 03-06 requires that earnings be allo- inclusion of participation rights related to PG&E Corporation's cated between common stock and the participating security. Convertible Subordinated Notes in the allocation of earnings.

PG&E Corporation adopted EITF 03-06 in the first quarter of The Convertible Subordinated Notes are convertible at the 2004 and for all subsequent and all prior periods presented. option of the holders into 18,558,655 common shares. All PG&E Corporation's participating securities participate on a In applying the "two-class" method, the following reflects 1: 1 basis in dividends with common shareholders.

the earnings (loss) allocated to common shareholders after the (in millions) 2004 2003 2002 Earnings (loss) allocated to common shareholders, basic Income from continuing operations $3,646 S 754 $1,682 Discontinued operations 653 (348) (2,476)

Cumulative effect of changes in accounting principles - (6) (60)

Rounding - - I

$4,299 S 400 S (853)

Earnings (loss) allocated to common shareholders, diluted Income from continuing operations $3,650 $ 755 $1,683 Discontinued operations 653 (348) (2,476)

Cumulative effect of changes in accounting principles - (6) (60)

$4,303 S 401 $ (853)

Options to purchase PG&E Corporation common shares of "Accounting and Disclosure Requirements Related to the 7,046,710 in 2004, 16,008,087 in 2003 and 21,150,557 in 2002 Medicare Prescription Drug, Improvement and Modernization were outstanding, but not included in the computation of Act of 2003," and provides guidance on the accounting, disclo-diluted earnings per share because the option exercise prices sure, effective date, and transition requirements related to the -

were greater than the average market price. Medicare Prescription Drug Act. FSP 106-2 was effective for the third quarter of 2004. The adoption of FSP 106-2 did not PG&E Corporation reflects the preferred dividends of sub-have any impact on the Consolidated Financial Statements of sidiaries as other expense for computation of both basic and PG&E Corporation or the Utility.

diluted earnings per share.

The U.S. Department of Health and Human Services issued ADOPTION OF NEW ACCOUNTING the final regulations on prescription drug benefits onJanu-POLICIES AND

SUMMARY

OF SIGNIFICANT ary 21, 2005. Despite the initial preliminary conclusion that the

.ACCOUNTING POLICIES Utility's postretirement medical plan, or the Plan, did not qual-The accounting policies used by PG&E Corporation and the ify for the federal subsidy, the final regulations may allow the Utility include those necessary for rate-regulated enterprises, Plan to qualify for the federal subsidy. PG&E Corporation and which reflect the ratemaking policies of the California Public the Utility are continuing to evaluate the effects, if any, of the Utilities Commission, or the CPUC, or the Federal Energy final regulations on the Plan, and the impact on the Consoli-Regulatory Commission, or the FERC. dated Financial Statements.

Accounting and Disclosure Requirements Related to the Consolidation of Variable Interest Entities Medicare Prescription Drug, Improvement and In December 2003, FASB issued Interpretation No. 46 (revised Modernization Act of 2003 December 2003), "Consolidation of Variable Interest Entities,"

In May 2004, FASB issued Staff Position SEAS No. 106-2, or FIN 46R. FIN 46R provides that an entity is a variable inter-

"Accounting and Disclosure Requirements Related to the est entity, or VIE, if it does not have sufficient equity Medicare Prescription Drug, Improvement and Modernization investment at risk, or if the holders of the entity's equity instru-Act of 2003," or FSP 106-2. FSP 106-2 supersedes FSP 106-1, ments lack the essential characteristics of a controlling financial interest. FIN 46R requires that the company that is subject to a majority of the risk of loss from a VIE's activities, or is entitled 92

to receive a majority of the entity's residual returns, or both, 2004, PG&E Corporation and the Utility adopted the new consolidate the VIE. A company that consolidates a VIE is DIG C15 guidelines for certain power contracts that contain called the primary beneficiary. option-like features that existed prior to July 1, 2003. The adop-tion of DIG C1 5 did not have any impact on the Consolidated PG&E Corporation and the Utility adopted FIN 46R on Financial Statements of PG&E Corporation or the Utility.

January 1, 2004. The adoption of FIN 46R did not have any impact on net income.

Regulation and Statement of Financial Accounting Low-Incomie Housing Partnerships Standards No. 71 The Utility invests in low-income housing partnerships, or PG&E Corporation and the Utility account for the financial LIHPs. The entities were formed to invest in low-income hous- effects of regulation in accordance with "Accounting for the ing projects sponsored by non-profit organizations in the state Effects of Certain Types of Regulation," as amended, or SFAS of California. The Utility determined that it was the primary No. 71. SPAS No. 71 applies to regulated entities whose rates beneficiary of one LIHP, resulting in its consolidation, and an are designed to recover the costs of providing service. The Util-increase in total assets and total liabilities of $12 million in ity is regulated by the CPUC, the FERC and the Nuclear PG&E Corporation's and the Utility's Consolidated Balance Regulatory Commission, or the NRC, among others. As dis-Sheets. The consolidated LIHP has issued debt in the amount cussed further in Note 2, during the first quarter of 2004, the of $5 million, which is secured by assets of the partnership, total- Utility began reapplying SFAS No. 71 to its generation opera-ing $26 million, and the Utility's commitment to make capital tions. As a result, as of March 31, 2004, the Utility recorded a infusions of approximately $11 million over the next five years. generation regulatory asset of approximately $1.2 billion. SPAS No. 71 now applies to all of the Utility's operations except for The Utility is not considered to be the primary beneficiary the operations of a natural gas pipeline.

of any other LIHPs. The maximum exposure to loss from its investment in unconsolidated LIlIPs is the Utility's investment SPAS No. 71 provides for recording regulatory assets and of $5 million at December 31, 2004. liabilities when certain conditions are met. Regulatory assets represent the capitalization of incurred costs that would other-Power PurchaseAgreements wise be charged to expense when it is probable that the incurred costs will be included for ratemaking purposes in the future.

The nature of power purchase agreements is such that the Util-Regulatory liabilities represent rate actions of a regulator that ity could have a significant variable interest in a power purchase will result in amounts that are to be credited to customers agreement counterparty if that entity is a VIE owning one plant that sells substantially all of its output to the Utility, and the through the ratemaking process.

contract price for power is correlated with the plant's variable To the extent that portions of the Utility's operations cease to costs of production. The Utility determined that none of its be subject to SPAS No. 71 or recovery is no longer probable as a current power purchase agreements represent significant vari- result of changes in regulation or the Utility's competitive posi-able interests. The EITF continues to review how companies tion, the related regulatory assets and liabilities are written off.

determine whether an arrangement is a variable interest. Their findings could impact how the determination is applied to the Accounting for Financial Instruments with Utility's power purchase agreements in the future. Characteristics of Both Liabilities and Equity In May 2003, the FASB issued Statement No. 150, "Accounting Changes in Accounting for Certain Derivative Contracts for Certain Financial Instruments with Characteristics of Both In November 2003, the FASB approved an amendment to an Liabilities and Equity," or SPAS No. 150. SPAS No. 150 interpretation issued by the Derivatives Implementation Group, addresses concerns of how to measure and classify in the bal-C15, or DIG C15, as previously amended in October 2001 and ance sheet certain financial instruments that have characteristics December 2001, that changed the definition of normal pur- of both liabilities and equity. The following freestanding finan-chases and sales for certain power contracts that contain cial instruments must be classified as liabilities: mandatorily option-like features. redeemable financial instruments, obligations to repurchase an issuer's equity shares by transferring assets, and certain obliga-PG&E Corporation and the Utility had previously adopted tions to issue a variable number of shares.

the new DIG C15 guidelines prospectively for new derivative instruments entered into afterJune 30, 2003. On January 1, 93

PG&E Corporation and the Utility adopted the requirements renewed continuously because the Utility intends to utilize these of SEAS No. 150 in the third quarter of 2003. As a result, the facilities indefinitely. Since the timing and extent of any potential Utility reclassified approximately $137 million of preferred stock asset retirements are unknown, the fair value of any obligations with mandatory redemption provisions as a noncurrent liability. associated with these facilities cannot be reasonably estimated.

The reclassification did not have an impact on earnings of PG&E The Utility collects estimated removal costs in rates through Corporation or the Utility. Upon adopting SFAS No. 150, all depreciation in accordance with regulatory treatment. These amounts paid or to be paid to the holders of preferred stock with amounts do not represent SEAS No. 143 asset retirement obli-mandatory redemption provisions in excess of the initial meas-gations. Historically, these removal costs have been recorded in ured amount are reflected in interest expense. Dividends paid or accumulated depreciation. However, as a result of guidance accrued in prior periods have not been reclassified.

from the staff of the Securities and Exchange Commission, or SEC, the Utility reclassified this obligation to a regulatory lia-Accounting for Asset Retirement Obligations bility in its 2003 and 2002 Consolidated Balance Sheet during On January 1, 2003, PG&E Corporation and the Utility 2003. The Utility's estimated removal costs recorded as a regu-adopted SFAS No. 143, "Accounting for Asset Retirement latory liability were approximately $2.0 billion at December 31, Obligations," or SFAS No. 143. The Utility identified its 2004 and approximately $1.8 billion at December 31, 2003.

nuclear generation and certain fossil fuel generation facilities as having asset retirement obligations under SFAS No. 143. SEAS Accounting for Goodwill and Other Intangible Assets No. 143 requires that an asset retirement obligation be recorded PG&E Corporation and the Utility had no goodwill on their at fair value in the period in which it is incurred if a reasonable Consolidated Balance Sheets at December 31, 2004 or 2003.

estimate of fair value can be made. In the same period, the asso-Other intangible assets consist mainly of hydroelectric facility ciated asset retirement costs are capitalized as part of the licenses and other agreements, with lives ranging from 17 to 40 carrying amount of the related long-lived asset. In each subse-years. The gross carrying amount of the hydroelectric facility quent period, the liability is accreted to its present value and the licenses and other agreements was approximately $73 million at capitalized cost is depreciated over the useful life of the long-December 31, 2004 and December 31, 2003. The accumulated lived asset. Rate-regulated entities may recognize regulatory.

amortization was approximately $23 million at December 31, assets or liabilities as a result of timing differences between the 2004 and $19 million at December 31, 2003.

recognition of costs as recorded in accordance with SFAS No.

143 and costs recovered through the ratemaking process. The The Utility's amortization expense related to intangible cumulative effect of the change in accounting principle for the assets was approximately $4 million in 2004, $3 million in 2003 Utility's fossil fuel facilities as a result of adopting SFAS No. 143 and $3 million in 2002. The estimated annual amortization was a loss of approximately $1 million, after-tax. expense based on the December 31, 2004 intangible asset bal-ance for the Utility's intangible assets for 2005 through 2009 is The Utility has established trust funds that are legally approximately $4 million each year.

restricted for purposes of settling its nuclear decommissioning obligations. The fair value and carrying value of these trust Cash and Cash Equivalents funds was approximately $1.6 billion at December 31, 2004 and approximately $1.5 billion at December 31, 2003. Invested cash and other investments with original maturities of three months or less are considered cash equivalents. Cash The Utility may have potential asset retirement obligations equivalents are stated at cost, which approximates fair value.

under various land right documents associated with its transmis- PG&E Corporation and the Utility primarily invest their cash sion and distribution facilities. The majority of the Utility's land in money market funds and in short-term obligations of the rights are perpetual. Any non-perpetual land rights generally are U.S. government and its agencies.

The Utility had account balances with Citigroup Asset Alan-agement and Janus Capital Group that were greater than 10%

of PG&E Corporation's and the Utility's total cash and cash equivalents balance at December 31, 2004.

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Restricted Cash Investments in Affiliates Restricted cash includes Utility amounts held in escrow as The Utility has investments in unconsolidated affiliates, which required by the bankruptcy court related to remaining disputed are mainly engaged in the purchase of low-income residential claims and as collateral while in Chapter 11, as required by the real estate property. The equity method of accounting is applied California Independent System Operator, or ISO, the State of to the Utility's investment in these entities. Under the equity California and other counterparties. The Utility also provides method, the Utility's share of equity income or losses of these deposits to counterparties in the normal course of operations entities is reflected as equity in earnings of affiliates. As of Decem-and under certain third party agreements. ber 31, 2004, the Utility's recorded investment in these entities totaled approximately $5 million in accordance with the equity Inventories method of accounting. As a limited partner, the Utility's exposure Inventories include materials, supplies and gas stored under- to potential loss is limited to its investment in each partnership.

ground and are valued at average cost. Materials and supplies are charged to inventory when purchased and then expensed or Related Party Agreements and Transactions capitalized to plant, as appropriate, when installed. Materials In accordance with various agreements, the Utility and other provisions are made for obsolete inventory. Gas stored under- subsidiaries provide and receive various services to and from ground is charged to inventory when purchased and then their parent, PG&E Corporation, and among themselves. The expensed upon distribution. Utility and PG&E Corporation exchange administrative and professional services in support of operations. These services Income Taxes are priced either at the fully loaded cost (ie., direct costs and PG&E Corporation and the Utility use the liability method of allocations of overhead costs) or at the higher of fully loaded accounting for income taxes. Income tax expense (benefit) cost or fair market value, depending on the nature of the serv-includes current and deferred income taxes resulting from oper- ices. PG&E Corporation also allocates certain other corporate ations during the year. Investment tax credits are amortized administrative and general costs to the Utility and other sub-over the life of the related property. Other tax credits, mainly sidiaries using agreed allocation factors, including the number synthetic fuel tax credits, are recognized in income as earned. of employees, operating expenses excluding fuel purchases, total assets and other cost allocation methodologies. The Utility pur-PG&E Corporation files a consolidated U.S. (federal) chases natural gas transportation services from Gas income tax return that includes domestic subsidiaries in which Transmission Northwest Corporation, or GTNIN, formerly its ownership is 80% or more. In addition, PG&E Corporation known as PG&E Gas Transmission, Northwest Corporation.

files combined state income tax returns where applicable. Effective April 1, 2003, the Utility no longer purchases natural PG&E Corporation and the Utility are parties to a tax-sharing gas from NEGT Energy Trading Holdings Corporation, or arrangement under which the Utility determines its income tax NEGT ET, formerly know as PG&E Energy Trading Hold-provision (benefit) on a stand-alone basis. ings Corporation. Both GTNWV and NTEGT ET are no longer Prior to July 8, 2003, the date of NEGT's Chapter 11 filing, related parties after the cancellation of PG&E Corporation's PG&E Corporation recognized federal income tax benefits equity interest in NEGT on the effective date of its plan of related to the losses of NEGT and its subsidiaries. However, reorganuzation, October 29, 2004. The Utility sold natural gas afterJuly 7, 2003, under the cost method of accounting PG&E transportation capacity and other ancillary services to NEGT Corporation has not recognized additional income tax benefits ET until NEGT's Chapter 11 proceeding was imminent. These for financial reporting purposes with respect to the losses of services were priced at either tariff rates or fair mark-et value, NEGT and its subsidiaries. PG&E Corporation is required to depending on the nature of the services provided. Through continue to include NEGT and its subsidiaries in its consoli- July 7, 2003, all significant intercompany transactions with dated income tax returns covering all periods through October 29, 2004, the effective date of NEGT's plan of reor-ganization and the cancellation of its equity ownership in NEGT. See Note 11 for further discussion.

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NEGT and its subsidiaries were eliminated in consolidation; are no longer eliminated in consolidation. The Utility's signifi-therefore, no profit or loss resulted from these transactions. cant related party transactions and related receivable (payable)

Beginning July 8, 2003, the Utility's transactions with NEGT balances were as follows:

Receivable (Payable)

Balance Outstanding at Year ended Year ended December 31, December 31, (inmillions) 2004 2003 2002 2004 2003 Utility revenues from:

Administrative services provided to PG&E Corporation S8 S 8 S 7 S 1 $

Natural gas transportation capacity services provided to NEGT ET _ 8 9 Contribution in aid of construction received from NEGT 2 Trade deposit due from GTNWV _ 3 15 Utility expenses from:

Administrative senices received from PG&E Corporation S81 S183 S106 $(20) $(396)

Interest accrued on pre-petition liabilities due to PG&E Corporation 2 6 8 (2)

Administrative services received from NEGT - 2 2 (1)

Software purchases from NEGT ET - 1 Natural gas commodity services received from NEGT ET - 10 49 Natural gas transportation services received from GTNWV 43 58 47 (8)

Trade deposit due to NEGT ET - (7) 7 As discussed further in Note 2, as of March 31, 2004, PG&E Property, Plant and Equipment Corporation recorded the impact of the settlement agreement, Property, plant and equipment are reported at their original entered into on December 19, 2003, among PG&E Corpora- costs. Original costs include:

tion, the Utility and the CPUC to resolve the Utility's Chapter 11 case, or the Settlement Agreement. The Settlement

• Labor and materials; Agreement precluded the Utility from reimbursing PG&E Cor-

• Construction overhead; and poration for certain Chapter 11 related costs. As such, PG&E Corporation reduced its receivable from the Utility, and the

• Capitalized interest or an allowance for funds used during Utility reduced its payable to PG&E Corporation by $129 mil- construction, or AFUDC.

lion. The transactions were recorded as a contribution of equity As discussed in Note 3, substantially all of the Utility's real to the Utility by PG&E Corporation, net of taxes of $52 mil- property and certain tangible personal property related to the lion, and an increase to additional-paid-in-capital by the Utility Utility's facilities serve as collateral for the first mortgage bonds, in the first quarter of 2004. or First Mortgage Bonds.

CapitalizedInterest andAFUDC- AFUDC is the estimated cost of debt and equity funds used to finance regulated plant additions that is allowed to be recorded as part of the costs of construction projects. AFUDC is recoverable from customers through rates once the property is placed in service. The Utility had capitalized interest and AFUDC of approximately $32 million at Decem-ber 31, 2004 and $29 million at December 31, 2003. PG&E Corporation on a stand-alone basis did not have any capitalized interest and AFUDC at December 31, 2004 and 2003.

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Depreciation- The Utility's composite depreciation rate was Impairment of Long-Lived Assets 3.42% in 2004, 2003 and 2002. The carrying values of long-lived assets are evaluated in accor-dance with the provisions of SPAS No. 144. In accordance with Estimated SFAS No. 144, PG&E Corporation and the Utility evaluate the (in millions) Gross Plant usefwl lives carrying amounts of long-lived assets for impairment whenever Electricity generating facilities S 1,885 15 to 50 years events occur or circumstances change that may affect the recov-Electricity distribution facilities 13,962 16 to 58 years erability or the estimated life of long-lived assets. SFAS No. 144 Electricity transmission 3,644 40 to 70 years Natural gas distribution facilities 4,634 23 to 54years became effective at the beginning of 2002 and supersedes SPAS Natural gas transportation 2,828 25 to 45 years No. 121, "Accounting for the Impairment or Disposal of Long-Natural gas storage 47 25 to 48 years Lived Assets and for Long-Lived Assets to Be Disposed Of,"

Other 3,045 5 to 40 years and the accounting and reporting provisions of Accounting Total $30,045 Principles Board Opinion No. 30, "Reporting the Results of Operations for a Disposal of a Segment of a Business." The adoption of SPAS No. 144 did not have a material impact on The useful lives of the Utility's property, plant and equip- the consolidated financial position, results of operations or cash ment are authorized by the CPUC and the FERC and flows of PG&E Corporation or the Utility. During 2003 and depreciation expense is included within the recoverable costs of 2002, NEGT recorded certain impairment charges in accor-service included in rates charged to customers. Depreciation dance with SPAS No. 144. See Note 5 for further discussion.

expense includes a component for the original cost of assets and a component for estimated future removal costs, net of any sal- Gains and Losses on Debt Extinguishments vage value at retirement. The Utility has a separate rate Gains and losses on debt extinguishments associated with regu-component for the accrual of its recorded obligation for nuclear lated operations that are subject to the provisions of SPAS decommissioning, which is included in depreciation, amortiza- No. 71 are deferred and amortized over the remaining original tion and decommissioning expense in the accompanying amortization period of the debt reacquired, consistent with Consolidated Statements of Operations. recovery of costs through regulated rates. Gains and losses on PG&E Corporation and the Utility charge the original cost debt extinguishments associated with unregulated operations of retired plant and removal costs less salvage value to accumu- are recognized at the time such debt is reacquired and are lated depreciation upon retirement of plant in service for the reported as interest expense.

Utility's lines of business that apply SPAS No. 71, which include electricity and natural gas distribution, electricity generation Fair Value of Financial Instruments and transmission, and natural gas transportation and storage. The fair value of a financial instrument represents the amount PG&E Corporation and the Utility expense repair and mainte- at which the instrument could be exchanged in a current trans-nance costs as incurred. action between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair NuclearFuel - Property, plant and equipment also includes value and carrying amount of financial instruments that are nuclear fuel inventories. Stored nuclear fuel inventory is stated recorded at historical amounts.

at weighted average cost. Nuclear fuel in the reactor is amor-tized based on the amount of energy output.

CapitalizedSoftare Costs - PG&E Corporation and the Utility capitalize costs incurred during the application development stage of internal use software projects to property, plant and.

equipment. Capitalized software costs totaled $231 million at December 31, 2004 and $273 million at December 31, 2003, net of accumulated amortization of approximately $196 million at December 31, 2004 and $159 million at December 31, 2003.

PG&E Corporation and the Utility amortize capitalized soft-ware costs ratably over the expected lives of the projects ranging from 3 to 15 years, commencing upon operational use, in accordance with regulatory recovery requirements.

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PG&E Corporation and the Utility use the following

• The fair values of fixed rate First Mortgage Bonds, fixed rate methods and assumptions in estimating fair value disclosures for pollution control loan agreements, rate reduction bonds, and financial instruments: the Utility's preferred stock were determined based on quoted market prices; and The fair values of cash and cash equivalents, restricted cash and deposits, net accounts receivable, price risk management

• The fair value of PG&E Corporation's 9.50% Convertible assets and liabilities, short-term borrowings, accounts payable, Subordinated debt for which no market quotation is readily customer deposits, the Utility's variable rate pollution control available, was determined by a third-party using the present bond loan agreements, Floating Rate First Mortgage Bonds value of future cash flows incorporating estimates of borrow-due 2006, and the pollution control bond bridge facilities ing rates currently available to PG&E Corporation for approximate their carrying values as of December 31, 2004 instruments of similar maturity and the Black-Scholes option and 2003; valuation model (including a stock volatility assumption of 15-20%).

The carrying amount and fair value of PG&E Corporation's and the Utility's financial instruments are as follows (the table below excludes financial instruments with fair values that approximate their carrying values, as these instruments are presented in the Consolidated Balance Sheets):

At December 31, 2004 2003 Carrying Carrying (in millions) Amount Fair Value Amount Fair Value Long-term debt (Note 3):

PG&E Corporation Convertible subordinated notes" 1) 280 738 280 649 Utility 5,632 5,813 4,839 4,905 Rate reduction bonds (Note 4) 870 911 1,160 1,252 Utility preferred stock with mandatory redemption provisions (Note 7) 122 127 137. 167

'1) Excludes the estimated fair value of dividend participation rights component on a pre-tax basis of approximately $91 million at December 31, 2004.

See Note 3 for further discussion.

Regulatory Assets Amortization of regulatory assets are charged to expense Regulatory assets comprise the following: during the period that the costs are reflected in regulated rev-enues. In light of the satisfaction of various conditions to the Balance at December 31, implementation of the plan of reorganization, the accounting probability standard required to be met under SFAS No. 71 in (in millions) 2004 2003 order for the Utility to recognize the regulatory assets provided Settlement Regulatory Asset S3,188 S -

under the Settlement Agreement (as described in Note 2) was Utility retained generation regulatory assets 1,181 Rate reduction bond assets 741 1,054 met as of March 31, 2004. Therefore, the Utility recorded the Regulatory assets for deferred income tax 490 324 $3.7 billion, .epre-tax ($2.2 billion, after-tax), regulatory u

asset Unamortized loss, net of gain, on established under the Settlement Agreement, or the Settlement reacquired debt 345 277 Regulatory Asset, and $1.2 billion, pre-tax ($0.7 billion, after-Environmental compliance costs 192 139 tax), for the Utility retained generation regulatory assets in the Post-transition period contract termination costs 142 -151 first quarter of 2004 (see Note 2 for further discussion). As of Regulatory assets associated with plan of reorganization 182 December 31, 2004, the Utility has recorded pre-tax offsets to Other, net 65 56 the Settlement Regulatory Asset of approximately $309 million

($183 million after-tax) for supplier settlements and approxi-Total regulatory assets -$6,526 $2,001 mately $233 million ($138 million, after-tax) for amortization of the Settlement Regulatory Asset.

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The Utility's regulatory asset related to rate reduction bonds liabilities related to employee benefit plan expenses represent is amortized simultaneously with the amortization of the rate the cumulative differences between expenses recognized for reduction bonds liability, and is expected to be recovered by the financial accounting purposes and expenses recognized for end of 2007. The Utility's regulatory assets related to deferred ratemaking purposes. These balances will be charged against income tax will be recovered over the period of reversal of the expense to the extent that future financial accounting expenses accumulated deferred taxes to which they relate. Based on cur- exceed amounts recoverable for regulatory purposes. The regu-rent regulatory ratemaking and income tax laws, the Utility latory liability associated with over-recovery of asset retirement expects to recover deferred income tax-related regulatory assets costs represents timing differences between the recognition of over periods ranging from 1 to 37 years. The Utility's regula- nuclear decommissioning obligations in accordance with GAAP tory asset related to the unamortized loss, net of gain, on applicable to non-regulated entities under SFAS No. 143, and reacquired debt will be recovered over the remaining original the amounts recognized for ratemaking purposes. The Utility's amortization period of the reacquired debt over periods ranging regulatory liability related to public purpose programs repre-from 1 to 22 years. The Utility's regulatory asset related to sents revenues designated for public purpose program costs that environmental compliance represents the portion of the Util- are expected to be incurred in the future. The Utility's regula-ity's environmental liability recognized at the end of the period tory liability for rate reduction bonds represents the deferral of in excess of the amount that has been recovered through rates over-collected revenue associated with the rate reduction bonds charged to customers. This amount will be recovered in future that the Utility expects to return to customers in the future. For rates. The Utility's regulatory assets associated with the plan of electricity distribution and generation, the Utility collected reorganization will be recovered over periods ranging from 2 to electricity revenue and surcharges subject to refund under the 30 years. The Utility's regulatory asset relating to post- frozen rate structure in 2003. The surcharge liability represents transition period contract termination costs are being amortized the amount of electricity revenue to be refunded.

and collected in rates on a straight-line basis until the end of September 2014, the contract's original termination date. This Regulatory Balancing Accounts amount will be recovered in future rates. Sales balancing accounts accumulate differences between rev-In general, the Utility does not earn a return on regulatory enues and the Utility's authorized revenue requirements. Cost assets where the related costs do not accrue interest. Accord- balancing accounts accumulate differences between incurred ingly, the only regulatory asset on which the Utility earns a costs and authorized revenue requirements. Under-collections return on is the regulatory assets relating to the Settlement that are probable of recovery through regulated rates are Agreement, retained generation and unamortized loss, net of recorded as regulatory balancing account assets. Over-gain on reacquired debt. collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities. The Util-Regulatory Liabilities ity's regulatory balancing accounts accumulate balances until they are refunded to or received from the Utility's customers Regulatory liabilities comprise the following:

through authorized rate adjustments.

Balance at December 31, During the California energy crisis, the Utility could not (in millions) 2004 2003 conclude that power generation and procurement-related bal-ancing accounts met the probability requirements of SFAS Cost of removal obligation $1,990 S1,810 Asset retirement costs 700 584 No. 71. However, the Utility was able to continue to record Employee benefit plans 687 925 balancing accounts associated with its electricity transmission Public purpose programs 191 185 and distribution and natural gas transportation businesses.

Rate reduction bonds 182 175 Surcharge liability 105 125 dther 180 175 Total regulatory liabilities $4,035 $3,979 The Utility's regulatory liabilities related to costs of removal represent revenues collected for asset removal costs that the Utility expects to incur in the future. The Utility's regulatory 99

The Utility's current regulatory balancing account assets As further discussed in Note 12, inJanuary 2001, the Cali-comprise the following: fornia Department of Water Resources, or DWR, began purchasing electricity to meet the portion of demand of the Balance at December 31, California investor-owned electric utilities that was not being (in millions) 2004 2003 satisfied from their own generation facilities and existing elec-Natural gas revenue balancing accounts S 76 S 20 tricity contracts. Under California law, the DIVR is deemed to Natural gas cost balancing accounts 95 58 sell the electricity directly to the Utility's retail customers, not Electricity revenue balancing accounts 151 75 to the Utility. Therefore, the Utility acts as a pass-through Electricity distribution cost balancing accounts 699 95 entity for electricity purchased by the DVRIZ on behalf of its Total S1,021 $248 customers. Although charges for electricity provided by the DWVR are included in the amounts the Utility bills its cus-tomers, the Utility deducts from its electricity revenues the The Utility's current regulatory balancing account liabilities amounts passed through to the DWR. The pass-through comprise the following: amounts are based on the quantities of electricity provided by the DWVR that are consumed by customers at the CPUC Balance at December 31, approved remittance rate. These pass-through amounts are (inmillions) 2004 2003 excluded from the Utility's electricity revenues in its Consoli-dated Statements of Operations.

Natural gas revenue balancing accounts $ - $ 9 Natural gas cost balancing accounts 34 162 Electricity transmission and distribution Allowance for Doubtful Accounts revenue balancing accounts 116 . 6 -PG&E Corporation and the Utility recognize an allowance for Electricity transmission cost doubtful accounts to record its accounts receivables at an esti-balancing accounts 219 9 mated net realizable value. The allowance is determined based Total $369 $186 upon a variety of factors, such as historical write-off experience, delinquency rates, current economic conditions and our assess-ment of customer collectibility. If circumstances related to the The Utility expects to collect from or refund to its cu's-Utility's assumptions change, recoverability estimates are tomers the balances included in current balancing accounts adjusted accordingly.

receivable and payable within the next twelve months. Regula-tory balancing accounts that the Utility does not expect to Accounting for Price Risk Management Activities collect or refund in the next twelve months are included in non-current regulatory assets and liabilities. PG&E Corporation, through the Utility, engages in price risk management activities for non-trading purposes. Price risk Revenue Recognition  ; management activities include the continuation of power for-ward contracts that were in existence before the Utility's Electricity revenues, which are comprised of generation, trans-Chapter 11 proceeding, new power contracts entered into since mission, and distribution services, are billed to the Utility's January 1, 2003 when the Utility resumed procurement of elec-customers at the CPUC-approved "bundled" electricity rate.

tricity, contracts related to the natural gas and nuclear fuel Natural gas revenues, which are comprised of transmission and portfolio, and interest rate hedges related to the issuance of distribution services, are also billed at CPUC-approved rates.

debt under the Utility's plan of reorganization.

The Utility's revenues are recognized as natural gas and elec-tricity are delivered, and include amounts for services rendered Derivative instruments include most forward contracts, but not yet billed at the end of each year. futures, swaps, options and other contracts. (Some contracts are accounted for as leases.) Derivative instruments designated as cash flow hedges are entered into to hedge variable price risk associated with the purchase and sale of commodities or to hedge variable interest rates on long-term debt. Additionally, derivative instruments may be eligible for a scope exclusion as further discussed below. For derivative instruments that are not designated as hedges or that are not eligible for a scope exclu-sion, they are adjusted to fair value through income.

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Derivative instruments recorded on PG&E Corporation's The Utility has derivative instruments for the physical deliv-and the Utility's Consolidated Balance Sheets are presented in ery of commodities transacted in the normal course of business as other current assets or other current liabilities. For derivative well as non-financial assets that are not exchange-traded. These instruments designated as cash flow hedges associated with non- derivative instruments are exempt from the requirements of regulated operations, unrealized gains or losses related to the SPAS No. 133 under the normal purchase and sales and non-effective portion of the change in the fair value of the derivative exchange traded contract exceptions, and are not reflected on the instrument are recorded in accumulated other comprehensive balance sheet at fair value. They are recorded and recognized in income until the hedged item is recognized in earnings. The income using accrual accounting. Therefore, revenues are recog-i ineffective portion of the change in the fair value of the deriva- rized as earned and expenses are recognized as incurred.

tive instrument is recognized immediately in earnings. For The Utility has certain commodity contracts for the pur-derivative instruments designated as cash flow hedges associated chase of nuclear fuel and core gas transportation and storage with the Utility's regulated operations, unrealized gains and contracts that are not derivative instruments and are not losses related to the effective and ineffective portions of the reflected on the balance sheet at fair value. Revenues are change in the fair value of the derivative instrument to the recorded as earned and expenses are recognized as incurred.

extent they are recoverable through regulated rates, are deferred and recorded in regulatory accounts.

Stock-Based Compensation Hedge accounting is discontinued prospectively if it is deter- PG&E Corporation and the Utility apply the intrinsic-value mined that the derivative instrument no longer qualifies as an method prescribed in Accounting Principles Board Opinion C effective hedge, or when the forecasted transaction is no longer No. 25, "Accounting for Stock Issued to Employees," in probable of occurring. If hedge accounting is discontinued the accounting for employee stock-based compensation, as allowed derivative instrument continues to be reflected at fair value, by SFAS No. 123, "Accounting for Stock-Based Compensa-with any subsequent changes in fair value recognized immedi- tion," or SPAS No. 123, as amended by SPAS No. 148, ately in earnings. Gains and losses related to a derivative 'Accounting for Stock-Based Compensation-Transition and instrument that were previously recorded in accumulated other Disclosure, an Amendment of FASB Statement No. 123," or comprehensive income will remain there until the hedged item SFAS No. 148. Under the intrinsic-value method, PG&E Cor-is recognized in earnings, unless the forecasted transaction is poration and the Utility do not recognize any compensation probable of not occurring, whereupon the gains and losses from expense for stock options, as the exercise price is equal to the the derivative instrument will be immediately recognized in fair market value of a share of PG&E Corporation common earnings. The gains and losses deferred in accumulated other stock at the time the options are granted.

comprehensive income are recognized in earnings when the hedged item matures or is exercised.

Net realized and unrealized gains or losses on derivative instruments are included in various lines on PG&E Corpora-tion's and the Utility's Consolidated Statements of Operations, including cost of electricity, cost of natural gas and interest expense. Cash inflows and outflows associated with the settle-ment of price risk management activities are recognized in operating cash flows on PG&E Corporation's and the Utility's Consolidated Statements of Cash Flows.

The fair value of contracts is estimated using the mid-point of quoted bid and ask forward prices, including quotes from counterparties, brokers, electronic exchanges and published indices, supplemented by online price information from news services. W'hen market data is not available, models are used to estimate fair value.

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The tables below show the effect on net income and earn- the fair-value method under SFAS No. 123 and using the valua-ings per share for PG&E Corporation and the Utility had it tion assumptions disclosed in Note 10, for the years ended elected to account for its stock-based compensation plans using December 31, 2004, 2003, and 2002:

Years ended December 31, (in millions, except per share amounts) 2004 2003 2002 Net earnings (loss):

As reported $4,504 $ 420 S (874)

Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects (14) (19) (20)

Pro forma $4,490 $ 401 $ (894)

Basic earnings (loss) per share:

As reported $10.80 $1.04 $(2.30)

Pro forma 10.77 0.99 (2.35)

Diluted earnings (loss) per share:

As reported 10.57 1.02 (2.27)

Pro forma 10.59 0.97 (2.33)

If compensation expense had been recognized using the fair value-based method under SFAS No. 123, the Utility's proforma consolidated earnings would have been as follows:

Year ended December 31, (in millions) 2004 2003 2002 Net earnings:

As reported $3,961 $ 901 $1,794 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects - (8) (8) (7)

Pro forma $3,953 $ 893 $1,787 Accumulated Other Comprehensive Income (Loss) transactions with shareholders. The following table sets forth Accumulated other comprehensive income (loss) reports a the changes in each component of accumulated other compre-measure for accumulated changes in equity of an enterprise that hensive income (loss):

results from transactions and other economic events, other than fledging Foreign Accumulated Transactions in Currency Retirement Other Accordance with Translation Plan Comprehensive SFAS No. 133 Adjustment Remeasurement Other Income (Loss)

Balance at December 31, 2001 $ 36 S(5) 5- S(1) S 30 Period change in:

Mlark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (139) - - - (139)

Net reclassification to earnings 13 - - - 13 Other - 2 - 1 3 Balance at December 31, 2002 (90) (3) _ - (93)

Period change in:

Alark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (8) _ _ - (8)

Net reclassification to earnings 17 - _ _ 17 Other - 3 (4) (1)

Balance at December 31, 2003 (81) - (4) _ (85)

Period change in:

Mlark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 3 - - - 3 NEGT losses reclassified to earnings upon elimination of equity interest by PG&E Corporation 77 - _ _ 77 Other - - 1 Balance at December 31, 2004 $ (1) 5- S(4) SI S (4) 102

Accumulated other comprehensive income (loss) included subsidiaries of the Utility, including PG&E Funding LLC, losses related to discontinued operations of approximately $77 (which issued rate reduction bonds) and PG&E Holdings LLC million at December 31, 2003 and approximately $93 million at (which holds stock of the Utility), were not included in the December 31, 2002. During the fourth quarter of 2004, the Utility's Chapter 11 proceeding. The Utility recorded its esti-remaining losses of approximately $77 million included in accu- mate of all valid claims of approximately $9.5 billion as mulated other comprehensive income (loss) were recognized in liabilities subject to compromise at December 31, 2003, includ-connection with PG&E Corporation's elimination of its equity ing interest on disputed claims and approximately $2.7 million interest in NEGT. of long-term debt.

ACCOUNTING PRONOUNCEMENTS ISSUED EMERGENCE FROM CHAPTER 11 BUT NOT YET ADOPTED On April 12, 2004, the Utility emerged from Chapter 11 when its plan of reorganization became effective, or the Effective Share-Based Payment Transactions Date. The plan of reorganization incorporated the terms of the In December 2004, the FASB issued Statement No. 123 Settlement Agreement approved by the CPUC on Decem-(revised December 2004), "Share-Based Payment," or SFAS ber 18, 2003, and entered into among the CPUC, the Utility No. 123R. SFAS No. 123R requires that the cost resulting from and PG&E Corporation on December 19, 2003, to resolve the all share-based payment transactions be recognized in the finan- Utility's Chapter 11 proceeding. Although the Utility's opera-cial statements and establishes a fair-value measurement tions are no longer subject to the oversight of the bankruptcy objective in determining the value of such a cost. SFAS court, the bankruptcy court retains jurisdiction to hear and No. 123R will be effective for the third quarter of 2005. PG&E determine disputes arising in connection with the interpreta-Corporation and the Utility are currently evaluating the impact tion, implementation or enforcement of (1) the Settlement of SFAS No. 123R on their Consolidated Financial Statements. Agreement, (2) the plan of reorganization, and (3) the bank-ruptcy court's December 22, 2003 order confirming the plan of Inventory Costs reorganization. In addition, the bankruptcy court retains juris-In December 2004, the FASB issued Statement No. 151, diction to resolve remaining disputed claims.

"Inventory Costs an amendment of ARB No. 43, Chapter 4", or SFAS No. 151. The guidance clarifies that the allocation of fixed production overhead to inventory is based on normal capacity. Abnormal amounts of idle facility, excess freight, han-dling costs and spoilage should be recognized as a current period charge. SFAS No. 151 will be effectiveJanuary 1, 2006.

The adoption of SFAS No. 151 is not expected to have a mate-rial effect on the financial position or results of operations of either PG&E Corporation or the Utility.

NOTE 2: THE UTILITY'S CHAPTER 11 FILING As a result of the California energy crisis, the Utility filed a vol-untary petition for relief under the provisions of Chapter 11 on April 6, 2001. The Utility retained control of its assets and was authorized to operate its business as a debtor-in-possession dur-ing its Chapter 11 proceeding. PG&E Corporation and the 103

In anticipation of its emergence from Chapter 11, the Utility accounts for the payment of disputed claims upon their resolu-consummated its public offering of $6.7 billion of First Mort- tion, reinstated certain obligations, and paid other obligations.

gage Bonds on March 23, 2004. Upon the Effective Date the The following table summarizes the sources and uses of funds Utility paid all valid daims, deposited funds into escrow on the Effective Date:

(inmillions) Sources Uses First Alortgage Bonds $ 6,700 Payments to Creditors S 8,394 Term Loans 799 Disputed Claims Escrows 1,843 Accounts Receivable Financing Facility 350 Total Debt Financing 7,849 Cash Used to Pay Claims 2,388 Sources of Funds for Claims 10,237 Uses of Funds for Claims 10,237 Reinstated Pollution Control Bond-Related Obligations 814 Reinstated Pollution Control Bond-Related Obligations 814 Reinstated Preferred Stock 421 Reinstated Preferred Stock 421 Cash on Hand 225 Preferred Dividends 93 Environmental Measures 10 Transaction Costs 122 Total Sources of Funds $11,697 Total Uses of Funds SI 1,697 In connection with the Utility's emergence from Chapter 11, 2003 decision. CCSF and Aglet allege that the Settlement the Utility received investment-grade issuer credit ratings of Agreement violates California law, among other claims. CCSF Baa3 from Moody's Investors Service, or Moody's, and BBB- requests that the appellate court hear and review the CPUC's from Standard & Poor's, or S&P. decisions, approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. Three Cali-On July 15, 2004, the U.S. District Court for the Northern fornia state senators have filed a brief in support of the CCSF District of California, or the District Court, dismissed the and Aglet petitions. The California Court of Appeal has not yet appeals of the bankruptcy court's order confirming the plan of acted on the petitions. PG&E Corporation and the Utility reorganization that had been filed by the two CPUC commis-believe the petitions are without merit and should be denied.

sioners who did not vote to approve the Settlement Agreement.

These two commissioners appealed the District Court's order to Under applicable federal precedent, once the plan of reor-the U.S. Court of Appeals for the Ninth Circuit, or Ninth Cir- ganization has been "substantially consummated," any pending cuit. An appeal of the confirmation order filed by the City of appeals of the confirmation order should be dismissed. If, Palo Alto remains pending at the District Court. PG&E Cor- notwithstanding this federal precedent, the bankruptcy court's poration and the Utility believe the appeals of the confirmation confirmation order or the Settlement Agreement is subse-order are without merit. quently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be In addition, on April 15, 2004, the City and County of San materially adversely affected.

Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, each filed a petition with the California Court of Appeal seeking FINANCIAL

SUMMARY

OF THE review of the CPUC's December 18, 2003 decision approving SETTLEMENT AGREEMENT the Settlement Agreement and the CPUC's March 16, 2004 decision denying applications for rehearing of its December 18, In light of the satisfaction of various conditions to the imple-mentation of the plan of reorganization, including the consummation of the public offering of the First Mortgage Bonds, the receipt of investment grade credit ratings, and final CPUC approval of the Settlement Agreement, the accounting probability standard required to be met under SFAS No. 71, in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement (as described below), was met as of March 31, 2004. Therefore, the Utility recorded the 104

$2.2 billion, after-tax ($3.7 billion, pre-tax) Settlement Regula- the Utility retained generation regulatory assets, as summarized tory Asset, and $0.7 billion, after-tax ($1.2 billion, pre-tax), for in the table below and discussed further in the paragraphs below:

Settlement Utility Retained Regulatory Generation (inmillions) Asset Regulatory Assets Total Authorized, pre-tax, January 1,2004 S 3,730 $1,249 S 4,979 Amortization fromJanuary I to March 31, 2004 (58) (21) (79)

Recognition of regulatory assets, pre-tax, Alarch 31, 2004 3,672 1,228 4,900 Deferred income taxes (1,496) (500) (1,996)

Recognition of regulatory assets, after tax, March 31, 2004 $ 2,176 $ 728 5 2,904 Settlement Regulatory Asset adjustment or reduction, except as necessary to reflect capital

• The Settlement Agreement established a $2.2 billion, after- expenditures and changes in authorized depreciation. Accord-tax, regulatory asset (which is equivalent to an approximately ingly, the Utility recognized a one-time, non-cash gain of $1.2

$3.7 billion, pre-tax, regulatory asset) as a new, separate and billion, pre-tax, for the retained generation regulatory assets additional part of the Utility's rate base that is being amor- in the first quarter of 2004. The individual components of the tized on a "mortgage-style" basis over nine years beginning regulatory assets are amortized over their respective lives, January 1, 2004. The Utility recognized a one-time, non-cash with a weighted average life of approximately 16 years. The gain of $3.7 billion, pre-tax, for the Settlement Regulatory Utility retained generation regulatory assets will earn an Asset in the first quarter of 2004. The Settlement Agreement authorized rate of return on its equity component of 11.22% in requires the Utility to reduce the after-tax Settlement Regula- 2004 and 2005.

totfy Asset for any refunds, claims offsets, or other credits that the Utility receives from energy suppliers relating to specified Ratemaking Matters electricity procurement costs incurred during the California

• In the Settlement Agreement, the CPUC agreed to set the energy crisis. As discussed in Note 1, as of December 3 1, "Utility's capital structure and authorized return on equity in 2004, the Utility has recorded offsets to the Settlement Regu- its annual cost of capital proceedings in its usual manner.

latory'Asset of approximately $309 million, pre-tax ($183 However, fromJanuary 1, 2004 until Moody's has issued an million, after-tax) for supplier settlements and collected issuer rating for the Utility of not less than A3 or S&P has approximately $233 million, pre-tax ($138 million, after-tax) issued a long-term issuer credit rating for the Utility of not for amortization of the Settlement Regulatory Asset. less than A', the Utility's authorized return on equity will be no less than 11.22% per year and its authorized equity ratio

• The Settlement Agreement authorized the Utility to earn a for ratemaking purposes will be no less than 52%. For 2004 rate of return on its equity component of the unamortized and 2005, the Utility's authorized equity ratio will be the balance of the Settlement Regulatory Asset of no less than greater of the proportion of equity approved in the Utility's 11.22% annually for its nine-year term. In February 2005, the 2004 and 2005 cost of capital proceedings, or 48.6%. In Utility completed a refinancing of the after-tax balance of the December 2004, the CPUC issued the Utility's cost of capital Settlement Regulatory Asset supported by a dedicated rate decision authorizing an equity ratio of 49.0% for 2004 and component as discussed below. The Utility will no longer 52% for 2005.

earn this 11.22 % rate of return on the Settlement Regulatory Asset, as it is no longer part of rate base. The equity and debt

• The CPUC also agreed to act promptly on certain of the Util-components of the Utility's rate of return will be replaced ity's pending ratemaling proceedings. The outcome of these with the lower interest rate of the securitized debt. proceedings may result in the establishment of additional regu-latory assets on the Utility's Consolidated Balance Sheet.

Utility Retained Generation Regulatory Assets

• In the Settlement Agreement, the CPUC deemed the Utility's adopted electricity generation rate base in a 2002 proceeding to be just and reasonable and not subject to modification, 105

Environmental Measures Fees and Expenses

• In the Settlement Agreement, the Utility agreed to encumber The Settlement Agreement required the Utility to reimburse with conservation easements or donate approximately 140,000 the CPUC for its professional fees and expenses incurred in acres of land to public agencies or non-profit conservation connection with the Chapter 11 proceeding. These amounts organizations. will be recovered from customers over a reasonable time of up to four years. As of December 31, 2004, the Utility had a regu-

• The Utility has established the Pacific Forest and Watershed latory asset of approximately $24 million relating to the CPUC Stewardship Council to oversee the environmental enhance-reimbursable fees and expenses. In addition, one of the terms of ments associated with these lands. The Utility has agreed to the Settlement Agreement precluded the Utility from reimburs-fund the council with $100 million in cash over 10 years. The ing PG&E Corporation for certain Chapter 11 related costs. As Utility paid two installments of $10 million each in Octo-such, PG&E Corporation reduced its receivable from the Util-ber 2004 and in January 2005 to this council. As of ity, and the Utility reduced its payable to PG&E Corporation, December 31, 2004, the Utility has recorded a $75 million by approximately $128 million. The transactions were recorded liability based on the discounted present value of future cash )

as a contribution of equity to the Utility by PG&E Corpora-payments to this council. The Utility will be entitled to tion, net of taxes, and an increase to additional paid-in capital recover these payments in rates. Therefore, the Utility recog-by the Utility in the first quarter 2004.

nized an offsetting regulatory asset and the recognition of the obligation had no impact on the Utility's results of operations.

REFINANCING SUPPORTED BY

• The Utility has also established a California non-profit corpo- A DEDICATED RATE COMPONENT ration that is dedicated to support research and investment in In connection with the Settlement Agreement, PG&E Corpo-clean energy technology, primarily in the Utility's service ter-ration and the Utility agreed to seek to refinance the remaining ritory. The Utility agreed to fund this corporation with $30 unamortized balance of the Settlement Regulatory Asset and million payable over five years. The Utility paid two install-related federal, state, and franchise taxes, in an aggregate ments of $2 million each in July 2004 and in January 2005 to amount of up to $3.0 billion, in two separate series up to one this corporation. These contributions may not be recovered in year apart, to be secured by a dedicated rate component, or rates. In the first quarter of 2004, the Utility recorded a $27 DRC, provided that authorizing legislation was adopted and million, pre-tax charge to earnings based on the discounted certain conditions were met. In June 2004, the California Gov-present value of future cash payments.

ernor signed into law Senate Bill 772, which authorizes the Of the approximately 140,000 acres referred to above, issuance of energy recovery bonds, or ERBs, to be secured by approximately 44,000 acres may be either donated or encum- the establishment of a DRC, to refinance the Settlement Regu-bered with conservation easements. The remaining land latory Asset and related taxes.

contains the Utility's or a joint licensee's hydroelectric genera-In November 2004, the CPUC approved the Utility's appli-tion facilities and may only be encumbered with conservation cation for a wholly owned subsidiary to issue ERBs. In easements. In the first quarter of 2004, the Utility recorded a December 2004, the Utility received a favorable private letter

$1 million, pre-tax charge to earnings associated with the land ruling from the IRS. After satisfaction of all conditions, on Feb-donation obligation.

ruary 10, 2005, PG&E Energy R'ecovery Funding LLC, or PERF, a limited liability company wholly owned and consoli-dated by the Utility (but legally separate from the Utility),

issued the first series of ERBs for approximately $1.9 billion.

The Utility, as servicer, will collect DRC charges from cus-tomers and remit collected amounts to PERF to enable PERF to pay principal and interest on the ERBs. The proceeds of the first series of ERBs were paid by PERF to the Utility and will be used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset through the redemption and repurchase of higher cost equity and debt.

106

The proceeds of the second series of ER1s, anticipated to be As of December 31, 2004, the Utility had accrued approxi-issued in November 2005 in an aggregate amount of up to mately $1.6 billion for remaining net disputed claims, consisting

$1.1 billion, will be paid by PERF to the Utility to pre-fund the of approximately $2.1 billion of accounts payable-disputed Utility's recovery through rates of the tax payments that will be claims primarily payable to the ISO and the Power Exchange, due as the Utility collects the DRC over the term of the first or the PX, offset by an accounts receivable amount from the series of ERBs to pay principal. ISO and the PX of approximately $0.5 billion. As disclosed in the table above, the Utility held $1.7 billion in escrow for the CHAPTER 11 CLAIMS payment of remaining disputed claims as of December 31, 2004.

Although the Utility was required to hold $1.7 billion in The following table summarizes the disposition of the net escrow, the Utility does not believe it is probable that it will be creditor claims made in the Utility's Chapter 11 proceeding, the found liable for approximately $0.1 billion of the $1.7 billion of amount of funds held in escrow for the resolution of disputed the disputed claims and, therefore, in accordance with SFAS claims and the disputed claims accrued by the Utility at No. 5, "Accounting for Contingencies," or SEAS No. 5, the December 31, 2004:

Utility has not recorded a liability in its financial statements for this amount. Upon resolution of these claims and under the (inbillions) terms of the Settlement Agreement, any refunds, claims offsets Total filed claims in the Utility's Chapter 11 proceeding $ 51.7 or other credits that the Utility receives from energy suppliers ISO, PX and generator claims disallowed (8.2)

Other claims disallowed by the bankruptcy court (25.4) will be returned to customers.

Claims objected to by the Utility and pending before the bankruptcy court (0.1)

Pass-through claims, including environmental, pending litigation and tort claims(') (4.7)

Principal payments made prior to the effectiveness of the plan of reorganization (2.3)

Claims settled with the cancellation of bonds owned by the Utility (0.3)

Payments on claims on and after the effectiveness of the plan of reorganizations) (8.2)

Reinstated Pollution Control Bonds (0.8)

Amount retained in escrow for remaining disputed claims - principal, at December 31, 2004 S 1.7 Disputed claims not accrued by the Utility (0.1)

Net disputed claims accrued by the Utility at December 31, 2004 S 1.6 e') The Utility has analyzed these claims and has recorded reserves for such claims that are included in the Utility's undiscounted environ-mental remediation liability of approximately $327 million at December 31, 2004 and the Utility's provision for legal matters of approximately $200 million at December 31, 2004, as discussed below in Note 12.

(2) The Utility also made payments of approximately $0.2 billion for interest and bank premiums upon the effectiveness of the plan of reorganization.

107

NOTE 3: DEBT LONG-TERM DEBT The following table summarizes PG&E Corporation's and the Utility's long-term debt that matures 'in one year or more from the date of issuance:

December 31, II (in millions) .2004 2003 PG&E Corporation Senior secured notes, 6'A%, due 2008 $ - $ 600 Convertible subordinated notes, 9.50%, due 2010 280 280 Other long-term debt 1 3 Less: current portion (1) -

280 883 Utility First and refunding mortgage bonds:

2.72% to 8.80% bonds, due 2004-2026 - 2,764 Unamortized discount, net of premium - (23)

Total first and refunding mortgage bonds - 2,741 First mortgage bonds:

2.30% to 6.05% bonds, due 2006-2034 6,200 -

Unamortized discount, net of premium (17) -

Total first mortgage bonds 6,183 Pollution control loan agreements, variable rates, due 2007 614 Pollution control loan agreement, 5.35%, due 2016 200 Pollution control bond agreements, 3.50%, due 2007 345 Pollution control bond bridge facilities, variable rates, due 2005 454 Other 4 Less: current portion (757) (310) 7,043 2,431 Total consolidated long-term debt, net of current portion S7,323 $3,314 Long-term debt subject to compromise:

Senior notes, 10.75%, due 2005 $ - S 680 Pollution control loan agreements, variable rates, due 2026 - 614 Pollution control loan agreements, 5.35%, due 2016 - 200 Unsecured medium-term notes, 6.94% to 9.58%, due 2004-2014 - 287 Deferrable interest subordinated debentures, 7.90%, due 2025 - 300 Other 17 Total long-term debt subject to compromise $ - $2,098 PG&E CORPORATION accrued since the last interest payment date. As a result of the Senior Secured Notes redemption, PG&E Corporation wrote Senior Secured Notes off approximately $14.6 million of unamortized loan fees in the On November 15, 2004, PG&E Corporation redeemed the' three months ended December 31, 2004.

$600 million of 6A% Senior Secured Notes due 2008, or Senior Secured Notes, in full. Redemption of the Senior Secured Convertible Subordinated Notes Notes required approximately $664.5 million of PG&E PG&E Corporation currently has outstanding $280 million of Corporation's cash, which included a redemption premium of 9.50% Convertible Subordinated Notes that are scheduled to approximately $50.7 million and $13.8 million of interest mature onJune 30, 2010. These Convertible Subordinated 108

Notes may be converted (at the option of the holder) at any credit facility, which was terminated on the Effective Date and time prior to maturity into 18,558,655 shares of common stock the letters of credit then outstanding were transferred to the of PG&E Corporation, at a conversion price of $15.09 per $850 million revolving credit facility.

share. The conversion price is subject to adjustment should a significant change occur in the number of PG&E Corporation's First Mortgage Bonds outstanding common shares. To date, the conversion price has On March 23, 2004, the Utility closed a public offering of $6.7 not required adjustment. In addition, the terms of the Convert- billion of First Mortgage Bonds. The First Mortgage Bonds ible Subordinated Notes entitle the note holders to participate were offered in multiple tranches consisting of 3.60% First in any dividends declared and paid on PG&E Corporation's Mortgage Bonds due March 1, 2009 in the principal amount of common shares based on their equity conversion value. The $600 million, 4.20% First Mortgage Bonds due March 1, 2011 holders have a one-time right to require PG&E Corporation to in the principal amount of $500 million, 4.80% First Mortgage repurchase the Convertible Subordinated Notes on June 30, - Bonds due March 1, 2014 in the principal amount of $1 billion, 2007, at a purchase price equal to the principal amount plus 6.05% First Mortgage Bonds due March 1, 2034 in the princi-accrued and unpaid interest (including liquidated damages arid pal amount of $3 billion, and Floating Rate First Mortgage pass-through dividends, if any). Bonds due April 3, 2006 in the principal amount of $1.6 billion.

The Utility received proceeds of $6.7 billion from the offering, In accordance with SPAS No. 133, the dividend participation net of a discount of $ 18 million. The interest rate for the Float-rights component is considered to be an embedded derivative ing Rate First Mortgage Bonds is based on the three-month instrument and, therefore, must be bifurcated from the Con-London Interbank Offered Rate, or LIBOR, plus 0.70%, which vertible Subordinated Notes and marked to market on PG&E resets quarterly. The next reset date is April 3, 2005. For 2004, Corporation's Consolidated Statements of Operations as a non-the average interest rate on the Floating Rate First Mortgage operating expense (in Other expense, net), and reflected at fair Bonds was 4.8%.

value on PG&E Corporation's Consolidated Balance Sheet at December 31, 2004 as $76 million of non-current liability (in On October 3, 2004, the Utility partially redeemed Floating Non-current liabilities-other) and $15 million of current lia- Rate First Mortgage Bonds due in 2006 in the aggregate princi-bility (in Current liabilities-other). At December 31, 2004, the pal amount of $500 million. On January 3, 2005, the Utility total estimated fair value of the dividend participation rights partially redeemed Floating Rate First Mortgage Bonds due in component on a pre-tax basis was approximately $91 million. 2006 in the aggregate principal amount of $300 million. In addition, the Utility plans to use a portion of the energy recov-Warrants ery bond proceeds to defease $600 million of Floating Rate Concurrent with the negotiation of an amendment of a previ- First Mortgage Bonds by the end of February 2005.

ously existing credit agreement in June 2002, now paid in full, In addition, approximately $2.5 billion of additional First warrants to purchase 2,397,541 shares of PG&E Corporation's Mortgage Bonds have been issued as security to various banks common stock were issued, at an exercise price of $0.01 per and insurance companies under the following agreements share. In October 2002, the above mentioned credit agreement (1) the Utility's $620 million letters of credit backing pollution was amended to increase the size of the facility by $300 million control bonds, (2) the Utility's reimbursement obligation under to a total of $720 million. In connection waith this amendment, an insurance policy relating to $200 million in pollution control PG&E Corporation issued to affiliates of the lenders additional bonds that were issued for the benefit of the Utility, (3) the warrants to purchase 2,669,390 shares of PG&E Corporation's Utility's $345 million loan agreements with the California Pol-common stock, with an exercise price of $0.01 per share. At' lution Control Financing Authority, or the CPCFA, (4) the December 31, 2004, 347,912 of these warrants were outstanding Utility's $454 million reimbursement agreements for pollution and exercisable with an expiration date of September 2, 2006. control bond bridge facilities, and (5) the Utility's $850 million working capital facility.

UTILITY The First Mortgage Bonds are secured by a first lien, subject In March 2004, in connection with the implementation of the to permitted exceptions, on substantially all of the Utility's real plan of reorganization, the Utility issued $6.7 billion of First property and certain tangible personal property related to the Mortgage Bonds and together with its consolidated subsidiaries, Utility's facilities. Subject to certain conditions, the Utility will entered into $2.9 billion of credit facilities. The Utility be entitled to terminate the lien and eliminate all terms and obtained an interim $400 million cash collateralized letter of 109

conditions relating to collateral for the First Mortgage Bonds letter of credit banks per the terms of the reimbursements on the release date. In general, the release date will occur when agreements. The letters of credit are then reinstated to the full the Utility provides written evidence to the trustee of the First amount of their initial commitments.

Mortgage Bonds that the ratings on the Utility's long-term Pollution Control Bond Term Loan Facilityand unsecured debt obligations following the release date would at 3.5% Pollution Control Loan Agreements least equal the (1) initial ratings assigned by Moody's and S&P on the First Mortgage Bonds, or (2) comparable ratings by any On the Effective Date, the Utility entered into a $345 million other nationally recognized rating agency or agencies selected term loan facility that was used to fund the Utility's purchase, in by the Utility if either Moody's or S&P do not then rate the lieu of redemption, of the CPCFMs Pollution Control Revenue Utility's long-term unsecured debt obligations. The First Mort- Bonds, 1992 Series A and B and 1993 Series A and B, or collec-gage Bonds received initial investment grade credit ratings of, tively the Old Bonds.

Baa2 from Moody's and BBB from S&P.

On June 29, 2004, the Utility entered into four separate loan If the lien securing the First Mortgage Bonds is released, the agreements, each dated as ofJune 1, 2004, with the CPCFA, indenture will limit the ability of the Utility and its significant which issued $345 million aggregate principal amount of its subsidiaries to incur secured debt and enter into sale and lease- Pollution Control Refunding Revenue Bonds, 2004 Series A back transactions. -($70 million), 2004 Series B ($90 million), 2004 Series C ($85 million), and 2004 Series D ($100 million), or collectively the Pollution Control Bonds New Bonds, to refund the Old Bonds. The funds made avail-Variable Rate and 5.35% Pollution Control Loan Agreements able from the refund of Old Bonds were used to repay the $345 million term loan facility. Principal and interest payments on Under pollution control loan agreements, the Utility is obli- the New Bonds are backed by bond insurance and the Utility's gated to reimburse the CPCFA for funds received by the Utility obligations under the new loan agreements are supported by from the issuance of the CPCFA's pollution control bonds for $345 million of First Mortgage Bonds that are held by the the benefit of the Utility. The principal amount of these loan trustee for the New Bonds.

obligations totaled $814 million at December 31, 2004. Interest rates on $614 million of $814 million of the obligations are PollutionControl Bond Bridge Facilities variable. For 2004, the average variable interest rates ranged During the Utility's Chapter 11 proceeding, approximately from 1.19% to 1.21%. The interest rate on the remaining $200 $454 million in aggregate principal amount of pollution control million of the obligations is fixed at 5.35%. bonds, which were issued for the Utility's benefit and were The CPCFA pollution control bonds in the principal amount credit enhanced with letters of credit were redeemed through of $200 million are backed by bond insurance. The CPCFA pol- draws on the letters of credit. On the Effective Date, the Utility lution control bonds in the principal amount of $614 million are executed bridge loans with new lenders who had purchased the backed by letters of credit of $620 million. The Utility's reim- $454 million reimbursement obligations owed by the Utility to bursement obligations are supported by $820 million in First the letter of credit issuers and entered into four separate Mortgage Bonds that have been issued to the bond insurer and amended and restated reimbursement agreements with new letter of credit banks. These bank agreements supplying the let- lenders. These reimbursement agreements include a covenant ters of credit indude a covenant requiring the Utility to requiring the Utility to maintain, as of the end of each fiscal maintain, as of the end of each fiscal quarter ending after the quarter ending after the Effective Date, a debt to capitalization Effective Date, a debt to capitalization ratio of at most 65%. ratio of at most 65%. The Utility intends to refinance the $454 million with long-term tax-exempt bonds or taxable debt. The Drawings for interest due under the loan agreements are outstanding balance of $454 million at December 31, 2004 made under these letters of credit on each scheduled interest under the amended and restated reimbursement agreements is payment date, which is the first business day of each month. On due and payable on June 5, 2005. At the Utility's request and at the same day, the Utility pays the amount of the draw to the the sole discretion of each lender, each amended and restated reimbursement agreement may be extended for additional peri-ods. On the Effective Date, the Utility supported its obligations under the amended and restated reimbursement agreement with

$454 million of First Mortgage Bonds.

110

Repayment Schedule At December 31, 2004, PG&E Corporation's and the Utility's combined aggregate amounts of maturing long-term debt as sched-uled are reflected in the table below:

(in millions) 2005 2006 2007 2008 2009 Thereafter Total PG&E Corporation $ 1 $ - $ - s- $ - $ 280 $ 281 Utility Long-term debt:

Average fixed interest rate 3.50% 3.60% 5.78% 5.43%

Fixed rate obligations $ - $ 345 $ 600 $4,683 $5,628 Average fixed interest rate 6.42% 6.44% 6.48% 6.45%

Rate reduction bonds S 2.90 $ 290 $ 290 $ - $ 870 Variable interest rate as of December 31, 2004 3.33% 2.72% i.19-1.21%

Variable rate obligations $ 754 $ 800 $ 614 $ - $2,168 Other $ 3 $ I $ - $ - #$ 4 Total consolidated long-term debt S1,048 $1,091 $1,249 S- $ 600 $4,963 S8,951 CREDIT FAC I LITI ES AND have any outstanding balances on its credit facilities. At Decem-SHORT-TERM BORROWINGS ber 31, 2004, the Utilityhad $300 millionin short-term borrowings outstanding under the $850 million revolving credit The following table summarizes PG&E Corporation's and the or wki c tl Utility's short-tenn borrowings and outstanding credit facilities facility, o xorng capia raciuty and app i $ m lion of letters of credit outstanding. There were no other at December 31,2004 and 2003. The Utility's credit facilities a outstanding balances on the Utility's credit facilities at Decem-and short-term borrowings subject to compromise at ber 31, 2004. PG&E Corporation and the Utility's, including December 31, 2003 were paid and cancelled on the Effective their consolidated subsidiaries, short-term borrowings and other Date. At December 31, 2004, PG&E Corporation did not credit facilities consist of the following:

December 31, 2004 December 31, 2003 Revolving (in millions) Credit Limit Outstanding Outstanding Short-Tertn Borrowings:

PG&E Corporation Senior credit facility $ 200 $ - S -

Total credit facilities $ 200 $ - S -

Utility Accounts receivable financing S 650 ' - S -

Working capital facility $ 850 $300 S -

Total credit facilities $1,500 $300 S -

Credit facilities subject to compromise:

5-year revolving credit facility $ - $ 938 Total credit facilities subject to compromise $ - $ 938 Short-term borrowings subject to compromise:

Bank borrowings-drawn letters of credit for accelerated pollution control agreement - $ - $ 454 Floating rate notes - 1,240 Commercial paper - 873 Total credit facilities and short-term borrowings subject to compromise $ - $3,505 111

December 31, 2004 (in millions) Outstanding Other Credit Facilities:

Utility Letters of credit<'):

Pollution control bonds reimbursement agreements S 620 Working capital facility 285 Total letters of credit S 905 First mortgage bonds issued to secure and support various debt and credit facilities('):

Pollution control loan agreements, variable rates, due 2007 $ 620 Pollution control loan agreements, 5.35%, due 2006 200 Pollution control loan agreements, 3.50%, due 2007 345 Pollution control bond bridge facilities, variable rates, due 2005 454 Working capital facility 850 Total first mortgage bonds issued to secure and support various debt and credit facilities S2,469 "l Off-balance sheet connmitments.

PG&E CORPORATION gate facility and a utilization fee based on the average daily amount outstanding under the senior credit facility are payable Senior Credit Facility by PG&E Corporation quarterly in arrears (the utilization fee is On December 10, 2004, PG&E Corporation entered into a levied during any quarter in which the average daily amount

$200 million three-year revolving senior unsecured credit facil- - outstanding is in excess of 50% of the aggregate facility). The ity, or senior credit facility, with a syndicate of lenders. The applicable margin, facility fee and utilization fee fluctuate with aggregate facility of $200 million includes a $50 million sub- the Utility's credit rating. The applicable margin ranges limit for the issuance of letters of credit and a $100 million between 0.70% and 1.35% for Eurodollar loans and 0% and sublimit for swing line loans. Borrowings under the senior 0.5% for base rate loans. The facility fee ranges between credit facility and letters of credit will be used primarily for 0.175% and 0.4% and the utilization fee ranges between working capital and other corporate purposes. The senior credit 0.125% and 0.25%.

facility has a term of three years and all outstanding amounts are due and payable on December 10, 2007. PG&E Corpora- Amounts outstanding under letter of credit arrangements tion can, at any time, repay amounts outstanding in whole or in bear interest at the Eurodollar rate plus applicable margin, as part. At PG&E Corporation's request and at the sole discretion detailed above. Interest, a fronting fee, to be determined of each lender, the senior credit facility may be extended for between PG&E Corporation and the issuing lender, and normal additional periods. PG&E Corporation has the right to lender costs of issuing and negotiating letter of credit arrange-increase, in one or more requests given no more than once a ments are payable quarterly in arrears.

year, the aggregate facility by up to $100 million provided cer- The senior credit facility includes covenants requiring that tain conditions are met. At December 31, 2004, PG&E PG&E Corporation maintain a ratio of total consolidated debt Corporation had not undertaken any borrowings or issued any to total consolidated capitalization of at most 65% and that letters of credit under the senior credit facility. PG&E Corporation own, directly or indirectly, at least 80% of Borrowings under the senior credit facility bear interest the common stock and at least 70% of the voting securities of based, at PG&E Corporation's election, on a Eurodollar rate or PG&E Corporation.

a base rate, plus an applicable margin. The base rate equals the higher of the administrative agent-announced base rate or 0.5% UTILITY above the federal funds rate. Interest is payable by PG&E Cor- Accounts Receivable Financing poration at least quarterly, or earlier for loans with shorter On March 5, 2004, the Utility entered into' certain agreements interest periods. In addition, a facility fee based on the aggre-providing for the continuous sale of a portion of the Utility's accounts receivable to PG&E Accounts Receivable Company, LLC, or PG&E ARC, a limited liability company wholly owned 11 2

by the Utility. In turn, PG&E ARC sells interests in its The working capital facility includes covenants requiring:

accounts receivable to commercial paper conduits or banks.

• Maintenance, as of the end of each fiscal quarter ending after PG&E ARC may obtain up to $650 million of financing under the Effective Date, of a debt to capitalization ratio of at most such agreements. The borrowings under this facility bear inter-65%; and est at commercial paper rates and a fixed margin based on the Utility's credit ratings. Interest on the facility is payable

• Until the lien securing the First Mortgage Bonds is released, a monthly. The maximum amount available for borrowing under limutation on liens other than those specifically permitted by this facility changes based upon the amount of eligible receiv- the indenture for the First Mortgage Bonds. As noted above, ables, concentration of eligible receivables and other factors. after the release of the lien, the First Mortgage Bond inden-The credit facility will terminate on March 5, 2007. The Utility ture then limits the ability of the Utility and its significant began selling accounts receivables to PG&E ARC on the Effec- subsidiaries to incur secured debt and enter into sale and tive Date and used the proceeds from the sale of the accounts leaseback transactions.

receivable in connection with this credit facility to pay allowed claims on the Effective Date. On Iay 7, 2004, PG&E ARC Cash Collateralized Letter of Credit paid off this credit facility, and on December 31, 2004, there On March 2, 2004, the Utility entered into a cash collateralized were no amounts drawn on the credit facility. Although PG&E $4oO million letter of credit facility that was used to issue letters ARC is a wholly owned consolidated subsidiary of the Utility, of credit to provide credit support in connection with the Util-PG&E ARC is legally separate from the Utility. The assets of ity's pre-existing and new natural gas procurement activities and PG&E ARC (including the accounts receivable) are not avail- related purchases of natural gas transportation services. As dis-able to creditors of the Utility or PG&E Corporation, and the cussed above, this credit facility was terminated on the Effective accounts receivable are not legally assets of the Utility or Date, and the outstanding balance of letters of credit was trans-PG&E Corporation. For the purposes of financial reporting, ferred to the $850 million working capital facility.

the credit facility is accounted for as a secured financing.

The accounts receivable facility includes a covenant from the NOTE 4:

Utility requiring it to maintain, as of the end of each fiscal RATE REDUCTION BONDS quarter ending after the Effective Date, a debt to capitalization ratio of at most 65%. In December 1997, PG&E Funding, LLC, a limited liability corporation wholly owned by and consolidated by the Utility, Working Capital Facility issued $2.9 billion of rate reduction bonds. The proceeds of the On March 5, 2004, the Utility entered into an $850 million rate reduction bonds were used by PG&E Funding, LLC to revolving credit facility, or working capital facility, with a syndi- purchase from the Utility the right, known as "transition prop-cate of banks. Loans under the working capital facility will be erty," to be paid a specified amount from a non-bypassable charge levied on residential and small commercial customers used primarily to cover operating expenses and seasonal fluctua-tions in cash flows. Letters of credit under the working capital (Fixed Transition Amount, or FTA, charges). FTA charges are authorized by the CPUC under state legislation and will be facility will be used primarily to provide credit enhancements to counter parties for natural gas and electricity procurement paid by residential and small commercial customers until the transactions. The working capital facility has a term of three rate reduction bonds are fully retired. Under the terms of a years and all outstanding amounts will be due and payable on transition property servicing agreement, FTA charges are col-lected by the Utility and remitted to PG&E Funding, LLC. As March 5, 2007. At the Utility's request and at the sole discretion a result of credit rating downgrades in January 2001, on of each lender, the working capital facility may be extended for additional periods. On the Effective Date, the Utility supported January 8, 2001, the Utility was required to begin remitting its obligation under the working capital facility with First Mlort- these FTA receipts to PG&E Funding, LLC on a daily basis, as gage Bonds. At December 31, 2004, there were $300 million of opposed to once a month, as had previously been required.

loans outstanding under the working capital facility, which had a weighted average interest rate of 3.42%. The Utility repaid the $300 million of loans outstanding on February 11, 2005.

The Utility also had approximately $285 million of letters of credit outstanding at December 31, 2004.

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The rate reduction bonds have expected maturity dates ranging On October 29, 2004, NTEGT's plan of reorganization from 2005 to 2007, and bear interest at rates ranging from 6.42% became effective, at which time NTEGT emerged from Chapter to 6.48%. The bonds are secured solely by the transition property 11 and PG&E Corporation's equity ownership in NEGT was and there is no recourse to the Utility or PG&E Corporation. cancelled. On the effective date, PG&E Corporation reversed its negative investment in NEGT and also reversed net deferred The total amount of rate reduction bonds principal out-income tax assets of approximately $428 million and a charge of standing was $870 million at December 31, 2004 and $1.16 approximately $120 million ($77 million, after tax), in accumu-billion at December 31, 2003. The scheduled principal pay-lated other comprehensive income, related to NTEGT. The ments on the rate reduction bonds for the years 2005 through resulting net gain has been offset by the $30 million payment 2007 are $290 million for each year. While PG&E Funding, made by PG&E Corporation to NEGT pursuant to the parties' LLC is a wholly owned consolidated subsidiary of the Utility, it settlement of certain tax-related litigation and other adjust-is legally separate from the Utility. The assets of PG&E Fund-ments to NEGT-related liabilities. A summary of the effect on.

ing, LLC are not available to creditors of the Utility or PG&E the quarter and year ended December 31, 2004 earnings from Corporation, and the transition property is not legally an asset discontinued operations is as follows:

of the Utility or PG&E Corporation.

(in millions)

NOTE 5: Investment in NEGT $1,208 DISCONTINUED OPERATIONS Accumulated other comprehensive income ' (120)

Cash paid pursuant to settlement of tax related litigation (30)

EffectiveJuly 8, 2003 (the date NTEGT filed a voluntary peti- Tax effect (374) tion for relief under Chapter 11), NTEGT and its subsidiaries Gain on disposal of NEGT, net of tax $ 684 were no longer consolidated by PG&E Corporation in its Con-solidated Financial Statements. Under GAAP, consolidation is generally required for entities owning more than 50% of the At December 31, 2004, PG&E Corporation's Consolidated outstanding voting stock of an investee, except when control is Balance Sheet includes approximately $138 million in income not held by the majority owner. Legal reorganization and bank- tax liabilities (including $86 million in current income taxes ruptcy represent conditions that can preclude consolidation in payable) and approximately $25 million of other net liabilities instances where control rests with an entity other than the related to N`EGT. Until PG&E Corporation reaches final set-majority owner. In anticipation of NEGT's Chapter 11 filing, tlement of these obligations, it will continue to disclose PG&E Corpioration's representatives who previously served on fluctuations in these estimated liabilities in discontinued opera-the NTEGT Board of Directors resigned on July 7, 2003, and tions. Beginning on the effective date of NEGT's plan of were replaced with Board members who were not affiliated with reorganization, PG&E Corporation no longer includes NEGT PG&E Corporation. As a result, PG&E Corporation no longer or its subsidiaries in its consolidated income tax returns.

retained significant influence over the ongoing operations of NEGT. NEGT OPERATING RESULTS Accordingly, at December 31, 2003, PG&E Corporation's Included within earnings from discontinued operations on the net negative investment in NTEGT of approximately $1.2 billion Consolidated Statements of Operations of PG&E Corporation was reflected as a single amount, under the cost method, within are NEGT's operating results, summarized below:

the December 31, 2003 Consolidated Balance Sheet of PG&E Corporation. This negative investment represents the losses of 188 Days ended Year ended NEGT recognized by PG&E Corporation in excess of its July 7, December 31, investment in and advances to NTEGT. (in millions) 2003 20C12 Operating revenues<') S 786 S 1,76 6 Income (Loss) before income taxes(') (595) (4,09 4)

(0 Amounts shown have been adjusted for intercompany eliminations.

114

Prior to July 8, 2003, NTEGT had accounted for certain of its As a result of the adoption of DIG C15 and C16, NEGT subsidiaries as discontinued operations. The operating results recognized net losses in 2002 related to the cumulative effect of shown above reflect the operating results of USGen New a change in accounting principle of $61 million, after-tax. As a England, Inc. through July 7, 2003 and the other previously dis- "result of the adoption of SFAS No. 143, NEGT recognized net continued operations through the respective disposal dates. The losses in 2003 related to a change in accounting principle of $5 2003 pre-tax loss of NEGT and its subsidiaries includes the fol- million, after-tax.

lowving gains and losses on disposal of those subsidiaries: a On October 29, 2004, the effective date of NEGT's plan of pre-tax gain of approximately $19 million on disposal related to reorganization, amounts due as a result of NEGT affiliates' the sale of Mountain View Power Partners, LLC in Janu-defaults on numerous agreements were determined and resolved.

ary 2003, an additional pre-tax loss of approximately $3 million PG&E Corporation is not a party to these agreements, nor does on disposal related to the sale of PG&E Energy Trading, it anticipate any obligation related to these agreements.

Canada Corporation in the first quarter of 2003, and a pre-tax loss of approximately $9 million on disposal related to the sale of certain Ohio generating plants and related equipment in the NOTE 6: COMMON STOCK second quarter of 2003. Also included in the 2003 pre-tax loss are impairments, write-offs, and other charges of approximately PG&E CORPORATION

$229 million.

PG&E Corporation has authorized 800 million shares of no-par The 2002 pre-tax loss of NEGT and its subsidiaries includes common stock of which 418,616,141 shares were issued and the following gains and losses on disposal of subsidiaries: a pre- outstanding at December 31, 2004 and 416,520,282 were issued tax loss of approximately $25 million on the anticipated and outstanding at December 31, 2003. A wholly owned sub-disposition of PG&E Energy Trading, Canada Corporation in sidiary of PG&E Corporation, Elm Power Corporation, holds the fourth quarter 2002, subsequently disposed of in 2003 as 24,665,500 shares of the outstanding shares.

described above, and a $1.1 billion pre-tax loss for USGen New During the fourth quarter of 2004, 1,863,600 shares of England, deemed discontinued operations in the fourth quarter PG&E Corporation common stock were repurchased through 2002. Also included in the 2002 pre-tax loss of NTEGT and its transactions with brokers and dealers on the Neew York Stock subsidiaries are impairments, write-offs, and other charges of Exchange and/or the Pacific Exchange for an aggregate pur-approximately $2.8 billion.

chase price of approximately $60 million. Of this amount, During the second quarter of 2003, NEGT determined that 850,000 shares were purchased at a cost of approximately its historical financial reporting presentation of revenues and $28 million and are held by Elm Power Corporation.

expenses related to hedging and certain ISO purchase and sales On December 15, 2004, PG&E Corporation entered into an transactions had not been consistent. Certain types of transac-accelerated share repurchase agreement with Goldman, Sachs &

tions had been reported on a net basis (whereby revenues had Co., or GS&Co., under which PG&E Corporation repurchased been offset by the related expense item) and other types of 9,769,600 shares of its outstanding common stock for an aggre-transactions had been reported on a gross basis. In order to pro-gate purchase price of approximately $318 mnillion, at an initial vide a consistent reporting of its trading and hedging price of $32.50 per share. The repurchase was funded from transactions, NEGT adopted a net presentation approach for available cash on hand. The repurchased shares have been such transactions. PG&E C6rporation believes that this method retired as of December 20, 2004. Under this arrangement, of presentation is preferable under the circumstances. Adopting PG&E Corporation has an obligation to pay GS&Co. a price this change reduced previously reported revenues and expenses adjustment based on the daily volume weighted average market of NTEGT by approximately $843 million for the year ended December 31, 2002. In addition, adjustments were made princi-pally for the effects of transactions that had not previously been eliminated in consolidation by NEGT. Such adjustments decreased previously reported revenues and expenses by approx-imately $671 million for the year ended December 31, 2002.

These changes did not result in any change in consolidated operating income or net income, in the Consolidated State-ments of Operations.

115

price of PG&E Corporation common stock over the term of PG&E Corporation previously issued warrants to purchase the arrangement. The price adjustment can be settled, at 5,066,931 shares of its common stock at an exercise price of PG&E Corporation's option, in cash or in shares of its common $0.01 per share to Jenders during 2002. During 2004, 4,003,812 stock and is accounted for as equity. The number of shares that shares of PG&E Corporation common stock were issued upon PG&E Corporation would issue in settlement of the price the exercise of the warrants. At December 31, 2004, 347,912 of adjustment feature is capped at approximately 19.5 million these warrants were outstanding and exercisable with an expira-shares. At December 31, 2004, this price adjustment obligation tion date of September 2, 2006.

amounted to approximately $7.4 million. If this obligation were PG&E Corporation did not declare or pay common or pre-settled in shares at December 31, 2004, PG&E Corporation ferred stock dividends in 2004, 2003 or 2002.

would have issued approximately 222,000 shares. PG&E Cor-poration expects the arrangement to terminate on Felruary 22, UTILITY 2005, and to pay GS&Co. approximately $14 million to settle its obligations. The Utility is authorized to issue 800 million shares of its $5 par value common stock, of which 321,314,760 shares were On December 15, 2004, the Board of Directors of the Util-issued and outstanding as of December 31, 2004 and 2003.

ity authorized the repurchase of up to $800 million, (which has PG&E Holdings, LLC, a wholly owned subsidiary of the Util-been increased to $1.8 billion following the receipt of proceeds ity, holds 19,481,213 of the outstanding shares. PG&E from the issuance of ERBs) of the Utility's common stock from Corporation and PG&E Holdings, LLC hold all of the Utility's PG&E Corporation, with such repurchases to be effective from outstanding common stock. Approximately 94% of the out-time to time, but no later than December 31, 2006. It was pre-standing common stock of the Utility that is owned by PG&E viously anticipated that the first series of ERBs would be issued Corporation was pledged as security for PG&E Corporation's as early as January 2005. Based on this expectation, on Decem-Senuor Secured Notes. On November 15, 2004, PG&E Corpo-ber 15, 2004, PG&E Corporation's Board of Directors ration redeemed these notes in full and the pledge was released.

authorized the repurchase of up to $975 million of its outstand-ing common stock. On February 16, 2005, this authorization The Utility may pay common stock dividends and repur-was increased to $1.05 billion. PG&E Corporation expects to chase its common stock provided cumulative preferred enter into a replacement accelerated share repurchase arrange- dividends on its preferred stock and mandatory preferred sink-ment by the end of February or early March 2005 to repurchase ing fund payments are paid. As further discussed in Note 7, an aggregate of $1.05 billion of its outstanding shares. The upon emergence from Chapter 11, the Utility,paid cumulative repurchased shares will be retired at that time. preferred dividends as of December 31, 2004 and preferred sinking fund payments related to 2004, 2003, and 2002.

PG&E Corporation repurchased and retired 6,580 shares of its common stock, at a cost of $102,274 during the year ended December 31, 2002. There were no stock repurchases during NOTE 7: PREFERRED STOCK the year ended December 31, 2003.

PG&E Corporation has authorized 85 million shares of pre-Of the 418,616,141 shares issued and outstanding at Decem- ferred stock, which may be issued as redeemable or ber 31, 2004, 1,601,710 shares are PG&E Corporation non-redeemable preferred stock. No preferred stock of PG&E restricted stock granted under the PG&E Corporation long- Corporation has been issued or is outstanding.

term incentive program. Further, PG&E Corporation issues common stock in connection with employee benefit plans. See UTILITY Note 10 for further discussion.

The Utility has authorized 75 million shares of $25 par value preferred stock, which may be issued as redeemable or non-redeemable preferred stock.

At December 31, 2004 and 2003, the Utility had issued and outstanding 5,784,825 shares of non-redeemable preferred stock Holders of the Utility's 5.0%, 5.5% and 6.0% series of non-redeemable preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.

116

At December 31, 2004 and 2003, the Utility had issued and Utility's Consolidated Balance Sheets. The reclassification did outstanding 5,973,456 shares of redeemable preferred stock. The not have an impact on earnings of PG&E Corporation or the Utility's redeemable preferred stock is subject to redemption at. Utility. At December 31, 2004, $122 million of such preferred the Utility's option, in whole or in part, if the Utility pays the stock remained on the Utility's Consolidated Balance Sheet.

specified redemption price plus accumulated and unpaid divi-dends through the redemption date. At December 31, 2004, NOTE 8: RISK MANAGEMENT annual dividends ranged from $1.09 to $1.76 per share and redemption prices ranged from $25.75 to $27.25 per share.

ACTIVITIES As discussed in Note 5, NEGT financial results are no longer At December 31, 2004, the Utility's redeemable preferred stock with mandatory redemption provisions consisted of 2.55 consolidated with those of PG&E Corporation following the million shares of the 6.57% series and 2.375 million shares of July 8, 2003 Chapter 11 filing of NEGT. NEGT's financial results through July 7, 2003 are reflected in discontinued opera-the 6.30% series. These series are redeemable at par value plus accumulated and unpaid dividends through the redemption v tions. Because NEGT financial results are no longer date. These series of preferred stock are subject to mandatory consolidated with those of PG&E Corporation, the only risk redemption provisions entitling them to sinking funds provid- management activities currently reported by PG&E Corpora-tion are related to Utility non-trading activities, which are ing for the retirement of the stock outstanding.

executed on a non-trading basis.

The redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions for the NON-TRADING ACTIVITIES 6.57% series are approximately $4 million per year from 2002 through 2006, and approximately $55 million in 2007, and for On the Utility's Consolidated Balance Sheets, price risk man-agement activities are presented at fair value of $5 million in the 6.30% series, approximately $3 million per year from 2004 other current assets and $11 million in other current liabilities through 2008, and approximately $47 million in 2009. The Utility's redeemable preferred stock with mandatory redemp- for December 31, 2004 and $8 million in other current assets tion provisions may be redeemed early, at the Utility's option, if for December 31, 2003. The costs of these derivatives are the Utility pays the specified redemption price plus accumu- recovered in regulated rates charged to customers and the Util-lated and unpaid dividends. In 2004, subsequent to the Utility's ity records the offset to the regulatory accounts.

emergence from Chapter 11, the Utility redeemed $15 million At December 31, 2004, the Utility had no cash flow hedges of preferred stock with mandatory redemption provisions associated with interest rate risk At December 31, 2003, the related to 2004, 2003, and 2002. Utility had cash flow hedges associated with interest rate risk presented at fair value of approximately $17 million in other Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal prefer- current assets and approximately $3 million in accumulated other comprehensive loss, net of tax. These hedges were associ-ence in dividend and liquidation rights. Due to the Utility's Chapter 11 proceeding, the Utility's Board of Directors did not ated with non-regulated operations and expired in the first declare or pay preferred stock dividends from January 31, 2001 quarter of 2004.

through emergence from Chapter 11. Upon emergence from The ineffective portion of changes in amounts of the Utility's Chapter 11 on the Effective Date, the Utility paid approxi- cash flow hedges associated with interest rate riskwas approxi-mately $101 million of preferred stock dividends, including mately $3 million for the year ended December 31, 2004 and approximately $11 million of interest on these dividends, as of approximately $4 million for the year ended December 31, 2003.

December 31, 2004. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.

PG&E Corporation and the Utility adopted the require-ments of SFAS No. 150 in 2003. As a result, the Utility reclassified approximately $137 million of preferred stock with mandatory redemption provisions as a noncurrent liability in the 117

CREDIT RISK Credit exposure for the Utility's largest customers and coun-terparties is calculated daily. If exposure exceeds the established Credit risk is the risk of loss that PG&E Corporation and the limits, the Utility takes immediate action to reduce the exposure Utility would incur if customers or counterparties failed to per-or obtain additional collateral, or both. Further, the Utility form their contractual obligations.

relies heavily on master agreements that require security, PG&E Corporation had gross accounts receivable of referred to as credit collateral, in the form of cash, letters of approximately $2.2 billion at December 31, 2004 and $2.5 bil- crudit,-corporate guarantees of acceptable credit quality, or eli-lion at December 31, 2003. The majority of the accounts gible securities if current net receivables and replacement cost receivable are associated with the Utility's residential and small exposure exceed contractually specified limits.

commercial customers. Based upon historical experience and The Utility calculates gross credit exposure for each of its evaluation of then-current factors, allowances for doubtful wholesale customers and counterparties as the current mark-to-accounts of approximately $93 million at December 31, 2004 market value of the contract (i.e., the amount that would be lost and $68 million at December 31, 2003 were recorded against if the counterparty defaulted today) plus or minus any outstand-those accounts receivable. In accordance with tariffs, credit risk ing net receivables or payables, before the application of credit exposure is limited by requiring deposits from new customers collateral. During 2004, the Utility recognized no material losses and from those customers whose past payment practices are due to contract defaults or bankruptcies. At December 31, 2004 below standard. The Utility has a regional concentration of there were three counterparties that represented greater than credit risk associated with its receivables from residential and 10% of the Utility's net credit exposure. Of these three counter-small commercial customers in northern and central California.

parties, two were investment grade representing a total of However, material loss due to non-performance from these cus-approximately 47% of the Utility's net wholesale credit exposure tomers is not considered likely.

and one was below-investment grade representing approximately The Utility manages credit risk for its largest customers or 17% of the Utility's net wholesale credit exposure.

counterparties by assigning credit limits based on an evaluation The Utility conducts business with wholesale counterparties of their financial condition, net worth, credit rating, and other mainly in the energy industry, including other California credit criteria as deemed appropriate. Credit limits and credit investor-owned electric utilities, municipal utilities, energy trad-quality are monitored frequently and a detailed credit analysis is ing companies, financial institutions, and oil and natural gas performed at least annually.

production companies located in the United States and Canada.

This concentration of counterparties may impact the Utility's overall exposure to credit risk because counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions. Credit losses experienced as a result of electrical and gas procurement activities are expected to be recoverable from customers and are therefore, not expected to have a material impact on earnings.

118

The schedule below summarizes the Utility's net credit risk exposure, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at December 31, 2004 and December 31, 2003:

Number of Net Exposure to Wholesale Wholesale Gross Credit Customer or Customer or Exposure Before Credit Net Credit Counterparties Counterparties (in millions) Credit Collateral(') Collateral Exposure(2) >10% >10%

December 31, 2004 $105 $ 7 $ 98 3 S62 December 31,2003 165 11 154 3 68

° Gross credit exposure equals mark-to-market value, notes receivable and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity or credit reserves. The Utility's gross credit expo-sure includes wholesale activity only. Retail activity and payables are not included. Retail activity at the Utility consists of the accounts receivable from the sale of natural gas and electricity to residential and small commercial customers.

( Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

The schedule below summarizes the credit quality of the Utility's net credit risk exposure to the Utility's wholesale customers and counterparties at December 31, 2004 and December 31, 2003:

(in millions) Net Credit Exposure(2 ) Percentage of Net Credit Exposure Credit Quality")

December 31, 2004 Investment grade() $ 79 81%

Non-investment grade 19 19%

Total $ 98 100%

December 31, 2003 Investment grade( 5M $108 70%

Non-investment grade 46 30%

Total $154 100%

') Credit ratings are determined by using publicly available information. If provided a guarantee by a higher rated entity (e.g., an affiliate), the rating is determined based on the rating of the guarantor.

V) Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guar-antees are not included as part of the calculation.

°' Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody's and BBB- by S&P. The Utility has assessed certain governmental authorities that are not rated through publicly available information as investment grade based upon an internal assessment of credit worthiness.

11 9

NOTE 9: NUCLEAR The estimated nuclear decommissioning cost described above DECOMMISSIONING is used for regulatory purposes. Decommissioning costs recov-ered in rates are placed in nuclear decommissioning trusts.

Nuclear decommissioning requires the safe removal of nuclear However, under GAAP requirements, the decommissioning cost facilities from service and the reduction of residual radioactivity estimate is calculated using a different method. In accordance to a level that permits termination of the NTRC license and with SFAS No. 143, the Utility adjusts its nuclear decommis-release of the property for unrestricted use. The Utility's sioning obligation to reflect the fair value of decommissioning nuclear power facilities consist of two units at the Diablo its nuclear power facilities. The Utility records the Utility's total Canyon power plant and the retired facility at Humboldt Bay nuclear decommissioning obligation as an asset retirement obli-Unit 3. For ratemaking purposes, the eventual decommission- gation on the Utility's Consolidated Balance Sheet. The total ing of Diablo Canyon Unit 1 is scheduled to begin in 2021 and nuclear decommissioning obligation accrued in accordance with to be completed in 2040. Decommissioning of Diablo Canyon GAAP was approximately $1.2 billion at December 31, 2004 and Unit 2 is scheduled to begin in 2025 and to be completed in $1.1 billion at December 31, 2003. The primary difference 2041, and decommissioning of Humboldt Bay Unit 3 is sched- between the Utility's estimated nuclear decommissioning uled to begin in 2009 and be completed in 2015. obligation as recorded in accordance with GAAP and the esti-The estimated nuclear decommissioning cost for the Diablo mate prepared in accordance with the CPUC requirements is Canyon power plant and Humboldt Bay Unit 3 is approxi- that GAAP incorporates various potential settlement dates for mately $1.89 billion in 2004 dollars (or approximately $5.25 the obligation and includes an estimated amount for third party billion in future dollars). These estimates are based on a 2002 labor costs into the fair value calculation.

decommissioning cost study and are prepared in accordance The Utility has three decommissioning trusts for its Diablo with CPUC requirements and are used in the Utility's Nuclear Canyon and Humboldt Bay Unit 3 nuclear facilities. The Util-Decommissioning Costs Triennial Proceeding. The Utility's ity has elected that tivo of these trusts be treated under the revenue requirements for nuclear decommissioning costs are Internal Revenue Code as qualified trusts. If certain conditions recovered from customers through a non-bypassable charge are met, the Utility is allowed a deduction for the payments that will continue until those costs are fully recovered. The made to the qualified trusts. These payments cannot exceed the decommissioning cost estimates are based on the plant location amount collected from customers through the decommissioning and cost characteristics for the Utility's nuclear plants. Actual charge. The qualified trusts are subject to a lower tax rate on decommissioning costs are expected to vary from these esti- income and capital gains, thereby increasing the trusts' after-tax mates because of changes in assumed dates of decommissioning, returns. Among other requirements, to maintain the qualified regulatory requirements, technology, costs of labor, materials trust status the IRS must approve the amount to be contributed and equipment. to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until such decommissioning costs are actually incurred.

In October 2003, the CPUC issued a decision in the 2002 Nuclear Decommissioning Costs Triennial Proceeding (cover-ing 2003 through 2005) finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the Diablo Canyon power plant's eventual decommissioning. In 2004, the Utility was authorized to collect approximately $18.4 million in rates and contributed approximately $18.4 million to the qualified nuclear decommissioning trust for Humboldt Bay Unit 3. For 2005, the Utility is authorized to collect approxi-120

mately $18.4 million in rates for decommissioning Humboldt All earnings on the assets held in the trusts, net of author-Bay Unit 3. Of this amount, the Utility expects to contribute ized disbursements from the trusts and investment management approximately $18.4 million to the qualified trusts for Hum- and administrative fees, are reinvested. Amounts may not be boldt Bay Unit 3. The Utility received approval from the IRS released from the decommissioning trusts until authorized by to contribute a portion of the collected amount to the qualified the CPUC. At December 31, 2004, the Utility had accumulated trust for Humboldt Bay Unit 3. The Utility has requested the nuclear decommissioning trust funds waith an estimated fair IRS approve a revised ruling for the total amount collected to value of approximately $1.6 billion, based on quoted market be contributed to the qualified trust for Humboldt Bay Unit 3. prices and net of deferred taxes on unrealized gains.

If the IRS does not approve the revised ruling request, the Util-In general, investment securities are exposed to various risks, ity must withdraw contributions it made to the qualified trust such as interest rate, credit and market volatility risks. Due to for 2004 and 2005 in excess of the current IRS ruling amount the level of risk associated with certain investment securities, it and contribute the excess amounts, on an after-tax basis, to the is reasonably possible that changes in the market values of non-qualified trust. The Utility would likely request that the investment securities could occur in the near term, and such CPUC approve an increase in revenue requirements to make up changes could materially affect the trusts' fair value.

for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes. The Utility records unrealized gains and losses on invest-ments held in the trusts in other comprehensive income in The funds in the decommnissioning trusts, along with accu-accordance with SFAS No. 115, "Accounting for Certain mulated earnings, will be used exclusively for decommissioning Investments in Debt and Equity Securities." Realized gains and and dismantling the Utility's nuclear facilities. The trusts main-losses are recognized as additions or reductions to trust asset tain substantially all of their investments in debt and equity balances. The Utility, however, accounts for its nuclear decom-securities. The CPUC has authorized the qualified trust to missioning obligations in accordance with SFAS No. 71.

invest a maximum of 50% of its funds in publicly traded equity Therefore, both realized and unrealized gains and losses are securities, of which up to 20% may be invested in publicly ultimately recorded in regulatory asset or liability accounts.

traded non-US equity securities. For the non-qualified trust, no more than 60% may be invested in publicly traded equities.

The allocation of the trust funds is monitored monthly. To the extent that market movements cause the asset allocation to move outside these ranges, the investments are rebalanced toward the target allocation.

The Utility estimates after-tax annual earnings, including realized gains and losses, in the qualified trusts to be 6.5% and in the non-qualified trusts to be 5.6%. Annual returns decrease in later years as higher portions of the trusts are dedicated to fixed income investments leading up to and during the entire course of decommissioning activities.

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The following table provides a summary of the fair value, based on quoted market prices, of the investments held in the Utility's nuclear decommissioning trusts:

Total Total Unrealized Unrealized Estimated (inmillions) Maturity Date Gains Losses Fair Value Year ended December 31, 2004 U.S. government and agency issues 2005-2033 $ 47 S- $ 681 Municipal bonds and other 2005-2034 14 - 181 Equity securities 523 - 880 Total S584 S- $1,742 Year ended December 31, 2003 U.S. government and agency issues 2004-2032 S 47 S- $ 586 Municipal bonds and other 2004-2034 11 - 147 Equity securities 409 (1) 790 Total $467 S(1) $1,523 The cost of debt and equity securities sold is determined by specific identification. The following table provides a summary of the activity for the debt and equity securities:

Year Ended December 31, (inrnillions) 2004 2003 2002 Proceeds received from sales of securities $1,821 $1,087 $1,631 Gross realized gains on sales of securities held as available-for-sale 28 27 51 Gross realized losses on sales of securities held as available-for-sale 22 (44) (91)

SPENT NUCLEAR dry cask storage facility is expected to start in the second quar-FUEL STORAGE PROCEEDINGS ter of 2005 after grading permits are obtained from the County of San Luis Obispo. To provide another storage alternative in Under the Nuclear Waste Policy Act of 1982, the Department the event construction of the dry cask storage facility is delayed, of Energy, or the DOE, is responsible for the permanent stor-the Utility has also requested that the NRC approve another age and disposal of spent nuclear fuel. The Utility has signed a storage option to install a temporary storage rack in each unit's contract with the DOE to provide for the disposal of spent existing spent fuel storage pool that would increase the on-site nuclear fuel and high-level radioactive waste from the Utility's storage capability to permit the Utility to operate Unit I until nuclear power facilities. Under the Utility's contract with the 2010 and Unit 2 until 201 1. If the Utility is unsuccessful in per-DOE, if the DOE completes a storage facility by 2010, the ear-mitting and constructing the on-site dry cask storage facility, liest that Diablo Canyon's spent fuel would be accepted for and is otherwise unable to increase its on-site storage capacity, storage or disposal would be 2018. At the projected level of it is possible that the operation of Diablo Canyon may have to operation for Diablo Canyon, the Utility's current facilities are be curtailed or halted as early as 2007 and until such time as able to store on-site all spent fuel produced through approxi-additional spent fuel can be safely stored.

mately 2007. The NRC granted authorization in March 2004 to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2.

However, several intervenors in that proceeding filed an appeal NOTE 10: EMPLOYEE of the NRC's decision with the U.S. Court of Appeals for the COMPENSATION PLANS Ninth Circuit, or Ninth Circuit. Oral arguments on that appeal PG&E Corporation and its subsidiaries provide non-are expected in the first quarter of 2005 with a decision antici- contributory defined benefit pension plans for certain pated in the second half of 2005. Construction of the on-site employees and retirees, referred to collectively as pension bene-fits. PG&E Corporation and the Utility have elected that 122

certain of the trusts underlying these plans be treated under the PG&E Corporation following the July 8, 2003 Chapter 11 Internal Revenue Code as qualified trusts. If certain conditions filing of NEGT. Accordingly, pension and other benefits infor-are met, PG&E Corporation and the Utility are allowed a mation is disclosed below for plans that PG&E Corporation deduction for payments made to the qualified trusts, subject to and the Utility sponsor at December 31, 2004. PG&E Corpo-certain Internal Revenue Code limitations. PG&E Corporation ration and its subsidiaries use a December 31 measurement date and its subsidiaries also provide contributory defined benefit for all of their plans.

medical plans for certain retired employees and their eligible dependents, and non-contributory defined benefit life insurance BENEFIT OBLIGATIONS plans for certain retired employees (referred to collectively as The following reconciles changes in aggregate projected benefit other benefits). The following schedules aggregate all PG&E obligations for pension benefits and changes in the benefit obli-Corporation's and the Utility's plans. As discussed in Note 5, gation of other benefits during 2004 and 2003:

N'EGT financial results are no longer consolidated in those of Pension Benefits PG&E Corporation Utility (in millions) 2004 2003 2004 2003 Projected benefit obligation atJanuary 1 57,516 $6,738 $7,509 $6,732 Service cost for benefits earned 194 170 194 170 Interest cost 482 446 482 445 Plan amendments 28 135 28 135 Actuarial loss 667 338 667 338 Settlement - (4) = (4)

Benefits and expenses paid (330) (307) (329) (307)

Projected benefit obligation at December31 $8,557 $7,516 S8,551 $7,509 Accumulated benefit obligation S7,638 $6,656 S7,632 $6,650 PG&E Corporation has participants in the Utility's Retirement Plan, Retirement Excess Benefit Plan and the Supplemental Executive Retirement Plan. PG&E Corporation's obligation for its participants in these plans was approximately $19 million at December 31, 2004 and $15 million at December 31, 2003, and is recorded as a liability in PG&E Corporation's Balance Sheets.

Other Benefits PG&E Corporation Utility (in millions) 2004 2003 2004 2003 Benefit obligation at January I $1,444 $1,197 $1,444 S1,197 Service cost for benefits earned 32 29 32 29 Interest cost 85 79 85 79 Actuarial loss (103) 61 (103) 61 Participants paid benefits 30 33 30 33 Plan amendments - 124 - 124 Benefits paid (89) (79) (89) (79)

Bencfit obligation at December31 $1,399 $1,444 $1,399 $1,444 PG&E Corporation has participants in the Utility's Postretirement Medical Plan and Postretirement Life Insurance Plan.

PG&E Corporation's obligation for its participants in these plans was approximately $1 million at December 31, 2004 and $1 million at December 31, 2003, and is recorded as a liability in PG&E Corporation's Balance Sheets.

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CHANGE IN PLAN ASSETS PG&E Corporation and the Utility use publicly quoted market values and independent pricing services depending on the nature of the assets, as reported by the trustee to determine the fair value of the plan assets.

The following reconciles aggregate changes in plan assets during 2004 and 2003:

Pension Benefits PG&E Corporation Utility (in millions) 2004 2003 2004 2003 Fair value of plan assets at January 1 $7,129 $6,153 $7,129 $6,153 Actual return on plan assets 787 1,280 787 1,280 Company contributions 27 7 27 7 Settlement - (4) - (4)

Benefits and expenses paid (329) (307) (329) (307)

Fair value of plan assets at December 31 $7,614 $7,129 $7,614 $7,129 Other Benefits PG&E Corporation Utility (in million) 2004 2003 2004 2003 Fair value ofplanasseis atJanuary 1 $ 955 $749 $ 955 $749 Actual return on plan assets 108 186 108 186 Company contributions 71 72 71 72 Plan participant contribution 30 33 30 33 Benefits and expenses paid (95) (85) (95) (85)

Fair value of plan assets at December 31 $1,069 $955 $1,069 $955 124

FUNDED STATUS The following schedule reconciles the plans' aggregate funded status to the prepaid or accrued benefit cost recorded on PG&E Corporation's and the Utility's Consolidated Balance Sheets. The funded status is the difference between the fair value of plan assets and projected benefit obligations.

Pension Benefits PG&E Corporation Utility December 31, December31, (in millions) 2004 '2003 2004 2003 Fair value of plan assets at December 31 $ 7,614 S 7,129 $ 7,614 $ 7,129 Projected benefit obligation at December 31 (8,557) (7,516) (8,551) (7,509)

Funded status plan assets less than projected benefit obligation (943) (387) (937) (380)

Unrecognized prior service cost 378 405 378 405 Unrecognized net loss 1,148 715 1,148 714 Unrecognized net transition obligation 2 8 2 8 Prepaid (accrued) benefit cost S 585 S 741 S 591 $ 747 Prepaid benefit cost $ 638 S 792 $ 638 S 792 Accrued benefit liability (53) (51) (47) (45)

Additional minimum liability - (7) - (7)

Intangible asset Accumulated other comprehensive income - 7 - 7 Prepaid (accrued) benefit cost $ 585 S 741 $ 591 S 747 Other Benefits PG&E Corporation Utility December 31, December 31, (in millions) 2004 2003 2004 2003 Fair value of plan assets at December31 S 1,069 $ 955 S 1,069 S 955 Benefit obligation at December 31 (1,399) (1,444) (1,399) (1,444)

Funded status plan assets less than benefit obligation (330) (489) (330) (489)

Unrecognized prior service cost 110 125 110 125 Unrecognized net loss 1 125 1 125 Unrecognized net transition obligation 205 232 205 232 Prepaid (accrued) benefit cost S (14) $ (7) $ (14) $ (7)

Prepaid benefit cost $ - S - $ - $ -

Accrued benefit liability (14) (7) (14) (7)

Additional minimum liability Prepaid (accrued) benefit cost S (14) S (7) S (14) $ (7) 125

The separate prepaid benefit costs and accrued benefit liabilities'of PG&E Corporation's pension and other benefit plans were as follows:

PG&E Corporation Utility December 31, December 31, (in millions) 2004 2003 2004 2003 Pension Benefits:

Prepaid benefit cost $638 $792 $638 $792 Accrued benefit liabilities (53) (51) (47) (45)

Other Benefits:

Prepaid benefit cost $ - $- $ - -

Accrued benefit liabilities (14) (7) (14) (7)

The aggregate projected benefit obligation, accumulated benefit obligation and fair value of plan assets for plans in which the fair value of plan assets are less than either the projected benefit obligation or accumulated benefit obligation as of December 31, 2004 and 2003 were as follows:

Pension Benefits Other Benefits (inmillions) 2004 2003 2004 2003 PG&E Corporation:

Projected benefit obligation $(8,557) $(7,516) $(1,399) $(1,444)

Accumulated benefit obligation (7,638) (6,656) - -

Fair value of plan assets 7,614 7,129 1,069 955 Utility Projected benefit obligation $(8,551) $(7,509) $(1,399) $(1,444)

Accumulated benefit obligation (7,632) (6,650) - -

Fair value of plan assets 7,614 7,129 1,069 955 COMPONENTS OF NET PERIODIC BENEFIT COST Pension Benefits PG&E Corporation Utility December 31, December 31, (in millions) 2004 2003 2002 2004 2003 2002 Service cost for benefits earned $ 194 S 170 S 140 $ 194 $ 170 $ 138 Interest cost 482 446 438 481 445 435 Expected return on Plan's assets (563) (507) (596) (563) (507) (592)

Amortized prior service cost 63 56 59 63 56 59 Amortization of unrecognized loss (gain), 6 46 (3) 6 46 (3)

Settlement loss - 1 5 - 1 5 Net periodic benefit cost (income) - 182 S212 $ 43 $ 181 $211 $ 42 Other Benefits PG&E Corporation Utility December 31, December 3 1, (in millions) 2004 2003 2002 2004 2003 2002 Service cost for benefits earned $ 32 $ 29 $ 25 S 32 $ 29 S 24 Interest cost 84 79 77 84 79 76 Expected return on Plan's assets (76) (61) (76) (76) (61) (75)

Amortized prior service cost 38 28 28 38 28 28 Amortization of unrecognized loss - 1 (4) - 1 (4)

Net periodic benefit cost (income) $78 $ 76 $ 50 S 78 $ 76 549 126

Valuation Assumptions The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic cost. Weighted average, year-end assumptions were used in determining the plans' projected benefit obligations, while prior year-end assumptions are used to compute net benefit cost.

Pension Benefits Other Benefits December 31, December 31, 2004 2003 2002 2004 2003 2002 Discount rate 5.80% 6.25% 6.75% 5.80% 6.25% 6.75%

Average rate of future compensation increases 5.00% 5.00% 5.00% - - -

Expected return on plan assets Pension Benefits 8.10% 8.10% 8.10% - - -

Other Benefits:

Defined Benefit-Mledical Plan Bargaining - 8.50% 8.50% 8.50%

Defined Benefit-Aledical Plan Non-Bargaining - 7.60% 7.60% 7.20%

Defined Benefit-Life Insurance Plan - 8.50% 8.50% 8.10%

The assumed health care cost trend rate for 2005 is approxi- The difference between actual and expected return on plan mately 10%, grading down to an ultimate rate in 2009 and beyond assets is included in net amortization and deferral, and is con-of approximately 5.0%. A one-percentage point change in assumed sidered in the determination of future net benefit income (cost).

health care cost trend rate would have the following effects: The actual return on plan assets was above the expected return in 2004 and 2003, and below the expected return in 2002.

One-Percentage One-Percentage (in millions) Point Increase Point Decrease Under SPAS No. 71, regulatory adjustments have been recorded in the Consolidated Statements of Operations and Effect on postretirement benefit oblig ation S30 $(27)

Consolidated Balance Sheets of the Utility to reflect the differ-Effect on service and interest cost 9 - (7) ence between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, Expected rates of return on plan assets were developed by which is based on a funding approach. The CPUC has author-determining projected stock and bond returns and then apply- ized the Utility to recover the costs associated wvith its other ing these returns to the target asset allocations of the employee benefits for 1993 and beyond. Recovery is based on the lesser of benefit trusts, resulting in a weighted average rate of return on the amounts collected in rates or the annual contributions on a plan assets. Fixed income projected returns were based on his- tax-deductible basis to the appropriate trusts.

torical returns for the broad U.S. bond market. Equity returns were based primarily on historical returns of the S&P 500 Asset Allocations Index. For the Utility Retirement Plan, the assumed return of The asset allocation of PG&E Corporation's and the Utility's 8.1% compares to a ten-year actual return of 9.5%.

pension and other benefit plans at December 31, 2004 and 2003, and target 2005 allocation was as follows:

Pension Benefits Other Benefits 2005 2004 2003 2005 2004 2003 Equity Securities U.S. Equity 40% 43% 42% 51% 51% 50%

Non-U.S. Equity 20% 22% 22% 20% 21% 22%

Debt Securities 40% 35% 36% 29% 28% 28%

Total 100% 100% 100% 100% 100% 100%

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Equity securities include a small amount (less than&0.1% of Benrefits Payments total plan assets) of PG&E Corporation common stock. The estimated benefits expected to be paid in each of the next five fiscal years and in aggregate for the five fiscal years there-The maturity of debt securities at December 31, 2004 and after are as follows:

2003 ranges from zero to 45 years, with a weighted average (in millions) PG&E Corporation Utility maturity of approximately 6.32 years.

Pension 2005 S 349 $ 349 PG&E Corporation's and the Utility's investment strategy for 2006 369 368 all plans is to maintain actual asset weightings within 5% of the 2007 389 389 target asset allocations. *Whenever the actual weighting exceeds 2008 412 411 the target weighting by 5%, the asset holdings are rebalanced. 2009 437 436 2010-2015 2,584 2,581 A benchmark portfolio for each asset class is set based on mar- Other benefits ket capitalization and valuations of equities and the durations and 2005 S 55 $ 55 credit quality of debt securities. Investment managers for each asset 2006 65 65 class are retained to periodically adjust, or actively manage, the 2007 76 76 2008 86 86 combined portfolio against the benchmark. Active management 2009 96 96 covers approximately 70% of the U.S. equity, 60% of the non-U.S.

20 10-2015 651 651 equity, and virtually 100% of the debt security portfolios.

DEFINED CONTRIBUTION PENSION PLAN CASH FLOW INFORMATION PG&E Corporation and its subsidiaries also sponsor defined Employer Contributions contribution pension plans. These plans are qualified under PG&E Corporation and the Utility expect to contribute applicable sections of the Internal Revenue Code. These plans approximately $20 million to its Pension Benefits Plan, to fund provide' for tax-deferred salary deductions and after-tax voluntary retirement program obligations and approximately employee contributions as well as employer contributions.

$65 million to its Other Benefits plans in 2005. These contribu- Employees designate the funds in which their contributions and tions would be consistent with PG&E Corporation's and the any employer contributions are invested. Employer contribu-Utility's funding policy, which is to contribute amounts that are tions include matching of up to 5% of an employee's base tax deductible, consistent with applicable regulatory decisions compensation and/or basic contributions of up to 5% of an and sufficient to meet minimum funding requirements. None of employee's base compensation. Matching employer contribu-these benefit plans are subject to a minimum funding require- tions are automatically invested in PG&E Corporation common ment in 2005. stock. Employees may reallocate matching employer contribu-tions and accumulated earnings thereon to another investment fund or funds available to the plan at any time after they have been credited to their account. Employer contribution expense reflected in PG&E Corporation's Consolidated Statements of Operations amounted to:

Year ended December 31, (in millions) PG&E Corporation Utility 2004 $40 S39 2003 38 37 2002 52 36 e's Includes NEGT-related amounts within PG&E Corporation.

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LONG-TERM INCENTIVE PROGRAM with or without associated stock appreciation rights and divi-dend equivalents.

PG&E Corporation maintains a long-term incentive program, or LTIP, that permits stock options, restricted stock and other Stock Options stock-based incentive awards to be granted to non-employee directors, executive officers and other employees of PG&E At December 31, 2004, 31,489,783 shares of PG&E Corpora-Corporation and its subsidiaries. Stock options can be granted tion common stock were authorized for award under the LTIP, of which 10,439,785 shares were available for grant.

PG&E Corporation The weighted average grant date fair values of options granted using the Black-Scholes valuation method were $8.70 per share in 2004, $7.27 per share in 2003, and $6.61 per share in 2002. Significant assumptions used in the Black-Scholes valuation method for shares granted in 2004, 2003, and 2002 were:

2004 2003 20021 Expected stock price volatility 45.0% 45.0% 30%

Expected annual dividend payment $1.20 $- $-

Risk-free interest rate 3.66% 3.46% 4.65%

Expected life 6.5 years 6.5 years 10 years Stock options issued afterJanuary 2003 become exercisable All options expire ten years and one day after the date of on a cumulative basis at one-fourth each year commencing one grant. Options outstanding at December 31, 2004, had option year from the date of the grant. Stock options issued before prices ranging from $12.50 to $33.50, and a weighted average January 2003 become exercisable on a cumulative basis at one- remaining contractual life of 5.60 years.

third each year commencing two years from the date of grant.

The following table summarizes stock option activity for the years ended December 31:

2004 2003 2002 Weighted Weighted Weighted Average Average Average Shares Option Price Shares Option Price Shares Option Price Outstanding at January I 27,416,380 $21.26 31,067,611 $22.22 34,080,405 $22.11 Granted 2,450,400 27.24 3,649,902 14.62 211,712 19.44 Exercised (8,173,864) >- 18.39 (3,818,837) 19.15 (332,436) 23.65 Cancelled (814,358) 21.37 (3,482,296) 25.18 (2,892,070) 20.56 Outstanding at December 31 20,878,558 22.76 27,416,380 21.26 31,067,611 22.22 Exercisable 13,981,720 24.67 16,072,654 25.34 15,487,462 27.05 129

The following summarizes information for options outstand- 7,485,820 options had exercise prices ranging from $27.75 to ing and exercisable at December 31, 2004. Of the outstanding $33.50, with a weighted average exercise price of $30.64 and a options at December 31, 2004: weighted average remaining contractual life of 3.55 years, of which 7,474,370 shares were exercisable at a weighted average

• 7,665,219 options had exercise prices ranging from $12.50 to exercise price of $30.64.

$16.68 with a weighted average exercise price of $14.59 and a weighted average remaining contractual life of 7.00 years, of In addition, 1,420,000 options were granted on January 3, 2005, which 3,227,390 shares were exercisable at a weighted average at an exercise price of $33.02, the then-current market price of exercise price of $14.72; PG&E Corporation common stock.

• 5,727,519 options had exercise prices ranging from $19.45 to Utility

$27.23 with a weighted average exercise price of $23.41 and a Stock; options outstanding to purchase PG&E Corporation weighted average remaining contractual life of 6.41 years, of common stock held by Utility employees at December 31, 2004 which 3,279,960 shares were exercisable at a weighted average had option prices ranging from $12.63 to $33.50, and a exercise price of $20.84; and weighted average remaining contractual life of 5.81 years.

The following table summarizes the stock option activity for the Utility employees for the years ended December 31:

2004 2003 2002 Weighted Weighted Weighted Average Average Average Shares Option Price Shares Option Price Shares Option Price Outstanding atjanuary 1 13,543,182 $21.01 13,300,300 $22.32 13,601,834 $22.35 Granted"' 1,903,238 26.05 2,160,425 14.62 - -

Exercised (4,146,084) 19.00 (1,310,156) 20.97 (187,935) 23.49 Cancelled (231,662) 23.40 (607,387) 27.05 (113,599) 23.98 Outstanding at December31 11,068,674 22.58 13,543,182 21.01 13,300,300 22.32 Exercisable 6,607,089 24.94 7,668,908 25.33 6,314,620 27.72

(') Includes net stock options related to employee transfers to the Utility.

The following summarizes information for options outstand-

• 2,995,314 options had exercise prices ranging from $19.81 to ing and exercisable at December 31, 2004. Of the outstanding $27.23, with a weighted average exercise price of $24.03 and a options at December 31, 2004: weighted average remaining contractual life of 6.99 years, of which 1,387,964 options were exercisable at a weighted aver-

• 4,300,054 options had exercise prices ranging from $12.63 to age exercise price of $20.32; and

$16.68, with a weighted average exercise price of $14.52 and a weighted average remaining contractual life of 7.05 years, of

• 3,773,306 options had exercise prices ranging from $28.06 to which 1,453,819 options were exercisable at a weighted aver- $33.50, with a weighted average exercise price of $30.63 and a age exercise price of $14.60; weighted average remaining contractual life of 3.46 years, of which 3,765,306 options were exercisable at a weighted aver-age exercise price of $30.63.

In addition, 1,042,550 options were granted to Utility employees on January 3, 2005 at an exercise price of $33.02, the then-current market price of PG&E Corporation common stocL Restricted Stock At December 31, 2004, a total of 2,088,920 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 1,351,675 shares were granted to Utility employees.

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PG&E Corporation granted 498,910 shares of restricted com- shares, subject to the achievement of certain performance tar-mon stock during 2004, of which 342,180 shares were granted to gets, vest on the third year anniversary following the date of the Utility employees. At December 31, 2004, 1,601,710 shares of grant. The number of performance shares that were outstand-restricted PG&E Corporation common stock were outstanding, ing at December 31, 2004 was 486,010 of which 330,832 were of which 1,056,610 related to Utility employees. The shares related to Utility employees. The amount of compensation were granted with restrictions and are subject to forfeiture unless expense recognized in 2004 in connection with the issuance of certain conditions are met. performance shares was approximately $3 million, of which $2 million was recognized by the Utility. On January 3, 2005, The restricted shares are held in an escrow account. The PG&E Corporation awarded 328,340 performance shares, of shares become available to the employees as the restrictions which 241,240 were awarded to Utility.employees.

lapse. For restricted stock granted in 2003, the restrictions on 80% of the shares lapse automatically over a period of four PG&E Corporation has granted performance units to cer-years at the rate of 20% per year. The compensation expense tain officers and employees of PG&E Corporation and its for these shares remains fixed at the value of the stock at grant subsidiaries. The performance units, subject to achievement of date. Restrictions on the remaining 20% of the shares will lapse certain performance targets, vest one-third peryear and are set-at a rate of 5% per year if PG&E Corporation is in the top tled in cash annually as vesting occurs in each of the three years quartile of its comparator group as measured by annual total following the year of grant. As a result of achieving perform-shareholder return for each year ending immediately before ance criteria, at December 31, 2004, all remaining units vested each annual lapse date. The compensation expense recognized and PG&E Corporation recognized compensation expense for these shares is variable, and changes with the common totaling approximately $5 million in 2004, of which $2 million stock's market price. The performance criteria during 2004 was related to the Utility. These amounts were paid in January 2005 not met. For restricted stock grants awarded in 2004, there to the participating individuals.

were no restricted stock shares containing performance criteria and the restrictions lapse ratably over four years. PG&E Corporation Supplemental Retirement Savings Plan Compensation expense associated with all the shares is rec- The supplemental retirement savings plan provides supple-ognized on a quarterly basis, by amortizing the unearned mental retirement alternatives to eligible officers and key compensation related to that period. Total compensation employees of PG&E Corporation and its subsidiaries by allow-expense resulting from the restricted stock issuance reflected on ing participants to defer portions of their compensation, PG&E Corporation's Consolidated Statements of Operations including salaries and amounts awarded under various incentive was approximately $9 million in 2004 and approximately $7 awards and to receive supplemental employer-provided retire-million in 2003, of which approximately $6 million in 2004 and ment benefits. Under the employee-elected deferral component approximately $4 million in 2003 was recognized by the Utility. of the plan, eligible employees may defer all or part of their The total unamortized balance of unearned compensation incentive awards, and 5% to 50% of their salary. Under the resulting from the restricted stock issuance reflected on PG&E supplemental employer-provided retirement benefits compo-Corporation's Consolidated Balance Sheets was approximately nent of the plan, eligible employees may receive full credit for

$26 million at December 31, 2004 and $20 million at Decem- employer matching and basic contributions, under the respec-ber 31, 2003. On January 3, 2005 PG&E Corporation awarded 328,340 shares of restricted stock, of which 241,240 shares were granted to Utility employees.

Performance Shares and Performance Units Starting in 2004, PG&E Corporation awarded 498,910 per-formance shares, or phantom stock, to certain officers and employees of PG&E Corporation and its subsidiaries of which 342,180 were awarded to Utility employees. The performance 131

tive defined contribution plan, in excess of limitations set out by These grants provided certain employees with PG&E Cor-the Internal Revenue Code. A separate non-qualified account is poration phantom restricted stock units that vested in full on maintained for each eligible employee to track deferred December 31, 2003 upon PG&E Corporation meeting certain amounts. The account's value is adjusted in accordance with the performance measures at that date. A total of 3,044,600 phan-performance of the investment options selected by the tom stock units were granted under this program. There were employee. Each employee's account is adjusted on a quarterly no similar grants in 2004. These units were marked to market basis and the change in value is recorded as additional compen- based on the market price of PG&E Corporation common sation expense or income in the Consolidated Financial , stock and amortized as a charge to income over a four-year Statements. Total compensation expense recognized by PG&E period. As a result of meeting the performance criteria at Corporation and the Utility in connection with the plan December 31, 2003, these units fully vested and the remaining amounted to: compensation expense was recognized in 2003. Total compensa-tion expense recognized in connection with these retention Year ended December 31, mechanisms, including cash payments and phantom restricted (in millions) PG&E Corporation Utility stock units, amounted to:

2004 $3 $1 2003 7 I Year ended December 31, 2002 2 - (in millions) PG&E Corporation Utility 2004 $- $-

RETENTION PROGRAMS 2003 63 38 2002 12 7 PG&E Corporation implemented various retention programs in 2001. One of these programs granted key personnel of PG&E

• In January 2004, approximately $84.5 million was paid to Corporation and its subsidiaries with lump-sum cash payments. participating individuals in the senior executive retention pro-In addition, another program granted units of special senior gram. There are no payments remaining under either plan.

executive retention grants.

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NOTE 11: INCOME TAXES The significant components of income tax (benefit) expense for continuing operations were:

PG&E Corporation Utility Year Ended December 31, (in millions) 2004 .2003 2002 2004 2003 2002 Current:

Federal $ 121 $ 61 S 495 S 73 S524 $ 591 State 91 41 218 85 171 247 Deferred:

Federal 1,877 422 420 2,000 (88) 349 State 384 (49) 15 410 (62) 2 Tax credits, net (7) (17) (11) (7) (17) (11)

Income tax expense $2,466 $458 $1,137 S2,561 S528 $1,178 The following describes net deferred income tax liabilities:

PG&E Corporation Utility Year ended December 31, (in millions) 2004 2003 2004 2003 Deferred income tax assets:

Customer advances for construction $ 472 $ 386 $ 472 S 386 Unamortized investment tax credits 108 110 108 110 Reserve for damages 270 273 270 273 Environmental reserve 194 172 194 172 Discontinued operations - 605 - -

Other 151 110 70 252 Total deferred income tax assets $1,195 $1,656 $1,114 S1,193 Deferred income tax liabilities:

Regulatory balancing accounts $2,097 $ 139 $2,097 5 139 Property related basis differences 2,413 2,005 2,413 2,005 Income tax regulatory asset 209 142 209 142 Unamortized loss on reacquired debt 137 110 137 110 Other 264 218 264 217 Total deferred income tax liabilities 5,120 2,614 5,120 2,613 Total net deferred income taxes liabilities 3,925 958 4,006 1,420 Classification of net deferred income taxes liabilities:

Included in current liabilities 394 102 377 86 Included in noncurrent liabilities 3,531 856 3,629 1,334 Total net deferred income taxes liabilities $3,925 S 958 $4,006 $1,420 133

The differences between income taxes and amounts calculated by applying the federal legal rate to income before income tax expense for continuing operations were:

PG&E Corporation Utility Year Ended December 31, 2004 2003 20()2 2004 2003 2002 Federal statutory income tax rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%

Increase in income tax rate resulting from:

State income tax (net of federal benefit) 4.6 4.7 5.3 4.7 4.9 5.4 Effect of regulatory treatment of depreciation differences (0.5) (2.9) 1.2 (0.4) (2.5) 1.1 Tax credits, net (0.2) (1.7) (0.5) (0.2) (1.5) (0.5)

Other, net 0.3 1.3 (1.2) 0.2 0.5 (1.7)

Effective tax rate 39.2% 36.4% 39.8% 39.3% 36.4% 39.3%

The IRS has completed its audit of PG&E Corporation's PG&E Corporation has accrued $52 million associated with 1997 and 1998 consolidated federal income tax returns and has NEGT related tax liabilities. In addition, PG&E Corporation assessed additional federal income taxes of approximately $79 has accrued a $41 million liability to cover potential tax obliga-million (including interest). PG&E Corporation has filed protests tions relating to non-NEGT issues raised in outstanding tax contesting certain adjustments made by the IRS in that audit and audits. The Utility has accrued $62 million to cover potential currently is discussing these adjustments with the IRS Appeals tax obligations for outstanding tax audits. Considering these Office. PG&E Corporation does not expect final resolution of reserves, PG&E Corporation does not expect the resolution of these appeals to have a material impact on its financial position or these matters to have a material impact on its financial position results of operations. or result of operations.

In the fourth quarter of 2003, PG&E Corporation made an All IRS audits of PG&E Corporation's federal income tax advance payment to the IRS of $75 million relating to the 1999 returns prior to 1997 have been closed.

and 2000 audit. The IRS completed its audit of PG&E Corpo-Prior to July 8, 2003, the date that NEGT filed for bank-ration's 1999 and 2000 consolidated federal income tax returns ruptcy, protection, PG&E Corporation recognized federal during the third quarter of 2004. As a result of the completion income tax benefits related to the losses of NEGT and its sub-of this audit, PG&E Corporation received a refund from the sidiaries. However, afterJuly 7, 2003, PG&E Corporation has IRS of $14 million in January of 2005.

not recognized additional income tax benefits for financial The IRS is auditing PG&E Corporation's 2001 and 2002 reporting purposes with respect to the losses of NEGT and its consolidated federal income tax returns. In September 2004, the subsidiaries even though it must continue to include NEGT and IRS issued notices of proposed adjustments that propose to dis- its subsidiaries in its consolidated income tax returns. As a result allow $104 million of synthetic fuel credits claimed on these tax of NEGT's plan of reorganization becoming effective on Octo-returns. In addition, the IRS has proposed to disallow abandon- ber 29, 2004, PG&E Corporation cancelled its equity interest in ment losses deducted on the 2002 tax return related to certain NEGT and no longer includes NEGT or its subsidiaries in its NEGT assets. These assets were transferred to NEGT lenders consolidated income tax returns. Remaining deferred tax assets in the third quarter of 2004. In addition, the IRS has challenged related to NEGT or its subsidiaries, were reversed in discontin-other deductions related to NEGT prior to its Chapter I I fil- ued operations in the Consolidated Statements of Operations at ing. PG&E Corporation is disputing the IRS's proposed the time PG&E Corporation's equity interest in NEGT was adjustments and will contest these disallowances if the IRS con- cancelled. See Note 5 for further discussion.

tinues to assert its current position.

In 2003, PG&E Corporation increased its valuation allowance due to the uncertainty in realizing certain state deferred tax assets related to NEGT or its subsidiaries. Valua-tion allowances of approximately $24 million were recorded in discontinued operations, and approximately $5 million in accu-mulated other comprehensive loss for the year ended 134

December 31, 2003. No valuation allowances were recorded while capacity payments are based on the qualifying facility's during 2004. total available capacity and 'contractual capacity commitment.

Capacity payments may be adjusted if the qualifying facility fails At December 31, 2003, PG&E Corporation had $420 mil-to meet or exceeds performance requirements specified in the lion of California net operating loss, or NOL. The California applicable power purchase agreement.

NOLs were fully utilized in 2004.

As of December 31, 2004, the Utility had agreements with 300 qualifying facilities for approximately 4,300 megawatts, or NOTE 12: COMMITMENTS MWV, that are in operation. Agreements for approximately 3,950 AND CONTINGENCIES MW expire at various dates between 2005 and 2028. Qualifying facility power purchase agreements for approximately 350 MW PG&E Corporation and the Utility have substantial financial have no specific expiration dates and will terminate only wvhen commitments and contingencies in connection with agreements the owner of the qualifying facility exercises its termination entered into supporting the Utility's operating activities. PG&E option. The Utility also has power purchase agreements with Corporation has no ongoing financial commitments relating to approximately 50 inoperative qualifying facilities. The total of NEGT's current operating activities. approximately 4,300 MW\' consists of approximately 2,600 MW from cogeneration projects, 700 MW from wind projects and COMMITME NTS 1,000 MIXr from projects with other fuel sources, including bio-PG&E CORPORATION mass, waste-to-energy, geothermal, solar and hydroelectric.

PG&E Corporation has previously agreed to accept the assign- OnJanuary 22,2004, the CPUC ordered the California ment of certain Canadian natural gas pipeline firm investor-owned electric utilities to allow owners of qualifying transportation contracts effective November 1, 2007, through facilities with certain power purchase agreements expiring October 31, 2023, the remaining term of the contracts' dura- before the end of 2005 to extend these contracts for five years tion. The firm quantity under the contracts is approximately 50 with modified pricing terms. As of December 31, 2004, thirteen million cubic feet per day, or MAfcfYd, and PG&E Corporation qualifying facilities had entered into such five-year contract has estimated annual reservation charges will range between extensions. Qualifying facility power purchase agreements approximately $10 million and $12 million. During the term of accounted for approximately 23% of the Utility's 2004 electric-the contracts, the applicable reservation charges will equal the ity sources, approximately 20% of the Utility's 2003 electricity full tariff rates set by regulatory authorities in Canada and the sources, and approximately 25% of the Utility's 2002 electricity United States, as applicable. PG&E Corporation is unable to sources. No single qualifying facility accounted for more than predict the utilization of these contracts, which will depend on 5% of the Utility's 2004, 2003 or 2002 electricity sources.

market prices, customer demand, and approval of cost recovery There are proceedings pending at the CPUC that may by the CPUC, among other factors. PG&E Corporation impact both the amount of payments to qualifying facilities and intends to assign these contracts to the Utility. the number of qualifying facilities holding power purchase agreements with the Utility. The CPUC will address whether UTILITY certain payments for short-term power deliveries required by Power Purchase Agreements the power purchase agreements comply with the pricing requirements of the PURPA. The CPUC is also considering QaiiafyingFacility Power PurrbaseAgreements -The Utility is whether to require the California investor-ow ned electric utili-required by CPUC decisions to purchase energy and capacity ties to enter into new power purchase agreements with existing from independent power producers that are qualifying facilities qualifying facilities with expiring power purchase agreements under the Public Utility Regulatory Policies Act of 1978, or and with newly-constructed qualifying facilities. PG&E Corpo-PURPA. To implement PURPA, the CPUC required California ration and the Utility are unable to estimate the outcome of investor-owned electric utilities to enter into long-term power these proceedings.

purchase agreements with qualifying facilities and approved the applicable terms, conditions, prices and eligibility requirements.

These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility's actual electrical output and CPUC-approved energy prices, 135

In a proceeding pending at the CPUC, the Utility has than one year. In 2004, the Utility both submitted and requested refunds in excess of $500 milion for overpayments requested bids in competitive solicitations to meet intermediate from June 2000 through March 2001 that were made to qualify- and long-term needs and anticipates procuring electricity under ing facilities pursuant to CPUC orders at approved rates. The contracts with multi-year terms beginning in 2005.

net after-tax amount of any qualifying facilities refunds, which the Renewable Energy Requirement-California law requires that, Utility actually realizes in cash, claim offsets or other credits, beginning in 2003, each California retail seller of electricity, would be credited to customers, either as a reduction to the prin-except for municipal utilities, must increase its purchases of cipal amount of the second series of ERBs anticipated to be renewable energy (such as biomass, wind, solar and geothermal issued in November 2005, or if refunds are received after the energy) by at least 1% of its retail sales per year, the annual second series of ERBs is issued, as a credit to the balancing procurement target, so that the amount of electricity purchased account that tracks recovery of the customer costs and benefits from renewable resources equals at least 20% of its total retail related to the ERBs. PG&E Corporation and the Utility are sales by the end of 2017. The Utility was excused from meeting unable to estimate the outcome of this proceeding.

its annual procurement target under the current law in 2003 IrrigationDistricts and Water Agencies -The Utility has con- and 2004 due to its Chapter 11 proceeding. With its exit from tracts with various irrigation districts and water agencies to Chapter 11, as ofJanuary 1, 2005, the Utility is no longer purchase hydroelectric power. Under these contracts, the Util- exempt from complying with its annual procurement target. To ity must make specified semi-annual minimum payments based meet the 20% goal by the end of 2017, the Utility estimates on the irrigation districts' and water agencies' debt service that it will need to purchase 700-800 G1Vh of electricity from requirements, regardless if any hydroelectric power is supplied, renewable resources each year. During 2003 and 2004, the Util-and variable payments for operation and maintenance costs ity entered into several new renewable power purchase incurred by the suppliers. These contracts expire on various contracts that will help the Utility meet its goals. The Utility dates from 2005 to 2031. The Utility's irrigation district and also is conducting negotiations with several renewable energy water agency contracts accounted for approximately 5% of the providers pursuant to a request for offers made by the Utility in Utility's 2004 electricity sources, approximately 5% of the Util- July 2004 that should result in the Utility entering into a num-ity's 2003 electricity sources and approximately 4% of the ber of new renewable contracts in 2005. InJanuary 2005, the Utility's 2002 electricity sources. California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC Other Power Purchase Agreements also has suggested that the 20% goal be met by 2010. The Util-Electricity Parrbasesto Satisft the Residual Net Open Position - In ity estimates that the accelerated goal would require the Utility 2004 the Utility continued buying electricity to meet its resid- to increase the amount of its annual renewable energy pur-ual net open position. During 2004, more than 10,000 Gigawatt chases to approximately 800-900 GWh. Based on the medium hours, or GlVh, of energy was bought and sold in the wholesale load scenario in the Utility's long-term electricity procurement market to manage the 2004 residual net open position. Most of plan, the Utility believes that it can meet the accelerated goal.

the Utility's contracts entered into in 2004 had terms of less Annual Receipts and Payments - The payments made under qualifying facility, irrigation district, water agency and bilateral agreements during 2002 through 2004 were as follows:

2004 2003 2002 Qualifying facility energy payments (inmillions) $1,002 $994 S1,051 Qualifying facility capacity payments (inmillions) $ 487 $499 S 506 Irrigation district and water agency payments (inmillions) $ 61 $ 62 S 57 Other power purchase agreement payments (inmillions) $ 834 $513 $ 196 136

At December 31, 2004, the undiscounted future expected power purchase agreement payments were as follows:

Irrigation District

& XVater Agency Qualifying Facility Opertions & Debt Other (in millions) Energy Capacity Maintenance Service Energy Capacity Total 2005 $1,060 $ 506 $ S $ 26 $ 53 $ 41 $ 1,737 2006 1,082 506 31 26 39 36 1,720 2007 1,070 486 30 26 29 36 1,677 2008 1,040 476 33 26 IS 9 1,599 2009 947 436 31 24 10 5 1,453 Thereafter 7,633 3,491 152 117 18 4 11,415 Total $12,832 $5,901 $328 $245 $164 S131 $19,601 Natural Gas Supply and Transportation Commitments natural gas, including a $10 million cash collateralized standby The Utility purchases natural gas directly from producers and letter of credit and a pledge of its core natural gas customer marketers in both Canada and the United States to serve its accounts receivable. In connection with its emergence from core customers. The contract lengths and natural gas sources of Chapter 11, the Utility received investment grade issuer credit the Utility's portfolio of natural gas procurement contracts has ratings from Moody's and S&P. As a result of these credit rating fluctuated, generally based on market conditions. ;upgrades, the Utility has obtained unsecured credit lines from the majority of its gas supply counterparties.

During the period that the Utility was in Chapter 11, the Utility used several different credit arrangements to purchase At December 31, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions) 2005 $829 2006 124 2007 7 2008 2009 Thereafter Total $960 Payments for natural gas purchases and gas transportation At December 31, 2004, the undiscounted obligations under services amounted to approximately $1.8 billion in 2004, $1.5 nuclear fuel agreements were as follows:

billion in 2003, and $898 million in 2002.

(in millions)

Nuclear Fuel Agreements 2005 $46 The Utility has purchase agreements for nuclear fuel. These 2006 54 agreements have terms ranging from two to eight years and are 2007 55 2008 50 intended to ensure long-term fuel supply. Deliveries under 9 of 2009 32 the 11 contracts in place at the end of 2003 were completed by Thereafter 53 2004. New contracts for deliveries in 2005 to 2012 are under Total S290 negotiation. In most cases, the Utility's nuclear fuel contracts are requirements-based. The Utility relies on large, well-established international producers of nuclear fuel in order to diversify its Payments for nuclear fuel amounted to approximately $119 sources and provide security of supply. Pricing terms also are million in 2004, $57 million in 2003 and $70 million in 2002.

diversified, ranging from fixed prices to market-based prices to base prices that are escalated using published indices.

137

Reliability Must Run Agreements million of allowed claims, credits, offsets, or cash from Mirant The ISO has entered into reliability must run, or RMR, agree- or its subsidiaries. The Utility is unable to predict whether and ments with various power plant owners, including the Utility, when the FERC or the bankruptcy courts will approve the set-that require designated units in certain power plants, known as tlement. Although the settlement resolves issues concerning any RAIR plants, to remain available to generate electricity upon the refund that might be owed by Mirant, it does not address the ISO's demand when needed for local transmission system relia- underlying merits of the RMR case, which will still be decided bility. At December 31, 2004, as a party to the Transmission by the FERC.

Control Agreement, or the TCA, the Utility estimated that it In November 2001, after the ALJ issued the initial decision could be obligated to pay the ISO approximately $570 million in in Mirant's rate case, two complaints were filed at the FERC costs incurred under these RMR agreements during the period against other RMR plant owners, including the Utility, alleging January 1, 2005 to December 31, 2006. Of this amount, the that the ratemaking methodology approved in the ALJ's initial Utility estimates that it would receive approximately $42 million decision should be applied to the other RMR agreements. The under its RAIR agreements during the same period. These costs' complainants asked the FERC to take no action until after the and revenues are subject to applicable ratemaking mechanisms. FERC issues its final decision in AMirant's rate case. If the FERC In June 2000, a FERC administrative law judge, or ALJ, adopts the ALJ's decision in the Mirant rate case and applies the issued an initial decision addressing subsidiaries of Mirant Cor- ratemaking methodology to the Utility's RMJR plants, the Utility poration. The decision approved rates and a ratemaking ,_could be required to refund payments it received from the ISO methodology that, if affirmed by the FERC, will require the for the availability of the Utility's RMIR plants. The Utility has Mirant subsidiaries that are parties to three RMIR agreements responded to the complaint asserting that the methodology with the ISO to refund to the ISO, and the ISO to refund to approved in the ALJ's decision should not apply to the Utility.

the Utility, excess payments of approximately $360 million,- The FERC has not yet acted on these complaints. On Decem-including interest, for the availability of Mirant's RIMR plants ber 23, 2004, the Utility filed a settlement with all the under these agreements. On July 14, 2003, Mirant filed a peti- complainants that, if approved by FERC, will result in the with-tion for reorganization under Chapter 11 and on December 15, diawal of the complaint with no decision by the FERC on its 2003, the Utility filed claims in Mirant's Chapter 11 proceeding merits. If the case is not dismissed, the Utility believes the ulti-including a claim for an RMIR refund. On January 14, 2005, the mate outcome of this matter will not have an adverse material Utility entered into a settlement with Mirant and its sub- effect on the Utility's results of operations or financial condition.

sidiaries that own RMR units that will resolve the Utility's claim. The settlement agreement is subject to approval by the Other Commitments and Operating Leases FERC, the bankruptcy court overseeing the Chapter 11 cases The Utility has other commitments relating to operating leases, filed by Mirant and these subsidiaries, and to the extent deemed capital infusion agreements, equipment replacements, the self-necessary by the Utility, by the bankruptcy court that retains generation incentive program exchange agreements and jurisdiction over the Utility's Chapter 11 case. Under the settle- telecommunication contracts. At December 31, 2004, the future ment, Airant will transfer to the Utility Mirant's interest in and minimum payments related to other commitments were as follows:

equipment for the partially built Contra Costa Unit 8 power (in millions) plant. If Contra Costa Unit 8 is not transferred to the Utility as 2005 $123 a result of various contingencies described in the settlement, 2006 31 Mirant will pay the Utility at least $70 million in lieu of the 2007 17 plant assets. In addition, under the settlement, the Utility will 2008 14 enter into a contract that gives the Utility the right to dispatch 2009 6 power from certain RAIR units owned by Mirant subsidiaries Thereafter 14 from 2006-2012, and the Utility will receive approximately $60 Total $205 Payments for other commitments amounted to approxi-mately $111 million in 2004, $74 million in 2003, and $34 million in 2002.

138

CONTINGENCIES power suppliers approximately $3.0 billion, leaving approxi-mately $1.2 billion in net unpaid bills.

PG&E CORPORATION In March 2003, the FERC confirmed most of the AIJ's find-PG&E Corporation retains a guarantee related to certain NEGT ings in the Refund Proceeding, but partially modified the indemnity obligations issued to the purchaser of an NEGT sub-refund methodology to include use of a new natural gas price sidiary company during 2000, up to $150 million. The methodology as the basis for mitigated prices. The FERC indi-underlying indemnity obligations of NEGT have expired and cated that it would consider later allowances claimed by sellers PG&E Corporation's sole remaining exposure relates to the for natural gas costs above the natural gas prices in the refund potential of environmental obligations that were known to methodology. The FERC directed the ISO and the PX (which NEGT at the time of the sale but not disclosed to the purchaser.

operates solely to reconcile remaining refund amounts owed) to PG&E Corporation has never received any claims nor does it

• make compliance filings establishing refund amounts. The ISO consider it probable any claims will occur under the guarantee.

has indicated that it plans to make its compliance filing during Accordingly, PG&E Corporation has made no provision for this the first half of 2005 with the PX to follow. In October 2003, guarantee at December 31, 2004.

the FERC affirmed its March 2003 decision and various parties appealed to the Ninth Circuit. Briefs have been submitted con-UTILITY cermnig which power suppliers are subject to refunds, the PX Block-Forward Contracts appropriate time period for which refunds can be ordered, and The Utility had PX block-forward contracts, which were seized which transactions are subject to refunds. These matters will be by California's then-Governor Gray Davis in February 2001 for argued before the Ninth Circuit on April 12 and 13, 2005, and the benefit of the state, acting under California's Emergency. a decision is expected in the following months.

Services Act. The block-forward contracts had an estimated The final refunds will not be determined until the FERC unrealized gain of up to $243 million at the time the state of issues a final decision in the Refund Proceeding, following the California seized them. The Utility, the PX, and some of the ISO and PX compliance filings and the resolution of the PX market participants have filed claims in state court against appeals of the FERC's orders. In addition, future refunds could the state of California to recover the value of the seized con- increase or decrease as a result of retroactive adjustments pro-tracts; the state of California disputes the plaintiffs' rights to posed by the ISO, which incorporate revised data provided by recover and valuations. The estimated value of the seized con- the Utility and other entities.

tracts has been fully reserved in the Utility's financial statements. This state court litigation is pending. In the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, California Energy Crisis Proceedings the FERC has asserted that it has the power to order power sup-pliers to disgorge any profits if the FERC finds that the tariffs in FERC Proceedings force at that time were violated or subject to manipulation. In Various entities, including the Utility and the state of California September 2004, the Ninth Circuit found that the FERC has the are seeking up to $8.9 billion in refunds for electricity over- authority to provide refunds for tariff violations involving inade-charges on behalf of California electricity purchasers for the quate transaction reporting for sales into the California spot period May 2000 to June 2001 through a proceeding pending at markets throughout the period before October 2, 2000. The the FERC. This proceeding, the Refund Proceeding, com- FERC has not yet acted on this finding and it is uncertain how it menced on August 2, 2000 when a complaint was filed against will be applied by the FERC.

all suppliers in the ISO and PX markets. On July 25, 2001, the The Utility recorded approximately $1.8 billion of claims FERC held that refunds would be available for certain over-filed by various electricity generators in its Chapter 11 proceed-charges, and established a process to determine the refunds but ing as liabilities subject to compromise. This amount is subject asserted that it could not order market-wide refunds for periods to a pre-petition offset of approximately $200 million, reducing before October 2, 2000. In December 2002, a FERC ALJ the net liability recorded to approximately $1.6 billion. Under a issued an initial decision in the Refund Proceeding finding that bankruptcy court order, the aggregate allowable amount of ISO, power suppliers overcharged the utilities, the state of California PX and generator claims was limited to approximately $1.6 bil-and other buyers approximately $1.8 billion from October 2, lion. The Utility currently estimates that the claims would have 2000 to June 20, 2001, but that California buyers still owe the; been reduced to approximately $1'0 billion based on the refund 139

methodology recommended in the FERC AIJ's initial decision. member within a 12-month period, the maximum recovery The revised methodology adopted by the FERC's March 2003 under all those nuclear insurance policies may not exceed $3.24 decision could further reduce the amount by several hundred billion plus the additional amounts recovered by NEIL for million dollars, offset by the amount of any additional fuel cost these losses from reinsurance. Under the Terrorism Risk Insur-allowance for suppliers. ance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign The Utility has entered into settlements with various power terrorism. The Terrorism Risk Insurance Act of 2002 expires on suppliers resolving the Utility's claims against these power suppli-December 31, 2005.

ers. As discussed in Note 1, as of December 31, 2004, the Utility has recorded offsets to the Settlement Regulatory Asset of Under the Price-Anderson Act, public liability claims from a approximately $309 million, pre-tax ($183 million, after-tax) in nuclear incident are limited to $10.8 billion. As required by the connection with settlements. The final net after-tax amount of Price-Anderson Act, the Utility purchased the maximum avail-any amounts received by the Utility under future settlements able public liability insurance of $300 million for Diablo Canyon.

with energy suppliers will be credited to customers, either as a The balance of the $10.8 billion of liability protection is covered reduction to the principal amount of the second series of ERBs, by a loss-sharing program (secondary financial protection) among anticipated to be issued in November 2005, or if refunds are utilities owning nuclear reactors. Under the Price-Anderson Act, received after the second series of ERBs is issued, as a credit to owner participation in this loss-sharing program is required for the balancing account that tracks recovery of the customer costs all owners of nuclear reactors that are licensed to operate, and benefits related to the ERBs. designed for the production of electrical energy, and have a rated capacity of 100 Ma or higher. If a nuclear incident results in As discussed in Note 13 below, in January 2005, the Utility costs in excess of $300 million, then the Utility may be responsi-and other parties entered into a settlement agreement with ble for up to $100.6 million per reactor, with payments in each Mirant Corporation and its subsidiaries, to resolve Mirant's lia-year limited to a maximum of $10 million per incident until the bility for FERC refunds, penalties and civil liabilities arising out Utility has fully paid its share of the liability. Since Diablo of the California energy crisis. The settlement agreement is Canyon has two nuclear reactors each with a rated capacity of subject to approval by the FERC, the bankruptcy court oversee-over 100 MIV, the Utility may be assessed up to $201.2 million ing AMirant's bankruptcy proceedings, and to the extent deemed per incident, with payments in each year limited to a maximum necessary by the Utility, the bankruptcy court that retains juris-of $20 million per incident. Although the Price-Anderson Act diction over the Utility's Chapter 11 case. Although settlement expired on December 31, 2003, coverage continues to be pro-discussions with a number of other major sellers and other mar-vided to all licensees, including Diablo Canyon, which had ket participants are continuing, the Utility cannot predict coverage before December 31, 2003. Congress may address whether these settlement negotiations will be successful.

renewal of the Price-Anderson Act in future energy legislation.

Nuclear Insurance In addition, the Utility has $53.3 million of liability insur-The Utility has several types of nuclear insurance for Diablo ance for the retired nuclear generating unit at Humboldt Bay Canyon and Humboldt Bay Unit 3. The Utility has insurance power plant and has a $500 million indemnification from the coverage for property damages and business interruption losses NRC, for public liability arising from nuclear incidents cover-as a member of Nuclear Electric Insurance Limited, or NEIL. ing liabilities in excess of the $53.3 million of liability insurance.

NEIL is a mutual insurer owned by utilities with nuclear facili-ties. NEIL provides property damage and business interruption Workers' Compensation Security coverage of up to $3.24 billion per incident. Under this insur-- The Utility is self-insured for workers' compensation. To main-ance, if any nuclear generating facility insured by NEIL suffers tain its status as a self-insurer for workers' compensation, the a catastrophic loss causing a prolonged outage, the Utility may Utility must either deposit collateral with the California Depart-be required to pay an additional premium of up to $42.5 million ment of Industrial Relations, or the DIR, or participate in the per one-year policy term. Alternative Security Deposit program, or the ASP, which is administered by the Self-Insurer's Security Fund, or the SISF.

NEIL also provides coverage for damages caused by acts of The ASP is a program that allows the SISF to arrange a com-terrorism at nuclear power plants. If one or more acts of posite deposit for participating self-insurers on a portfolio basis, domestic terrorism cause property damage covered under any of rather than individual self-insurers arranging their deposits indi-the nuclear insurance policies issued by NEIL to any NEIL vidually. The SISF arranges portfolio security to be delivered to 140

the DIR for the aggregate self-insured workers' compensation

• After assumption, the Utility's issuer rating by Moody's will be liabilities for participating self-insurers. The SISF composite no less than A2 and the Utility's long-term issuer credit rating deposit for participating self-insurers, including the Utility, was by S&P will be no less than A, established onJuly 1, 2004, and resulted in the release of the

• The CPUC first makes a finding that the DWR power pur-

$348 million collateral ($305 million in surety bonds and $43 chase contracts to be assumed are just and reasonable; and million in cash) that existed atJune 30, 2004. As a result, PG&E Corporation's guarantee of the Utility's reimbursement obliga-

• The CPUC has acted to ensure that the Utility will receive tion associated with these surety bonds was reduced by $305 full and timely recovery in its retail electricity rates of all costs million, and the remaining liability is expected to be immaterial. associated with the DWR power purchase contracts to be assumed without further review.

PG&E Corporation's guarantee of the Utility's underlying obligation to pay workers' compensation claims remains in ENVIRONMENTAL MATTERS place. As of December 31, 2004, the actuarially determined workers' compensation liability was approximately $226 million. The Utility may be required to pay for environmental remedia-tion at sites where it has been, or may be, a potentially DWR Contracts responsible party under the Comprehensive Environmental The DWR provided approximately 25% of the electricity deliv- Response Compensation and Liability Act of 1980, or CER-ered to the Utility's customers for the year ended December 31, CLA, as amended, and similar state environmental laws. These 2004. The DXVrR purchased the electricity under contracts with sites include former manufactured gas plant sites, power plant various generators. The Utility is responsible for administration sites, and sites used by the Utility for the storage, recycling, or and dispatch of the DVVR's electricity procurement contracts disposal of potentially hazardous materials. Under federal and allocated to the Utility for purposes of meeting a portion of the California laws, the Utility may be responsible for remediation Utility's net open position, which is the portion of the demand of hazardous substances even if the Utility did not deposit those of a utility's customers, plus applicable reserve margins, not sat- substances on the site.

isfied from that utility's own generation facilities and existing The cost of environmental remediation is difficult to esti-electricity contracts. The DWVR remains legally and financially mate. The Utility records an environmental remediation responsible for the electricity procurement contracts. liability when site assessments indicate remediation is probable The current DWR contracts terminate at various times and it can estimate a range of reasonably likely clean-up costs.

through 2012, and consist of must-take and capacity charge The Utility reviews its remediation liability on a quarterly basis contracts. Under must-take contracts, the DIVR must take and for each site where it may be exposed to remediation responsi-pay-for electricity generated by the applicable generating facility bilities. The liability is an estimate of costs for site regardless of whether the electricity is needed. Under capacity investigations, remediation, operations and maintenance, moni-charge contracts, the DWR must pay a capacity charge but is toring and site closure using current technology, enacted laws not required to purchase electricity unless that electricity is dis- and regulations, experience gained at similar sites, and an patched and delivered. In the Utility's proposed long-term assessment of the probable level of involvement and financial integrated energy resource plan filed with the CPUC in condition of other potentially responsible parties. Unless there July 2004 and approved in December 2004, the Utility has not is a better estimate within this range of possible costs, the Util-assumed that the electricity provided under DWR contracts will ity records the costs at the lower end of this range. It is be renewed beyond their current expiration dates. reasonably possible that a change in these estimates may occur in the near term-due to uncertainty concerning the Utility's The DONOR has stated publicly that it intends to transfer full responsibility, the complexity of environmental laws and regula-legal title to, and responsibility for, the DINrR power purchase tions, and the selection of compliance alternatives. The Utility contracts to the California investor-owned electric utilities'as estimates the upper end of the cost range using reasonably pos-soon as possible. However, the DWNVR power purchase contracts sible outcomes least favorable to the Utility.

cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will The Utility had an undiscounted environmental remediation not require the Utility to accept an assignment of, or to assume liability of approximately $327 million at December 31, 2004, legal or financial responsibility for, the DWR power purchase and approximately $314 million at December 31, 2003. During contracts unless each of the following conditions has been met: the year ended December 31, 2004, the liability increased by approximately $13 million mainly due to reassessment of the 141

estimated cost of remediation and remediation payments. The chromium litigation cases. Approximately 1,035 of these approximately $327 million accrued at December 31, 2004, claimants filed claims requesting an approximate aggregate includes approximately $102 million related to the pre-closing amount of $580 million and approximately another 225 remediation liability associated with divested generation facili- claimants filed claims for an "unknown amount." Pursuant to ties and approximately $225 million related to remediation costs the Utility's plan of reorganization, these claims have passed for those generation facilities that the Utility still owns, gas through the Utility's Chapter 11 proceeding unimpaired.

gathering sites, compressor stations, third-party disposal sites, The Utility is responding to the suits in which it has been and manufactured gas plant sites that either are owned by the served and is asserting affirmative defenses. The Utility will Utility or are the subject of remediation orders by environmen-pursue appropriate legal defenses, including statute of limita-tal agencies or claims by the current owners of the former tions, exclusivity of workers' compensation laws, and factual manufactured gas plant sites. Of the approximately $327 million defenses, including lack of exposure to chromium and the environmental remediation liability, approximately $144 million inability of chromium to cause certain of the illnesses alleged.

has been included in prior rate setting proceedings and the Utility expects that approximately $141 million will be allow- To assist in managing and resolving litigation with this many able for inclusion in future rates. The Utility also recovers its plaintiffs, the parties agreed to select plaintiffs from three of the costs from insurance carriers and from other third parties cases for a test trial. Plaintiffs' counsel selected ten of these ini-whenever possible. Any amounts collected in excess of the Util- -tial trial plaintiffs, defense counsel selected seven of the initial ity's ultimate obligations may be subject to refund to customers. trial plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 14 motions challenging the test The Utility's undiscounted future costs could increase to as trial plaintiffs' lack of admissible scientific evidence that much as $480 million if the other potentially responsible parties chromium caused the alleged injuries. The court began hearing are not financially able to contribute to these costs, or if the argument on two of the motions in February 2004. At a hearing extent of contamination or necessary remediation is greater on February 14, 2005, the court indicated that it had signed than anticipated. The amount of approximately $480 million orders denying the first two motions, but the orders have not does not include an estimate for the cost of remediation at been delivered to the parties. The court set a trial date of known sites owned or operated in the past by the Utility's pred-

-January 9, 2006 for the first eighteen plaintiffs. The other ecessor corporations for which the Utility has not been able to ,

motions will be heard throughout 2005.

determine whether a liability exists.

The Utility has recorded a $160 million reserve in its finan-LEGAL MATTERS cial statements with respect to the chromium litigation. PG&E Corporation and the Utility believe that, after taking into In the normal course of business, PG&E Corporation and the account the reserves recorded at December 31, 2004, the ulti-Utility are named as parties in a number of claims and lawsuits.

mate outcome of this matter will not have a material adverse The most significant of these are discussed below. On the impact on PG&E Corporation's or the Utility's financial condi-Effective Date, the automatic stay of pending litigation was tion or future results of operations.

lifted, so that any state court lawsuits pending before the Util-ity's Chapter 11 filing that had not yet received relief from the RECORDED LIABILITY FOR LEGAL MATTERS stay can proceed.

In accordance with SFAS No. 5, PG&E Corporation and the Chromium Litigation Utility make a provision for a liability when it is both probable There are 14 civil suits pending against the Utility in several that a liability has been incurred and the amount of the loss can California state courts in which plaintiffs allege that exposure to be reasonably estimated. These provisions are reviewed quar-chromium at or near the Utility's compressor stations at Hink- terly and adjusted to reflect the impacts of negotiations, ley and Kettleman, California, and the area of California near settlements and payments, rulings, advice of legal counsel and Topock, Arizona, caused personal injuries, wrongful deaths, or other information and events pertaining to a particular case. In other injury and seek related damages. One of these suits also assessing such contingencies, PG&E Corporation's and the names PG&E Corporation as a defendant. Currently, there are Utility's policy is to exclude anticipated legal costs.

approximately 1,200 plaintiffs in the chromium litigation cases. The liability for legal matters is included in PG&E Corpora-Approximately 1,260 individuals filed proofs of claims in the tion's and the Utlity's other noncurrent liabilities in the Utility's Chapter 11 case, most of whom also are plaintiffs in the Consolidated Balance Sheets, and totaled approximately $200 142

million at December 31, 2004 and $205 nmlilion at Decem- The first part of the two-part settlement is between Mirant ber 31, 2003. Based on current information, PG&E and several California parties, including the California Attorney Corporation and the Utility do not believe that it is probable General's Office, the DWR, the CPUC, SCE, San Diego that losses associated with legal matters that exceed amounts Gas & Electric Company, or the California Parties, and the already recognized will be incurred in amounts that would be Utility resolving market manipulation claims, including Mirant's material to PG&E Corporation's or the Utility's financial posi- liability for FERC refunds, penalties and civil liabilities arising tion or results of operations.

• out of the California energy crisis in 2000 to 2001. Under this portion of the agreement, Mirant will provide the California Parties approximately $320 million in cash equivalents and $175 NOTE 13: SUBSEQUENT EVENTS:

million of allowed bankruptcy claims. Of these amounts, the ENERGY RECOVERY BONDS Utility will receive approximately $130 million in cash equiva-lents and $40 million in allowed claims. The final cash value of In connection with the Settlement Agreement, PG&E Corpora-the allowed claims will not be known until the completion of tion and the Utility agreed to seek to refinance the remaining Mirant's bankruptcy proceeding. The Utility's net after-tax unamortized portion of the Settlement Regulatory Asset and refund amount will benefit its customers through adjustment of associated federal and state income and franchise taxes, in an future revenue requirements.

aggregate principal amount of up to $3.0 billion in two separate series up to one year apart, as expeditiously as practicable after The second part of the settlement is between the Utility and the Effective Date using a securitized financing supported by a Mirant and is designed to settle claims that Airant overcharged DRC provided that certain conditions were met. On Febru- the Utility under Mirant's RMR contracts and other disputes.

ary 10, 2005, PERF, a limited liability company wholly owned Under the settlement agreement, Mirant has agreed to transfer to and consolidated by the Utility, issued $1.9 billion of ERBs. The the Utility the equipment, permits and contracts for the con-proceeds of the ERBs were used by PERF to purchase from the struction of Contra Costa Unit 8, a modern 530-megawatt power Utility the right, known as "recovery property," to be paid a plant Mirant started to build, but never completed. The Utility specified amount from a DRC. DRC charges are authorized by plans to file an application with the CPUC to seek authorization the CPUC under state legislation and will be paid by the Util- to complete and operate Contra Costa Unit 8 under a cost-of-ity's electricity customers until the ERBs are fully retired. Under service ratemaking structure. If the Utility and Mirant do not the terms of a recovery property servicing agreement, DRC complete the necessary transfer agreement or if the Utility does charges are collected by the Utility and remitted to PERE not receive the necessary approvals, including CPUC authoriza-tion, the Utility will be paid at least $70 million in lieu of The aggregate principal amount of the first series of ERBs transferring the assets. The settlement agreement also includes a issued is approximately $1.9 billion. They were issued in five contract that would give the Utility the right from 2006 through classes, with scheduled maturities ranging from September 25, 2012 to dispatch power from certain RMIR units owned by 2006 to December 25, 2012, and final legal maturities ranging AMirant subsidiaries when the facilities are not needed by the ISO from September 25, 2008 to December 25, 2014. Interest rates to meet local reliability needs. In addition, the Utility will receive on the five classes range from 3.32% for the earliest maturing approximately $60 million of allowed claims, credits, offsets, class to 4.47% for the latest maturing class.

and/or cash from Mirant Corporation or its subsidiaries and While PERF is a wholly owned consolidated subsidiary of Mirant will withdraw its outstanding claim in the Utility's bank-the Utility, PERF is legally separate from the Utility. The ruptcy proceeding of approximately $20 million. The settlement assets of PERF (including the recovery property) are not avail-. may also include separate options under which the Utility, under able to creditors of PG&E Corporation or the Utility and the certain circumstances, would have the right to acquire AMirant's recovery property is not legally an asset of the Utility or existing Contra Costa and Pittsburg power plants.

PG&E Corporation.

The settlement agreement is not effective until it is approved by the FERC, the bankruptcy court overseeing Mirant's bank-MIRANT SETTLEMENT

- ruptcy proceedings and, to the extent deemed necessary by the In January 2005, the Utility entered into a settlement agree- Utility, the bankruptcy court that retains jurisdiction over the ment with Mirant Corporation and several of its subsidiaries, Utility's Chapter 11 case. PG&E Corporation and the Utility resolving overcharges and market manipulation claims from the are unable to predict whether and when the settlement agree-sale of electricity by Mirant's California operations. ment will be approved.

143

QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

Quarter ended (in millions, except per share amounts) December 31 September 30 June 30 March 31 20040)

PG&E Corporation Operating revenues $2,986 S2.623 S2,749 S2,722 Operating income0 5 3 ) 584 509 672

• 5,353 Income from continuing operations 187 228 372 3,033 Net incomeN 871 228 372 3,033 Earnings per common share from continuing operations, basic 0.45 0.55 0.89 7.36 Earnings per common share from continuing operations, diluted 0.44 0.53 0.88 7.15 Common stock price per share:

High 34.46 30.40 30.32 29.35 Low 30.32 27.50 25.90 26.47 Utility Operating revenues $2,986 S2,623 $2,749 S2,722 Operating income'5 X3 ) 584 516 682 5,362 Net income 248 248 412 3,074 Income available for common stock 243 244 408 3,066 2003")

PG&E Corporation Operating revenues' $2,538 S3,103 $2,729 $2,065 Operating income 317 1,173 780 73 Income (loss) from continuing operations 37 508 328 (82)

Net income (loss)161 37 510 227 (354)

Earnings (loss) per common share from continuing operations, basic 0.09 1.25 0.81 (0.21)

Earnings (loss) per common share from continuing operations, diluted 0.09 1.22 0.80 (0.21)

Common stock price per share:

High '27.98 24.00 22.01 15.35 Low 23.43 20.63 13.41 11.69 Utility Operating revenues(S) $2,538 $3,103 $2,730 $2,067 Operating income 340 1,195 755 49 Net income (loss) 62 589 345 (73)

Income (loss) available for common stock 58 583 339 (79)

(t The operating results of NEGT through July 7, 2003 have been excluded from continuing operations and reported as discontinued operations for all periods. Effective July 8, 2003, NEGT and its subsidiaries are no longer consolidated by PG&E Corporation in its Consolidated Financial State-ments. See Note 5 of the Notei to the Consolidated Financial Statements for further discussion.

, Operating income for first quarter 200T4, as part of the implementation of its plan of reorganization, includes the Utility's recognition of a $2.2 bil-lion, after-tax ($3.7 billion, pre-tax) Settlement Regulatory Asset and $0.7 billion, after-tax ($1.2 billion, pre-tax), for the Utility's retained generation regulatory assets. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion.

'3 Operating income for the second quarter 2004, includes the net impact of the 2003 GRC decision of approximately S432 million, pre-tax. As a result the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets, and unfunded taxes, depreciation, and decommissioning.

(4) Net income for the fourth quarter 2004, includes a gain on disposal of NEGT of approximately S684 million, net of tax. On October 29, 2004, the effective date of NEGTrs plan of reorganization, PG&E Corporation's equity ownership in NEGT was cancelled. See Note 5 of the Notes to the Consolidated Financial Statements for further discussion.

(5) Operating revenues for the fourth quarter 2003, includes the recognition of a regulatory liability of approximately $125 million for surcharge rev-enues collected during 2003 that were determined to be probable of refund under applicable accounting principles.

(6) Net income for the first quarter 2Oo3 includes $200 million of impairments, write-offs and charges recognized byNEGT. These impairments have been excluded from continuing operations and are reported as discontinued operations.

144

MANAGEMENT'S REPORT ON INTERNAL- CONTROL OVER FINANCIAL REPORTING Management of PG&E Corporation and Pacific Gas and Elec- management has been unable to assess the effectiveness of tric Comnpany, or the Utility, is responsible for establishing and internal control at this entity due to the fact that PG&E Cor-maintaining adequate internal control over financial reporting. poration and the Utility do not have the ability to dictate or PG&E Corporation's and the Utility's internal control over modify the controls of this entity and do not have the ability, in financial reporting is a process designed to provide reasonable practice, to assess those controls. PG&E Corporation's and the assurance regarding the reliability of financial reporting and the Utility's Consolidated Balance Sheets include an increase of $12 preparation of financial statements for external purposes in million in total assets and total liabilities asa result of the con-.

accordance with generally accepted accounting principles, or solidation of a low-income housing partnership consolidated GAAP. Internal control over financial reporting includes those under FIN 46R.

policies and procedures that (1) pertain to the maintenance of Management assessed the effectiveness of internal control records that, in reasonable detail, accurately and fairly reflect over financial reporting as of December 31, 2004, based on the the transactions and dispositions of the assets of PG&E Corpo-criteria established in InternalControl-IntegratedFramework ration and the Utility, (2) provide reasonable assurance that issued by the Comnittee of Sponsoring Organizations of the transactions are recorded as necessary to permit preparation of Treadway Commission. Based on its assessment and those crite-financial statements in accordance with GAAP and that receipts ria, management has concluded that PG&E Corporation and and expenditures are being made only in accordance with, the Utility maintained effective internal control over financial authorizations of management and directors of PG&E Corpo-reporting as of December 31, 2004.

ration and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acqui- Deloitte & Touche LLP, an independent registered public sition, use, or disposition of assets that could have a material accounting firm, has audited the Consolidated Financial State-effect on the financial statements. ments of PG&E Corporation and the Utility for the three years ended December 31, 2004, appearing in this annual report and Because of its inherent limitations, internal control over has issued an attestation report on management's assessment of financial reporting may not prevent or detect misstatements.

internal control over financial reporting, as stated in their Also, projections of any evaluation of effectiveness to future report, which is included in this annual report on page 147.

periods are subject to the risk that controls may become inade-quate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

The Consolidated Financial Statements of PG&E Corpora-tion and the Utility include the accounts of an entity consolidated pursuant to Financial Accounting Standards Board Interpretation No. 46R, or FIN 46R. Management's responsi-bility for and assessment of the effectiveness of internal control over financial reporting does not extend to this entity because 145

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Boards of Directors and Shareholders of In our opinion, such consolidated financial statements pres-PG&E Corporation and Pacific Gas and Eledric Company ent fairly, in all material respects, the respective consolidated financial position of the Company and of the Utility as of We have audited the accompanying consolidated balance December 31, 2004 and 2003, and the respective results of their sheets of PG&E Corporation and subsidiaries (the "Company")

consolidated operations and cash flows for each of the three and of Pacific Gas and Electric Company and subsidiaries (the years in the period ended December 31, 2004, in conformity "Utility") as of December 31, 2004 and 2003, and the related with accounting principles generally accepted in the United consolidated statements of operations, cash flows and share--

States of America.

holders' equity of the Company and of the Utility for each of the three years in the period endedDecember 31, 2004. These As discussed in Note 1 of the Notes to the Consolidated financial statements are the responsibility of the respective man- Financial Statements, in March 2004, the Company changed agements of the Company and of the Utility. Our responsibility the method of computing earnings per share. During 2003, the is to express an opinion on these financial statements based on Company and the Utility adopted new accounting standards to our audits. account for asset retirement obligations and financial instru-ments with characteristics of both liabilities and equity. During We conducted our audits in accordance with the standards of 2002, the Company adopted new accounting standards to the Public Company Accounting Oversight Board (United account for goodwill and intangible'assets, impairment of long-States). Those standards require that we plan and perform the lived assets and certain derivative contracts.

audits to obtain reasonable assurance about whether the financial statements are free 6f material misstatement. An audit includes We have also audited, in accordance with the standards of examining, on a test basis, evidence supporting the amounts and the Public Company Accounting Oversight Board (United disclosures in the financial statements. An audit also includes States), the effectiveness of the Company's and the Utility's assessing the accounting principles used and significant estimates internal control over financial reporting as of December 31, made by management, as well as evaluating the overall financialI 2004, based on the criteria established in Internal Control-statement presentation. Waie believe that our audits provide a IntegratedFrazmework issued by the Committee of Sponsoring reasonable basis for our opinion. Organizations of the Treadway Commission and our report dated February 16, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

DELOITTE & TOUCHE LLP San Francisco, California February 16, 2005 146

REPORT OF INDEPENDENT REGISTERED-PUBLIC ACCOUNTING FIRM To the Boards of Directors and Shareholders of A company's internal control over financial reporting is a PG&E Corporation and Pacific Gas and Electric Company process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Performing similar functions, and effected by the company's FinancialReporting, that PG&E Corporation and subsidiaries board of directors, management, and other personnel to provide (the "Company") and Pacific Gas and Electric Company and reasonable assurance regarding the reliability of financial report-subsidiaries (the "Utility") maintained effective internal control ing and the preparation of financial statements for external over financial reporting as of December 31, 2004, based on cri- purposes in accordance with generally accepted accounting prin-teria established in InternalControl-IntegratedFramewvork ciples. A company's internal control over financial reporting issued by the Committee of Sponsoring Organizations of the includes those policies and procedures that (1) pertain to the Treadway Commission. As described in Managewient's Report on maintenance of records that, in reasonable detail, accurately and InternalControl Over FinancialReporting, management excluded fairly reflect the transactions and dispositions of the assets of the from their assessment the internal control over financial report- company; (2) provide reasonable assurance that transactions are ing of an entity consolidated pursuant to Financial Accounting

- recorded as necessary to permit preparation of financial state-Standards Board Interpretation No. 46R which represents total ments in accordance with generally accepted accounting assets and total liabilities of $12 million as of December 31, principles, and that receipts and expenditures of the company are 2004. Accordingly, our audits did not include the internal con-being made only in accordance with authorizations of manage-trol over financial reporting for this entity. The Company's and ment and directors of the company-, and (3) provide reasonable the Utility's management is responsible for maintaining effec-assurance regarding prevention or timely detection of unautho-tive internal control over financial reporting and for their rized acquisition, use, or disposition of the company's assets that assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on man- could have a material effect on the financial statements.

agement's assessment and an opinion on the effectiveness of the Because of the inherent limitations of internal control over Company's and the Utility's internal control over financial financial reporting, including the possibility of collusion or reporting based on our audits.

improper management override of controls, material misstate-We conducted our audits in accordance with the standards' of ments due to error or fraud may not be prevented or detected the Public Company Accounting Oversight Board (United on a timely basis. Also, projections of any evaluation of the effec-States). Those standards require that we plan and perform the tiveness of the internal control over financial reporting to future audits to obtain reasonable assurance about whether effective periods are subject to the risk that the controls may become internal control over financial reporting was maintained in all inadequate because of changes in conditions, or that the degree material respects. Our audits included obtaining an understand- of compliance with the policies or procedures may deteriorate.

ing of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circum-stances. Webelieve that our audits provide a reasonable basis for our opinions.

147

REPORT OF INDEPENDENT REGISTERED :CORPORATE GOVERNANCE PUBLIC ACCOUNTING FIRM (CONTINUED)

In our opinion', management's assessment that the Company The following documents are available both on PG&E Corpo-and the Utility maintained effective internal control over finan- ration's website, wwxv.pgecorp.com, and Pacific Gas and cial reporting as of December 31, 2004, is fairly stated, in all Electric Company's website, www.pge.com:

material respects, based on the criteria established in Internal *Thecodes of conduct and ethics adopted by PG&E Corpora-Control-IntegratedFramework issued by the Committee of tion and Pacific Gas and Electric Company applicable to their Sponsoring Organizations of the Treadway Commission. Also in respective directors, officers and employees; our opinion, the Company and the Utility maintained, in all

• PG&E Corporation's and Pacific Gas and Electric Company's material respects, effective internal control over financial report- corporate governance guidelines; and ing as of December 31, 2004, based on the criteria established in

• Key Board Committee charters, including charters for the Internal Control-IntegratedFrameworkissued by the Committee companies' Audit Committees and the PG&E Corporation of Sponsoring Organizations of the Treadway Commission. .Nominating, Compensation, and Governance Committee.

We have also audited, in accordance with the standards of the Shareholders also may obtain print copies of these docu-Public Company Accounting Oversight Board (United States) ments by submitting a written request to Linda Y.H. Cheng, the consolidated financial statements and financial statement Vrice President and Corporate Secretary of both PG&E Corpo-schedules as of and for the year ended December 31, 2004 of the ration and Pacific Gas and Electric Company, One Market, Company and the Utility and our report dated February 16, Spear Tower, Suite 2400, San Francisco, California 94105.

2005 expressed an unqualified opinion (and indudes an explana- On May 20, 2004, Robert D. Glynn, Jr., vho at the time was tory paragraph relating to accounting changes) on those financial Chairman of the Board, Chief Executive Officer.and President statements and financial statement schedules. of PG&E Corporation, submitted an Annual CEO Certification to the New York Stock Exchange (NYSE) certifying that he was DELOITTE & TOUCHE LLP not aware of any violation by PG&E Corporation of the NYSE's San Francisco, California corporate governance listing standards.

February 16, 2005 148

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PERMANENT COMMITTEES OF THE BOARDS OF DIRECTORS OF PG&E CORPORATION AND PACIFIC GAS A'ND ELECTRIC COMPANYM EXECUTIVE COMMITTEES Annually reviews a five-year financial plan that incorporates

- PG&E Corporation's business strategy goals, as well as an Subject to certain limits, may exercise the powers and perform

- annual budget that reflects elements of the approved five-year the duties of the Boards of Directors.

plan.

Robert D. Glynn, Jr., Chair David A. Coulter, Chair David A. Coulter Leslie S. Biller C. Lee Cox C. Lee Cox Peter A. Darbee Barbara L. Rambo Mary S. Metz Barry Lawson Williams Gordon R. Smith(')

Barry Lawson Williams NOMINATING, COMPENSATION, AND GOVERNANCE COMMITTEE AUDIT COMMITTEES Recommends candidates for nomination as directors and Review financial and accounting practices, internal controls, reviews the composition, performance, and compensation of external and internal auditing programs, business ethics, and the Boards of Directors. Reviews corporate governance matters, compliance with laws, regulations, and policies that may have a material impact on the Consolidated Financial Statements.

Corporation and Pacific Gas and Electric Company. Reviews Satisfy themselves as to the independence and competence of employment, compensation, and benefits policies and practices, the independent public accountants, select and appoint the firm and long-range planning for executive development and of independent public accountants to audit PG&E Corpora-..

succession.

tion's and Pacific Gas and Electric Company's accounts, and pre-approve all audit and non-audit services provided by the C. Lee Cox, Chair independent public accountants. David A. Coulter David M. Lawrence, MD Barry Lawson Williams, Cbair Barbara L. Rambo David R. Andrews Barry Lawson Williams Leslie S. Biller Mary S. Metz PUBLIC POLICY COMMITTEE FINANCE COMMITTEE Reviews public policy issues that could significantly affect the interests of customers, shareholders, or employees, policies and Reviews financial and capital investment policies and objectives practices with respect to those issues, and significant societal, and specific actions required to achieve those objectives, long-governmental, and environmental trends and issues that may term financial and investment plans and strategies, annual finan-affect the operations of PG&E Corporation, Pacific Gas and cial plans, dividend policy, short-term and long-term financing Electric Company, or their respective subsidiaries.

plans, proposed capital expenditures, proposed divestitures, major commercial and investment banking, financial consulting, Mary S. Metz, Chair and other financial relations, and risk management activities. David R. Andrews David M. Lawrence, MD (1) The committee membership shown is effective through the adjournment of the 2005 Joint Annual Meetings of Shareholders on April 20,2005. Except for the Executive and Audit Committees, all committees listed above are committees of the PG&E Corporation Board of Directors. The Executive and Audit Committees of the PG&E Corporation and Pacific Gas and Electric Company Boards have the same members, except that Gordon R. Smith is a member of the Pacific Gas and Electric Company Executive Committee only.

15 0

PG&E CORPORATION PACIFIC-GAS AND ELECTRIC OFFICERS COMPANY OFFICERS ROBERT D. LGLYNN, JR. ROBERT D. GLYNN, JR. LINDA Y.H. CHENG Chairman of the Board Chairman of the Board Vice President and Corporate Secretary PETER A. DARBEE GORDON R. SMITH LINDA E. CHIN President and Chief Executive Officer President and Chief Executive Officer Vice President, General Services LESLIE H. EVERETT THOMAS- B. KING ROBERT L. HARRIS Senior Vice President and Executive Vice President and t Vice President, Environmental Affairs Assistant to the Chief Executive Officer Chief of Utility Operations ROBERT T. HOWARD RUSSELL M. JACKSON THOMAS E. BOTTORFF Vice President, Senior Vice President, Human Resources Senior Vice President, California Gas Transmission Customer Service and Revenue CHRISTOPHER P. JOHNS DONNA JACOBS Senior Vice President, JEFFREY D. BUTLER Vice President, Nuclear Services Chief Financial Officer, and Controller Senior Vice President, Transmission and Distribution ROY M. KUGA DANIEL D. RICHARD, JR. Vice President, Gas and Electric Supply Senior Vice President, Public Affairs KENT M. HARVEY Senior Vice President, PATRICIA M. LAWICKI GORDON R. SMITH Chief Financial Officer, and Treasurer Vice President and Senior Vice President Chief Information Officer RUSSELL M. JACKSON BRUCE R. WORTHINGTON Senior Vice President, Human Resources DINYAR B. MISTRY Senior Vice President and Vice President and Controller General Counsel ROGER J. PETERS Senior Vice President and DAVID H. OATLEY LEROY T. BARNES, JR. General Counsel Vice President and General Manager, Vice President and Treasurer Diablo Canyon Power Plant DANIEL D. RICHARD,- JR.

LINDA Y.H. CHENG Senior Vice President, Public Affairs FRANK J. REGAN Vice President and Corporate Secretary Vice President GREGORY M.. RUEGER DEANN HAPNER Senior Vice President, KAREN A. TOMCALA Vice President, Special Projects Generation and Chief Nuclear Officer Vice President, Regulatory Relations STEVEN L. KLINE BEVERLY Z. ALEXANDER KIMBERLY R. WALSH Vice President, Federal Governmental Vice President, Customer Satisfaction Vice President, Communications and Regulatory Relations JAMES R.- BECKER FONG WAN GABRIEL B. TOGNERI Vice President, Diablo Canyon Power Vice President, Power Contracts and Vice President, Investor Relations Plant Operations and Station Director Electric Resource Development JAMES A. TRAMUTO SHANKAR BHATTACHARYA Vice President Vice President, Asset Management 151

SHAREHOLDER INFORMATION For financial and other information about PG&E Corporation Investor Services does not know the identity PG&E Corporation and Pacific Gas and General Information of the individual shareholders who hold Electric Company, please visit our websites, 415.267.7000 their shares in this manner. They simply www.pgecorp.com and www.pge.com, know that a broker holds a number of Pacific Gas and Electric Company respectively. shares which may be held for any number of General Information investors. If you hold your stockin a street If you have questions about your PG&E 415.973.7000 Corporation common stock account or name account, you receive all tax.forms, Stock Exchange Listings publications, and proxy materials through Pacific Gas and Electric Company preferred PG&E Corporation's common stock is your broker. If you are receiving unwanted stock account, please write or call our transfer agent, Mellon Investor Services: traded on the New York,'Pacific, and Swiss duplicate mailings, you should contact your stock exchanges.The official New York broker to eliminate the duplications.

Mellon Investor Services Stock Exchange symbol is 'PCG" but PG&E Corporation P.O. Box 3310 (Securities Transfer) PG&E Corporation common stock is listed Investor Services Program P.O. Box 3315 (General Correspondence) in daily newspapers under "PG&E" or If you hold PG&E Corporation or Pacific P.O. Box 3316 (Change of Address) 'PG&E Cp."(') '

Gas and Electric Company stock in your P.O. Box 3317 (Lost Certificate Pacific Gas and Electric Company has 11 own name, rather than through a broker, Replacement) issues of preferred stock, all of which are you may automatically reinvest dividend P.O. Box 3338 (Investor Services Program) listed on'the American and Pacific stock payments from common and/or preferred South Hackensack, NJ 07606 exchanges. stock in shares of PG&E Corporation Toll-free Telephone Services: Issue Newspaper Symbol(l) common stock through the Investor 1.800.719.9056 Services Program (ISP). You may obtain an First Preferred, Cumulative, Par Value S25 Per Share Website: www.melloninvestor.com ISP brochure and enroll by contacting Redeemable:

If you have general questions about PG&E 7.04% PacGE pfU Mellon Investor Services. If your shares are 6.57% PacGE pfY held by a broker (in "street name"), you are Corporation or Pacific Gas and Electric 6.30% PacGE pfZ Company, please write or call the Corporate 5.00% PacGE pfD not eligible to participate in the ISP.

Secretary's Office: 5.00% Series A PacGE pfE Direct Deposit of Dividends 4.80% PacGE pfG Vice President and Corporate Secretary 4.50%. PacGE pfH If you hold stock in your own name, Linda Y.H. Cheng 4.36% PacGE pfl rather than through a broker, you may Non-Redeemable: have your common and/or preferred PG&E Corporation 6.00% PacGE pfA One Market, Spear Tower 5.50% PacGE pMh dividends transmitted to your bank Suite 2400 5.00% PacGE pfC electronically. You may obtain a direct San Francisco, CA 94105-1126 deposit authorization form by contacting 415.267.7070 2005 Dividend Payment Dates Mellon Investor Services.

Fax 415.267.7268 PG&E Corporation Common Stock Replacement of Dividend Checks April 15 Securities analysts, portfolio managers, or If you hold stock in your own name and July.15 other representatives of the investment do not receive your dividend check within October 15 .

community should write or call the Investor ten days after the payment date, or if a Pacific Gas and Electric Company Relations Office: check is lost or destroyed,' you should Preferred Stock notify Mellon Investor Services so that Vice President, Investor Relations February 15 payment can be stopped on the check and Gabriel B. Togneri May 15 a replacement mailed.

PG&E Corporation August 15 One Market, SpearTower November 15 Lost or Stolen Stock Certificates Suite 2400 If you hold stock in your own name and Stock Held in Brokerage San Francisco, CA 94105-1126 Accounts ('Street Name") your stock certificate has been lost, stolen, 415.267.7080 or in some way destroyed, you should notify When you purchase your stock and it is Fax 415.267.7265 Mellon Investor Services immediately.

held for you by your broker, the shares are listed with Mellon Investor Services in the broker's name, or 'street name." Mellon (1) Local newspaper symbols may vary.

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