2010 Annual Report

Last year will long be remembered as one of the most difficult in our company’s history, as we confronted and worked to overcome formidable challenges. Above all was the September 9 explosion on our natural gas pipeline in San Bruno, California, which tragically claimed eight lives, injured many more, destroyed or damaged dozens of homes, and shook many people’s confidence in PG&E.

There are no words sufficient to fully convey my personal sadness at this tragedy. As we move forward to implement lessons learned from this accident and become a stronger and safer company, I know I can speak for everyone at PG&E when I say that the people whose lives have been impacted continue to be in all our thoughts and prayers.

This accident and other challenges in 2010 have made it clear that we have a long journey ahead to become the industry leader we aspire to be, and our team and I are more determined than ever to do what it takes to reach that goal.

Our pledge is that PG&E will ultimately emerge from this experience not simply as a better company, but rather as a standard-bearer for excellence among utilities. Indeed, we take seriously our responsibility to see that the lessons from this event not only help PG&E reach a new level of performance, but also help others in our industry to do the same.

Most of all, our resolve is focused on raising the standards for the way PG&E manages and operates its natural gas infrastructure. We are also committed to cultivating stronger relationships with our customers—beginning with restoring their trust in the safety and integrity of our system and operating practices.

As we pursue these goals, we are cooperating with our regulators, policy makers, and other stakeholders. As always, though, our success will also depend on the efforts of our 20,000 men and women. Their spirit of service has been the soul of PG&E for more than 100 years, and it has sustained us through the ups and downs that any long-lived company inevitably experiences.

Even amid last year’s challenges, PG&E employees accomplished important goals on behalf of our customers. They re-inspected thousands of miles of natural gas lines in the wake of the San Bruno accident. They restored power following outages more quickly than any time in a decade and reduced the frequency of outages to the lowest level in more than two decades. They safely and efficiently brought two new power plants

into operation. They achieved ambitious sustainability targets for reducing our energy and water use. And they helped our customers realize significant savings through further gains in energy efficiency.

But perhaps most telling, they came forward in overwhelming numbers to help victims of the San Bruno accident, providing PG&E with a strong presence in the community and putting a human face on our commitment to help residents recover and rebuild.

However, without diminishing the importance of these and other individual accomplishments, let it be said clearly that no one on our leadership team was satisfied with the sum of PG&E’s performance in 2010.

The challenges encountered last year raised concerns among our customers, put strains on relationships, and, in some cases, hurt our standing in the eyes of valued stakeholders. Our team is working aggressively to reverse these setbacks and learn from these events.

Importantly, PG&E’s longer-term performance results remain solid. In recent years we have made meaningful strides in areas from reliability and workplace safety to energy efficiency and environmental leadership. And, despite the impact of the challenges in 2010, we have delivered competitive returns for shareholders over the past several years.

This letter presents an overview of last year’s accomplishments and challenges, together with insights into our plans for the current year and beyond as we work to regain our momentum and deliver the level of performance our stakeholders have rightly come to expect.

MAINTAINING SOLID FINANCIAL PERFORMANCE

As we do every year, in 2010 we again strove to see that PG&E continues to represent a solid investment opportunity. We recognize that only by consistently delivering on this requirement can we also see to it that PG&E is able to access new capital on the best terms for our customers and fund the substantial investments necessary to provide service on their behalf.

Once again last year, new capital investments in PG&E’s utility asset base, together with incentives earned by helping customers realize significant energy efficiency savings goals, helped to drive growth in core earnings. However, the financial impacts of the San Bruno accident had an adverse effect on the company’s earnings as

reported in accordance with generally accepted accounting principles (GAAP).

On a GAAP basis, net income after dividends on preferred stock (also called “income available for common shareholders”) was $1.10 billion, or $2.82 per share, for 2010. This compared with $1.22 billion, or $3.20 per share, for 2009.

The year-over-year decline in net income reflected San Bruno-related costs totaling $283 million on a pre-tax basis, or $0.43 per share. These costs included a $220 million provision for property damage, personal injury, and other third-party claims, as well as an additional $63 million in direct costs for providing support to the San Bruno community, re-inspecting natural gas lines, and other activities. Although we expect that most of the costs the utility incurs for third-party claims relating to the accident will ultimately be recovered through insurance, GAAP required us to record a charge equal to the low end of the estimated range for potential liability costs of $220 million to $400 million.

On an earnings from operations basis, a non-GAAP measure adjusted to reflect normal operations and exclude items like the accident-related costs, earnings per share rose 6.5 percent to $3.42, on earnings of $1.33 billion, compared to $3.21 per share, or $1.22 billion, in 2009. (The “Financial Highlights” table on page 7 reconciles GAAP total net income with non-GAAP earnings from operations.) These results were well within the company’s 2010 guidance range of $3.35 per share to $3.50 per share for earnings from operations.

STRENGTHENING THE UTILITY’S INFRASTRUCTURE

We continued to invest substantially in our system last year, deploying $3.9 billion of new capital to expand and improve our gas and electric assets, strengthen safety and reliability, and meet the needs of new customers.

Within our electric distribution and transmission operations, a major focus was continuing to upgrade targeted transmission and distribution circuits and install new equipment to improve reliability. Additionally, we secured regulatory approval to invest an additional $357 million of capital through 2013 for PG&E’s Cornerstone Improvement Program. This program aims to create more capacity and interconnectedness on the power grid, enabling us to better isolate power outages and redirect power flows onto neighboring circuits to restore service more quickly.

We also continued to invest in PG&E’s natural gas system, with an emphasis on retrofitting or replacing older transmission and distribution pipe. This work has been a

long-term priority, and in light of the San Bruno accident, we are accelerating and expanding many plans to reinforce our gas infrastructure.

The focal point for this work going forward is a proposed new 10-year pipeline modernization program, Pipeline 2020. Announced late last year, Pipeline 2020 is one of the most significant initiatives PG&E has ever launched, with ambitious goals and a sweeping scope.

Pipeline 2020 will propose to make targeted investments to test, inspect, and upgrade or replace parts of our transmission pipeline system, and to add remote-controlled or automatic shut-off valves in locations in our system where they can be effective. It will drive advancements in best practices across the industry and also includes funding to support new research into next-generation pipeline inspection technology. In addition, it encompasses efforts to create a new model for coordinating with local first responders and community leaders and increasing pipeline safety awareness.

In the coming months, we plan to share with California regulators our proposals for the first phase of this gas infrastructure modernization work that we believe is important to creating a safer and more reliable energy future for our customers.

In 2010, we also continued to grow PG&E’s conventional electric generation portfolio as we began operations at the new units at our Humboldt Bay Generating Station and the new state-of-the-art Colusa Generating Station. We also received CPUC approval to purchase the Oakley Generating Station, a natural-gas-fired facility that is forecast to be the most efficient power plant of its kind in California when PG&E takes ownership, which is scheduled for 2016.

For the first time in our recent history, we also added renewable generation to our utility-owned portfolio with the inauguration of the Vaca-Dixon photovoltaic solar station. This represents the first major project under our five-year program to develop up to 500 megawatts of clean solar photovoltaic power, 250 megawatts of which will be owned by PG&E. When the entire program is online, we expect that it will provide enough renewable power each year to serve roughly 150,000 homes.

Finally, our Diablo Canyon nuclear power plant continues to provide safe, carbon-free electric power for our customers. As the regulatory process for relicensing this essential facility moves forward, our focus remains on ensuring safe and reliable operations.

Among last year’s most notable accomplishments were settlements reached in PG&E’s 2011 General Rate Case and its 2011 Gas Transmission and Storage Rate Case, both of

which are now before the California Public Utilities Commission. The settlements, if approved, will provide revenue increases that will support critical new investments to enhance and expand service to customers. We also expect to be able to do this while minimizing rate increases for our customers.

IMPROVING OPERATIONAL PERFORMANCE

We continued to focus on improving PG&E’s operational performance last year—a priority that has become even more pressing in view of the San Bruno accident.

Last year’s results included gains in employee safety and service reliability—two benchmarks that we consider to be key barometers of overall operational performance. These results can be attributed to ongoing investments in our system, enhancements in training, and the adoption of improved procedures and practices.

OSHA recordable injuries were reduced by more than 20 percent compared with 2009 levels. We also cut motor vehicle safety incidents. Moreover, the 2010 results represented a continuation of comparably strong improvements in each of the last several years. That said, these gains were not enough to meet the targets we had set for ourselves in 2010.

Similarly, although the company improved electric reliability again last year, the progress fell short of our aggressive targets—even as electric outage duration in 2010 was the shortest in the last decade, and outage frequency was the lowest since 1988.

In 2011, we are redoubling our efforts in both safety and reliability, as is reflected in the higher targets we have once again set for ourselves.

In particular, reinforcing an uncompromising culture of safety will remain a top priority. Serious injuries still occurred far too frequently and two workers lost their lives in preventable accidents last year. This year, we are concentrating our attention on eliminating these most serious incidents, with our eyes still on the ultimate goal of zero injuries.

Closely linked and equally important to employee safety is our commitment and responsibility to public safety.

As noted earlier, we view the San Bruno accident and the findings that have emerged from the investigation thus far as clear signs that we must raise the bar on many of our natural gas system standards and practices. To assist us and leave no stone unturned in these efforts, we have assembled an experienced corps of leading outside advisors who are bringing their collective safety and operations expertise to this critical work. We are also undertaking a global search for an experienced senior gas executive to

become PG&E’s new senior vice president of gas operations. As lessons continue to emerge from the San Bruno accident, our pledge is that we will apply them aggressively to improve our pipeline operations.

ENGAGING WITH CUSTOMERS AND COMMUNITIES

As changes in our industry begin to reshape the utility customer experience, we believe a critical measure of our success will be our ability to engage customers effectively. Already, a growing number of consumers are relying on their energy providers to help them navigate an evolving landscape that includes high-tech smart grid devices, electric vehicles, distributed generation, and new rates based on dynamic pricing. And at least as many others are looking to their utilities to help them find new efficiencies and cope with cost pressures in the face of new economic realities.

We heard clearly from our customers last year that these were opportunities for improvement at PG&E, and we took a number of steps as a result.

Perhaps most significant, we ramped up customer outreach and customer education around PG&E’s program to replace traditional gas and electric meters with 10 million new digital SmartMeter^™ devices. These efforts came in response to concerns from customers and communities over the meters’ accuracy and other issues.

SmartMeter^™ devices offer customers more control over how they use gas and electricity and represent a foundational step toward a smarter grid that will leverage advanced communications, computing, and control technology to provide more affordable, reliable, and cleaner electrical service, as well as support the anticipated growth in electric vehicle use.

A thorough independent study last year confirmed the meters’ precision. However, the study also pointed out a need for additional communications to consumers. We have since increased our outreach in a number of ways. For example, before SmartMeters^™ are installed in any community, PG&E now holds open forums where customers can ask questions and see firsthand the meters’ many advantages.

While we have been encouraged by the positive reception these increased outreach efforts have received in many areas, we are committed to continuing to work with those customers who still have questions about the new technology as we work to complete the program by our 2012 target.

These and other issues last year underscored that, to be fully successful, PG&E must work harder to stay ahead of customer concerns proactively. Indeed, our ability to do this will only become more important going forward.

In 2011, we are focused again on improving overall customer satisfaction, which fell during 2010 as reflected in ratings that were well below our targets. The San Bruno accident and SmartMeter^™ concerns contributed heavily to these declines, as did PG&E’s sponsorship of a controversial state ballot initiative defeated by voters last June. However, we recognize that these were not the only factors. Customers are also sending a signal that they expect PG&E to be more responsive to their service needs in general.

With that in mind, in the second half of last year, we initiated a system-wide listening tour in which PG&E officers and other members of management spent time in the field hearing candid—and sometimes difficult—feedback directly from our customers on a broad range of issues.

This outreach and engagement is continuing in 2011, and we are actively incorporating what we learn to help improve the way we are doing business.

We are also increasing PG&E’s engagement within its communities. In 2010, PG&E employees volunteered 27,500 hours of their time, a 10 percent increase over 2009. They also set a new record for philanthropy through our annual charitable giving drive. And last year we again increased PG&E Corporation’s charitable support in our communities, with contributions exceeding $19.3 million. In 2011, we will aim to build on these efforts once again.

INCREASING EFFICIENCY AND RENEWABLE ENERGY

Even in a year of challenge, PG&E’s commitment to the environment has remained firm. MSCI/RiskMetrics, a leading investment research and advisory firm that evaluates investor risk and value related to sustainability issues, ranked PG&E number one on its 2010 global assessment of environmental attributes of 29 companies in the utility sector. In particular, PG&E was recognized for its low carbon emissions risk, overall sustainability management strategy, and strategic opportunities in renewable power and energy efficiency.

Newsweek magazine named PG&E the greenest utility in the country for the second consecutive year in 2010. We were again named to the Dow Jones Sustainability World Index, one of only five U.S. utilities to earn that distinction. And the Carbon Disclosure Project recognized PG&E as one of the top 10 companies in the S&P 500 for climate change-related disclosure and performance.

Our belief in the importance of environmental leadership has driven performance across our business, most notably in the areas of energy efficiency and renewable energy.

In 2010, our energy efficiency initiatives helped customers save over 250 megawatts of electricity and 23 million therms of natural gas, or the approximate amount of natural gas consumed by tens of thousands of average homes in our service area in one year. We also provided over $170 million in energy efficiency rebates, helping customers save money and providing additional stability to the electric grid through reduced demand.

Through our energy efficiency efforts, the company continued to earn significant incentives under the framework approved by the CPUC in which utilities share in the benefits of energy efficiency savings they help customers achieve. In December 2010, the CPUC awarded PG&E $29.1 million in incentives after a final review and consideration of the savings achieved by the company in its 2006–2008 program cycle, which is credited with saving $1.5 billion in energy costs.

PG&E’s accomplishments were also solid on the renewable energy front. In 2010, we added about 290 megawatts of renewable energy to our supply, helping to increase our renewables deliveries to 17.7 percent of our total energy mix. PG&E also signed additional contracts to buy another 2,000 megawatts of renewable power in the future.

The additions to our supply will help PG&E achieve California’s goals to significantly increase renewable energy deliveries over the next decade. The state’s 33 percent target by 2020 is currently the most ambitious renewable energy goal in the country. Similarly, these efforts will also help the company as it works to meet requirements to reduce greenhouse gas emissions under California’s landmark Global Warming Solutions Act.

As we pursue these goals, we remain fully committed to achieving results in ways that most effectively minimize the costs for utility customers.

LOOKING FORWARD

If, as we said in the opening of this letter, 2010 will be looked back on as a year in which we faced tremendous challenges, we are determined that it will also be remembered as a turning point—a pivotal moment that led us to rethink the way PG&E approaches key aspects of its business and raise its operational performance and service to set a new standard.

This determination will continue to drive us in 2011, and it will shape the way we continue to respond to the challenges that lie ahead.

Our priorities this year will continue to focus above all on the safety and integrity of our operations. As the investigations into the San Bruno tragedy move forward this year, we know we will gain more insights that will

inform our efforts in this area. Our commitment is to apply them aggressively and take the appropriate steps to renew our customers’ confidence in our system and practices.

We also will continue to actively reach out to customers to cultivate stronger relationships built on trust and confidence in PG&E. In everything we are doing today, we are striving to see PG&E through our customers’ eyes and act in ways we would want to be served if we were in their shoes.

By succeeding in these two priorities, we will have a strong foundation to deliver on the responsibility we always have to create value for our investors.

We remain confident that PG&E’s future is as full of opportunity as it has ever been. Even so, we understand that many of our stakeholders are watching closely—and perhaps even cautiously—as we move ahead.

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. The Utility served approximately 5.2 million electric distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2010.

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 primary rate-setting proceeding at the CPUC is the general rate case (“GRC”), which occurs approximately every three years. The primary rate-setting proceeding at the FERC is the electric transmission owner (“TO”) rate case, which occurs every year.

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 determines the capital structure the Utility must maintain (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, including a rate of return on equity (“ROE”). The CPUC has set the Utility’s authorized ROE through 2011 at 11.35%. A change in ROE will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Service utility bond

index increases or decreases by more than 1% as compared to the applicable benchmark. The amount of the Utility’s authorized equity earnings is determined by the 52% equity component, the 11.35% ROE, and the aggregate amount of rate base authorized by the CPUC. The rate of return that the Utility earns on its FERC-jurisdictional rate base is not specifically authorized, but rates are designed to allow the Utility to earn a reasonable rate of return.

The Utility’s ability to recover the revenue requirements authorized by the CPUC in a 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. The Utility’s ability to recover a portion of its 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 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, such as customer energy efficiency goals.

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. 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.

KEY FACTORS AFFECTING RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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:

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The Outcome of Pending Investigations of Natural Gas Explosions and Fires. On September 9, 2010, a Utility-owned natural gas pipeline ruptured in a residential area located in the City of San Bruno, California (“San Bruno accident”) which resulted in the deaths of eight people, injuries to numerous individuals, and extensive property damage. Both the National Transportation Safety Board (“NTSB”) and the CPUC are investigating the San Bruno accident. A cause of the pipeline rupture has not yet been determined. The investigations will examine various aspects of the operating, maintenance, and emergency response practices used in the Utility’s natural gas operations, as well as the Utility’s record-keeping and compliance with pipeline safety regulations. In addition, various civil lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility related to the San Bruno accident. (See “Legal Matters” below.) During 2010, the Utility recorded a total of $283 million of costs associated with the San Bruno accident, including a provision of $220 million for estimated third-party claims and $63 million of costs incurred to provide immediate support to the San Bruno community, re-inspect the Utility’s natural gas transmission lines, and to perform other activities following the accident. The Utility estimates that it may incur as much as $400 million for third-party claims. (See Note 15 of the Notes to the Consolidated Financial Statements.) The total amount of third-party liability claims will depend on the final determination of the causes for the pipeline rupture and responsibility for the personal injuries and property damages, and the number and nature of third-party claims. Although PG&E Corporation and the Utility currently consider it likely that most of the costs

the Utility incurs for third-party claims will ultimately be covered by its liability insurance, no amounts for insurance recoveries have been recorded as of December 31, 2010. The CPUC also has initiated an investigation of a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California (“Rancho Cordova accident”). The Utility expects that it will continue to incur unforecasted costs related to its natural gas operations as the investigations of the San Bruno and Rancho Cordova accidents progress, including costs to conduct an exhaustive review of records related to the Utility’s natural gas transmission system and to perform pressure tests on portions of its natural gas transmission system. Further, if state or federal legislation that is being considered to address natural gas transmission operations and maintenance is enacted, the Utility may incur additional costs to comply with new statutory requirements. The Utility may not be able to recover these additional unforecasted costs through rates. (See “Operating and Maintenance Expenses” and “Pending Investigations” below.) Finally, PG&E Corporation’s and the Utility’s financial condition, results of operation, and cash flows may be affected by the amount of penalties and fines, if any, that may be imposed on the Utility related to these matters.

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The Outcome of Ratemaking Proceedings. There are several rate cases that are currently pending at the CPUC and the FERC, the outcome of which will determine the majority of the Utility’s base revenue requirements for 2011 and several years thereafter. These proceedings are discussed below under “Regulatory Matters.” From time to time, the Utility also requests that the CPUC authorize additional base revenue requirements for specific capital expenditure projects such as new power plants. (See “Capital Expenditures” below.) The outcome of these proceedings can be affected by many factors, including general economic conditions, the level of customer rates, and political and regulatory policies. (See “Risk Factors” below.)

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The Ability of the Utility to Control Operating Costs and Capital Expenditures. The Utility’s revenue requirements are generally set by the CPUC and the FERC at a level to allow the Utility the opportunity to recover its forecasted operating expenses; to recover depreciation, tax, and interest expenses associated with forecasted capital expenditures; and to earn an ROE. Actual costs may differ from forecasts, or the Utility may incur significant unanticipated costs, such as costs related to storms, outages, or catastrophic events, or costs incurred to comply with regulatory orders or legislation.

Differences in the amount or timing of forecasted or authorized costs and actual costs can affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. (See “Capital Expenditures” below.) To the extent the Utility is unable to conclude that costs are probable of recovery through rates, the Utility will incur a charge to income. (See “Critical Accounting Policies” below.)

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Authorized Capital Structure, Rate of Return, and Financing. The Utility’s CPUC-authorized capital structure for its electric and natural gas distribution and electric generation rate base, consisting of 52% common equity and 48% debt and preferred stock, will remain in effect through 2012. The Utility’s CPUC-authorized ROE of 11.35% will remain in effect through 2011 but is subject to change based on an annual adjustment mechanism described below under “Liquidity and Financial Resources.” The timing and amount of the Utility’s future debt financing will depend on the timing and amount of capital expenditures and other factors. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. PG&E Corporation may issue debt or equity to fund these equity contributions. (See “Liquidity and Financial Resources” below.)

SUMMARY OF CHANGES IN EARNINGS PER COMMON SHARE AND INCOME AVAILABLE FOR COMMON SHAREHOLDERS FOR 2010

PG&E Corporation’s income available for common shareholders decreased by $121 million, or 10%, from $1,220 million in 2009 to $1,099 million in 2010. The following table is a summary reconciliation of the key changes in income available for common shareholders and earnings per common share for the year ended December 31, 2010:


	Earnings			Earnings Per Common Share (Diluted)
Income Available for Common Shareholders – 2009	$	1,220		$	3.20
San Bruno accident ⁽¹⁾		(168	)		(0.43	)
Tax refund ⁽²⁾		(66	)		(0.18	)
Statewide ballot initiative ⁽³⁾		(45	)		(0.12	)
Recovery of hydroelectric generation-related costs ⁽⁴⁾		(28	)		(0.07	)
Federal health care law ⁽⁵⁾		(19	)		(0.05	)
Rate base earnings ⁽⁶⁾		88			0.23
Accelerated work on gas system ⁽⁷⁾		59			0.16
Severance costs ⁽⁸⁾		38			0.10
Other ⁽⁹⁾		20			0.05
Increase in shares outstanding ⁽¹⁰⁾		–			(0.07	)
Income Available for Common Shareholders – 2010	$	1,099		$	2.82

⁽¹⁾

During 2010, the Utility recorded charges of $168 million, after-tax, for the San Bruno accident. These charges primarily included a provision for estimated third-party claims for personal injury and property damage claims, and other damage claims, as well as costs incurred to provide immediate support to the San Bruno community, re-inspect the Utility’s natural gas transmission lines, and perform other activities following the accident.

⁽²⁾	During 2009, PG&E Corporation recognized $66 million for the interest benefit associated with a federal tax refund.

⁽³⁾	During 2010, the Utility contributed $45 million to support Proposition 16 – The Taxpayers Right to Vote Act.

⁽⁴⁾	During 2009, the Utility recognized income of $28 million, after-tax, for the recovery of costs previously incurred in connection with its hydroelectric generation facilities.

⁽⁵⁾	During 2010, the Utility recorded a charge of $19 million triggered by the elimination of the tax deductibility of Medicare Part D federal subsidies.

⁽⁶⁾	During 2010, the Utility recognized earnings of $88 million, after-tax, attributable to the ROE on higher authorized capital investments.

⁽⁷⁾	During 2009, the Utility incurred $59 million, after-tax, for costs to perform accelerated system-wide natural gas integrity surveys and associated remedial work.

⁽⁸⁾	During 2009, the Utility accrued $38 million, after-tax, of severance costs related to the elimination of approximately 2% of its workforce.

⁽⁹⁾	During 2010, the Utility incurred lower expenses for nuclear refueling outages, uncollectible customer accounts and disability costs, partially offset by a charge for SmartMeter^™ related capital costs and higher storm and outage expenses.

⁽¹⁰⁾	Represents the impact of a lower number of shares outstanding in 2009 compared to 2010; this has no dollar impact on earnings.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This report contains 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, tax, and other liabilities; estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies; the anticipated outcome of various regulatory, governmental, and legal proceedings; estimated losses and insurance recoveries associated with the San Bruno accident; estimated future cash flows; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” and “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:

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the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels and timely recover its costs through rates;

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the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigations by the NTSB and CPUC into the cause of the San Bruno accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory; the CPUC investigation of the Rancho Cordova accident; whether the Utility incurs civil or criminal penalties as a result of these proceedings; whether the Utility is required to incur additional costs for third-party liability claims or to comply with regulatory or legislative mandates which costs the Utility is unable to recover through rates or insurance; and whether the Utility incurs third-party liabilities or other costs in connection with service disruptions that may occur as the Utility complies with regulatory orders to decrease pressure in its natural gas transmission system;

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reputational harm that PG&E Corporation and the Utility may suffer depending on the outcome of the various

investigations, including those by the NTSB and the CPUC; the outcome of civil litigation; and the extent to which civil or criminal proceedings may be pursued by regulatory or governmental agencies;

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the adequacy and price of electricity and natural gas supplies, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

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explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, human errors, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages; reduce generating output; damage the Utility’s assets or operations; subject the Utility to third-party claims for property damage or personal injury; or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

•

the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

•

the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

•

changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;

•

the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon Power Plant (“Diablo Canyon”); the availability of nuclear fuel; the outcome of the Utility’s application to renew the operating licenses for Diablo Canyon; and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, cooling water intake, or other matters associated with the operations at Diablo Canyon;

•

whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;

•

the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

•

whether the Utility can successfully complete its program to install advanced meters for its electric and natural gas customers, allay customer concerns about the new metering technology, and integrate the new meters with its customer billing and other systems while also implementing the system design changes necessary to accommodate retail electric rates based on dynamic pricing (i.e., electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices) by the CPUC’s due dates;

•

how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company and the extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;

•

the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, including those arising from the San Bruno accident, that are not recoverable through insurance, rates, or from other third parties;

•

the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

•

the impact of environmental laws and regulations addressing the reduction of carbon dioxide and other

greenhouse gases (“GHG”), water, the remediation of hazardous waste, and other matters, and whether the Utility is able to recover the costs of compliance with such laws, including the cost of emission allowances and offsets that the Utility may incur under federal or state cap-and-trade regulations;

•

the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses; and

•

the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (the “Tax Relief Act”).

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 2010, 2009, and 2008:

UTILITY

The following presents the Utility’s operating results for 2010, 2009, and 2008.

Electric Operating Revenues

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’ load is satisfied by electricity provided under long-term contracts between the California Department of Water Resources (“DWR”) and various power suppliers. The commodity costs and associated revenues to recover the costs allocated to the Utility by the DWR are not included in the Consolidated Statements of Income.

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


(in millions)	2010		2009		2008
Revenues excluding pass-through costs	$	6,123	$	5,905	$	5,562
Revenues for recovery of pass-through costs		4,521		4,352		5,176
Total electric operating revenues	$	10,644	$	10,257	$	10,738

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $387 million, or 4%, in 2010 compared to 2009. Costs that are passed through to customers and do not impact net income increased by $169 million, primarily due to increases in the cost of electricity procurement partially offset by decreases in the cost of public purpose programs. (See “Cost of Electricity” below.) Electric operating revenues, excluding costs passed through to customers, increased by $218 million. This was primarily due to increases in authorized base revenues.

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $481 million, or 4%, in 2009 compared to 2008. Costs that are passed through to customers and do not impact net income decreased by $824 million, primarily due to decreases in the costs of public purpose programs and electricity procurement. (See “Cost of Electricity” below.) Electric operating revenues, excluding

costs passed through to customers, increased by $343 million. This was primarily due to $344 million of increases in authorized base revenues composed of an attrition increase (as approved in the last GRC covering 2007 through 2010) and increases in revenues to recover capital expenditures that have separately authorized by the CPUC.

The Utility’s future electric operating revenues will be impacted by final authorization by the CPUC in the 2011 GRC and by the FERC in the TO rate cases. (See “Regulatory Matters” below.) The Utility also expects to continue to collect revenue requirements related to CPUC-approved capital expenditures outside the GRC, including capital expenditures for the SmartMeter^™ advanced metering project. Revenues will increase to the extent that the CPUC approves the Utility’s proposals for other capital projects. Finally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism. (See “Regulatory Matters” below.)

Cost of Electricity

The Utility’s mix of resources used to serve customers is determined by the availability of the Utility’s own electricity generation, the amount of electricity supplied under the DWR’s contracts allocated to the Utility’s customers, and the cost-effectiveness of other third-party sources of electricity. The Utility’s cost of electricity includes costs to purchase power from third parties, certain transmission costs, the cost of fuel used in its own 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 operating the Utility’s own generation facilities, which are included in operating and maintenance expense in the Consolidated Statements of Income.

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


(in millions)	2010		2009		2008
Cost of purchased power	$	3,647	$	3,508	$	4,261
Fuel used in own generation facilities		251		203		164
Total cost of electricity	$	3,898	$	3,711	$	4,425
Average cost of purchased power per kWh ⁽¹⁾	$	0.081	$	0.082	$	0.089
Total purchased power (in kWh)		44,837		42,767		47,668

⁽¹⁾

Kilowatt-hour

The Utility’s total cost of electricity increased by $187 million, or 5%, in 2010 compared to 2009. This was caused by an increase in purchased power and an increase in the cost of fuel used in the Utility’s own generation facilities as the Utility increased its non-nuclear generation to replace power that had previously been provided under a DWR contract that expired at the end of 2009 (costs associated with power provided to the Utility’s customers under DWR contracts are not included in the Utility’s cost of purchased power). The volume of purchased power is driven 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 decreased by $714 million, or 16%, in 2009 compared to 2008, primarily due to an 8% decrease in the average price 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.

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, 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, replaced, or renegotiated. Additionally, the cost of electricity is expected to continue reflecting the higher cost of procuring renewable energy as the Utility increases the amount of its renewable energy deliveries to comply with current and future California law and regulatory requirements. The Utility expects that it will be able to continue passing through the costs of its renewable energy purchase commitments to customers. (See “Environmental Matters – Renewable Energy Resources” and “Risk Factors” below.)

The Utility’s future cost of electricity also will be affected by federal or state legislation or rules that may be adopted to regulate GHG emissions. (See “Environmental Matters – Climate Change” and “Risk Factors” below.)

Natural Gas Operating Revenues

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 Utility transports gas throughout its service territory by using its distribution system to deliver to end-use customers as well as 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 2010, core customers represented over 99% of the Utility’s total customers and 39% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total customers and 61% of its total natural gas deliveries.

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


(in millions)	2010		2009		2008
Revenues excluding pass-through costs	$	1,703	$	1,667	$	1,616
Revenues for recovery of passed-through costs		1,493		1,475		2,274
Total natural gas operating revenues	$	3,196	$	3,142	$	3,890

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $54 million, or 2%, in 2010 compared to 2009. This reflects an $18 million increase in the costs that are passed through to customers and do not impact net income, primarily due to an increase in the cost of public purpose programs. Natural gas operating revenues, excluding costs passed through to customers, increased by $36 million, primarily due to an increase in authorized base revenue, partially offset by a decrease in natural gas storage revenues. (The Utility’s storage facilities were at capacity throughout the year, and less gas was transported from storage due to the milder weather that prevailed. As result, the Utility was unable to accept more gas for storage.)

The Utility’s total natural gas operating revenues, including revenues intended to recover costs that are

passed through to customers, decreased by $748 million, or 19%, in 2009 compared to 2008. This reflects a $799 million decrease in the total cost of natural gas that is passed through to customers and generally does not impact net income. (See “Cost of Natural Gas” below.) Natural gas operating revenues, excluding costs passed through to customers, increased by $51 million, primarily due to an increase in authorized base revenues.

The Utility’s future natural gas operating revenues will be impacted by final authorization by the CPUC in the 2011 GRC and the 2011 Gas Transmission and Storage rate case. Finally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism. (See “Regulatory Matters” below.)

Cost of Natural Gas

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 following table provides a summary of the Utility’s cost of natural gas:


(in millions)	2010		2009		2008
Cost of natural gas sold	$	1,119	$	1,130	$	1,955
Transportation cost of natural gas sold		172		161		135
Total cost of natural gas	$	1,291	$	1,291	$	2,090
Average cost per Mcf ⁽¹⁾ of natural gas sold	$	4.69	$	4.47	$	7.43
Total natural gas sold (in millions of Mcf)		249		253		263

⁽¹⁾

One thousand cubic feet

The Utility’s total cost of natural gas decreased by less than $1 million in 2010 compared to 2009. The Utility received $49 million in the first quarter of 2010 to be refunded to customers as part of a litigation settlement arising from the manipulation of the natural gas market by third parties during 1999 through 2002. The decrease resulting from the settlement was partially offset by an increase in transportation costs primarily due to attrition adjustments and an increase in procurement costs due to increases in the average market price of natural gas purchased.

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 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 natural 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

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; changes in the accrual for legal matters; 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 $89 million, or 2%, in 2010 compared to 2009. During 2010, the change in pass-through operating and maintenance costs as compared to 2009 was immaterial. The increase in operating and maintenance expenses was primarily due to $283 million of costs associated with the San Bruno accident. This amount includes a provision of $220 million for estimated third-party claims, including personal injury and property damage claims, damage to infrastructure, and other damage claims. (See Note 15 of the Notes to the Consolidated Financial Statements.) The additional $63 million of costs associated with the San Bruno accident were incurred to provide immediate support to the San Bruno community, re-inspect the Utility’s natural gas transmission lines, and perform other activities following the accident. Additionally, operating and maintenance expenses increased due to a $36 million provision that was recorded for SmartMeter^™ related

capital costs that are forecasted to exceed the CPUC-authorized amount for recovery. (See “Regulatory Matters – Deployment of SmartMeter^™ Technology” below.) These increases were partially offset by decreases of approximately $139 million in labor costs and other costs as compared to 2009, when costs were incurred in connection with an additional scheduled refueling outage at Diablo Canyon and accelerated natural gas leak surveys (and associated remedial work); $67 million in severance costs as compared to the same period in 2009, when charges were incurred related to the reduction of approximately 2% of the Utility’s workforce; and $21 million in uncollectible customer accounts, as a result of customer outreach and increased collection efforts.

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^™ advanced 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 currently estimates that it may incur as much as $180 million for third-party claims related to the San Bruno accident in future years, in addition to the $220 million provision recorded in 2010. (See Note 15 of the Notes to the Consolidated Financial Statements.) The Utility also expects to continue to incur other costs related to the San Bruno accident, including costs to comply with CPUC orders and NTSB recommendations that have been issued in connection with the investigation of the San Bruno accident, such as costs to perform an exhaustive review of records related to the Utility’s natural gas transmission system and to perform pressure tests on portions of its natural gas transmission system. The Utility currently estimates that these costs could range from approximately $200 million to $300 million for 2011. These estimates could change depending on a number of factors, including the outcome of the NTSB and CPUC investigations; the outcome of the “safety phase” of the Utility’s 2011 Gas Transmission and Storage Rate Case;

and the outcome of future rule-making, ratemaking, or investigatory proceedings at the CPUC. (See “Regulatory Matters” and “Pending Investigations” below.) In addition, current estimates could be affected by state and federal legislative requirements that may be adopted to establish operating practice standards for natural gas transmission operations and safety, to require the use of certain types of inspection methods and equipment, and to require the installations of certain types of valves. If this or similar legislation is enacted, the Utility may incur unforecasted costs to comply with new statutory requirements. PG&E Corporation and the Utility are uncertain whether all or a portion of the costs the Utility may incur to respond to orders, recommendations, or new legislative requirements would be recoverable through rates and the timing of any such recovery. Finally, if the CPUC institutes one or more formal investigations related to the San Bruno accident or the Utility’s natural gas operating and maintenance practices in addition to the formal investigation of the Rancho Cordova accident, the CPUC may impose fines or penalties, which may be material, on the Utility if the CPUC determines that the Utility violated laws, rules, regulations, or orders.

Depreciation, Amortization, and Decommissioning

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 $153 million, or 9%, in 2010 compared to 2009, primarily due to an increase in authorized capital additions.

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 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.

Interest Income

The Utility’s interest income decreased by $24 million, or 73%, in 2010 as compared to 2009, primarily due to lower interest rates affecting various regulatory balancing accounts and fluctuations in those accounts. In addition,

interest income decreased as compared to 2009, when the Utility received interest income on previously incurred costs related to the proposed divestiture of its hydroelectric generation facilities.

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 13 of the Notes to the Consolidated Financial Statements.) 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 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.

Interest Expense

The Utility’s interest expense decreased by $12 million, or 2%, in 2010 as compared to 2009. This decrease was primarily attributable to decreases in the outstanding balances of the liability for Chapter 11 disputed claims, energy recovery bonds (“ERBs”), and various regulatory balancing accounts, and to lower interest rates on short-term debt. The decrease was partially offset by an increase in outstanding senior notes. (See Note 4 of the Notes to the Consolidated Financial Statements.)

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.

The Utility’s interest expense in future periods will be impacted by changes in interest rates, changes in the

liability for Chapter 11 disputed claims, changes in regulatory balancing accounts and regulatory assets, 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.)

Other Income, Net

The Utility’s other income, net decreased by $37 million, or 63%, in 2010 compared to 2009. The decrease was primarily due to a $45 million increase in other expenses as a result of costs the Utility incurred to support a California ballot initiative that appeared on the June 2010 ballot, which are not recoverable in rates. This expense was partially offset by a $15 million increase in allowance for equity funds used during construction, due to higher average balances of construction work in progress.

The Utility’s other income, net increased by $31 million, or 111%, in 2009 compared to 2008, when the Utility incurred costs to oppose a California ballot initiative related to renewable energy and to oppose the City of San Francisco’s municipalization efforts.

Income Tax Provision

The Utility’s income tax provision increased by $92 million, or 19%, in 2010 compared to 2009. The effective tax rates were 34% and 28% for 2010 and 2009, respectively. The effective tax rate for 2010 increased as compared to the same period in 2009, when the Utility recognized state tax benefits arising from tax accounting method changes and benefits of various audit settlements at higher levels than 2010 settlements. The effective tax rate also increased due to the reversal of a deferred tax asset in the first quarter of 2010 that had previously been recorded to reflect the future tax benefits attributable to the Medicare Part D subsidy after 2012, which was eliminated as part of the federal health care legislation passed during March 2010. (See Note 9 of the Notes to the Consolidated Financial Statements.)

The Utility’s income tax provision decreased by $6 million, or 1%, in 2009 compared to 2008. The effective tax rates were 28% and 29% 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 matters. (See Note 9 of the Notes to the Consolidated Financial Statements.)

The differences between the Utility’s income taxes and amounts calculated by applying the federal statutory rate to income before income tax expense for continuing operations for 2010, 2009, and 2008 were as follows:


	2010			2009			2008
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		1.0			1.4			3.3
Effect of regulatory treatment of fixed asset differences		(3.0	)		(2.6	)		(3.1	)
Tax credits		(0.4	)		(0.5	)		(0.5	)
IRS audit settlements		(0.2	)		(4.2	)		(4.1	)
Other, net		1.5			(1.3	)		(1.7	)
Effective tax rate		33.9	%		27.8	%		28.9	%

PG&E CORPORATION, ELIMINATIONS, AND OTHER

Operating Revenues and Expenses

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 PG&E Corporation’s 9.5% Convertible Subordinated Notes, which were no longer outstanding at December 31, 2010, and 5.8% Senior Notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating revenues and expenses in 2010 compared to 2009 and 2009 compared to 2008.

Other Income (Expense), Net

PG&E Corporation’s other income, net decreased by $3 million, or 38%, in 2010 compared to 2009, primarily due to smaller investment-related gains in the rabbi trusts established in connection with the non-qualified deferred compensation plans. The investment-related gains resulted in a net increase to other income of $40 million, or 125%, in 2009 compared to 2008.

Income Tax Benefit

PG&E Corporation’s income tax benefit increased by $5 million, or 23%, in 2010 primarily due to a write-off of a deferred tax asset in 2009, with no comparable amount in the current year.

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.

Discontinued Operations

In the fourth quarter of 2008, PG&E Corporation reached a settlement of federal tax audits for 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 Consolidated Financial Statements.) No similar amount was recognized in 2010 or 2009.

LIQUIDITY AND FINANCIAL RESOURCES

OVERVIEW

The Utility’s ability to fund operations depends on the levels of its operating cash flows and access to the capital and credit markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal load 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. The CPUC authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The Utility has short-term borrowing 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, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, fund tax equity investments, and pay dividends primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital and credit markets.

The following table summarizes PG&E Corporation’s and the Utility’s revolving credit facilities at December 31, 2010:

For the year ended December 31, 2010, the average outstanding cash borrowings and commercial paper balance were $33 million and $655 million, respectively.

PG&E Corporation’s and the Utility’s credit agreements contain covenants that are usual and customary for credit facilities of this type, including covenants limiting liens, mergers, substantial asset sales, and other fundamental changes. Both the $750 million and the $1.9 billion revolving credit facilities require that the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. In addition, the $187 million revolving credit facility agreement requires that PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility.

At December 31, 2010, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities listed in the table above.

2010 FINANCINGS

PG&E Corporation

On November 4, 2010, PG&E Corporation entered into an Equity Distribution Agreement pursuant to which

PG&E Corporation’s sales agents may offer and sell, from time to time, PG&E Corporation common stock having an aggregate gross offering price of up to $400 million. Sales of the shares are made by means of ordinary brokers’ transactions on the New York Stock Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable securities laws. As of December 31, 2010, PG&E Corporation had issued 2,357,796 shares of common stock pursuant to the Equity Distribution Agreement for cash proceeds of $110 million, net of fees and commissions paid of $1 million.

In addition, during 2010, PG&E Corporation issued 5,105,505 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 $192 million of cash. PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s Convertible Subordinated Notes at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding at December 31, 2010, and the conversion had no impact on cash.

Utility

The following table summarizes debt issuances in 2010. (See Note 4 of the Notes to the Consolidated Financial Statements.)


(in millions)	Issue Date		Amount
Senior Notes
5.8%, due 2037		April 1	$	250
3.5%, due 2020		September 15		550
Floating rate, due 2011		October 12		250
3.5%, due 2020		November 18		250
5.4%, due 2040		November 18		250
Total senior notes				1,550
Pollution control bonds
Series 2010E, 2.25%, due 2026 ⁽¹⁾		April 8		50
Total debt issuances in 2010			$	1,600

⁽¹⁾

These bonds bear interest at 2.25% per year through April 1, 2012; are subject to mandatory tender on April 2, 2012; and may be remarketed in a fixed or variable rate mode.

The net proceeds from the issuance of Utility senior notes in 2010 were used to repay outstanding commercial paper and for general corporate purposes. The net proceeds from the issuance of the pollution control bonds by the California Infrastructure and Economic Development Bank for the benefit of the Utility were used to fund capital investments and general working capital needs.

The Utility also received a contribution of $190 million of cash from PG&E Corporation during 2010 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.

FUTURE FINANCING NEEDS

The amount and timing of the Utility’s future financings will depend on various factors, including:

•

the amount of cash internally generated through normal business operations;

•

the timing and amount of forecasted capital expenditures authorized in GRC or TO rate cases, or whether the CPUC approves the Utility’s requests for specific capital projects outside of the GRC (discussed below under “Capital Expenditures”);

•

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;

•

the timing and amount of payments made to third parties in connection with the San Bruno accident, and the timing and amount of related insurance recoveries;

•

the reduction in future tax payments as a result of legislation in December 2010 that allows for bonus

depreciation on qualified property (discussed below under “Utility – Operating Activities”); and

•

the conditions in the capital markets, and other factors. (See Notes 13 and 15 of the Notes to the Consolidated Financial Statements.)

PG&E Corporation may issue debt or equity in the future to fund equity contributions to the Utility and to fund tax equity investments to the extent that internally generated funds are not sufficient. PG&E Corporation’s financing needs depend primarily on the timing and amount of contributions made to the Utility to maintain the Utility’s 52% common equity ratio authorized by the CPUC. Further, at December 31, 2010, PG&E Corporation made certain tax equity investments (see “PG&E Corporation” below) and may fund similar investments in the future, resulting in additional financing needs.

PG&E Corporation and the Utility have had continued access to the capital markets on reasonable terms and continue to believe that the Utility’s cash flows from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, make payments to third parties related to the San Bruno accident, and finance future capital expenditures and investments.

DIVIDENDS

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

•

Comparability: Pay a dividend competitive with the securities of comparable companies based on payout ratio (the proportion of earnings paid out as dividends) and, with respect to PG&E Corporation, yield (i.e., dividend divided by share price);

•

Flexibility: Allow sufficient cash to pay a dividend and to fund investments while avoiding having to issue new equity unless PG&E Corporation’s or the Utility’s capital expenditure requirements are growing rapidly and PG&E Corporation or the Utility can issue equity at reasonable cost and terms; and

•

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

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 CPUC requires that the PG&E Corporation Board of Directors give first priority to 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, in setting the amount of dividends.

The Boards of Directors must also consider the CPUC requirement that the Utility maintain, on average, its CPUC-authorized capital structure, including a 52% equity component.

The following table summarizes PG&E Corporation’s and the Utility’s dividends paid:


(in millions)	2010		2009		2008
PG&E Corporation:
Common stock dividends paid	$	662	$	590	$	546
Common stock dividends reinvested in Dividend Reinvestment and Stock Purchase Plan		18		17		20
Utility:
Common stock dividends paid	$	716	$	624	$	568
Preferred stock dividends paid		14		14		14

On December 15, 2010, the Board of Directors of PG&E Corporation declared a quarterly dividend of $0.455 per share, totaling $183 million, which was paid on January 15, 2011 to shareholders of record on December 31, 2010. On February 16, 2011, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, payable on April 15, 2011 to shareholders of record on March 31, 2011.

On December 15, 2010, 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, 2011 to preferred shareholders of record on January 31, 2011. On February 16, 2011, the Board of Directors of the Utility declared a cash dividend on its outstanding series of preferred stock, payable on May 15, 2011 to shareholders of record on April 29, 2011.

PG&E Corporation and the Utility each have revolving credit facilities that require the company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. This covenant, along with

the CPUC’s requirement for the Utility to maintain the 52% equity component of its capital structure, are considered to be restrictions on the payment of dividends. Based on the calculation of these ratios for each company, no amount of PG&E Corporation’s retained earnings and $5.3 billion of the Utility’s retained earnings were restricted at December 31, 2010.

In addition, the Utility was required to maintain at least $9.7 billion of its net assets as equity in order to maintain the capital structure of at least 52% equity at December 31, 2010. As a result, $9.7 billion of the Utility’s net assets are restricted and may not be transferred to PG&E Corporation in the form of cash dividends.

UTILITY

Operating Activities

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 2010, 2009, and 2008 were as follows:


(in millions)	2010			2009			2008
Net income	$	1,121		$	1,250		$	1,199
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		2,116			1,927			1,838
Allowance for equity funds used during construction		(110	)		(94	)		(70	)
Deferred income taxes and tax credits, net		762			787			593
Other		46			(27	)		(6	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(105	)		157			(83	)
Inventories		(43	)		109			(59	)
Accounts payable		109			(33	)		(137	)
Disputed claims and customer refunds		–			(700	)		–
Income taxes receivable/payable		(58	)		21			43
Other current assets		(7	)		122			(187	)
Other current liabilities		130			183			60
Regulatory assets, liabilities, and balancing accounts, net		(394	)		(516	)		(374	)
Other changes in noncurrent assets and liabilities		(331	)		(282	)		(51	)
Net cash provided by operating activities	$	3,236		$	2,904		$	2,766

During 2010, net cash provided by operating activities increased $332 million compared to 2009. This increase

reflects the Utility’s payment to the California Power Exchange (“PX”) in 2009, partially offset by net tax refunds that the Utility received in 2009 that were higher than the amount received in 2010. (The Utility’s payment to the PX decreased the Utility’s liability for the remaining net disputed claims that had been made in the Utility’s Chapter 11 proceeding. See Note 13 of the Notes to the Consolidated Financial Statements.) The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as collateral, power purchases, and customer billings.

During 2009, net cash provided by operating activities increased $138 million compared to 2008. This increase reflects significantly lower commodity market prices in 2009 compared to 2008, which resulted in fewer cash outflows related to the timing of inventory and procurement activities. These net inflows were partially offset by the payment to the PX.

On December 17, 2010, the Tax Relief Act was signed into law, allowing qualified property placed into service after September 8, 2010, and before January 1, 2012, to be eligible for 100% bonus depreciation for tax purposes and qualified property placed into service in 2012 to be eligible for 50% bonus depreciation for tax purposes. (See Note 9 of the Notes to the Consolidated Financial Statements.) As a result, the Utility expects to make no federal tax payment in 2011. A reduction in the 2012 federal tax payment is expected; however, the amount cannot be reasonably estimated at this time. (See “Regulatory Matters – CPUC Resolution Regarding the Tax Relief Act” below.)

Additionally, there is uncertainty around the timing and amount of payments to be made to third parties in connection with the San Bruno accident, the timing and amount of related insurance recoveries, any penalties that may be assessed, costs associated with related investigations, and costs associated with changes to pipeline management and operations.

Investing Activities

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 and the occurrence of storms and other events causing outages or damages to the Utility’s infrastructure. 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. (See Note 11 of the Notes to the Consolidated Financial Statements.)

The Utility’s cash flows from investing activities for 2010, 2009, and 2008 were as follows:


(in millions)	2010			2009			2008
Capital expenditures	$	(3,802	)	$	(3,958	)	$	(3,628	)
Decrease in restricted cash		66			666			36
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,405			1,351			1,635
Purchases of nuclear decommissioning trust investments		(1,456	)		(1,414	)		(1,684	)
Other		19			11			1
Net cash used in investing activities	$	(3,768	)	$	(3,344	)	$	(3,640	)

Net cash used in investing activities increased by $424 million in 2010 compared to 2009, primarily due to the Utility’s $700 million payment to the PX, which decreased the restricted cash balance in 2009. (See Note 13 of the Notes to the Consolidated Financial Statements.) This increase was partially offset by a decrease in capital expenditures of $156 million as compared to 2009. Capital expenditures decreased in 2010 due to permitting delays, the postponement of purchases of materials that would otherwise have been capitalized earlier in the year, and poor weather conditions in the first half of 2010, which delayed construction activities as resources were re-directed to emergency response activities.

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 the Utility’s payment to the PX, partially offset by an increase of $330 million in capital expenditures. The increase in capital expenditures in 2009 compared to 2008 was due to the increase in installation of 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 the timing and amount of capital expenditures. (See “Capital Expenditures” below for further discussion of expected spending and significant capital projects.)

Financing Activities

The Utility’s cash flows from financing activities for 2010, 2009, and 2008 were as follows:


(in millions)	2010			2009			2008
Borrowings under revolving credit facilities	$	400		$	300		$	533
Repayments under revolving credit facilities		(400	)		(300	)		(783	)
Net issuances of commercial paper, net of discount of $3 in 2010 and 2009, and $11 in 2008		267			43			6
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2010 and 2009		249			499			–
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $23 in 2010, $25 in 2009, and $19 in 2008		1,327			1,384			2,185
Short-term debt matured		(500	)		–			–
Long-term debt matured or repurchased		(95	)		(909	)		(454	)
Energy recovery bonds matured		(386	)		(370	)		(354	)
Preferred stock dividends paid		(14	)		(14	)		(14	)
Common stock dividends paid		(716	)		(624	)		(568	)
Equity contribution		190			718			270
Other		(73	)		(5	)		(36	)
Net cash provided by financing activities	$	249		$	722		$	785

In 2010, net cash provided by financing activities decreased by $473 million compared to 2009. In 2009, net cash provided by financing activities decreased by $63 million compared to 2008. 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.

PG&E CORPORATION

As of December 31, 2010, PG&E Corporation’s affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation will provide payments of up to $300 million, and in return, receive the benefits of local rebates, federal investment tax credits or grants, and a share of these companies’ customer payments. PG&E Corporation could be required to pay up to an additional $41 million in the event that its ownership interests are liquidated when in a deficit position. (See Note 2 of the Notes to the Consolidated Financial Statements.) However, PG&E Corporation’s financial exposure for these arrangements is generally limited to its lease payments and investment contributions to these companies. As of December 31, 2010, PG&E Corporation had made total payments of $149 million under these tax equity agreements. Lease payments and investment contributions are included in cash flows from operating and investing activities, respectively, within the Consolidated Statements of Cash Flows.

In addition to the investments above, PG&E Corporation had the following material cash flows on a stand-alone basis for the years ended December 31, 2010, 2009, and 2008: dividend payments, interest payments, common stock issuance, the senior note issuance of $350 million in March 2009, net tax refunds of $189 million in 2009, and transactions between PG&E Corporation and the Utility.

The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 2010.


A Letter to our Stakeholders			1

Financial Statements			6

PG&E Corporation and Pacific Gas and Electric Company Boards of Directors			118

Officers of PG&E Corporation and Pacific Gas and Electric Company			119

Shareholder Information			120


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			55

Notes to the Consolidated Financial Statements			65

Quarterly Consolidated Financial Data			114

Management’s Report on Internal Control Over Financial Reporting			115

Report of Independent Registered Public Accounting Firm			116


(unaudited, in millions, except share and per share amounts)	2010			2009
Operating Revenues	$	13,841		$	13,399
Income Available for Common Shareholders
Earnings from operations ⁽²⁾		1,331			1,223
Items impacting comparability ⁽³⁾		(232	)		(3	)
Reported Consolidated Income Available for Common Shareholders		1,099			1,220
Income Per Common Share, Diluted
Earnings from operations ⁽²⁾		3.42			3.21
Items impacting comparability ⁽³⁾		(0.60	)		(0.01	)
Reported Consolidated Net Earnings Per Common Share, Diluted		2.82			3.20
Dividends Declared Per Common Share		1.82			1.68
Total Assets at December 31,	$	46,025		$	42,945
Number of common shares outstanding at December 31,		395,227,205			371,272,457


(in millions, except per share amounts)	2010			2009		2008⁽¹⁾		2007		2006
PG&E Corporation For the Year
Operating revenues	$	13,841		$	13,399	$	14,628	$	13,237	$	12,539
Operating income		2,308			2,299		2,261		2,114		2,108
Income from continuing operations		1,113			1,234		1,198		1,020		1,005
Earnings per common share from continuing operations, basic		2.86			3.25		3.23		2.79		2.78
Earnings per common share from continuing operations, diluted		2.82	⁽²⁾		3.20		3.22		2.78		2.76
Dividends declared per common share ⁽³⁾		1.82			1.68		1.56		1.44		1.32
At Year-End
Common stock price per share	$	47.84		$	44.65	$	38.71	$	43.09	$	47.33
Total assets		46,025			42,945		40,860		36,632		34,803
Long-term debt (excluding current portion)		10,906			10,381		9,321		8,171		6,697
Capital lease obligations (excluding current portion) ⁽⁴⁾		248			282		316		346		376
Energy recovery bonds (excluding current portion) ⁽⁵⁾		423			827		1,213		1,582		1,936

Pacific Gas and Electric Company For the Year
Operating revenues	$	13,840		$	13,399	$	14,628	$	13,238	$	12,539
Operating income		2,314			2,302		2,266		2,125		2,115
Income available for common stock		1,107			1,236		1,185		1,010		971
At Year-End
Total assets		45,679			42,709		40,537		36,310		34,371
Long-term debt (excluding current portion)		10,557			10,033		9,041		7,891		6,697
Capital lease obligations (excluding current portion) ⁽⁴⁾		248			282		316		346		376
Energy recovery bonds (excluding current portion) ⁽⁵⁾		423			827		1,213		1,582		1,936


	Year ended December 31,
(in millions)	2010			2009			2008
Utility
Electric operating revenues	$	10,644		$	10,257		$	10,738
Natural gas operating revenues		3,196			3,142			3,890
Total operating revenues		13,840			13,399			14,628
Cost of electricity		3,898			3,711			4,425
Cost of natural gas		1,291			1,291			2,090
Operating and maintenance		4,432			4,343			4,197
Depreciation, amortization, and decommissioning		1,905			1,752			1,650
Total operating expenses		11,526			11,097			12,362
Operating income		2,314			2,302			2,266
Interest income		9			33			91
Interest expense		(650	)		(662	)		(698	)
Other income, net		22			59			28
Income before income taxes		1,695			1,732			1,687
Income tax provision		574			482			488
Net income		1,121			1,250			1,199
Preferred stock dividend requirement		14			14			14
Income Available for Common Stock	$	1,107		$	1,236		$	1,185
PG&E Corporation, Eliminations, and Other ⁽¹⁾
Operating revenues	$	1		$	–		$	–
Operating expenses		7			3			5
Operating loss		(6	)		(3	)		(5	)
Interest income		–			–			3
Interest expense		(34	)		(43	)		(30	)
Other income (expense), net		5			8			(32	)
Loss before income taxes		(35	)		(38	)		(64	)
Income tax benefit		(27	)		(22	)		(63	)
Loss from continuing operations		(8	)		(16	)		(1	)
Discontinued operations ⁽²⁾		–			–			154
Net income (loss)	$	(8	)	$	(16	)	$	153
Consolidated Total
Operating revenues	$	13,841		$	13,399		$	14,628
Operating expenses		11,533			11,100			12,367
Operating income		2,308			2,299			2,261
Interest income		9			33			94
Interest expense		(684	)		(705	)		(728	)
Other income (expense), net		27			67			(4	)
Income before income taxes		1,660			1,694			1,623
Income tax provision		547			460			425
Income from continuing operations		1,113			1,234			1,198
Discontinued operations ⁽²⁾		–			–			154
Net income		1,113			1,234			1,352
Preferred stock dividend requirement of subsidiary		14			14			14
Income Available for Common Shareholders	$	1,099		$	1,220		$	1,338

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	December 31,
(in millions)	2010		2009
PG&E Corporation	$	240	$	193
Utility		51		334
Total consolidated cash and cash equivalents		291		527
Utility restricted cash		563		633
	$	854	$	1,160


	Payment due by period
(in millions)	Less Than 1 Year		1–3 Years		3–5 Years		More Than 5 Years			Total
Contractual Commitments:
Utility
Long-term debt ⁽¹⁾:
Fixed rate obligations	$	1,085	$	1,598	$	2,026	$	16,104		$	20,813
Variable rate obligations		312		635		47		307			1,301
Energy recovery bonds		435		436		–		–			871
Purchase obligations ⁽⁴⁾:
Power purchase agreements ⁽²⁾:
Qualifying facilities		1,086		1,720		1,617		4,392			8,815
Renewable contracts		804		2,223		3,589		40,887			47,503
Irrigation district and water agencies		80		109		47		43			279
Other power purchase agreements		694		1,512		1,189		4,227			7,622
Natural gas supply and transportation		710		464		331		1,128			2,633
Nuclear fuel		84		174		323		1,057			1,638
Pension and other benefits ⁽³⁾		369		862		903		451	⁽⁶⁾		2,585
Capital lease obligations ⁽⁴⁾		50		100		80		124			354
Operating leases ⁽⁴⁾		25		41		25		73			164
Preferred dividends ⁽⁵⁾		14		28		28		–			70
PG&E Corporation
Long-term debt ⁽¹⁾:
Fixed rate obligations		20