XFD

TABLE OF CONTENTS


A Letter to our Stakeholders		1

Financial Statements		6

PG&E Corporation and Pacific Gas and Electric Company Boards of Directors		116

Officers of PG&E Corporation and Pacific Gas and Electric Company		117

Shareholder Information		118

Five years ago, we set a new course for PG&E, energized by an ambitious vision, a renewed focus on values, and a smart and simple strategy. This fusion of vision, values, and strategy has been the force behind half a decade of dynamism and growth. And it remains as durable and relevant today as when we first embraced it.

PG&E’s journey over the past five years has been a remarkable one. Emerging from the turmoil and stigma of the state’s energy crisis—the lowest time in the company’s history—we revitalized PG&E’s relationships with our customers and communities, revamped our operations, and reclaimed our identity as a standard-bearer for innovation, collaboration, and progress. Along the way, we rediscovered the best things about our people and our culture. At the same time, we openly embraced the need for new ways of working and thinking about the future of our business.

Invigorated by this renewal, PG&E has risen to become one of the industry’s leading performers in recent years. Our results for customers and shareholders in 2009 built on this track record once again.

Among our accomplishments were new enhancements to our infrastructure, major improvements in safety and reliability, further deployment of smart grid technology, new commitments to increase renewable energy supplies, and significant energy savings through our customer energy efficiency programs.

These and other achievements helped us increase overall customer satisfaction while also providing a competitive total return to investors.

Today, looking at 2010 and beyond, our task is to sustain PG&E’s strong momentum—and to ensure we are doing so in ways that are in step with and responsive to shifts and challenges in the economy.

More than any other single factor last year, the business environment was marked by concern over the recession’s implications for our customers and communities, which have been hit with some of America’s worst job-loss and home-foreclosure rates.

In response, PG&E has stepped up outreach and provided financial assistance to large numbers of customers through a wide assortment of programs. Across the hundreds of communities we serve, we also increased the support we provide through shareholder-funded charitable contributions. Last year’s total giving was our highest ever, consistent with our belief that PG&E’s special privilege as a utility comes with a unique duty to give back.

Equally critical, we followed through on commitments to maintain a steady flow of capital investments. This meant that many local suppliers, contractors, and subcontractors who count on PG&E as a mainstay of their business were able to keep doing so. This has been all the more important in light of decisions by many other companies to throttle back on new investments and spending.

Moving forward, one of the biggest roles we expect to play for customers and communities is to serve as an even greater force for economic revival and growth.

The investments we are making today in California’s infrastructure—and those we are seeking permission to make in the next few years—support new and existing jobs and put money back into local economies at a moment when private sector investment is so vital.

But even more important is the broader economic promise that smart energy investments hold.

Many experts believe that a 21^st-century energy economy will be the backbone for America’s growth and competitiveness in the decades ahead. We agree. The clean, highly efficient, and highly reliable energy infrastructure we are working to build is fundamental to this future.

For these reasons, the downturn has made the job of modernizing California’s energy economy more pressing, not less. We believe that state leaders understand this and will support efforts that strike the right balance between the pragmatism that immediate challenges dictate and the continuing investment necessary to ensure a stable, vibrant economic climate.

For our part, we intend to stay true to the same vision, values, and strategy that have delivered for customers and shareholders in recent years. In 2010, we are focused again on knowing and responding to the unique needs of our different customers, running our operations with excellence, working constructively with policymakers and regulators, demonstrating environmental leadership, and staying connected with our communities.

This letter outlines examples of the ways we are putting this strategy into action, the results it is making possible, and the outlook for the current year and beyond.

Ensuring that PG&E Corporation represents a solid value for investors is an essential prerequisite for our success. Utilities that are financially sound and healthy have the wherewithal to attract new capital at reasonable costs and fund smart long-term investments for customers.

Last year’s financial results showed that we continue to provide the kinds of opportunities that investors are seeking. We grew core earnings primarily through a combination of new capital investments in PG&E’s utility asset base, along with incentives earned by helping customers realize aggressive energy efficiency targets and efficiencies realized by effectively managing our resources.

Total net income for 2009 was solid at $1.22 billion, or $3.20 per share, as reported under generally accepted accounting principles (GAAP). This compared with net income of $1.34 billion for 2008, which was enlarged significantly by the one-time benefits of a multiyear tax settlement.

Earnings per share from operations, a non-GAAP measure adjusted to reflect normal operations and exclude unusual items like last year’s tax settlement, were $3.21 per share, up almost 9 percent over 2008 levels. (The “Financial Highlights” table on page 7 reconciles GAAP total net income with non-GAAP earnings from operations.)

These results were just above the midpoint of our earnings guidance range, and they exceeded Wall Street’s consensus expectation.

In addition to earnings growth, in early 2009 we raised PG&E Corporation’s common stock dividend. The 8 percent increase was in keeping with our view that dividend growth should accompany growth in earnings over time. In fact, we raised the dividend again in early 2010 on the strength of our full-year 2009 results and our confidence in the outlook for 2010.

Total shareholder return for 2009—stock price appreciation plus dividends—was 20 percent. As strong as PG&E’s return was, however, it put us in the middle of the pack last year relative to comparable utilities, many of which were rebounding from the dramatic decline in late 2008.

But if some of our peers bounced back more strongly, it is also the case that in many instances their shares had fallen further. As we noted last year, PG&E shares held their value better than many other utilities during the downturn.

A truer indication of PG&E’s relative strength is the company’s two- and three-year total shareholder returns. Over the past three years, our return put the company firmly in the top half of the peers we track. And over the past two years, our return has been the best in the group.

More importantly, our financial forecasts for 2010 and 2011 reflect expectations that earnings will keep growing at a competitive pace. Indeed, our goal is to deliver total shareholder returns that are in the top 25 percent among comparable utilities.

Last year’s capital investment once again focused principally on increasing reliability and capacity across the extensive network of wires, pipes, generating stations, and other essential assets at the heart of California’s energy infrastructure.

PG&E’s total capital expenditures in 2009 were $3.9 billion. This exceeded our initial capital spending goals for the year, but remained consistent with our projected range for annual average capital expenditures over the 2008 through 2011 time frame.

The majority of these resources supported ongoing efforts to strengthen local electric and natural gas distribution systems. For example, we made improvements to a number of our least reliable electric circuits, we added new protective equipment to lines, and we installed new hardware to enhance power restoration capabilities in certain reliability hot spots.

We also proceeded with efforts to lay the foundation for the emerging smart grid, through the ongoing transition to SmartMeter^™ technology. By year’s end, total installations of new gas and electric meters reached approximately 4.5 million out of a total of 10 million that will be in place by mid-2012.

With its ability to send timely energy-usage data and its Web-like connectivity options, SmartMeter^™ technology will be the basis for a range of new energy management tools and capabilities, which are key to improving customer service, increasing reliability, expanding energy efficiency and demand response, and optimizing the use of renewable energy sources and, soon, electric vehicles.

Last year also saw further heavy investment in electric transmission, with a focus on asset replacement and alleviating grid congestion. Other projects in this area were aimed at interconnecting new generation, including new renewable power sources, and improving reliability through automation.

PG&E also won federal support for a project to install new monitoring and communications technology within our electric transmission system. Known as synchrophasors, the devices will help identify and address potential reliability concerns and improve our ability to integrate intermittent renewable power resources.

Within our power generation operations, we forged ahead with both conventional and renewable generating projects.

PG&E’s Gateway Generating Station went into service in early 2009, ahead of schedule, within budget, and with an exceptional safety record in construction—all of which set the stage for an exceptionally safe and reliable first year of operations. A showcase for the latest in clean, highly efficient gas-fired generation, the plant earned project-of-the-year accolades from Power Engineering magazine. Construction also progressed on two other conventional-fueled facilities, Humboldt Bay and Colusa Generating Station. Humboldt Bay is expected to be completed in the third quarter of 2010, and Colusa Generating Station is expected to be completed several months later.

Importantly, we also unveiled PG&E’s first plans to own new renewable generation assets. These include a proposed project to build 250 megawatts of PG&E-owned solar photovoltaic resources (in addition to another 250 megawatts that would be owned by other developers). We also proposed to buy and operate a major wind energy facility. If approved and built, it would provide enough power for about 100,000 average homes. Both the solar and wind projects are awaiting regulatory approval.

Within our existing fleet, we completed major capital projects to help ensure the ongoing safe and reliable operation of the Diablo Canyon Power Plant, a critical source of carbon-free nuclear power for millions of Californians. We also began the multiyear regulatory process to renew the licenses for this essential facility so that it will be available to provide power well into this century.

Even with the right investments in our system, delivering for customers ultimately depends on our people and practices. As a result, operational excellence—safety, reliability, productivity, and on-budget and on-time performance—is central to our strategy.

Last year’s operational metrics show that PG&E’s intensive efforts in these areas are paying off.

Nowhere is this more true than on our number one priority, safety. In 2009, the three basic safety indicators we monitor all continued to move decisively in the right direction.

Thanks to improved training, improved work procedures, and an emphasis on accountability, we achieved major reductions in recordable injuries, lost workdays, and motor vehicle incidents.

We exceeded our goals in all three categories. Most extraordinarily, since 2006, we have bettered performance in each of these areas by more than 50 percent.

However, notwithstanding these achievements, our safety results are not yet where they must be. On-the-job tragedies took the lives of two workers last year, and our overall safety scores still trail those of the top performers in the industry.

Our pledge is that reducing safety incidents will remain a top priority until we reach the absolute goal of zero injuries.

Importantly, while this commitment is about people first, it is also about performance: A safer workplace is a more productive, efficient, cost-effective workplace. In fact, excellence in safety is one of the best bellwethers of overall operational excellence.

Another key benchmark of excellence is reliability. In fact, our customers consistently rank reliability as a top driver for satisfaction.

In 2009, through a combination of strategic investments, more rigorous and efficient work practices, and excellent teamwork, we dramatically drove down both the frequency and duration of electric outages, our two key reliability measures.

Although our targets set a high bar for the year, our teams exceeded the goals on both measures. PG&E customers experienced service interruptions less often than at any time in the last 22 years. And if they did, we restored their service faster than at any time in the past nine years.

We also focused again on the reliability of our natural gas operations. Last year’s accomplishments included completing 1.9 million on-location service line inspections as part of an ongoing initiative to survey the integrity of our entire gas distribution network on an accelerated basis. This progress exceeded our target for the year.

Other operational highpoints included more progress in streamlining processes and making it easier for our employees to serve customers; solid storm recovery efforts; excellent execution on the steam generator, dry cask storage, and reactor-head replacement projects at Diablo Canyon; and the remarkably safe and smooth construction of the Humboldt and Colusa generating projects.

Our principal barometer for measuring customer satisfaction—a series of independent surveys that look at customers’ views on reliability, pricing, service interactions, and overall favorability—rose in 2009 compared with 2008, exceeding our target.

We view last year’s positive feedback as a considerable accomplishment in light of the strain that the tough economy has placed on some customers. We attribute this to the marked improvements in electric reliability and our outreach to customers who were struggling to stay current with their bills.

As noted earlier, we significantly ramped up efforts to inform customers about various ways PG&E can lend a hand to those who need it. Our Breathe Easy Solutions™ initiative raised broad customer awareness of a full range of options, from direct financial assistance to flexible payment plans and help through energy efficiency programs.

Among the most telling signs of success was the increased enrollment in PG&E’s CARE Program, which assists income-qualified customers through discounts on their monthly energy bills. The program added more than 466,000 new participants in 2009.

Higher program enrollment numbers were also a validation of our efforts to know our customers better than ever before. More than ever, we are making smart use of our knowledge of customers’ specific needs and preferences to tailor our service offerings and effectively match customers with the right products and programs. This will remain a key pillar of our strategy going forward.

Of all the influences reshaping our business—the advent of smart technologies, the tough economy, the need to replace aging infrastructure, and rising customer expectations—the most fundamental is the need to produce and use energy in ways that are cleaner and more efficient. Climate change, water scarcity, waste reduction, air and water quality, habitat protection, and other sustainability issues are compelling utilities to take a fresh look at their end-to-end operations and assess basic policies and priorities.

Last year, we continued to answer this challenge in different ways, from reducing water and energy consumption in our facilities to offsetting the carbon emissions associated with the energy we use in our offices and maintenance facilities.

One of the most important ways was helping customers through our industry-leading energy efficiency initiatives.

In 2009, we again enabled customers to achieve extraordinary energy savings. We expect that when the final analysis of last year’s programs is complete, it will confirm that we surpassed the gas and electric savings goals that the state set for the year.

We also received $33.4 million in energy efficiency incentives last year, earned in return for helping customers achieve savings in the 2006-2008 program cycle.

Energy efficiency remains the most readily available, cost-effective, and powerful resource to meet new demand, produce energy savings, and reduce emissions in the near term. In fact, in the decade ahead, PG&E plans to meet almost half of customers’ new energy demand through energy efficiency.

In addition to helping customers save energy, we continued to provide them with an energy supply that is among the cleanest in the nation. PG&E’s carbon dioxide emissions rate is approximately 50 percent lower than that of the average utility.

Our supply will become even cleaner in the future. In 2009, we signed 42 new renewable energy purchase contracts. If all of these projects are built, these agreements will represent additions of more than 4,200 megawatts of new renewable resources to our future supply.

PG&E also successfully secured $25 million from the U.S. Department of Energy to fund preliminary work on a compressed-air energy storage project. The project will use night-time energy, when wind power is most abundant, to pump air underground. The air can then be released to drive turbines as needed, delivering 300 megawatts of power for up to 10 hours.

On the policy front, we continued to work with policymakers to advance federal climate and energy legislation that puts a price on carbon emissions. We believe strongly that well-crafted legislation to address greenhouse gas emissions can provide clarity that drives business investment in cleaner, more efficient technologies while also protecting consumers.

These and other examples of leadership on the environment have distinguished PG&E in the eyes of key observers. In 2009, PG&E was one of only two U.S. utility companies named to the prestigious Dow Jones Sustainability World Index, which lists the top 10 percent of companies worldwide that lead their industries in managing economic, environmental, and social issues.

As we look forward, 2010 is set to be a demanding and pivotal year—demanding because of the goals we have set for ourselves and the difficulties that persist in the economy, and pivotal because the way we balance and resolve critical issues this year will in many ways set the stage for the next few years and the opportunities ahead.

Even so, our confidence in PG&E’s vision, values, and strategy remains firm. We know the road ahead will hold challenges. But we also know that PG&E is well suited to succeed in this environment.

Our plans for additional investment in California’s energy future are compelling and in harmony with the priorities of our customers and the state’s leaders.

Our successful efforts to help customers last year are continuing in 2010, including efforts to ease rate pressures and ensure affordable service.

Our determination to keep raising the bar on safety and reliability is unyielding.

Our commitment to working constructively with regulators to produce win-win solutions for customers is as strong as ever.

Our leadership on clean energy and efficiency promises to enable us to capture more new opportunities in this area.

Above all, our people are among the most talented, dedicated, and innovative in the industry.

As a result, we look to the future with great optimism. Earlier this year, in fact, we reaffirmed our commitment to become the nation’s leading utility—and we set a goal to do so by 2014. We are defining this objective now more clearly than we ever have before, with high bars set for customer satisfaction, employee engagement, environmental leadership, and shareholder return.

The many accomplishments of 2009 and the past five years give us a platform that now puts these goals within striking distance. You have our team’s pledge that we will work relentlessly toward this vision in 2010 and over the next several years. We look forward to sharing our progress with all of our stakeholders.

Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation

PG&E Corporation common stock is traded on the New York Stock Exchange. The official New York Stock Exchange symbol for PG&E Corporation is “PCG.”

This graph compares the cumulative total return on PG&E Corporation common stock (equal to dividends plus stock price appreciation) during the past five fiscal years with that of the Standard & Poor’s 500 Stock Index and the Dow Jones Utilities Index.

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

The Utility served approximately 5.1 million electric distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2009. The Utility had $42.7 billion in assets at December 31, 2009 and generated revenues of $13.4 billion in the 12 months ended December 31, 2009.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electric and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and over the rates and terms and conditions of service governing the Utility on its interstate natural gas transportation contracts. Before setting rates, the CPUC and the FERC determine the annual amount of revenue (“revenue requirements”) that the Utility is authorized to collect from its customers to recover its reasonable operating and capital costs of providing utility services. The authorized revenue requirements also provide the Utility an opportunity to earn a return on “rate base,” the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility service to its customers. The CPUC requires the Utility to maintain a certain capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) when financing its rate base and authorizes the Utility to earn a specific rate of return on each capital component.

The Utility’s ability to recover the revenue requirements, authorized by the CPUC in the general rate case (“GRC”), does not depend on the volume of the Utility’s sales of electricity and natural gas services. This “decoupling” of revenues and sales eliminates volatility in the revenues earned by the Utility due to fluctuations in customer demand. However, fluctuations in operating and maintenance costs may impact the Utility’s ability to earn its authorized rate of return. Generally, the Utility’s recovery of its FERC-authorized revenue requirements can vary with the volume of electricity sales. A portion of the Utility’s CPUC-authorized revenue requirements for its natural gas transportation and storage services also depends on the volume of natural gas transported and the extent to which the Utility provides firm transmission services.

The Utility also collects additional revenue requirements to recover certain costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; to fund public purpose, demand response, and customer energy efficiency programs; and to recover certain capital expenditures. The Utility’s ability to recover these costs is not dependent on the volume of the Utility’s sales. Therefore, although the timing and amount of these costs can impact the Utility’s revenue, these costs generally do not impact earnings.

The Utility’s revenues and earnings also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent the Utility meets certain performance criteria.

The Utility uses regulatory balancing accounts primarily to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. The CPUC periodically authorizes adjustments to electric and natural gas rates to (1) reflect over- and under-collections in the Utility’s major electric and natural gas balancing accounts, and (2) implement various other electric and natural gas revenue requirement changes authorized by the CPUC and the FERC. Generally, these rate changes become effective on the first day of the following year. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.

This is a combined annual report of PG&E Corporation and the Utility, and includes separate Consolidated

Financial Statements for each of these two entities. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries as well as the accounts of variable interest entities for which the Utility absorbs a majority of the risk of loss or gain. This combined Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) of PG&E Corporation and the Utility should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in this annual report.

SUMMARY OF CHANGES IN EARNINGS PER COMMON SHARE AND INCOME AVAILABLE FOR COMMON SHAREHOLDERS FOR 2009

PG&E Corporation’s diluted earnings per common share (“EPS”) for 2009 were $3.20 per share, compared to $3.63 per share for 2008. PG&E Corporation’s 2009 income available for common shareholders decreased by $118 million, or 9%, to $1,220 million, compared to 2008 income available for common shareholders of $1,338 million. The decrease in diluted EPS and income available for common shareholders in 2009 as compared to 2008 is primarily due to (1) $257 million of net income recognized in 2008 resulting from a settlement of tax audits for 2001 through 2004, and (2) $59 million, after tax, attributable to costs to perform accelerated natural gas leak surveys and associated remedial work. These decreases were partially offset by (1) a $91 million, after tax, increase due to the Utility’s return on equity (“ROE”) earned on higher authorized capital investment, and (2) a tax benefit of $66 million associated with the settlement of tax refund claims involving the 1998 and 1999 tax years.

PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, recover its authorized costs timely, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E Corporation’s and the Utility’s results of operations and financial condition, including:

This combined annual report and the letter to shareholders that accompanies it contain forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, estimated future cash flows, and the level of future equity or debt issuances, and are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

The table below details certain items from the accompanying Consolidated Statements of Income for 2009, 2008, and 2007:

The following presents the Utility’s operating results for 2009, 2008, and 2007.

The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of electric procurement, public purpose, energy efficiency, and demand response programs. The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties. In addition, a portion of the Utility’s customers’ demand for electricity (“load”) is satisfied by electricity provided under long-term contracts between the California Department of Water Resources (“DWR”) and various power suppliers.

The following table provides a summary of the Utility’s electric operating revenues:

The Utility’s total electric operating revenues decreased by $481 million, or 4%, in 2009 compared to 2008, reflecting a decrease in revenues to recover the cost of electricity procurement (which decreased by $714 million) and the cost of public purpose programs (which decreased by $110 million). These costs are passed through to customers and do not impact net income. (See “Cost of Electricity” and “Operating and Maintenance” below.) Electric operating revenues, excluding items passed through to customers, increased by $343 million. This was primarily due to $344 million of increases in authorized base revenues consisting of $103 million for the 2009 attrition adjustment, $35 million for the cost of a second refueling outage at Diablo Canyon, and $206 million representing additional authorized revenue requirements to recover the capital costs of new assets placed in service (such as the Gateway Generating Station, the new steam generators at Diablo Canyon Unit 1 and Unit 2, and the SmartMeter^TM advanced metering project) and the associated rate of return. In 2009, the CPUC also authorized the Utility to recover $35 million of costs the Utility incurred during 2000 and 2001 related to efforts taken by the Utility in connection with the proposed divestiture of its hydroelectric generation facilities, as directed by the CPUC.

The Utility’s total electric operating revenues increased by $1,257 million, or 13%, in 2008 compared to 2007, reflecting an increase in revenues to recover the cost of electricity procurement (which increased by $976 million) and the cost of public purpose and energy efficiency programs (which increased by $266 million). These increases were partially offset by a $276 million decrease in revenue that was recovered in 2007 for the payment of principal and interest related to the rate reduction bonds (“RRBs”) that matured in December 2007. Costs related to electricity procurement, public purpose programs, and the RRBs are passed through to customers and do not impact net income. (See “Cost of Electricity” and “Operating and Maintenance” below.) Electric operating revenues, excluding items passed through to customers, increased by $291 million. This was primarily due to $255 million of increases in authorized base revenues consisting of $103 million for the 2008 attrition adjustment, $56 million for electric transmission revenues, and $96 million representing additional authorized revenue requirements to recover the capital costs of new assets placed in service (such as the new steam generators at Diablo Canyon Unit 2 and the SmartMeter^TM advanced metering project) and the associated rate of return.

The Utility’s electric operating revenues for 2010 are expected to increase by $68 million due to the attrition adjustment that was authorized by the CPUC in the 2007 GRC. The Utility’s electric operating revenues for future years are also expected to increase, as authorized by the FERC in the TO rate cases and by the CPUC in the 2011 GRC. Additionally, the Utility’s future electric operating revenues may be impacted by the revenue requirements to recover certain pension contributions as authorized by the CPUC during 2009. The Utility also expects to continue to collect revenue requirements related to CPUC-approved capital expenditures outside the GRC, including capital expenditures for the new Utility-owned generation projects and the SmartMeter^TM advanced metering project. Revenues will increase to the extent that the CPUC approves the Utility’s proposals for other capital projects. Finally, the CPUC has not yet determined how the existing energy efficiency incentive mechanism will be modified, so the amount of incentive revenues the Utility may earn for the implementation of its programs in 2009 and future years is uncertain. (See “Regulatory Matters” below.)

The Utility’s cost of electricity includes costs to purchase power from third parties, certain transmission costs, the cost of fuel used in its generation facilities, and the cost of fuel supplied to other facilities under tolling agreements. The Utility’s cost of electricity also includes realized gains and losses on price risk management activities. (See Notes 10 and 11 of the Notes to the Consolidated Financial Statements.) The Utility’s cost of electricity is passed through to customers. The Utility’s cost of electricity excludes non-fuel costs associated with the Utility’s own generation facilities, which are included in Operating and maintenance expense in the Consolidated Statements of Income. The cost of electricity provided under power purchase agreements between the DWR and various power suppliers is also excluded from the Utility’s cost of electricity.

The following table provides a summary of the Utility’s cost of electricity and the total amount and average cost of purchased power:

The Utility’s total cost of electricity decreased by $714 million, or 16%, in 2009 compared to 2008, primarily due to an 8% decrease in the average cost of purchased power and a 10% decrease in the total volume of purchased power. The decrease in the average cost of purchased power was primarily driven by lower market prices for electricity and gas. The decrease in the volume of purchased power primarily resulted from an increase in the amount of power generated by facilities owned by the Utility such as the new Gateway Generating Station. The Utility’s mix of resources is determined by the availability of the Utility’s own electricity generation and the cost-effectiveness of each source of electricity.

The Utility’s total cost of electricity increased by $988 million, or 29%, in 2008 compared to 2007, primarily due to a 32% increase, or an 11,511 million kWh increase, in total volume of purchased power. Following the DWR’s termination of its power purchase agreement with Calpine Corporation in December 2007, the volume of power provided by the DWR to the Utility’s customers decreased by 8,784 million kWh. As a result, the Utility was required to increase its purchases of power from third parties to meet customer load. In addition, the Utility increased its power purchases in 2008 during the scheduled extended outage at Diablo Canyon Unit 2 to replace the four steam generators. The extended outage lasted from February through mid-April 2008, in comparison to the planned refueling outage of Diablo Canyon Unit 1 that occurred entirely in May 2007. Increases in market prices during the first half of 2008 were entirely offset by a decrease in market prices during the second half of 2008 and price risk management activity.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the level of hydroelectric and nuclear power that the Utility produces, the cost of procuring more renewable energy, changes in customer demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts expire or are terminated, novated, or renegotiated.

The Utility’s future cost of electricity also may be affected by federal or state legislation or rules that may be adopted to regulate the emissions of greenhouse gases (“GHG”) from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures electricity. In particular, costs are likely to increase in the future when California’s statewide GHG emissions reduction law is implemented. (See “Environmental Matters” and “Risk Factors” below.)

The Utility sells natural gas and natural gas transportation services. The Utility’s transportation services are provided by a transmission system and a distribution system. The transmission system transports gas throughout its service territory for delivery to the Utility’s distribution system, which, in turn, delivers natural gas to end-use customers. The transmission system also delivers natural gas to large end-use customers who are connected directly to the transmission system. In addition, the Utility delivers natural gas to off-system markets, primarily in southern California.

The Utility’s natural gas customers consist of two categories: residential and smaller commercial customers known as “core” customers and industrial and larger commercial customers known as “non-core” customers. The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas from either the Utility or alternate energy

service providers. The Utility does not procure natural gas for non-core customers. When the Utility provides both transportation and natural gas supply, the Utility refers to the combined service as “bundled natural gas service.” In 2009, core customers represented over 99% of the Utility’s total customers and 38% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total customers and 62% of its total natural gas deliveries.

The following table provides a summary of the Utility’s natural gas operating revenues:

The Utility’s total natural gas operating revenues decreased by $748 million, or 19%, in 2009 compared to 2008, primarily due to a $799 million decrease in the total cost of natural gas. This cost is passed through to customers and generally does not impact net income. (See “Cost of Natural Gas” below.) Natural gas operating revenues, excluding items passed through to customers, increased by $51 million. This was primarily due to $53 million of increase in authorized base revenues consisting of $22 million for the 2009 attrition adjustments, $10 million as a result of the 2007 Gas Accord IV Settlement Agreement, and $21 million representing additional authorized revenue requirements to recover the capital costs of new assets placed in service (such as the SmartMeter^TM advanced metering project).

The Utility’s natural gas operating revenues increased by $133 million, or 4%, in 2008 compared to 2007, primarily due to an increase in costs of natural gas of $55 million and public purpose programs of $24 million, which are passed through to customers and generally do not have an impact on earnings. Natural gas operating revenues, excluding items passed through to customers, increased by $54 million, primarily due to a $22 million increase in base revenue requirements as a result of attrition adjustments authorized in the 2007 GRC and an increase in natural gas revenue requirements of $25 million to fund the SmartMeter^TM advanced metering project.

The Utility’s natural gas operating revenues for 2010 are expected to increase by $22 million due to attrition adjustments that were authorized by the CPUC in the 2007 GRC. The Utility’s future natural gas operating revenues for 2011 through 2014 will depend on the amount of revenue requirements authorized by the CPUC in the Utility’s 2011 GRC and the Gas Transmission and Storage rate case. (See “Regulatory Matters” below.) In addition, the Utility expects future natural gas operating revenues to increase to the extent that the CPUC approves the Utility’s separately funded projects. (See “Capital Expenditures” below.) Finally, the CPUC has not yet determined how the existing energy efficiency incentive mechanism will be modified, so the amount of incentive revenues that the Utility may earn for the implementation of its programs in 2009 and future years is uncertain. (See “Regulatory Matters” below.)

The Utility’s cost of natural gas includes the purchase costs of natural gas, transportation costs on interstate pipelines, and gas storage costs but excludes the transportation costs on intrastate pipelines for core and non-core customers, which are included in Operating and maintenance expense in the Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See Notes 10 and 11 of the Notes to the Consolidated Financial Statements.)

The Utility’s total cost of natural gas decreased by $799 million, or 38%, in 2009 compared to 2008, primarily due to decreases in the average market price of natural gas.

The Utility’s total cost of natural gas increased by $55 million, or 3%, in 2008 compared to 2007, primarily due to increases in the average market price of natural gas purchased. The increase was partially offset by a $23 million refund that the Utility received as part of a settlement with TransCanada’s Gas Transmission Northwest Corporation related to 2007 gas transmission capacity rates.

The Utility’s future cost of natural gas will be affected by the market price of natural gas and changes in customer demand. In addition, the Utility’s future cost of gas may be affected by federal or state legislation or rules to regulate the GHG emissions from the Utility’s natural gas transportation and distribution facilities and from natural gas consumed by the Utility’s customers.

Operating and maintenance expenses consist mainly of the Utility’s costs to operate and maintain its electricity and natural gas facilities, customer billing and service expenses, the cost of public purpose programs, and administrative and general expenses. Operating and maintenance expenses are influenced by wage inflation; changes in liabilities for employee benefits; property taxes; the timing and length of Diablo Canyon refueling outages; the occurrence of storms, wildfires, and other events causing outages and damages in the Utility’s service territory; environmental remediation costs; legal costs; materials costs; the level of uncollectible customer accounts; and various other factors. Although some of the Utility’s operating and maintenance expenses, like the cost of public purpose programs, are passed through to customers and generally do not impact net income, many other expenses are less predictable and less controllable and do impact net income. The Utility’s ability to earn its authorized rate of return depends in large part on the success of its ability to manage these expenses and to achieve operational and cost efficiencies.

The Utility’s operating and maintenance expenses (including costs passed through to customers) increased by $146 million, or 3%, in 2009 compared to 2008. During 2009, the pass-through costs of public purpose programs decreased by $111 million as compared to the level of program spending in 2008. Excluding costs passed through to customers, operating and maintenance expenses increased by $257 million, primarily due to approximately $100 million of costs to perform accelerated natural gas leak surveys and associated remedial work, $67 million of employee severance costs incurred due to the reduction of approximately 2% of the Utility’s workforce, $42 million of costs related to the SmartMeter^TMadvanced metering project, and $35 million of costs for the second refueling outage at Diablo Canyon. The remaining increase consists primarily of employee wage and benefit costs that were partially offset by lower storm-related costs as compared to 2008 when costs were incurred in connection with the January 2008 winter storm.

The Utility’s operating and maintenance expenses increased by $325 million, or 8%, in 2008 compared to 2007. This increase reflects a $290 million increase in the cost of public purpose programs compared to the level of spending in 2007, as program spending typically increases in the last year of a three-year program cycle. Program costs are passed through to customers and generally do not impact net income. Excluding items passed through to customers, operating and maintenance expenses increased by $35 million, primarily due to $39 million of costs to conduct expanded natural gas leak surveys in parts of the Utility’s service territory and to make related repairs in an effort to improve operating and maintenance processes in the Utility’s natural gas system, $38 million of labor expenses consisting of the labor costs that were incurred in connection with the January 2008 winter storm (there was no similar storm in the same period in 2007), and $10 million of maintenance costs due to the longer duration of the planned outage of Diablo Canyon Unit 2 in 2008 compared to the Diablo Canyon Unit 1 outage in 2007. These increases were partially offset by a decrease of $12 million of costs as compared to 2007, when the CPUC ordered the Utility to make customer refunds related to billing practices.

The Utility anticipates that it will incur higher costs in the future to improve the safety and reliability of its electric and natural gas system infrastructure and to maintain its aging electric distribution system. The Utility also expects that it will incur higher expenses in future periods to obtain permits or comply with permitting requirements, including costs associated with renewing FERC licenses for the Utility’s hydroelectric generation facilities. Also, in January 2010, the Utility incurred approximately $20 million of additional expenses in connection with winter storms. To help offset these increased costs, the Utility intends to continue its efforts to identify and implement initiatives to achieve operational efficiencies and to create future sustainable cost savings.

The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil and nuclear decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $102 million, or 6%, in 2009 compared to 2008, primarily due to an increase in authorized capital additions and depreciation rate changes.

The Utility’s depreciation, amortization, and decommissioning expenses decreased by $119 million, or 7% in 2008 compared to 2007, mainly due to decreases in amortization expense related to the RRB regulatory asset. The RRB regulatory asset was fully recovered through rates when the RRBs matured in December 2007; therefore, no amortization was recorded in 2008. These decreases were partially offset by increases to depreciation expense primarily due to capital additions and depreciation rate changes.

The Utility’s depreciation expense for future periods is expected to increase as a result of an overall increase in capital expenditures and implementation of depreciation rates authorized by the CPUC. Depreciation expenses in subsequent years will be determined based on rates set by the CPUC in the 2011 GRC and the 2011 Gas Transmission and Storage rate case, and by the FERC in future TO rate cases.

The Utility’s interest income decreased by $58 million, or 64%, in 2009 compared to 2008, primarily due to lower interest rates affecting various regulatory balancing accounts and regulatory assets and lower balances in those accounts. In addition, interest income decreased due to lower interest rates earned on funds held in escrow pending the disposition of disputed claims that had been made in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”). (See Note 14 of the Notes to the Consolidated Financial Statements for information about the Chapter 11 disputed claims.) These decreases were partially offset by an increase in interest income for the recovery of interest on previously incurred costs related to the Utility’s hydroelectric generation facilities.

The Utility’s interest income decreased by $59 million, or 39%, in 2008 as compared to 2007, when the Utility received $16 million in interest income on a federal tax refund. In addition, decreases in interest income were due to lower interest rates earned on funds held in escrow related to Chapter 11 disputed claims and a lower escrow balance reflecting settlements of Chapter 11 disputed claims.

The Utility’s interest income in future periods will be primarily affected by changes in the balance of funds held in escrow pending resolution of the Chapter 11 disputed claims, changes in regulatory balancing accounts, and changes in interest rates.

The Utility’s interest expense decreased by $36 million, or 5%, in 2009 as compared to 2008. This was primarily attributable to lower interest rates and outstanding balances on liabilities that the Utility incurs interest expense on (such as the liability for Chapter 11 disputed claims and various regulatory balancing accounts). This decrease was partially offset by higher outstanding balances for long-term debt due to timing of senior note issuances. (See Note 4 of the Notes to the Consolidated Financial Statements for further discussion.)

The Utility’s interest expense decreased by $34 million, or 5%, in 2008 as compared to 2007, primarily due to a decrease in interest expense accrued on the liability for Chapter 11 disputed claims as the FERC-mandated interest rates declined. Additionally, interest expense decreased due to the reduction in the outstanding balance of Energy Recovery Bonds (“ERB”) and the maturity of the RRBs in December 2007. These decreases were partially offset by additional interest expense primarily related to $1.8 billion in senior notes that were issued in March, October, and November 2008.

The Utility’s interest expense in future periods will be impacted by changes in interest rates, changes in the balance of the liability for Chapter 11 disputed claims, changes in regulatory balancing accounts, and changes in the amount of debt outstanding as long-term debt matures and additional long-term debt is issued. (See “Liquidity and Financial Resources” below.)

The Utility’s other income, net increased by $31 million, or 111%, in 2009 compared to 2008, when the Utility incurred costs to oppose the statewide initiative related to renewable energy (Proposition 7) and the City of San Francisco’s municipalization efforts. These costs also caused the Utility’s other income, net to decrease by $24 million, or 46%, in 2008 compared to 2007.

The Utility estimates it will incur approximately $25 million to $35 million in 2010 to support a California ballot initiative that proposes to require local governments to gain voter support before using taxpayer money to establish electric service. These costs will not be recoverable in rates.

The Utility’s income tax provision decreased by $6 million, or 1%, in 2009 compared to 2008. The effective tax rates were 27.8% and 28.9% for 2009 and 2008, respectively. The lower effective tax rate for 2009 was primarily due to the recognition of California tax and related interest benefits attributable to the settlement of various federal tax issues. (See Note 9 of the Notes to the Consolidated Financial Statements for further discussion.)

The Utility’s income tax provision decreased by $83 million, or 15%, in 2008 compared to 2007. The effective tax rates were 28.9% and 35.8% for 2008 and 2007, respectively. The decrease in the effective tax rate for 2008 was primarily due to a settlement of federal tax audits for the tax years 2001 through 2004 and approval by the Internal Revenue Service of the Utility’s change in accounting method for the capitalization of indirect service costs for tax years 2001 through 2004.

PG&E Corporation and the Utility are entitled to a tax-exempt federal subsidy (“Medicare Part D subsidy”) as established by the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. The health care reform legislation proposed by the U.S. Congress would eliminate the tax deduction for the Medicare Part D subsidy included in the Utility’s accrued postretirement medical costs. (See Note 13 of the Notes to the Consolidated Financial Statements for further discussion). The impact of this legislation could result in a charge to earnings of up to $25 million representing a reduction in tax benefits related to contributions of future subsidies received to the benefit plan trusts.

PG&E Corporation’s revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation’s operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation’s operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation’s interest expense relates to its 9.50% convertible subordinated notes and 5.75% senior notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating revenues and expenses in 2009 compared to 2008 and 2008 compared to 2007.

PG&E Corporation’s other income, net increased by $40 million, or 125%, in 2009 compared to 2008, primarily due to investment-related gains in the rabbi trusts established in connection with the non-qualified deferred compensation plans.

PG&E Corporation’s other expense, net increased by $23 million, or 255%, in 2008 compared to 2007, primarily due to an increase in investment losses in the rabbi trusts established in connection with the non-qualified deferred compensation plans.

PG&E Corporation’s income tax benefit decreased by $41 million, or 65%, in 2009 compared to 2008, primarily due to a settlement of federal tax audits for the tax years 2001 to 2004 in 2008 with no similar adjustment in 2009.

PG&E Corporation’s income tax benefit increased by $31 million, or 97%, in 2008 compared to 2007, primarily due to a settlement of federal tax audits for the tax years 2001 through 2004 in 2008 with no similar adjustment in 2007.

In the fourth quarter of 2008, PG&E Corporation reached a settlement of federal tax audits of tax years 2001 through 2004 and recognized after-tax income of $257 million, including $154 million related to losses incurred and synthetic fuel tax credits claimed by PG&E Corporation’s former subsidiary, National Energy & Gas Transmission, Inc. (“NEGT”). As a result, PG&E Corporation recorded $154 million in income from discontinued operations in 2008. (See Note 9 of the Notes to the Financial Statements for further discussion.) No similar amount was recognized in 2009.

The Utility’s ability to fund operations depends on the levels of its operating cash flow and access to the capital markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal demand for electricity and natural gas, volatility in energy commodity costs, collateral requirements related to price risk management activity, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, among other factors. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. On May 7, 2009, the CPUC increased the Utility’s short-term borrowing authority by $1.5 billion, for an aggregate authority of $4.0 billion, including $500 million that is restricted to certain contingencies.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, refinance debt, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, and make dividend payments primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital markets.

The following table summarizes PG&E Corporation’s and the Utility’s cash positions:

Restricted cash primarily consists of cash held in escrow pending the resolution of the remaining disputed claims filed in the Utility’s reorganization proceeding under Chapter 11. PG&E Corporation and the Utility maintain separate bank accounts. PG&E Corporation and the Utility primarily invest their cash in money market funds.

The following table summarizes PG&E Corporation’s and the Utility’s outstanding commercial paper and credit facilities at December 31, 2009:

At December 31, 2009, PG&E Corporation and the Utility were in compliance with all covenants under these revolving credit facilities. (See Note 4 of the Notes to the Consolidated Financial Statements for further detail.)

The following table summarizes PG&E Corporation’s and the Utility’s debt issuances in 2009:

The net proceeds from the various Utility senior notes in 2009 were used to finance capital expenditures and for general working capital and other corporate purposes. The net proceeds from the pollution control bonds were used to repurchase the corresponding series of 2008 pollution control bonds. (See Note 4 of the Notes to the Consolidated Financial Statements for further detail.)

During 2009, PG&E Corporation issued 6,773,290 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan, generating $219 million of cash. The equity issuances, combined with the proceeds from the issuance of $350 million of senior notes and other funds, allowed PG&E Corporation to contribute $718 million of cash to the Utility in 2009 to ensure that the Utility had adequate capital to fund its capital expenditures and to maintain the 52% common equity ratio authorized by the CPUC.

The amount and timing of the Utility’s future financing needs will depend on various factors, including the conditions in the capital markets, the timing and amount of forecasted capital expenditures, and the amount of cash internally generated through normal business operations, among other factors. The Utility’s future financing needs

will also depend on the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay. (See Note 14 of the Notes to the Consolidated Financial Statements.)

PG&E Corporation may issue debt or equity in the future to fund the Utility’s operating expenses and capital expenditures to the extent that internally generated funds are not available. Assuming that PG&E Corporation and the Utility can access the capital markets on reasonable terms, PG&E Corporation and the Utility believe that the Utility’s cash flow from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, and finance future capital expenditures.

As of January 31, 2010, PG&E Corporation’s and the Utility’s credit ratings from Moody’s and Standard & Poor’s (“S&P”) ratings service were as follows:

Moody’s and S&P are nationally recognized credit-rating organizations. These ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. A credit rating is not a recommendation to buy, sell, or hold securities.

The dividend policies of PG&E Corporation and the Utility are designed to meet the following three objectives:

The Boards of Directors of PG&E Corporation and the Utility have each adopted a target dividend payout ratio range of 50% to 70% of earnings. Dividends paid by PG&E Corporation and the Utility are expected to remain in the lower end of the target payout ratio range so that more internal funds are readily available to support each company’s capital investment needs. Each Board of Directors retains authority to change the respective common stock dividend policy and dividend payout ratio at any time, especially if unexpected events occur that would change its view as to the prudent level of cash conservation. No dividend is payable unless and until declared by the applicable Board of Directors.

In addition, the declaration of the Utility’s dividends is subject to the CPUC-imposed conditions that the Utility maintain on average its CPUC-authorized capital structure and that the Utility’s capital requirements, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner, be given first priority.

During 2009, the Utility paid common stock dividends totaling $624 million to PG&E Corporation. During 2009, PG&E Corporation paid common stock dividends of $1.65 per share, totaling $590 million, net of $17 million that was reinvested in additional shares of common stock by participants in the Dividend Reinvestment and Stock Purchase Plan. On December 16, 2009, the Board of Directors of PG&E Corporation declared a dividend of $0.42 per share, totaling $157 million, which was paid on January 15, 2010 to shareholders of record on December 31, 2009. On February 17, 2010, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, payable on April 15, 2010, to shareholders of record on March 31, 2010.

During 2009, the Utility paid cash dividends to holders of its outstanding series of preferred stock totaling $14 million. On December 16, 2009, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock totaling $4 million that was paid on February 15, 2010 to preferred shareholders of record on January 29, 2010. On February 17, 2010, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock, payable on May 15, 2010, to shareholders of record on April 30, 2010.

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.

The Utility’s cash flows from operating activities for 2009, 2008, and 2007 were as follows:

During 2009, net cash provided by operating activities increased $138 million compared to the same period in 2008, primarily due to the collection of $821 million in rates to recover an under-collection in the Utility’s energy resource recovery balancing account that was incurred in 2008 due to higher than expected energy procurement costs. (See Note 3 of the Notes to the Consolidated Financial Statements.) The increase in operating cash flows also reflects a decline of $520 million in net collateral paid by the Utility related to price risk management activities in 2009. Collateral payables and receivables are included in Other changes in noncurrent assets and liabilities, Other current assets, and Other current liabilities in the table above. (See Note 10 of the Notes to the Consolidated Financial Statements.) Operating cash flows in 2009 were also favorably impacted by an increase of $75 million due to the timing and amount of various tax settlements and payments. (See Note 9 of the Notes to the Consolidated Financial Statements for further discussion.)

Increases in operating cash flows in 2009 were partially offset by a $700 million payment to the California Power Exchange to reduce the Utility’s liability for the remaining net disputed claims (see Note 14 of the Notes to the Consolidated Financial Statements), a refund of $230 million received by the Utility in 2008 from the California Energy Commission with no similar refund in 2009, and the subsequent return of this $230 million refund to customers in 2009 (see Note 3 of the Notes to the Consolidated Financial Statements).

During 2008, net cash provided by operating activities increased by $225 million compared to the same period in 2007, primarily due to an increase in net income tax refunds received of $689 million and an increase of $230 million for a refund received by the Utility from the California Energy Commission with no similar refund in 2007. These increases in operating cash flows were partially offset by an increase of $459 million in net collateral paid by the Utility related to price risk management activities in 2008 reflecting declining natural gas prices.

Various factors can affect the Utility’s future operating cash flows, including the timing of cash collateral payments and receipts related to price risk management activity. The Utility’s cash collateral activity will fluctuate based on changes in the Utility’s net credit exposure to counterparties, which primarily depends on electricity and gas price movement. The Utility’s operating cash flows also will be impacted by electricity procurement costs and the timing of rate adjustments authorized to recover these costs. The CPUC has established a balancing account mechanism to adjust the Utility’s electric rates whenever the forecasted aggregate over-collections or under-collections of the Utility’s electric procurement costs for the current year exceed 5% of the Utility’s prior-year generation revenues, excluding generation revenues for DWR contracts.

The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in investing activities depends primarily upon the amount and timing of the Utility’s capital expenditures, which can be affected by many factors, including the timing of regulatory approvals, the occurrence of storms and other events causing outages or damages to the Utility’s infrastructure, and the completion of electricity and natural gas reliability improvement projects.

Net cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of the nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility makes contributions to trust funds to provide for the eventual decommissioning of each nuclear unit.

The Utility’s cash flows from investing activities for 2009, 2008, and 2007 were as follows:

Net cash used in investing decreased by $296 million in 2009 compared to 2008, primarily due to a $700 million decrease in the restricted cash balance that resulted from a payment to the California Power Exchange to reduce the Utility’s liability for the remaining net disputed claims (see Note 14 of the Notes to the Consolidated Financial Statements), partially offset by an increase of $330 million in capital expenditures. Net cash used in investing activities increased $975 million in 2008 compared to 2007, primarily due to an increase of $860 million in 2008 of capital expenditures. The increase in capital expenditures for both 2009 and 2008 as compared to the prior year was for installing the SmartMeter™ advanced metering infrastructure, generation facility spending, replacing and expanding gas and electric distribution systems, and improving the electric transmission infrastructure. (See “Capital Expenditures” below.)

Future cash flows used in investing activities are largely dependent on expected capital expenditures. (See “Capital Expenditures” below for further discussion of expected spending and significant capital projects.)

The Utility’s cash flows from financing activities for 2009, 2008, and 2007 were as follows:

In 2009, net cash provided by financing activities decreased by $63 million compared to 2008. In 2008, net cash provided by financing activities increased by $590 million compared to 2007. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

With the exception of dividend payments, interest, common stock issuance, the senior note issuance of $350 million in March 2009, net tax refunds of $189 million, and transactions between PG&E Corporation and the Utility, PG&E Corporation had no material cash flows on a stand-alone basis for the years ended December 31, 2009, 2008, and 2007.

The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 2009.

As shown in the table above, the Utility’s commitments under the many renewable power purchase agreements that the Utility has entered into are expected to grow significantly, assuming that the facilities are timely developed. These costs are expected to be passed on to customers through rate adjustments.

The contractual commitments table above excludes potential commitments associated with the conversion of existing overhead electric facilities to underground electric facilities. At December 31, 2009, the Utility was committed to spending approximately $237 million for these conversions. These funds are conditionally committed depending on the timing of the work, including the schedules of the respective cities, counties, and telephone utilities involved. The Utility expects to spend approximately $40 million to $80 million each year in connection with these projects. Consistent with past practice, the Utility expects that these capital expenditures will be included in rate base as each individual project is completed and recoverable in rates charged to customers.

The contractual commitments table above also excludes potential payments associated with unrecognized tax benefits. Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amount and period of future payments to major tax jurisdictions related to unrecognized tax benefits. Matters relating to tax years that remain subject to examination are discussed in Note 9 of the Notes to the Consolidated Financial Statements.

The Utility’s capital expenditures for property, plant, and equipment totaled $3.9 billion in 2009, $3.7 billion in 2008, and $2.8 billion in 2007. The Utility expects that capital expenditures will total approximately $4.0 billion or more in 2010. The amount of capital expenditures differs from the amount of rate base additions used for regulatory purposes primarily because capital expenditures are not added to rate base until the assets are placed in service. In addition, the difference can be affected by the varying amounts or rates of depreciation used for regulatory and accounting purposes. The Utility’s weighted average rate base in 2009 was $19.8 billion. Based on the estimated capital expenditures for 2010, the Utility projects a weighted average rate base of approximately $21.4 billion for 2010. The Utility forecasts that it will make various capital investments in its electric and natural gas transmission and distribution infrastructure to maintain and improve system reliability, safety, and customer service; to extend the life of or replace existing infrastructure; and to add new infrastructure to meet already authorized growth. The CPUC authorized most of the Utility’s revenue requirements to recover forecasted capital expenditures in multi-year GRCs and gas transmission and storage rate cases. The FERC authorizes revenue requirements to recover forecasted capital expenditures related to electric transmission operations in TO rate cases. (See “Regulatory Matters” below.)

The CPUC authorizes most of the Utility’s revenue requirements to recover forecasted capital expenditures in multi-year GRCs and gas transmission and storage rate cases. In addition, from time to time, the CPUC authorizes the Utility to collect additional revenue requirements to recover capital expenditures related to specific projects that the CPUC has approved. For example, in 2009 the Utility incurred capital costs of approximately $490 million to install advanced meters and approximately $350 million for new generation facilities that are expected to become operational in 2010. As discussed below, the Utility has requested CPUC approval for other capital projects, such as the Utility’s proposal to implement a distribution reliability improvement program and to develop new generation facilities. The FERC authorizes revenue requirements to recover forecasted capital expenditures related to electric transmission operations in TO rate cases. (See “Regulatory Matters” below.)

The Utility’s ability to invest in its electric and natural gas systems and develop new generation facilities is subject to many risks, including risks related to securing adequate and reasonably priced financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. (See “Risk Factors” below.)

PROPOSED ELECTRIC DISTRIBUTION RELIABILITY PROGRAM (CORNERSTONE IMPROVEMENT PROGRAM)

The Utility has requested that the CPUC approve a proposed electric distribution reliability improvement program, including initiatives designed to decrease the frequency and duration of electricity outages in order to bring the Utility’s reliability performance closer to that of other investor-owned electric utilities and provide other reliability benefits. The Utility forecasts that it would incur approximately $2 billion of capital expenditures and $59 million of operating and maintenance expenses to implement the program. The Utility has requested that the CPUC authorize the Utility to recover these forecast costs beginning in 2011 and continuing through 2016. The CPUC’s hearings to determine whether major capital expenditures are necessary to maintain or improve distribution reliability and, if necessary, to determine the extent and timing of such expenditures, were concluded in August 2009.

It is anticipated that the CPUC will issue a final decision during the second quarter of 2010.

The Utility’s CPUC-approved long-term electricity procurement plan, covering 2007 through 2016, forecasts that the Utility will need to obtain an additional 800 to 1,200 megawatts (“MW”) of new generation resources by 2015 above the Utility’s planned additions of renewable resources, energy efficiency, demand reduction programs, and previously approved contracts for new generation resources. Due to the cancellation of two projects selected in its 2004 request for offers (“RFOs”) for new long-term generation resources, the Utility was authorized to increase the new generation resource need to obtain 1,112 to 1,512 MW. The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources only through purchase and sale agreements (“PSAs”) (i.e., a PSA is a “turnkey” arrangement in which a new generating facility is constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements). The utilities are prohibited from submitting offers for utility-built generation in their respective RFOs until questions can be resolved about how to compare utility-owned generation offers with offers from independent power producers. The utilities are permitted to propose utility-owned generation projects through a separate application outside of the RFO process in the following circumstances: (1) to mitigate

market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources (such as renewable energy sources), (3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement), and (4) to meet unique reliability needs.

On September 30, 2009, the Utility requested that the CPUC approve several agreements executed by the Utility following the completion of its April 1, 2008 RFOs of new long-term generation resources to meet customer demand as forecasted in the Utility’s 2007–2016 long-term electricity procurement plan previously approved by the CPUC. One of the agreements submitted to the CPUC proposes that a 586 MW natural gas-fired facility be developed and constructed by a third party and then transferred to the Utility after commercial operation begins. The proposed facility would be operationally flexible, enabling the Utility to increase its use of renewable power by balancing the fluctuating output of wind and solar resources. The facility is proposed to be built in Oakley, California and completed in 2014. (The remaining agreements submitted to the CPUC are power purchase agreements.)

In February 2009, the Utility applied to the CPUC for approval of the Utility’s proposed five-year program to develop up to 500 MW of renewable generation resources based on solar photovoltaic (“PV”) technology. The program would include the development of 250 MW of utility-owned PV facilities at an estimated capital cost of approximately $1.5 billion. The Utility also proposed to enter into power purchase agreements for the remaining 250 MW of PV generation to be developed by independent power producers. On January 26, 2010, a proposed decision was issued recommending that the Utility be authorized to build up to 50 MW of PV facilities per year for each of the five years of the program and that the Utility be allowed to recover project costs based on the weighted average price of the winning bids received in response to the Utility’s RFO for power purchase agreements under the program, subject to an overall price cap. If adopted by the CPUC, the Utility would be unable to include the new utility-owned PV facilities in rate base. Instead of earning an ROE, the Utility’s revenue requirement for recovery of the cost of developing any utility-owned facilities would depend on the amount of power produced by the utility-owned PV facilities and the applicable weighted average price of winning bids received in response to annual program RFOs. The Utility would not be required to build any of the authorized utility-owned capacity under the proposed decision, but rather would elect annually whether to build utility-owned facilities after the applicable weighted average winning bid price had been determined. An alternate proposed decision that also was issued on January 26, 2010 contains similar recommendations. The Utility continues to believe that traditional rate-base treatment would be appropriate. The CPUC is expected to issue a final decision during the first quarter of 2010.

Additionally, on December 3, 2009, the Utility filed an application with the CPUC requesting approval to acquire and operate a wind project to be developed and constructed by Iberdrola Renewables, Inc. in Southern California. The proposed project would have a capacity of up to 246 MW with a guaranteed minimum capacity of 189 MW. The final size of the project would depend upon permitting requirements, completion of land rights acquisition, and turbine supply. Assuming the project is built to its full capacity of 246 MW, the Utility estimates it would incur capital costs of approximately $900 million. The project is targeted to become operational as early as December 2011. A CPUC decision is expected by the end of 2010.

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources.

The Utility is subject to substantial regulation. Set forth below are matters pending before the CPUC, FERC, and the NRC. The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s results of operations or financial condition.

In the Utility’s last GRC, the CPUC authorized the Utility’s revenue requirements for 2007 through 2010 for its basic business and operational costs related to its electric and natural gas distribution and electric generation operations. On December 21, 2009, the Utility filed its 2011 GRC application. The Utility is requesting that the CPUC authorize the amount of base revenues that the Utility may collect from customers to recover its costs for electric and natural gas distribution operations and electric generation operations for a three-year period (2011 through 2013). The Utility’s request represents a proposed revenue

increase for 2011 of $1.1 billion, or 6.4%, above the 2010 total revenue forecast. The critical driver of the Utility’s request in this 2011 GRC will be the need to invest in energy infrastructure to meet customers’ expectations for service quality. The Utility estimates that it will need to spend an average of about $2.7 billion in capital expenditures annually on these infrastructure improvements, especially replacement of gas and electric systems that are reaching the end of their useful lives. The Utility also needs adequate funds to continue to safely operate, maintain, and upgrade generation plants to serve growing demand.

The Utility also has proposed that the CPUC establish balancing accounts for several categories of costs that are subject to a high degree of volatility based on economic conditions and other factors, including new customer connections, emergency service restoration, uncollectible accounts, and employee health care costs.

The Utility also has requested that the CPUC establish a ratemaking mechanism for 2012 and 2013 designed to increase the Utility’s authorized revenues in years between GRCs to reflect increases in rate base due to capital investments in infrastructure and increases in wages and expenses. The proposed mechanism also would require revenue requirements to be adjusted to reflect changes in franchise, payroll, income, or property tax rates, as well as new taxes or fees imposed by governmental agencies. The Utility estimates that this mechanism would result in a revenue requirement increase of $275 million in 2012 and an additional increase of $343 million in 2013. The Utility will advise the CPUC of the actual amount of these proposed increases in October 2011 and October 2012 for the years 2012 and 2013, respectively.

The Utility requested that the CPUC issue a final decision by the end of 2010. If the decision is delayed, the Utility will, consistent with CPUC practice in prior GRCs, request the CPUC to issue an order directing that the authorized revenue requirement changes be effective January 1, 2011, even if the decision is issued subsequent to that date.

PG&E Corporation and the Utility are unable to predict what amount of revenue requirements the CPUC will authorize for the period from 2011 through 2013, when a final decision in this proceeding will be received, or how the final decision will impact their financial condition or results of operations.

On September 18, 2009, the Utility filed an application with the CPUC to initiate the Utility’s 2011 Gas Transmission and Storage rate case so that the CPUC can determine the rates and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2011. The rates and terms and conditions of the Utility’s gas transmission and storage services for 2008 through 2010 were set by the terms of a CPUC-approved all-party settlement agreement known as the Gas Accord IV that was approved by the CPUC in September 2007. The Utility proposes to continue a majority of the Gas Accord IV’s terms and conditions of natural gas transportation and storage services.

The Utility has requested that the CPUC approve a 2011 natural gas transmission and storage revenue requirement of $529.1 million, an increase of $67.3 million over the 2010 adopted revenue requirement. The Utility also seeks attrition increases for 2012, 2013, and 2014 of $32.4 million, $30.7 million, and $22.6 million, respectively.

Under the Utility’s proposal, a substantial portion of the authorized revenue requirements — primarily those costs allocated to residential and small commercial customers (called “core” customers) — would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility has proposed to simplify the current rate structure by, among other changes, setting rates for core and non-core customers based on forecast demand. The Utility’s ability to recover its remaining revenue requirements would continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. To reduce the Utility’s financial risk associated with these factors, the Utility has proposed to share equally with customers any under-collection or over-collection of natural gas transmission and storage revenue requirements. The Utility has proposed additional cost recovery mechanisms for costs that are difficult to forecast, such as the cost of electricity used to operate natural gas compressor stations and costs to comply with GHG regulations.

The Utility has requested that the CPUC issue a final decision by the end of 2010. If the CPUC does not issue a final decision by the end of 2010 to approve new rates effective January 1, 2011, the September 2007 CPUC decision approving the Gas Accord IV provides that the rates and terms and conditions of service in effect as of December 31, 2010 will remain in effect, with an automatic 2% escalation in rates, for local transmission only, as of January 1, 2011.

The Utility generally files a TO rate case every year to request that the FERC authorize the Utility to collect an annual retail transmission revenue requirement at rates based on the Utility’s forecast of customer demand for the particular rate case year. The Utility’s ability to recover the FERC-authorized revenue requirement is subject to the actual volume of electricity sales for the particular rate case year. The Utility is typically able to collect the proposed new rates based on the amount of the requested annual revenue requirement before the FERC issues a decision authorizing new rates. The rates collected before the FERC issues a decision are subject to refund to customers.

On June 18, 2009, the FERC approved a settlement that sets the Utility’s annual retail transmission base revenue requirement at $776 million, effective March 1, 2009. As part of the settlement, the Utility will refund any over-collected amounts to customers, with interest, through an adjustment to rates in 2011.

On July 30, 2009, the Utility filed an application with the FERC requesting an annual retail transmission revenue requirement of $946 million. The proposed rates represent an increase of $170 million over current authorized revenue requirements. On September 30, 2009, the FERC accepted the Utility’s application making the proposed rates effective March 1, 2010 subject to refund following the conclusion of hearings and the outcome of judge-supervised settlement discussions.

The CPUC established a ratemaking mechanism to provide incentives to the California investor-owned utilities to meet the CPUC’s energy savings goals through implementation of the utilities’ energy efficiency programs. As originally established, this mechanism was intended to apply to the 2006 through 2008 and 2009 through 2011 program cycles. In January 2009, the CPUC established a new rulemaking proceeding to modify the mechanism for energy efficiency programs in 2009 and future years. It is uncertain what modifications will ultimately be adopted by the CPUC.

On December 17, 2009, in accordance with the existing mechanism, the CPUC awarded the Utility incentive revenues of $33.4 million based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. (This amount is in addition to incentive revenues of $41.5 million awarded by the CPUC to the Utility in December 2008 based on the Utility’s 2006 through 2007 program performance.) Consistent with the incentive award process previously adopted by the CPUC, the CPUC held back an additional $40.3 million of incentive revenues. The additional amount of incentive revenues that the Utility could receive, if any, will be determined after final energy savings for the 2006 through 2008 program cycle are verified and the true-up process is completed in 2010. The CPUC adopted a schedule for the final true-up process that calls for a final decision by the end of 2010.

With respect to the utilities’ 2009 through 2011 energy efficiency programs, the CPUC issued a decision on September 24, 2009 that changed the program cycle to cover 2010 through 2012. The CPUC also authorized the Utility to continue to collect the bridge funding for its 2009 programs and authorized the Utility to collect $1.3 billion to fund its 2010 through 2012 programs, a 42% increase over the amount authorized for the 2006 through 2008 programs. The CPUC has not yet determined how the existing incentive mechanisms will be modified. Therefore, the amount of incentive revenues the Utility may earn for implementation of its energy efficiency programs in 2009 and future years, if any, is uncertain.

The NRC oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay. NRC regulations require extensive monitoring and review of the safety, radiological, environmental, and security aspects of these facilities. The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. On November 24, 2009, the Utility filed an application to request the NRC to renew each of the operating licenses for Diablo Canyon for 20 years, until November 2044 for Unit 1 and August 2045 for Unit 2, citing a critical need in California for the long-term supply of clean, affordable, and reliable electricity. The license renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. On January 29, 2010, the Utility requested that the CPUC authorize the Utility to recover in rates the costs of seeking license renewal. The Utility currently estimates that it will incur $85 million through 2014 in connection with the relicensing process.

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” below.) These laws and requirements relate to a broad

range of the Utility’s activities, including the discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions.

PG&E Corporation and the Utility believe the link between man-made GHG emissions and global climate change is clear and convincing and that mandatory GHG reductions are necessary. PG&E Corporation and the Utility believe the development of a market-based cap-and-trade system, in conjunction with successful energy efficiency and demand-side management programs and the development of renewable energy resources, can reduce GHG emissions while diversifying energy supply resources and minimizing costs to customers. Various laws and regulations addressing climate change and GHG emissions are being considered at the state, federal, and regional levels. Several contentious issues must be resolved before a state, regional, or national cap-and-trade program for emission allowances can be established, including determining whether emission allowances should be auctioned or freely allocated to the utilities to reduce customer costs, whether price caps or collars should be established for emission allowances, the use of emission offsets, and how any auction revenues or other value should be used.

The California Global Warming Solutions Act of 2006 (“AB 32”) requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. The California Air Resources Board (“CARB”) has been authorized to monitor and enforce compliance with AB 32. In December 2008, the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target. These recommendations include implementing a 33% renewable portfolio standard (“RPS”) by 2020, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program. The CARB is required to adopt regulations to implement the scoping plan no later than January 1, 2011 to become effective on January 1, 2012.

In November 2009, the CARB issued preliminary draft regulations to establish a cap-and-trade program that would set a declining ceiling on GHG emissions and allow companies to buy and sell emission allowances or offsets to meet it. For the electric sector, the CARB proposes to assign responsibility to acquire emission allowances or offsets to the generator for in-state power and to the entity that holds title to the electricity for imports into California. For the natural gas sector, the CARB will consider assigning responsibility to acquire emission allowances or offsets to the local gas distribution company with respect to the emissions of small commercial and residential natural gas consumers beginning in 2012 instead of 2015 as the CARB had originally contemplated. The owners of natural gas compressor stations would also be responsible for compliance. Although the CARB has not yet addressed the allocation of emission allowances, in December 2009, an advisory committee to the CARB, the Economic and Allocation Advisory Committee (“EAAC”), recommended that the utilities be required to pay for emission allowances rather than receive all or a portion of such allowances for free. The Utility estimates that its additional compliance costs to acquire emission allowances to meet its compliance obligations and procure electricity at market prices that reflect the supplier’s cost of emission allowances, could total approximately $1 billion per year beginning in 2012. This estimate assumes a market price for emissions allowances of $30 per metric tonne and that the Utility is not freely allocated some or all of its emission allowances to reduce customer costs as recommended by the EAAC. This estimate is based on the Utility’s forecasts of customer demand and levels of Utility-owned nuclear and hydroelectric generation and assumes average weather conditions. The Utility expects that these increased costs would be included in the Utility’s cost of electricity that is passed through to customers or be recovered in rates as reasonable costs of complying with environmental regulations and mandates. The CARB is scheduled to issue final regulations in October 2010. The ultimate financial impact of a cap-and-trade system will depend on the final form of regulations adopted by the CARB, the actual market price of emissions allowances, and the resolution of the issues discussed above.

While proposed legislation is being considered at the federal level, the Environmental Protection Agency (“EPA”), charged with implementation and enforcement of the Clean Air Act, released a final ruling in December 2009, finding that GHG emissions cause or contribute to air pollution that endangers public health and welfare. It is expected that the EPA will adopt regulations to establish new thresholds for GHG emissions from vehicles and that the EPA will propose regulations that would apply to new or existing industrial facilities, power plants, and other stationary sources. At the regional level, the Western Climate Initiative (“WCI”), comprising seven states — including California — and four Canadian provinces, has proposed to establish a regional cap-and-trade program to reduce GHG emissions beginning in 2012. California has indicated that it seeks to participate in the WCI, but it has also indicated that it will proceed with AB 32 implementation regardless of whether the WCI cap-and-trade program is implemented.

The Utility has voluntarily reported its GHG emissions to the California Climate Action Registry (“CCAR”) on an annual basis since 2002. In 2009, the Utility also voluntarily reported its 2008 GHG emissions to The Climate Registry (“TCR”), a new non-profit organization that is developing consistent reporting and measurement standards across industry sectors in North America. In 2009, the Utility also began reporting its GHG emissions to the CARB as required by AB 32. The EPA also has adopted regulations that require qualifying GHG-emitting facilities to submit annual GHG emissions reports beginning in 2011. PG&E Corporation and the Utility provide detailed GHG emissions data in their annual Corporate Responsibility Report, available on their websites. As a result of the time necessary for a thorough third-party verification of the Utility’s GHG emissions in accordance with the highest standards developed by the CCAR and TCR, preliminary emissions data for 2008 is the most recent data available. Preliminary emissions data for 2008 is also contained in PG&E Corporation’s and the Utility’s Annual Report on Form 10-K for the year ended December 31, 2009.

During 2009, the Utility continued its programs to develop strategies to mitigate the impact of the Utility’s operations on the environment (including customer energy usage) and to develop its strategy to plan for the actions it will need to take to adapt to likely impacts that climate change will have on the Utility’s future operations. With respect to electric operations, climate scientists project that climate change will lead to increased electricity demand due to more extreme and frequent hot weather events and reduced hydroelectric generation due to reductions in snowpack in the Sierra Nevada. The Utility is analyzing and exploring a combination of operating changes to its hydroelectric system that may include, but are not limited to, higher winter carryover reservoir storage levels, reduced conveyance flows in canals and flumes during winter storm periods, reduced discretionary reservoir releases during the late spring and summer period, and increased sediment releases from diversion dams. If the Utility’s future hydroelectric generation is reduced due to drought conditions or climate change, the Utility might have to replace some of this electricity from other sources, including natural gas. The amount of fossil-fueled generation needed to replace decreased hydroelectric generation can be reduced if renewable resources, such as geothermal and biomass, are timely developed. (See “Capital Expenditures” above for a description of the Utility’s efforts to invest in renewable resources.)

With respect to natural gas operations, the Utility has taken voluntary proactive steps to reduce the release of methane, a GHG released as part of the delivery of natural gas.

The Utility’s strategies to reduce GHG emissions — such as offering energy efficiency and demand response programs for customers, infrastructure improvements, and the support of renewable energy development — are also effective strategies for adapting to the expected increased demand for electricity in extreme hot weather events likely to be caused by climate change. PG&E Corporation and the Utility are also assessing the benefits and challenges associated with various climate change policies, identifying how a comprehensive program can be structured to mitigate overall costs to customers and the economy as a whole, as well as to ensure that the environmental objectives of the program are met.

In addition, there is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the California Water Resources Control Board (“Water Board”), the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If either of the final regulations adopted by the EPA or the Water Board requires the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. (See Note 16 of the Notes to the Consolidated Financial Statements for more information.)

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under environmental laws. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances at former manufactured gas plant (“MGP”) sites; power plant sites; and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site. In particular, the Utility has a program, in cooperation with environmental agencies and third-party owners, to evaluate and take appropriate action to mitigate any potential environmental concerns posed by certain former MGP sites within the Utility’s service territory. As part of this program, the Utility recently contacted the owners of property located on three former MGP sites in urban, residential areas of San Francisco to offer to test the soil for

residues, and depending on the results of such tests, to take appropriate remedial action. Until the Utility’s investigation of these MGP sites in San Francisco is complete, the extent of the Utility’s obligation to remediate is established, and any appropriate remedial actions are determined, the Utility is unable to determine the amounts it may spend in the future to remediate these sites and no amounts have been accrued for these sites (other than investigative costs). Although it is reasonably possible that the Utility will incur losses in the future related to these sites, the Utility is unable to reasonably estimate the amount of such loss. The Utility expects that it will recover 90% of the costs to remediate MGP sites under a ratemaking mechanism established by the CPUC. The Utility will seek to recover remaining costs through insurance. (See “Risk Factors” and “Critical Accounting Policies” below, as well as Note 16 of the Notes to the Consolidated Financial Statements, for a discussion of estimated environmental remediation liabilities.)

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. (See Note 16 of the Notes to the Consolidated Financial Statements for a discussion of the accrued liability for legal matters.)

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electricity transmission, natural gas transportation, and storage; other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.

The Utility actively manages market risks through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.

The Utility is exposed to commodity price risk as a result of its electricity procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings but may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

The Utility’s natural gas transportation and storage costs for non-core customers may not be fully recoverable. The Utility is subject to price and volumetric risk for the portion of intrastate natural gas transportation and storage capacity that has not been sold under long-term contracts providing for the recovery of all fixed costs through the collection of fixed reservation charges. The Utility sells most of its capacity based on the volume of gas that the Utility’s customers actually ship, which exposes the Utility to volumetric risk.

The Utility uses value-at-risk to measure the shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services that could impact revenues due to changes in market prices and customer demand. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. Value-at-risk uses market data to quantify the Utility’s price exposure. When market data is not available, the Utility uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.

The Utility’s value-at-risk calculated under the methodology described above was approximately $12

million at December 31, 2009. The Utility’s high, low, and average values-at-risk during the 12 months ended December 31, 2009 were approximately $17 million, $9 million, and $14 million, respectively.

See Note 10 of the Notes to the Consolidated Financial Statements for further discussion of price risk management activities.

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2009, if interest rates changed by 1% for all current PG&E Corporation and the Utility variable rate and short-term debt and investments, the change would have an immaterial impact to net income over the next 12 months.

The Utility conducts business with counterparties mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. If a counterparty failed to perform on its contractual obligation to deliver electricity or gas, then the Utility may find it necessary to procure electricity or gas at current market prices, which may be higher than the contract prices.

The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility ties many energy contracts to master commodity enabling agreements that may require security (referred to as “Credit Collateral” in the table below). Credit Collateral may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Credit Collateral or performance assurance may be required from counterparties when current net receivables and replacement cost exposure exceed contractually specified limits.

The following table summarizes the Utility’s net credit risk exposure to its counterparties, as well as the Utility’s credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of December 31, 2009 and 2008:


Financial Highlights		7

Comparison of Five-Year Cumulative Total Shareholder Return		8

Selected Financial Data		9

Management’s Discussion and Analysis		10

PG&E Corporation and Pacific Gas and Electric Company Consolidated Financial Statements		49

Notes to the Consolidated Financial Statements		59

Quarterly Consolidated Financial Data		112

Management’s Report on Internal Control Over Financial Reporting		113

Report of Independent Registered Public Accounting Firm		114


(unaudited, in millions, except share and per share amounts)	2009			2008
Operating Revenues	$	13,399		$	14,628
Income Available for Common Shareholders
Earnings from operations⁽¹⁾		1,223			1,081
Items impacting comparability⁽²⁾		(3	)		257
Reported consolidated income available for common shareholders		1,220			1,338
Income Per Common Share, diluted
Earnings from operations⁽¹⁾		3.21			2.95
Items impacting comparability⁽²⁾		(0.01	)		0.68
Reported consolidated net earnings per common share, diluted		3.20			3.63
Dividends Declared Per Common Share		1.68			1.56
Total Assets at December 31,	$	42,945		$	40,860
Number of common shares outstanding at December 31,		371,272,457			362,346,685


(in millions, except per share amounts)	2009		2008		2007		2006		2005
PG&E Corporation⁽¹⁾ For the Year
Operating revenues	$	13,399	$	14,628	$	13,237	$	12,539	$	11,703
Operating income		2,299		2,261		2,114		2,108		1,970
Income from continuing operations		1,234		1,198		1,020		1,005		920
Earnings per common share from continuing operations, basic		3.25		3.23		2.79		2.78		2.37
Earnings per common share from continuing operations, diluted		3.20		3.22		2.78		2.76		2.34
Dividends declared per common share⁽²⁾		1.68		1.56		1.44		1.32		1.23
At Year-End
Book value per common share⁽³⁾	$	26.68	$	24.64	$	22.91	$	21.24	$	19.94
Common stock price per share		44.65		38.71		43.09		47.33		37.12
Total assets		42,945		40,860		36,632		34,803		34,074
Long-term debt (excluding current portion)		10,381		9,321		8,171		6,697		6,976
Rate reduction bonds (excluding current portion)		–		–		–		–		290
Energy recovery bonds (excluding current portion)		827		1,213		1,582		1,936		2,276
Noncontrolling interest – preferred stock of subsidiary		252		252		252		252		252

Pacific Gas and Electric Company For the Year
Operating revenues	$	13,399	$	14,628	$	13,238	$	12,539	$	11,704
Operating income		2,302		2,266		2,125		2,115		1,970
Income available for common stock		1,236		1,185		1,010		971		918
At Year-End
Total assets		42,709		40,537		36,310		34,371		33,783
Long-term debt (excluding current portion)		10,033		9,041		7,891		6,697		6,696
Rate reduction bonds (excluding current portion)		–		–		–		–		290
Energy recovery bonds (excluding current portion)		827		1,213		1,582		1,936		2,276


	Year ended December 31,
(in millions)	2009			2008			2007
Utility
Electric operating revenues	$	10,257		$	10,738		$	9,481
Natural gas operating revenues		3,142			3,890			3,757
Total operating revenues		13,399			14,628			13,238
Cost of electricity		3,711			4,425			3,437
Cost of natural gas		1,291			2,090			2,035
Operating and maintenance		4,343			4,197			3,872
Depreciation, amortization, and decommissioning		1,752			1,650			1,769
Total operating expenses		11,097			12,362			11,113
Operating income		2,302			2,266			2,125
Interest income		33			91			150
Interest expense		(662	)		(698	)		(732	)
Other income, net		59			28			52
Income before income taxes		1,732			1,687			1,595
Income tax provision		482			488			571
Net income		1,250			1,199			1,024
Preferred stock dividend requirement		14			14			14
Income Available for Common Stock	$	1,236		$	1,185		$	1,010
PG&E Corporation, Eliminations, and Other⁽¹⁾
Operating revenues	$	–		$	–		$	(1	)
Operating expenses		3			5			10
Operating loss		(3	)		(5	)		(11	)
Interest income		–			3			14
Interest expense		(43	)		(30	)		(30	)
Other income (expense), net		8			(32	)		(9	)
Loss before income taxes		(38	)		(64	)		(36	)
Income tax benefit		(22	)		(63	)		(32	)
Loss from continuing operations		(16	)		(1	)		(4	)
Discontinued operations⁽²⁾		–			154			–
Net income (loss)	$	(16	)	$	153		$	(4	)
Consolidated Total
Operating revenues	$	13,399		$	14,628		$	13,237
Operating expenses		11,100			12,367			11,123
Operating income		2,299			2,261			2,114
Interest income		33			94			164
Interest expense		(705	)		(728	)		(762	)
Other income (expense), net		67			(4	)		43
Income before income taxes		1,694			1,623			1,559
Income tax provision		460			425			539
Income from continuing operations		1,234			1,198			1,020
Discontinued operations⁽²⁾		–			154			–
Net income		1,234			1,352			1,020
Preferred stock dividend requirement of subsidiary		14			14			14
Income Available for Common Shareholders	$	1,220		$	1,338		$	1,006


(in millions)	2009			2008			2007
Electric revenues	$	12,244		$	12,063		$	11,710
DWR pass-through revenues⁽¹⁾		(1,987	)		(1,325	)		(2,229	)
Total electric operating revenues	$	10,257		$	10,738		$	9,481


	December 31,
(in millions)	2009		2008
PG&E Corporation	$	193	$	167
Utility		334		52
Total consolidated cash and cash equivalents		527		219
Utility restricted cash		633		1,290
Total consolidated cash, including restricted cash	$	1,160	$	1,509


(in millions)	Issue Date	Amount
PG&E Corporation
Senior Notes
5.75%, due 2014	March 12	$	350
Utility
Senior Notes
6.25%, due 2039	March 6		550
Floating rate, due 2010	June 11		500
5.40%, due 2040	November 18		550
Total Utility senior notes			1,600
Pollution control bonds
Series 2009 A and B, variable rates, due 2026	September 1		149
Series 2009 C and D, variable rates, due 2016	September 1		160
Total pollution control bonds			309
Total Utility debt			1,909
Total debt issuances in 2009		$	2,259


	Moody’s	S&P
Utility
Corporate credit rating	A3	BBB+
Senior unsecured debt	A3	BBB+ to A-2
Credit facility	A3	BBB+
Pollution control bonds backed by letters of credit	Not rated to Aaa/VMIG1	AA-/A-1+ to AAA/A-1+
Pollution control bonds backed by bond insurance	A3	BBB+ to A
Pollution control bonds – nonbacked	A3	BBB+
Preferred stock	Baa2	BBB-
Commercial paper program	P-2	A-2
PG&E Energy Recovery Funding LLC
Energy recovery bonds	Aaa	AAA
PG&E Corporation
Corporate credit rating	Baa1	BBB+
Convertible subordinated notes	Baa1	BBB+
Senior unsecured debt	Baa1	BBB
Credit facility	Baa1	Not rated


	Payment due by period
(in millions)	Total		Less Than 1 Year		1–3 Years		3–5 Years		More Than 5 Years
Contractual Commitments:
Utility
Long-term debt⁽¹⁾:
Fixed rate obligations	$	16,141	$	637	$	1,547	$	2,391	$	11,566
Variable rate obligations		1,397		3		956		58		380
Energy recovery bonds⁽²⁾		1,306		435		871		–		–
Purchase obligations:
Power purchase agreements⁽³⁾:
Qualifying facilities		11,163		1,326		2,265		2,006		5,566
Renewable contracts		34,725		626		1,844		2,009		30,246
Irrigation district and water agencies		335		74		132		67		62
Other power purchase agreements		3,234		257		706		666		1,605
Natural gas supply and transportation		1,080		660		212		93		115
Nuclear fuel		1,657		134		178		249		1,096
Pension and other benefits⁽⁴⁾		1,138		280		531		327		–
Capital lease obligations⁽⁵⁾		404		50		100		92		162
Operating leases		119		22		39		32		26
Preferred dividends⁽⁶⁾		70		14		28		28		–
Other commitments		18		18		–		–		–
PG&E Corporation
Long-term debt⁽¹⁾:
Fixed rate obligations		725		310		40		375		–


(in millions)	Gross Credit Exposure Before Credit Collateral⁽¹⁾		Credit Collateral		Net Credit Exposure⁽²⁾		Number of Wholesale Customers or Counterparties >10%	Net Exposure to Wholesale Customers or Counterparties >10%
December 31, 2009	$	202	$	24	$	178	3	$	154
December 31, 2008	$	240	$	84	$	156	2	$	107