##### Table of Contents





UNITED STATES SECURITIES AND
EXCHANGE COMMISSION

Washington, D.C., 20549

FORM 10-Q

|           |  |                                                                                                                             
|---------- |  | ----------------------------------------------------------------------------------------------------------------------------
|(Mark One)
|[X]        |  | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934                                     
|           |  | For the quarterly period ended March 31,
2011  OR                                                                           
|[    ]     |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 
For the transition period from
 to





|                                                                                                 |  |                                                      |  |                                                                                     |  |                                              |  |                                    |  | 
|------------------------------------------------------------------------------------------------ |  | ---------------------------------------------------- |  | ----------------------------------------------------------------------------------- |  | -------------------------------------------- |  | ---------------------------------- |  | 
|Commission File
Number                                                                           |  | Exact Name of
Registrant as specified
in its charter |  |                                                                                     |  | State or other Jurisdiction
of Incorporation |  | IRS Employer
Identification Number |  | 
|                                                                                                 |  |                                                      |  |                                                                                    
|1-12609                                                                                          |  | PG&E Corporation                                     |  |                                                                                     |  | California                                   |  | 94-3234914                        
|1-2348                                                                                           |  | Pacific Gas and Electric Company                     |  | California                                                                          |  | 94-0742640                                  
|Pacific Gas and Electric Company
77 Beale Street P.O. Box 770000
San Francisco, California 94177 |  |                                                      |  | PG&E Corporation
One Market, Spear Tower Suite 2400
San Francisco, California 94105 |  |                                             
|Address of principal executive offices, including zip code                                      
|Pacific Gas and Electric Company
(415) 973-7000                                                  |  |                                                      |  | PG&E Corporation
(415) 267-7000                                                     |  |                                             

Registrants telephone number, including area code

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  [X]
Yes    [    ]  No

Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).

|                                  |  |                      |  | 
|--------------------------------- |  | -------------------- |  | 
|PG&E Corporation                  |  | [X] Yes [    ] No    |  | 
|                                  |  |                     
|Pacific Gas and Electric Company: |  | [    ] Yes [    ] No |  | 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See definitions of large accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act.



|                                  |  |                                |  |                                 
|--------------------------------- |  | ------------------------------ |  | --------------------------------
|PG&E Corporation:                 |  | [X] Large accelerated filer    |  | [    ] Accelerated Filer        
|                                  |  | [    ] Non-accelerated filer   |  | [    ] Smaller reporting company
|Pacific Gas and Electric Company: |  | [    ] Large accelerated filer |  | [    ] Accelerated Filer        
|                                  |  | [X] Non-accelerated filer      |  | [    ] Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

|                                  |  |                   |  | 
|--------------------------------- |  | ----------------- |  | 
|PG&E Corporation:                 |  | [    ] Yes [X] No |  | 
|Pacific Gas and Electric Company: |  | [    ] Yes [X] No |  | 

Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest
practicable date.

Common Stock Outstanding as of April 25, 2011:



|                                 |  |             |  | 
|-------------------------------- |  | ----------- |  | 
|PG&E Corporation                 |  | 397,949,716 |  | 
|Pacific Gas and Electric Company |  | 264,374,809 |  | 









---

##### Table of Contents

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011

TABLE OF CONTENTS



|           |  |                                                                                       |  |                                                        |      |  |    | 
|---------- |  | ------------------------------------------------------------------------------------- |  | ------------------------------------------------------ | ---- |  | -- | 
|PART I.    |  | FINANCIAL INFORMATION                                                                 |  |                                                        | PAGE | 
|ITEM 1.    |  | CONDENSED CONSOLIDATED FINANCIAL STATEMENTS                                           |  |                                                        |      | 
|           |  | PG&E Corporation                                                                      |  |                                                        |      | 
|           |  | Condensed Consolidated Statements of Income                                           |  |                                                        | 2    | 
|           |  | Condensed Consolidated Balance Sheets                                                 |  |                                                        | 3    | 
|           |  | Condensed Consolidated Statements of Cash Flows                                       |  |                                                        | 5    | 
|           |  | Pacific Gas and Electric Company                                                      |  |                                                        |      | 
|           |  | Condensed Consolidated Statements of Income                                           |  |                                                        | 6    | 
|           |  | Condensed Consolidated Balance Sheets                                                 |  |                                                        | 7    | 
|           |  | Condensed Consolidated Statements of Cash Flows                                       |  |                                                        | 9    | 
|           |  | NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS                              |  |                                                        |      | 
|           |  | NOTE 1:                                                                               |  | Organization and Basis of Presentation                 |      |  | 10 | 
|           |  | NOTE 2:                                                                               |  | Significant Accounting Policies                        |      |  | 10 | 
|           |  | NOTE 3:                                                                               |  | Regulatory Assets, Liabilities, and Balancing Accounts |      |  | 12 | 
|           |  | NOTE 4:                                                                               |  | Debt                                                   |      |  | 15 | 
|           |  | NOTE 5:                                                                               |  | Equity                                                 |      |  | 16 | 
|           |  | NOTE 6:                                                                               |  | Earnings Per Share                                     |      |  | 16 | 
|           |  | NOTE 7:                                                                               |  | Derivatives and Hedging Activities                     |      |  | 18 | 
|           |  | NOTE 8:                                                                               |  | Fair Value Measurements                                |      |  | 22 | 
|           |  | NOTE 9:                                                                               |  | Resolution of Remaining Chapter 11 Disputed Claims     |      |  | 27 | 
|           |  | NOTE 10:                                                                              |  | Commitments and Contingencies                          |      |  | 27 | 
|           |  |                                                                                      
|ITEM 2.    |  | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  |                                                        |      | 
|           |  | Overview                                                                              |  |                                                        | 35   | 
|           |  | Cautionary Language Regarding Forward-Looking Statements                              |  |                                                        | 37   | 
|           |  | Results of Operations                                                                 |  |                                                        | 40   | 
|           |  | Liquidity and Financial Resources                                                     |  |                                                        | 45   | 
|           |  | Contractual Commitments                                                               |  |                                                        | 49   | 
|           |  | Capital Expenditures                                                                  |  |                                                        | 49   | 
|           |  | Off-Balance Sheet Arrangements                                                        |  |                                                        | 49   | 
|           |  | Contingencies                                                                         |  |                                                        | 49   | 
|           |  | Natural Gas Pipeline Matters                                                          |  |                                                        | 49   | 
|           |  | Regulatory Matters                                                                    |  |                                                        | 53   | 
|           |  | Environmental Matters                                                                 |  |                                                        | 57   | 
|           |  | Legal Matters                                                                         |  |                                                        | 58   | 
|           |  | Risk Management Activities                                                            |  |                                                        | 58   | 
|           |  | Critical Accounting Policies                                                          |  |                                                        | 60   | 
|           |  |                                                                                      
|ITEM 3.    |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                            |  |                                                        | 61   | 
|ITEM 4.    |  | CONTROLS AND PROCEDURES                                                               |  |                                                        | 61   | 
|           |  |                                                                                      
|PART II.   |  | OTHER INFORMATION                                                                     |  |                                                        |      | 
|ITEM 1.    |  | LEGAL PROCEEDINGS                                                                     |  |                                                        | 62   | 
|ITEM 1A.   |  | RISK FACTORS                                                                          |  |                                                        | 63   | 
|ITEM 2.    |  | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS                           |  |                                                        | 64   | 
|ITEM 5.    |  | OTHER INFORMATION                                                                     |  |                                                        | 64   | 
|ITEM 6.    |  | EXHIBITS                                                                              |  |                                                        | 65   | 
|           |  |                                                                                      
|SIGNATURES |  |                                                                                       |  |                                                        | 66   | 



1



---

##### Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



|                                                    |  |                    |         |  |      |  |         | 
|--------------------------------------------------- |  | ------------------ | ------- |  | ---- |  | ------- | 
|                                                    |  | (Unaudited)        |        
|                                                    |  | Three Months Ended |        
|                                                    |  | March 31,          |        
|(in millions, except per share amounts)             |  | 2011               |         |  | 2010 | 
|Operating Revenues                                  |  |                    |         |  |      |  |         | 
|Electric                                            |  |                    | $ 2,617 |  |      |  | $ 2,510 | 
|Natural gas                                         |  |                    | 980     |  |      |  | 965     | 
|                                                    |  |                    |         |  |      |  |         | 
|Total operating revenues                            |  |                    | 3,597   |  |      |  | 3,475   | 
|                                                    |  |                    |         |  |      |  |         | 
|Operating Expenses                                  |  |                    |         |  |      |  |         | 
|Cost of electricity                                 |  |                    | 888     |  |      |  | 920     | 
|Cost of natural gas                                 |  |                    | 508     |  |      |  | 495     | 
|Operating and maintenance                           |  |                    | 1,226   |  |      |  | 991     | 
|Depreciation, amortization, and decommissioning     |  |                    | 491     |  |      |  | 451     | 
|                                                    |  |                    |         |  |      |  |         | 
|Total operating expenses                            |  |                    | 3,113   |  |      |  | 2,857   | 
|                                                    |  |                    |         |  |      |  |         | 
|Operating Income                                    |  |                    | 484     |  |      |  | 618     | 
|Interest income                                     |  |                    | 2       |  |      |  | 2       | 
|Interest expense                                    |  |                    | (177)   |  |      |  | (168)   | 
|Other income (expense), net                         |  |                    | 17      |  |      |  | (6)     | 
|                                                    |  |                    |         |  |      |  |         | 
|Income Before Income Taxes                          |  |                    | 326     |  |      |  | 446     | 
|Income tax provision                                |  |                    | 124     |  |      |  | 185     | 
|                                                    |  |                    |         |  |      |  |         | 
|Net Income                                          |  |                    | 202     |  |      |  | 261     | 
|Preferred stock dividend requirement of subsidiary  |  |                    | 3       |  |      |  | 3       | 
|                                                    |  |                    |         |  |      |  |         | 
|Income Available for Common Shareholders            |  |                    | $  199  |  |      |  | $  258  | 
|                                                    |  |                    |         |  |      |  |         | 
|Weighted Average Common Shares Outstanding, Basic   |  |                    | 396     |  |      |  | 371     | 
|                                                    |  |                    |         |  |      |  |         | 
|Weighted Average Common Shares Outstanding, Diluted |  |                    | 397     |  |      |  | 389     | 
|                                                    |  |                    |         |  |      |  |         | 
|Net Earnings Per Common Share, Basic                |  |                    | $ 0.50  |  |      |  | $ 0.69  | 
|                                                    |  |                    |         |  |      |  |         | 
|Net Earnings Per Common Share, Diluted              |  |                    | $ 0.50  |  |      |  | $ 0.67  | 
|                                                    |  |                    |         |  |      |  |         | 
|Dividends Declared Per Common Share                 |  |                    | $ 0.46  |  |      |  | $ 0.46  | 
|                                                    |  |                    |         |  |      |  |         | 

See accompanying Notes to the Condensed Consolidated Financial Statements.



2



---

##### Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



|                                                                                                                         |  |               |          |  |                  |  |          | 
|------------------------------------------------------------------------------------------------------------------------ |  | ------------- | -------- |  | ---------------- |  | -------- | 
|                                                                                                                         |  | (Unaudited)   |         
|                                                                                                                         |  | Balance At    |         
|(in millions)                                                                                                            |  | March 31,2011 |          |  | December 31,2010 | 
|ASSETS                                                                                                                   |  |               |          |  |                  |  |          | 
|Current Assets                                                                                                           |  |               |          |  |                  |  |          | 
|Cash and cash equivalents                                                                                                |  |               | $ 240    |  |                  |  | $ 291    | 
|Restricted cash ($35 and $38 related to energy recovery bonds at March 31, 2011 and December 31, 2010,
respectively)     |  |               | 431      |  |                  |  | 563      | 
|Accounts receivable                                                                                                      |  |               |          |  |                  |  |          | 
|Customers (net of allowance for doubtful accounts of $85 and $81 at March 31, 2011 and December 31, 2010,
respectively)  |  |               | 922      |  |                  |  | 944      | 
|Accrued unbilled revenue                                                                                                 |  |               | 616      |  |                  |  | 649      | 
|Regulatory balancing accounts                                                                                            |  |               | 1,293    |  |                  |  | 1,105    | 
|Other                                                                                                                    |  |               | 814      |  |                  |  | 794      | 
|Regulatory assets                                                                                                        |  |               | 580      |  |                  |  | 599      | 
|Inventories                                                                                                              |  |               |          |  |                  |  |          | 
|Gas stored underground and fuel oil                                                                                      |  |               | 78       |  |                  |  | 152      | 
|Materials and supplies                                                                                                   |  |               | 214      |  |                  |  | 205      | 
|Income taxes receivable                                                                                                  |  |               | 35       |  |                  |  | 47       | 
|Other                                                                                                                    |  |               | 248      |  |                  |  | 193      | 
|                                                                                                                         |  |               |          |  |                  |  |          | 
|Total current assets                                                                                                     |  |               | 5,471    |  |                  |  | 5,542    | 
|                                                                                                                         |  |               |          |  |                  |  |          | 
|Property, Plant, and Equipment                                                                                           |  |               |          |  |                  |  |          | 
|Electric                                                                                                                 |  |               | 34,068   |  |                  |  | 33,508   | 
|Gas                                                                                                                      |  |               | 11,482   |  |                  |  | 11,382   | 
|Construction work in progress                                                                                            |  |               | 1,369    |  |                  |  | 1,384    | 
|Other                                                                                                                    |  |               | 14       |  |                  |  | 15       | 
|                                                                                                                         |  |               |          |  |                  |  |          | 
|Total property, plant, and equipment                                                                                     |  |               | 46,933   |  |                  |  | 46,289   | 
|Accumulated depreciation                                                                                                 |  |               | (15,061) |  |                  |  | (14,840) | 
|                                                                                                                         |  |               |          |  |                  |  |          | 
|Net property, plant, and equipment                                                                                       |  |               | 31,872   |  |                  |  | 31,449   | 
|                                                                                                                         |  |               |          |  |                  |  |          | 
|Other Noncurrent Assets                                                                                                  |  |               |          |  |                  |  |          | 
|Regulatory assets ($645 and $735 related to energy recovery bonds at March 31, 2011 and December 31, 2010,
respectively) |  |               | 5,655    |  |                  |  | 5,846    | 
|Nuclear decommissioning trusts                                                                                           |  |               | 2,054    |  |                  |  | 2,009    | 
|Income taxes receivable                                                                                                  |  |               | 566      |  |                  |  | 565      | 
|Other                                                                                                                    |  |               | 641      |  |                  |  | 614      | 
|                                                                                                                         |  |               |          |  |                  |  |          | 
|Total other noncurrent assets                                                                                            |  |               | 8,916    |  |                  |  | 9,034    | 
|                                                                                                                         |  |               |          |  |                  |  |          | 
|TOTAL ASSETS                                                                                                             |  |               | $ 46,259 |  |                  |  | $ 46,025 | 
|                                                                                                                         |  |               |          |  |                  |  |          | 

See accompanying Notes to the Condensed Consolidated Financial Statements.



3



---

##### Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------- | -------- |  | ------------ |  | -------- | 
|                                                                                                                                                                    |  | (Unaudited) |         
|                                                                                                                                                                    |  | Balance At  |         
|                                                                                                                                                                    |  | March 31,   |          |  | December 31, | 
|(in millions, except share amounts)                                                                                                                                 |  | 2011        |          |  | 2010         | 
|LIABILITIES AND EQUITY                                                                                                                                              |  |             |          |  |              |  |          | 
|Current Liabilities                                                                                                                                                 |  |             |          |  |              |  |          | 
|Short-term borrowings                                                                                                                                               |  |             | $ 1,288  |  |              |  | $ 853    | 
|Long-term debt, classified as current                                                                                                                               |  |             | 922      |  |              |  | 809      | 
|Energy recovery bonds, classified as current                                                                                                                        |  |             | 409      |  |              |  | 404      | 
|Accounts payable                                                                                                                                                    |  |             |          |  |              |  |          | 
|Trade creditors                                                                                                                                                     |  |             | 974      |  |              |  | 1,129    | 
|Disputed claims and customer refunds                                                                                                                                |  |             | 691      |  |              |  | 745      | 
|Regulatory balancing accounts                                                                                                                                       |  |             | 531      |  |              |  | 256      | 
|Other                                                                                                                                                               |  |             | 520      |  |              |  | 379      | 
|Interest payable                                                                                                                                                    |  |             | 784      |  |              |  | 862      | 
|Income taxes payable                                                                                                                                                |  |             | 128      |  |              |  | 77       | 
|Deferred income taxes                                                                                                                                               |  |             | 79       |  |              |  | 113      | 
|Other                                                                                                                                                               |  |             | 1,446    |  |              |  | 1,558    | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|Total current liabilities                                                                                                                                           |  |             | 7,772    |  |              |  | 7,185    | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|Noncurrent Liabilities                                                                                                                                              |  |             |          |  |              |  |          | 
|Long-term debt                                                                                                                                                      |  |             | 10,294   |  |              |  | 10,906   | 
|Energy recovery bonds                                                                                                                                               |  |             | 321      |  |              |  | 423      | 
|Regulatory liabilities                                                                                                                                              |  |             | 4,584    |  |              |  | 4,525    | 
|Pension and other postretirement benefits                                                                                                                           |  |             | 2,288    |  |              |  | 2,234    | 
|Asset retirement obligations                                                                                                                                        |  |             | 1,583    |  |              |  | 1,586    | 
|Deferred income taxes                                                                                                                                               |  |             | 5,721    |  |              |  | 5,547    | 
|Other                                                                                                                                                               |  |             | 2,030    |  |              |  | 2,085    | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|Total noncurrent liabilities                                                                                                                                        |  |             | 26,821   |  |              |  | 27,306   | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|Commitments and Contingencies (Note 10)                                                                                                                             |  |             |          |  |              |  |          | 
|Equity                                                                                                                                                              |  |             |          |  |              |  |          | 
|Shareholders Equity                                                                                                                                                |  |             |          |  |              |  |          | 
|Preferred stock                                                                                                                                                     |  |             | -        |  |              |  | -        | 
|Common stock, no par value, authorized 800,000,000 shares, 397,453,525 shares outstanding at March 31, 2011 and
395,227,205 shares outstanding at December 31, 2010 |  |             | 6,983    |  |              |  | 6,878    | 
|Reinvested earnings                                                                                                                                                 |  |             | 4,624    |  |              |  | 4,606    | 
|Accumulated other comprehensive loss                                                                                                                                |  |             | (193)    |  |              |  | (202)    | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|Total shareholders equity                                                                                                                                          |  |             | 11,414   |  |              |  | 11,282   | 
|Noncontrolling Interest  Preferred Stock of Subsidiary                                                                                                             |  |             | 252      |  |              |  | 252      | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|Total equity                                                                                                                                                        |  |             | 11,666   |  |              |  | 11,534   | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 
|TOTAL LIABILITIES AND EQUITY                                                                                                                                        |  |             | $ 46,259 |  |              |  | $ 46,025 | 
|                                                                                                                                                                    |  |             |          |  |              |  |          | 

See accompanying Notes to the Condensed Consolidated Financial Statements.



4



---

##### Table of Contents

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



|                                                                                  |  |                    |         |  |      |  |         | 
|--------------------------------------------------------------------------------- |  | ------------------ | ------- |  | ---- |  | ------- | 
|                                                                                  |  | (Unaudited)        |        
|                                                                                  |  | Three Months Ended |        
|                                                                                  |  | March 31,          |        
|(in millions)                                                                     |  | 2011               |         |  | 2010 | 
|Cash Flows from Operating Activities                                              |  |                    |         |  |      |  |         | 
|Net income                                                                        |  |                    | $ 202   |  |      |  | $ 261   | 
|Adjustments to reconcile net income to net cash provided by operating activities: |  |                    |         |  |      |  |         | 
|Depreciation, amortization, and decommissioning                                   |  |                    | 550     |  |      |  | 506     | 
|Allowance for equity funds used during construction                               |  |                    | (20)    |  |      |  | (28)    | 
|Deferred income taxes and tax credits, net                                        |  |                    | 99      |  |      |  | 137     | 
|Other                                                                             |  |                    | (15)    |  |      |  | 26      | 
|Effect of changes in operating assets and liabilities:                            |  |                    |         |  |      |  |         | 
|Accounts receivable                                                               |  |                    | 35      |  |      |  | 114     | 
|Inventories                                                                       |  |                    | 65      |  |      |  | 59      | 
|Accounts payable                                                                  |  |                    | 182     |  |      |  | 87      | 
|Income taxes receivable/payable                                                   |  |                    | 34      |  |      |  | 69      | 
|Other current assets and liabilities                                              |  |                    | (205)   |  |      |  | (319)   | 
|Regulatory assets, liabilities, and balancing accounts, net                       |  |                    | (10)    |  |      |  | (376)   | 
|Other noncurrent assets and liabilities                                           |  |                    | 171     |  |      |  | (141)   | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net cash provided by operating activities                                         |  |                    | 1,088   |  |      |  | 395     | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Cash Flows from Investing Activities                                              |  |                    |         |  |      |  |         | 
|Capital expenditures                                                              |  |                    | (945)   |  |      |  | (855)   | 
|Decrease in restricted cash                                                       |  |                    | 132     |  |      |  | 4       | 
|Proceeds from sales and maturities of nuclear decommissioning trust investments   |  |                    | 726     |  |      |  | 337     | 
|Purchases of nuclear decommissioning trust investments                            |  |                    | (735)   |  |      |  | (343)   | 
|Other                                                                             |  |                    | (61)    |  |      |  | 9       | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net cash used in investing activities                                             |  |                    | (883)   |  |      |  | (848)   | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Cash Flows from Financing Activities                                              |  |                    |         |  |      |  |         | 
|Net issuances of commercial paper, net of discount of $1 in 2011                  |  |                    | 415     |  |      |  | 418     | 
|Long-term debt matured                                                            |  |                    | (500)   |  |      |  | -       | 
|Energy recovery bonds matured                                                     |  |                    | (97)    |  |      |  | (93)    | 
|Common stock issued                                                               |  |                    | 82      |  |      |  | 10      | 
|Common stock dividends paid                                                       |  |                    | (174)   |  |      |  | (157)   | 
|Other                                                                             |  |                    | 18      |  |      |  | 6       | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net cash provided by (used in) financing activities                               |  |                    | (256)   |  |      |  | 184     | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net change in cash and cash equivalents                                           |  |                    | (51)    |  |      |  | (269)   | 
|Cash and cash equivalents at January 1                                            |  |                    | 291     |  |      |  | 527     | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Cash and cash equivalents at March 31                                             |  |                    | $ 240   |  |      |  | $ 258   | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Supplemental disclosures of cash flow information                                 |  |                    |         |  |      |  |         | 
|Cash paid for:                                                                    |  |                    |         |  |      |  |         | 
|Interest, net of amounts capitalized                                              |  |                    | $ (215) |  |      |  | $ (193) | 
|Supplemental disclosures of noncash investing and financing activities            |  |                    |         |  |      |  |         | 
|Common stock dividends declared but not yet paid                                  |  |                    | $ 181   |  |      |  | $ 169   | 
|Capital expenditures financed through accounts payable                            |  |                    | 174     |  |      |  | 215     | 
|Noncash common stock issuances                                                    |  |                    | 6       |  |      |  | -       | 

See accompanying Notes
to the Condensed Consolidated Financial Statements.



5



---

##### Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



|                                                |  |                    |         |  |      |  |         | 
|----------------------------------------------- |  | ------------------ | ------- |  | ---- |  | ------- | 
|                                                |  | (Unaudited)        |        
|                                                |  | Three Months Ended |        
|                                                |  | March 31,          |        
|(in millions)                                   |  | 2011               |         |  | 2010 | 
|Operating Revenues                              |  |                    |         |  |      |  |         | 
|Electric                                        |  |                    | $ 2,616 |  |      |  | $ 2,510 | 
|Natural gas                                     |  |                    | 980     |  |      |  | 965     | 
|                                                |  |                    |         |  |      |  |         | 
|Total operating revenues                        |  |                    | 3,596   |  |      |  | 3,475   | 
|                                                |  |                    |         |  |      |  |         | 
|Operating Expenses                              |  |                    |         |  |      |  |         | 
|Cost of electricity                             |  |                    | 888     |  |      |  | 920     | 
|Cost of natural gas                             |  |                    | 508     |  |      |  | 495     | 
|Operating and maintenance                       |  |                    | 1,226   |  |      |  | 990     | 
|Depreciation, amortization, and decommissioning |  |                    | 490     |  |      |  | 451     | 
|                                                |  |                    |         |  |      |  |         | 
|Total operating expenses                        |  |                    | 3,112   |  |      |  | 2,856   | 
|                                                |  |                    |         |  |      |  |         | 
|Operating Income                                |  |                    | 484     |  |      |  | 619     | 
|Interest income                                 |  |                    | 2       |  |      |  | 2       | 
|Interest expense                                |  |                    | (171)   |  |      |  | (156)   | 
|Other income (expense), net                     |  |                    | 17      |  |      |  | (6)     | 
|                                                |  |                    |         |  |      |  |         | 
|Income Before Income Taxes                      |  |                    | 332     |  |      |  | 459     | 
|Income tax provision                            |  |                    | 131     |  |      |  | 195     | 
|                                                |  |                    |         |  |      |  |         | 
|Net Income                                      |  |                    | 201     |  |      |  | 264     | 
|Preferred stock dividend requirement            |  |                    | 3       |  |      |  | 3       | 
|                                                |  |                    |         |  |      |  |         | 
|Income Available for Common Stock               |  |                    | $  198  |  |      |  | $  261  | 
|                                                |  |                    |         |  |      |  |         | 

See accompanying Notes to the Condensed Consolidated Financial Statements.



6



---

##### Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



|                                                                                                                         |  |             |          |  |              |  |          | 
|------------------------------------------------------------------------------------------------------------------------ |  | ----------- | -------- |  | ------------ |  | -------- | 
|                                                                                                                         |  | (Unaudited) |         
|                                                                                                                         |  | Balance At  |         
|                                                                                                                         |  | March 31,   |          |  | December 31, | 
|(in millions)                                                                                                            |  | 2011        |          |  | 2010         | 
|ASSETS                                                                                                                   |  |             |          |  |              |  |          | 
|Current Assets                                                                                                           |  |             |          |  |              |  |          | 
|Cash and cash equivalents                                                                                                |  |             | $  52    |  |              |  | $  51    | 
|Restricted cash ($35 and $38 related to energy recovery bonds at March 31, 2011 and December 31, 2010,
respectively)     |  |             | 431      |  |              |  | 563      | 
|Accounts receivable                                                                                                      |  |             |          |  |              |  |          | 
|Customers (net of allowance for doubtful accounts of $85 and $81 at March 31, 2011 and December 31, 2010,
respectively)  |  |             | 922      |  |              |  | 944      | 
|Accrued unbilled revenue                                                                                                 |  |             | 616      |  |              |  | 649      | 
|Regulatory balancing accounts                                                                                            |  |             | 1,293    |  |              |  | 1,105    | 
|Other                                                                                                                    |  |             | 842      |  |              |  | 856      | 
|Regulatory assets                                                                                                        |  |             | 580      |  |              |  | 599      | 
|Inventories                                                                                                              |  |             |          |  |              |  |          | 
|Gas stored underground and fuel oil                                                                                      |  |             | 78       |  |              |  | 152      | 
|Materials and supplies                                                                                                   |  |             | 214      |  |              |  | 205      | 
|Income taxes receivable                                                                                                  |  |             | 43       |  |              |  | 48       | 
|Other                                                                                                                    |  |             | 243      |  |              |  | 190      | 
|                                                                                                                         |  |             |          |  |              |  |          | 
|Total current assets                                                                                                     |  |             | 5,314    |  |              |  | 5,362    | 
|                                                                                                                         |  |             |          |  |              |  |          | 
|Property, Plant, and Equipment                                                                                           |  |             |          |  |              |  |          | 
|Electric                                                                                                                 |  |             | 34,068   |  |              |  | 33,508   | 
|Gas                                                                                                                      |  |             | 11,482   |  |              |  | 11,382   | 
|Construction work in progress                                                                                            |  |             | 1,369    |  |              |  | 1,384    | 
|                                                                                                                         |  |             |          |  |              |  |          | 
|Total property, plant, and equipment                                                                                     |  |             | 46,919   |  |              |  | 46,274   | 
|Accumulated depreciation                                                                                                 |  |             | (15,047) |  |              |  | (14,826) | 
|                                                                                                                         |  |             |          |  |              |  |          | 
|Net property, plant, and equipment                                                                                       |  |             | 31,872   |  |              |  | 31,448   | 
|                                                                                                                         |  |             |          |  |              |  |          | 
|Other Noncurrent Assets                                                                                                  |  |             |          |  |              |  |          | 
|Regulatory assets ($645 and $735 related to energy recovery bonds at March 31, 2011 and December 31, 2010,
respectively) |  |             | 5,655    |  |              |  | 5,846    | 
|Nuclear decommissioning trusts                                                                                           |  |             | 2,054    |  |              |  | 2,009    | 
|Income taxes receivable                                                                                                  |  |             | 614      |  |              |  | 614      | 
|Other                                                                                                                    |  |             | 364      |  |              |  | 400      | 
|                                                                                                                         |  |             |          |  |              |  |          | 
|Total other noncurrent assets                                                                                            |  |             | 8,687    |  |              |  | 8,869    | 
|                                                                                                                         |  |             |          |  |              |  |          | 
|TOTAL ASSETS                                                                                                             |  |             | $ 45,873 |  |              |  | $ 45,679 | 
|                                                                                                                         |  |             |          |  |              |  |          | 

See accompanying Notes to the Condensed Consolidated Financial Statements.



7



---

##### Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS



|                                                                                                                                  |  |             |          |  |              |  |          | 
|--------------------------------------------------------------------------------------------------------------------------------- |  | ----------- | -------- |  | ------------ |  | -------- | 
|                                                                                                                                  |  | (Unaudited) |         
|                                                                                                                                  |  | Balance At  |         
|                                                                                                                                  |  | March 31,   |          |  | December 31, | 
|(in millions, except share amounts)                                                                                               |  | 2011        |          |  | 2010         | 
|LIABILITIES AND SHAREHOLDERS EQUITY                                                                                              |  |             |          |  |              |  |          | 
|Current Liabilities                                                                                                               |  |             |          |  |              |  |          | 
|Short-term borrowings                                                                                                             |  |             | $ 1,288  |  |              |  | $ 853    | 
|Long-term debt, classified as current                                                                                             |  |             | 922      |  |              |  | 809      | 
|Energy recovery bonds, classified as current                                                                                      |  |             | 409      |  |              |  | 404      | 
|Accounts payable                                                                                                                  |  |             |          |  |              |  |          | 
|Trade creditors                                                                                                                   |  |             | 974      |  |              |  | 1,129    | 
|Disputed claims and customer refunds                                                                                              |  |             | 691      |  |              |  | 745      | 
|Regulatory balancing accounts                                                                                                     |  |             | 531      |  |              |  | 256      | 
|Other                                                                                                                             |  |             | 539      |  |              |  | 390      | 
|Interest payable                                                                                                                  |  |             | 774      |  |              |  | 857      | 
|Income taxes payable                                                                                                              |  |             | 137      |  |              |  | 116      | 
|Deferred income taxes                                                                                                             |  |             | 87       |  |              |  | 118      | 
|Other                                                                                                                             |  |             | 1,249    |  |              |  | 1,349    | 
|                                                                                                                                  |  |             |          |  |              |  |          | 
|Total current liabilities                                                                                                         |  |             | 7,601    |  |              |  | 7,026    | 
|                                                                                                                                  |  |             |          |  |              |  |          | 
|Noncurrent Liabilities                                                                                                            |  |             |          |  |              |  |          | 
|Long-term debt                                                                                                                    |  |             | 9,945    |  |              |  | 10,557   | 
|Energy recovery bonds                                                                                                             |  |             | 321      |  |              |  | 423      | 
|Regulatory liabilities                                                                                                            |  |             | 4,584    |  |              |  | 4,525    | 
|Pension and other postretirement benefits                                                                                         |  |             | 2,227    |  |              |  | 2,174    | 
|Asset retirement obligations                                                                                                      |  |             | 1,583    |  |              |  | 1,586    | 
|Deferred income taxes                                                                                                             |  |             | 5,833    |  |              |  | 5,659    | 
|Other                                                                                                                             |  |             | 1,965    |  |              |  | 2,008    | 
|                                                                                                                                  |  |             |          |  |              |  |          | 
|Total noncurrent liabilities                                                                                                      |  |             | 26,458   |  |              |  | 26,932   | 
|                                                                                                                                  |  |             |          |  |              |  |          | 
|Commitments and Contingencies (Note 10)                                                                                           |  |             |          |  |              |  |          | 
|Shareholders Equity                                                                                                              |  |             |          |  |              |  |          | 
|Preferred stock                                                                                                                   |  |             | 258      |  |              |  | 258      | 
|Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at March 31, 2011 and
December 31, 2010 |  |             | 1,322    |  |              |  | 1,322    | 
|Additional paid-in capital                                                                                                        |  |             | 3,306    |  |              |  | 3,241    | 
|Reinvested earnings                                                                                                               |  |             | 7,114    |  |              |  | 7,095    | 
|Accumulated other comprehensive loss                                                                                              |  |             | (186)    |  |              |  | (195)    | 
|                                                                                                                                  |  |             |          |  |              |  |          | 
|Total shareholders equity                                                                                                        |  |             | 11,814   |  |              |  | 11,721   | 
|                                                                                                                                  |  |             |          |  |              |  |          | 
|TOTAL LIABILITIES AND SHAREHOLDERS EQUITY                                                                                        |  |             | $ 45,873 |  |              |  | $ 45,679 | 
|                                                                                                                                  |  |             |          |  |              |  |          | 

See accompanying Notes to the Condensed Consolidated Financial Statements.



8



---

##### Table of Contents

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



|                                                                                  |  |                    |         |  |      |  |         | 
|--------------------------------------------------------------------------------- |  | ------------------ | ------- |  | ---- |  | ------- | 
|                                                                                  |  | (Unaudited)        |        
|                                                                                  |  | Three Months Ended |        
|                                                                                  |  | March 31,          |        
|(in millions)                                                                     |  | 2011               |         |  | 2010 | 
|Cash Flows from Operating Activities                                              |  |                    |         |  |      |  |         | 
|Net income                                                                        |  |                    | $ 201   |  |      |  | $ 264   | 
|Adjustments to reconcile net income to net cash provided by operating activities: |  |                    |         |  |      |  |         | 
|Depreciation, amortization, and decommissioning                                   |  |                    | 534     |  |      |  | 491     | 
|Allowance for equity funds used during construction                               |  |                    | (20)    |  |      |  | (28)    | 
|Deferred income taxes and tax credits, net                                        |  |                    | 99      |  |      |  | 138     | 
|Other                                                                             |  |                    | (15)    |  |      |  | 26      | 
|Effect of changes in operating assets and liabilities:                            |  |                    |         |  |      |  |         | 
|Accounts receivable                                                               |  |                    | 69      |  |      |  | 114     | 
|Inventories                                                                       |  |                    | 65      |  |      |  | 59      | 
|Accounts payable                                                                  |  |                    | 190     |  |      |  | 94      | 
|Income taxes receivable/payable                                                   |  |                    | 34      |  |      |  | 77      | 
|Other current assets and liabilities                                              |  |                    | (196)   |  |      |  | (325)   | 
|Regulatory assets, liabilities, and balancing accounts, net                       |  |                    | (10)    |  |      |  | (376)   | 
|Other noncurrent assets and liabilities                                           |  |                    | 144     |  |      |  | (126)   | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net cash provided by operating activities                                         |  |                    | 1,095   |  |      |  | 408     | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Cash Flows from Investing Activities                                              |  |                    |         |  |      |  |         | 
|Capital expenditures                                                              |  |                    | (945)   |  |      |  | (855)   | 
|Decrease in restricted cash                                                       |  |                    | 132     |  |      |  | 4       | 
|Proceeds from sales and maturities of nuclear decommissioning trust investments   |  |                    | 726     |  |      |  | 337     | 
|Purchases of nuclear decommissioning trust investments                            |  |                    | (735)   |  |      |  | (343)   | 
|Other                                                                             |  |                    | 7       |  |      |  | 5       | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net cash used in investing activities                                             |  |                    | (815)   |  |      |  | (852)   | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Cash Flows from Financing Activities                                              |  |                    |         |  |      |  |         | 
|Net issuances of commercial paper, net of discount of $1 in 2011                  |  |                    | 415     |  |      |  | 418     | 
|Long-term debt matured                                                            |  |                    | (500)   |  |      |  | -       | 
|Energy recovery bonds matured                                                     |  |                    | (97)    |  |      |  | (93)    | 
|Preferred stock dividends paid                                                    |  |                    | (4)     |  |      |  | (4)     | 
|Common stock dividends paid                                                       |  |                    | (179)   |  |      |  | (179)   | 
|Equity contribution                                                               |  |                    | 65      |  |      |  | 20      | 
|Other                                                                             |  |                    | 21      |  |      |  | 8       | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net cash provided by (used in) financing activities                               |  |                    | (279)   |  |      |  | 170     | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Net change in cash and cash equivalents                                           |  |                    | 1       |  |      |  | (274)   | 
|Cash and cash equivalents at January 1                                            |  |                    | 51      |  |      |  | 334     | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Cash and cash equivalents at March 31                                             |  |                    | $52     |  |      |  | $60     | 
|                                                                                  |  |                    |         |  |      |  |         | 
|Supplemental disclosures of cash flow information                                 |  |                    |         |  |      |  |         | 
|Cash paid for:                                                                    |  |                    |         |  |      |  |         | 
|Interest, net of amounts capitalized                                              |  |                    | $ (215) |  |      |  | $ (193) | 
|Supplemental disclosures of noncash investing and financing activities            |  |                    |         |  |      |  |         | 
|Capital expenditures financed through accounts payable                            |  |                    | $ 174   |  |      |  | $ 215   | 

See accompanying Notes to
the Condensed Consolidated Financial Statements.



9



---

##### Table of Contents

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation 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 is regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). The Utilitys accounts for electric and gas operations are
maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

This quarterly report on Form 10-Q is a
combined report of PG&E Corporation and the Utility that includes separate Condensed Consolidated Financial Statements for each company. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the
Utility. PG&E Corporations Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utilitys Condensed Consolidated Financial
Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally
accepted in the United States of America (GAAP) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission
(SEC) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporations and the Utilitys Condensed Consolidated Financial Statements reflect
all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented. The information at
December 31, 2010 in both PG&E Corporations and the Utilitys Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their
combined 2010 Annual Report on Form 10-K filed with the SEC on February 17, 2011. PG&E Corporations and the Utilitys combined 2010 Annual Report on Form 10-K, together with the information incorporated by reference into such
report, is referred to in this quarterly report as the 2010 Annual Report. This quarterly report should be read in conjunction with the 2010 Annual Report.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic
conditions that are difficult to predict. Some of the more critical estimates and assumptions relate to the Utilitys regulatory assets and liabilities, loss contingencies associated with environmental remediation and legal matters, asset
retirement obligations (AROs), and pension plan and other postretirement plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and
reasonable. Actual results could differ materially from those estimates.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the
Consolidated Financial Statements in the 2010 Annual Report. Any significant changes to those policies or new significant policies are described below.

Pension and Other Postretirement Benefits

PG&E Corporation and the
Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as pension benefits), contributory postretirement medical plans for eligible employees and retirees and their
eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as other benefits). PG&E Corporation and the Utility use a December 31 measurement date
for all plans.



10



---

##### Table of Contents

The net periodic benefit costs reflected in PG&E Corporations Condensed
Consolidated Statements of Income for the three months ended March 31, 2011 and 2010 were as follows:



|                                                                                                                                                                                                                              |  |                             |       |  |                             |  |       |      |  |  |      |  |  |  |      | 
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------------- | ----- |  | --------------------------- |  | ----- | ---- |  |  | ---- |  |  |  | ---- | 
|                                                                                                                                                                                                                              |  | Pension Benefits            |       |  | Other Benefits              | 
|                                                                                                                                                                                                                              |  | Three Months EndedMarch 31, |       |  | Three Months EndedMarch 31, | 
|(in millions)                                                                                                                                                                                                                 |  | 2011                        |       |  | 2010                        |  |       | 2011 |  |  | 2010 | 
|Service cost for benefits earned                                                                                                                                                                                              |  |                             | $ 82  |  |                             |  | $ 69  |      |  |  | $ 11 |  |  |  | $ 10 | 
|Interest cost                                                                                                                                                                                                                 |  |                             | 164   |  |                             |  | 161   |      |  |  | 23   |  |  |  | 23   | 
|Expected return on plan assets                                                                                                                                                                                                |  |                             | (167) |  |                             |  | (156) |      |  |  | (20) |  |  |  | (18) | 
|Amortization of transition obligation                                                                                                                                                                                         |  |                             | -     |  |                             |  | -     |      |  |  | 6    |  |  |  | 6    | 
|Amortization of prior service cost                                                                                                                                                                                            |  |                             | 9     |  |                             |  | 13    |      |  |  | 6    |  |  |  | 6    | 
|Amortization of unrecognized loss                                                                                                                                                                                             |  |                             | 12    |  |                             |  | 11    |      |  |  | 1    |  |  |  | 1    | 
|                                                                                                                                                                                                                              |  |                             |       |  |                             |  |       |      |  |  |      |  |  |  |      | 
|Net periodic benefit cost                                                                                                                                                                                                     |  |                             | 100   |  |                             |  | 98    |      |  |  | 27   |  |  |  | 28   | 
|Less: transfer to regulatory account(1)                                                                                                                                                                                       |  |                             | (36)  |  |                             |  | (58)  |      |  |  | -    |  |  |  | -    | 
|                                                                                                                                                                                                                              |  |                             |       |  |                             |  |       |      |  |  |      |  |  |  |      | 
|Total                                                                                                                                                                                                                         |  |                             | $ 64  |  |                             |  | $ 40  |      |  |  | $ 27 |  |  |  | $ 28 | 
|                                                                                                                                                                                                                              |  |                             |       |  |                             |  |       |      |  |  |      |  |  |  |      | 
|(1) The Utility recorded $36 million and $58 million for the three month periods ended March 31, 2011 and 2010, respectively, to a regulatory account as the amounts are
probable of recovery from customers in future rates. | 

There was no material difference between PG&E Corporations and the Utilitys consolidated net periodic benefit costs for
the three months ended March 31, 2011 and 2010.

Variable Interest Entities

The Utility has contracts to purchase energy and capacity from variable interest entities (VIEs). The Utility evaluated these
contracts and determined that it either does not have a variable interest in the VIE or it is not the primary beneficiary of the VIE where a variable interest exists. The determination of whether the Utility has a variable interest in a VIE includes
an analysis of the impact the power purchase agreement has on the variability in the VIEs gross margin. The primary beneficiary determination considers which entity has the power to direct the activities of the VIE most significant to the
VIEs economic performance, and may include any decision-making rights associated with designing the VIE, dispatch rights, operating and maintenance activities, and re-marketing activities of the power plant after the end of the power purchase
agreement with the Utility. The Utilitys financial exposure is limited to the amount it pays for delivered electricity and capacity and the Utility has not provided any other support to these VIEs. (See Note 10 below.)

The Utility was the primary beneficiary of PG&E Energy Recovery Funding LLC (PERF) at March 31, 2011, and
consolidated PERF. The Utility is exposed to PERFs losses and returns through the Utilitys 100% equity investment in PERF and the Utility was involved in the design of PERF, which was an activity that was significant to PERFs
economic performance. The assets of PERF were $799 million at March 31, 2011 and primarily consisted of assets related to energy recovery bonds (ERBs), which are included in other noncurrent assets  regulatory assets in the
Condensed Consolidated Balance Sheets. The liabilities of PERF were $730 million at March 31, 2011 and consisted of energy recovery bonds, which are included in current and noncurrent liabilities in the Condensed Consolidated Balance Sheets.
(See Note 4 below.) The assets of PERF are only available to settle the liabilities of PERF and PERFs creditors have no recourse to the Utility.

As of March 31, 2011, 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 agreed to provide lease payments and investment contributions of up to $300 million to these companies in exchange for the right to receive the benefits from local rebates, federal
investment tax credits or grants, and a share of the customer payments made to these companies. As of March 31, 2011, PG&E Corporation had made total payments of $216 million under these tax equity agreements. These amounts are recorded in
other noncurrent assets  other in PG&E Corporations Condensed Consolidated Balance Sheets. PG&E Corporation holds a variable interest in these companies as a result of these agreements. PG&E Corporation was not the primary
beneficiary of, and did not consolidate any of these companies at March 31, 2011. In making this determination, PG&E Corporation evaluated which party has control over these companies significant economic activities such as designing
the companies, vendor selection, construction, customer selection, and re-marketing activities at the end of customer leases, and determined that these activities are under the control of these companies.



11



---

##### Table of Contents

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

As a regulated entity, the Utilitys rates are designed to recover the costs of providing service. The Utility capitalizes and
records, as a regulatory asset, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are expected to be
recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to
customers in the future are recorded as regulatory liabilities.

The Utility uses regulatory balancing accounts to accumulate
differences between actual billed and unbilled revenues and the Utilitys authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and
unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets.
Over-collections that are probable of being refunded to customers are recorded as regulatory balancing account liabilities.

Regulatory
Assets

Current Regulatory Assets

At March 31, 2011 and December 31, 2010, the Utility had current regulatory assets of $580 million and $599 million, respectively, consisting primarily of price risk management regulatory assets
and the Utilitys retained generation regulatory assets. The current portion of price risk management regulatory assets represents the deferral of unrealized losses related to price risk management derivative instruments with terms of one year
or less. (See Note 7 below.) The current portion of the Utilitys retained generation regulatory assets represents one year of amortization of these regulatory assets over the respective lives of the underlying generation facilities, consistent
with the period over which the related revenues are recognized.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:



|                                                  |  |                |         |  |                   |  |         | 
|------------------------------------------------- |  | -------------- | ------- |  | ----------------- |  | ------- | 
|                                                  |  | Balance at     |        
|(in millions)                                     |  | March 31, 2011 |         |  | December 31, 2010 | 
|Pension benefits                                  |  |                | $ 1,775 |  |                   |  | $ 1,759 | 
|Deferred income taxes                             |  |                | 1,285   |  |                   |  | 1,250   | 
|Utility retained generation                       |  |                | 649     |  |                   |  | 666     | 
|Energy recovery bonds                             |  |                | 645     |  |                   |  | 735     | 
|Environmental compliance costs                    |  |                | 412     |  |                   |  | 450     | 
|Price risk management                             |  |                | 331     |  |                   |  | 424     | 
|Unamortized loss, net of gain, on reacquired debt |  |                | 175     |  |                   |  | 181     | 
|Other                                             |  |                | 383     |  |                   |  | 381     | 
|                                                  |  |                |         |  |                   |  |         | 
|Total long-term regulatory assets                 |  |                | $ 5,655 |  |                   |  | $ 5,846 | 
|                                                  |  |                |         |  |                   |  |         | 

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized
for ratemaking purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 12 of the
Notes to the Consolidated Financial Statements in the 2010 Annual Report.)

The regulatory assets for deferred income taxes
represent deferred income tax benefits previously passed through to customers. The CPUC requires the Utility to pass through certain tax benefits to customers by reducing rates, thereby ignoring the effect of deferred taxes on rates. Based on
current regulatory ratemaking and income tax laws, the Utility expects to recover these regulatory assets over average plant depreciation lives of 1 to 45 years.

In connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utilitys proceeding under Chapter 11 of the U.S. Bankruptcy
Code (Chapter 11 Settlement Agreement), the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utilitys retained generation assets. The individual components of these regulatory assets are being amortized
over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 13 years.



12



---

##### Table of Contents

The regulatory asset for ERBs represents the refinancing of the regulatory asset provided
for in the Chapter 11 Settlement Agreement. (See Note 4 below.) The regulatory asset is amortized over the life of the bonds, consistent with the period over which the related revenues and bond-related expenses are recognized. The Utility expects to
fully recover this asset by the end of 2012 when the ERBs mature.

The regulatory assets for environmental compliance costs
represent estimated environmental compliance costs that the Utility expects to recover in future rates as actual environmental compliance costs are incurred. The Utility expects to recover these costs over the next 32 years. (See Note 10 below.)

Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management
derivative instruments with terms in excess of one year. (See Note 7 below.)

The regulatory assets for unamortized loss, net
of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the next 16 years, which is the remaining
amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

At March 31, 2011
and December 31, 2010, other primarily consisted of regulatory assets relating to ARO expenses for decommissioning of the Utilitys fossil-fuel generation facilities that are probable of future recovery through the ratemaking
process; costs that the Utility incurred in terminating a 30-year power purchase agreement which are being amortized and collected in rates through September 2014; costs incurred in relation to the Utilitys plan of reorganization under Chapter
11 that became effective in April 2004; and removal costs associated with the replacement of old electromechanical meters with SmartMeter devices.

In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return only on its retained generation regulatory assets
and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2011 and December 31, 2010, the Utility had current regulatory liabilities of $79 million and $81 million, respectively, primarily consisting of amounts that the Utility expects to
refund to customers for over-collected electric transmission rates and amounts that the Utility expects to refund to electric transmission customers for their portion of settlements the Utility entered into with various electricity suppliers to
resolve certain remaining Chapter 11 disputed claims. Current regulatory liabilities are included in current liabilities  other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities
are composed of the following:



|                                       |  |                |         |  |                   |  |         | 
|-------------------------------------- |  | -------------- | ------- |  | ----------------- |  | ------- | 
|                                       |  | Balance at     |        
|(in millions)                          |  | March 31, 2011 |         |  | December 31, 2010 | 
|Cost of removal obligation             |  |                | $ 3,296 |  |                   |  | $ 3,229 | 
|Recoveries in excess of ARO            |  |                | 643     |  |                   |  | 600     | 
|Public purpose programs                |  |                | 503     |  |                   |  | 573     | 
|Other                                  |  |                | 142     |  |                   |  | 123     | 
|                                       |  |                |         |  |                   |  |         | 
|Total long-term regulatory liabilities |  |                | $ 4,584 |  |                   |  | $ 4,525 | 
|                                       |  |                |         |  |                   |  |         | 

The regulatory liability for the Utilitys cost of removal obligations represents differences between
amounts collected in rates for asset removal costs and the asset removal costs recorded in accordance with GAAP.



13



---

##### Table of Contents

The regulatory liability for recoveries in excess of ARO represents differences between ARO
expenses recorded in accordance with GAAP and amounts collected in rates for the decommissioning of the Utilitys nuclear power facilities. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory
liability for recoveries in excess of ARO also represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. The public
purpose programs regulatory liabilities primarily consist of revenues collected from customers to pay for costs that the Utility expects to incur in the future under energy efficiency programs designed to encourage the manufacture, design,
distribution, and customer use of energy efficient appliances and other energy-using products; under the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural
properties; and under the Self-Generation Incentive program to promote distributed generation technologies installed on the customers side of the Utility meter that provide electricity and gas for all or a portion of that customers load.

Other at March 31, 2011 and December 31, 2010 primarily consisted of regulatory liabilities related to
the gain associated with the Utilitys acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered into with Mirant Corporation, insurance recoveries for hazardous
substance remediation, and the price risk management regulatory liabilities representing the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year. (See Note 7 below.).

Regulatory Balancing Accounts

The Utilitys current regulatory balancing accounts represent the amounts expected to be received from or refunded to the Utilitys customers through authorized rate adjustments within the next
12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in other noncurrent assets  regulatory assets and noncurrent liabilities  regulatory liabilities in the
Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, net



|                                          |  |                      |       |  |                   |  |       | 
|----------------------------------------- |  | -------------------- | ----- |  | ----------------- |  | ----- | 
|                                          |  | Receivable (Payable) |      
|                                          |  | Balance at           |      
|(in millions)                             |  | March 31, 2011       |       |  | December 31, 2010 | 
|Utility generation                        |  |                      | $ 439 |  |                   |  | $ 303 | 
|Distribution revenue adjustment mechanism |  |                      | 241   |  |                   |  | 145   | 
|Public purpose programs                   |  |                      | 188   |  |                   |  | 164   | 
|Hazardous substance                       |  |                      | 57    |  |                   |  | 38    | 
|Gas fixed cost                            |  |                      | (89)  |  |                   |  | 56    | 
|Energy procurement                        |  |                      | (91)  |  |                   |  | (25)  | 
|Energy recovery bonds                     |  |                      | (110) |  |                   |  | (34)  | 
|Other                                     |  |                      | 127   |  |                   |  | 202   | 
|                                          |  |                      |       |  |                   |  |       | 
|Total regulatory balancing accounts, net  |  |                      | $ 762 |  |                   |  | $ 849 | 
|                                          |  |                      |       |  |                   |  |       | 

The utility generation balancing account is used to record and recover the authorized revenue requirements
associated with Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The distribution revenue adjustment mechanism balancing account is used to record and recover the authorized electric
distribution revenue requirements and certain other electric distribution-related authorized costs. The Utilitys recovery of these revenue requirements is independent, or decoupled, from the volume of sales; therefore, the Utility
recognizes revenue evenly over the year, even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During the colder months of winter there is generally an under-collection in these balancing
accounts due to lower electricity sales and lower rates. During the warmer months of summer there is generally an over-collection due to higher electricity sales and higher rates.

The public purpose programs balancing accounts are primarily used to track the recovery of the authorized public purpose program revenue
requirements and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research,
development, and demonstration programs; and renewable energy programs.



14



---

##### Table of Contents

The hazardous substance balancing accounts are used to track recoverable hazardous substance
clean up costs through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs. The current balance represents eligible remediation costs incurred by the Utility during 2010 that will be
recovered through an annual true-up filing with the CPUC in January 2012. (See Note 10 below.)

The gas fixed cost balancing
account is used to track the recovery of CPUC-authorized gas distribution revenue requirements and certain other gas distribution-related costs. Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts
discussed above, the Utilitys recovery of these revenue requirements is decoupled from the volume of sales. During the colder months of winter there is generally an over-collection in this balancing account due to higher natural gas sales.
During the warmer months of summer there is generally an under-collection due to lower natural gas sales.

The Utility is
generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs. The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to
incur during the following year. The Utilitys electric rates are set to recover such expected costs.

The ERB balancing
account records the benefits and costs associated with ERBs that are provided to, or received from, customers. This account ensures that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits
received by the Utility after the second series of ERBs was issued.

At March 31, 2011 and
December 31, 2010, other primarily consisted of balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeterTMadvanced metering project.

NOTE 4: DEBT

PG&E Corporation

Credit Facility

At March 31, 2011, PG&E Corporation had no cash borrowings outstanding under its $187 million revolving credit facility.

Utility

Credit
Facilities

At March 31, 2011, the Utility had no cash borrowings outstanding under its $1.9 billion and $750
million revolving credit facilities.

At March 31, 2011, the Utility had $315 million of letters of credit outstanding
under its $1.9 billion revolving credit facility.

The Utilitys revolving credit facilities also provide liquidity
support for commercial paper offerings. At March 31, 2011, the Utility had $1.0 billion of commercial paper outstanding at an average yield of 0.39%.

Other Short-term Borrowings

At March 31, 2011, the interest
rate on the Utilitys $250 million principal amount of Floating Rate Senior Notes, due October 11, 2011, was 0.88%. The interest rate for the Floating Rate Senior Notes is equal to the three-month LIBOR plus 0.58% and resets quarterly. On
April 11, 2011, the interest rate was reset to 0.87%.

Energy Recovery Bonds

In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion. The proceeds of the ERBs were used by PERF to
purchase from the Utility the right, known as recovery property, to be paid a specified amount from a dedicated rate component to be collected from the Utilitys electricity customers. The total amount of ERB principal outstanding
was $730 million at March 31, 2011.



15



---

##### Table of Contents

While PERF is a wholly owned subsidiary of the Utility, it is legally separate from the
Utility. The assets (including the recovery property) of PERF are not available to creditors of the Utility or PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

NOTE 5: EQUITY

PG&E Corporations and the Utilitys changes in equity for the three months ended March 31, 2011 were as follows:



|                                                   |  |                  |          |  |                           |  |          | 
|-------------------------------------------------- |  | ---------------- | -------- |  | ------------------------- |  | -------- | 
|                                                   |  | PG&E Corporation |          |  | Utility                   | 
|(in millions)                                      |  | TotalEquity      |          |  | TotalShareholders Equity | 
|Balance at December 31, 2010                       |  |                  | $ 11,534 |  |                           |  | $ 11,721 | 
|Net income                                         |  |                  | 202      |  |                           |  | 201      | 
|Common stock issued                                |  |                  | 88       |  |                           |  | -        | 
|Share-based compensation expense                   |  |                  | 15       |  |                           |  | -        | 
|Common stock dividends declared                    |  |                  | (181)    |  |                           |  | (179)    | 
|Preferred stock dividend requirement               |  |                  | -        |  |                           |  | (3)      | 
|Preferred stock dividend requirement of subsidiary |  |                  | (3)      |  |                           |  | -        | 
|Other comprehensive income                         |  |                  | 9        |  |                           |  | 9        | 
|Equity contribution                                |  |                  | -        |  |                           |  | 65       | 
|Other                                              |  |                  | 2        |  |                           |  | -        | 
|                                                   |  |                  |          |  |                           |  |          | 
|Balance at March 31, 2011                          |  |                  | $ 11,666 |  |                           |  | $ 11,814 | 
|                                                   |  |                  |          |  |                           |  |          | 

For the three months ended March 31, 2011, PG&E Corporation issued 2,032,223 shares of common stock
upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan.

For
the three months ended March 31, 2011, PG&E Corporation contributed equity of $65 million to the Utility in order to maintain the 52% common equity ratio authorized by the CPUC and to ensure that the Utility has adequate capital to fund its
capital expenditures.

Comprehensive Income

Comprehensive income consists of net income and other comprehensive income, which includes certain changes in equity that are excluded from net income. Specifically, adjustments for employee benefit
plans, net of tax, are recorded in other comprehensive income.



|                                                                                                                                                                             |  |                             |       |  |                             |  |       |      |  |  |       |  |  |  |       | 
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------------- | ----- |  | --------------------------- |  | ----- | ---- |  |  | ----- |  |  |  | ----- | 
|                                                                                                                                                                             |  | PG&E Corporation            |       |  | Utility                     | 
|                                                                                                                                                                             |  | Three Months EndedMarch
31, |       |  | Three Months EndedMarch 31, | 
|(in millions)                                                                                                                                                                |  | 2011                        |       |  | 2010                        |  |       | 2011 |  |  | 2010  | 
|Net income                                                                                                                                                                   |  |                             | $ 202 |  |                             |  | $ 261 |      |  |  | $ 201 |  |  |  | $ 264 | 
|Employee benefit plan adjustment, net of tax(1)                                                                                                                              |  |                             | 9     |  |                             |  | (80)  |      |  |  | 9     |  |  |  | (80)  | 
|                                                                                                                                                                             |  |                             |       |  |                             |  |       |      |  |  |       |  |  |  |       | 
|Comprehensive Income                                                                                                                                                         |  |                             | $ 211 |  |                             |  | $ 181 |      |  |  | $ 210 |  |  |  | $ 184 | 
|                                                                                                                                                                             |  |                             |       |  |                             |  |       |      |  |  |       |  |  |  |       | 
|(1)These balances are net of income tax expense of $6 million and net of income tax benefit of $55 million for the three months ended March 31, 2011 and 2010,
respectively. | 

NOTE 6: EARNINGS PER SHARE

For the three months ended March 31, 2011, PG&E Corporations basic earnings per common share (EPS) was
calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. For the three months ended March 31, 2010, PG&E Corporation calculated EPS using the two-class
method because PG&E Corporations convertible subordinated notes that were then outstanding were considered to be participating securities under applicable accounting standards. Under the two-class method, the sum of distributed earnings to
common shareholders and undistributed earnings allocated to common shareholders is divided by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings were allocated to both
common shares and participating securities. Since all of PG&E Corporations convertible subordinated notes have been converted into common stock there were no participating securities outstanding as of March 31, 2011.



16



---

##### Table of Contents

The following is a reconciliation of PG&E Corporations income available for common
shareholders and weighted average shares of common stock outstanding for calculating basic EPS:



|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------------- | ------ |  | ---- |  | ------ | 
|                                                                                                                                                                                                                              |  | Three Months EndedMarch 31, |       
|(in millions, except per share amounts)                                                                                                                                                                                       |  | 2011                        |        |  | 2010 | 
|Basic                                                                                                                                                                                                                         |  |                             |        |  |      | 
|Income Available for Common Shareholders                                                                                                                                                                                      |  |                             | $ 199  |  |      |  | $ 258  | 
|Less: distributed earnings to common shareholders                                                                                                                                                                             |  |                             | 181    |  |      |  | 169    | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|Undistributed earnings                                                                                                                                                                                                        |  |                             | $ 18   |  |      |  | $ 89   | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|Allocation of undistributed earnings to common shareholders                                                                                                                                                                   |  |                             |        |  |      |  |        | 
|Distributed earnings to common shareholders                                                                                                                                                                                   |  |                             | $ 181  |  |      |  | $ 169  | 
|Undistributed earnings allocated to common shareholders                                                                                                                                                                       |  |                             | 18     |  |      |  | 85     | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|Total common shareholders earnings                                                                                                                                                                                            |  |                             | $ 199  |  |      |  | $ 254  | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|Weighted average common shares outstanding, basic                                                                                                                                                                             |  |                             | 396    |  |      |  | 371    | 
|Convertible subordinated notes                                                                                                                                                                                                |  |                             | -      |  |      |  | 16     | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|Weighted average common shares outstanding and participating securities                                                                                                                                                       |  |                             | 396    |  |      |  | 387    | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|Net earnings per common share, basic                                                                                                                                                                                          |  |                             |        |  |      |  |        | 
|Distributed earnings, basic(1)                                                                                                                                                                                                |  |                             | $ 0.46 |  |      |  | $ 0.46 | 
|Undistributed earnings, basic                                                                                                                                                                                                 |  |                             | 0.04   |  |      |  | 0.23   | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|Total                                                                                                                                                                                                                         |  |                             | $ 0.50 |  |      |  | $ 0.69 | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|                                                                                                                                                                                                                              |  |                             |        |  |      |  |        | 
|(1) Distributed earnings, basic may differ from actual per
share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual, number of shares outstanding. | 

In calculating diluted EPS, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding
stock-based compensation. During 2010, when PG&E Corporations convertible subordinated notes were outstanding, the if-converted method was also applied in calculating diluted EPS to reflect the dilutive effect of the
convertible subordinated notes to the extent that the impact was dilutive when compared to basic EPS. As noted above, these convertible subordinated notes were fully converted into shares of common stock in 2010 and were not outstanding during 2011.

The following is a reconciliation of PG&E Corporations income available for common shareholders and weighted
average shares of common stock outstanding for calculating diluted EPS:



|                                                                       |  |                    |        |  |      |  |        | 
|---------------------------------------------------------------------- |  | ------------------ | ------ |  | ---- |  | ------ | 
|                                                                       |  | Three months ended |       
|                                                                       |  | March 31,          |       
|(in millions, except per share amounts)                                |  | 2011               |        |  | 2010 | 
|Diluted                                                                |  |                    |        |  |      | 
|Income available for common shareholders                               |  |                    | $ 199  |  |      |  | $ 258  | 
|Add earnings impact of assumed conversion of participating securities: |  |                    |        |  |      |  |        | 
|Interest expense on convertible subordinated notes, net of tax         |  |                    | -      |  |      |  | 4      | 
|                                                                       |  |                    |        |  |      |  |        | 
|Income available for common shareholders and assumed conversion        |  |                    | $ 199  |  |      |  | $ 262  | 
|                                                                       |  |                    |        |  |      |  |        | 
|                                                                       |  |                    |        |  |      |  |        | 
|Weighted average common shares outstanding, basic                      |  |                    | 396    |  |      |  | 371    | 
|Add incremental shares from assumed conversions:                       |  |                    |        |  |      |  |        | 
|Convertible subordinated notes                                         |  |                    | -      |  |      |  | 16     | 
|Employee share-based compensation                                      |  |                    | 1      |  |      |  | 2      | 
|                                                                       |  |                    |        |  |      |  |        | 
|Weighted average common shares outstanding, diluted                    |  |                    | 397    |  |      |  | 389    | 
|                                                                       |  |                    |        |  |      |  |        | 
|Total earnings per common share, diluted                               |  |                    | $ 0.50 |  |      |  | $ 0.67 | 
|                                                                       |  |                    |        |  |      |  |        | 

For each of the periods presented above, the calculation of outstanding shares on a diluted basis excluded
an insignificant amount of options and securities that were antidilutive.



17



---

##### Table of Contents

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

The Utility and PG&E Corporation, mainly through its ownership of the Utility, face market risk primarily related to electricity and natural gas commodity prices. All of the Utilitys risk
management activities involving derivatives reduce the volatility of commodity costs on behalf of its customers. The CPUC allows the Utility to charge customer rates designed to recover the Utilitys reasonable costs of providing services,
including the cost to obtain and deliver electricity and natural gas.

The Utility uses both derivative and non-derivative
contracts in managing its customers exposure to commodity-related price risk, including:



| |  |  | forward contracts that commit the Utility to purchase a commodity in the future;
| | - |  | --------------------------------------------------------------------------------



| |  |  | swap agreements that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity;
and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | option contracts that provide the Utility with the right to buy a commodity at a predetermined price.
| | - |  | -----------------------------------------------------------------------------------------------------

These instruments are not held for speculative purposes and are subject to certain regulatory requirements.

Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the Condensed
Consolidated Balance Sheets. As long as the ratemaking mechanisms discussed above remain in place and the Utilitys risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from
customers, in rates, all costs related to commodity-related price risk-related derivative instruments. Therefore, all unrealized gains and losses associated with the change in fair value of these derivative instruments are deferred and recorded
within the Utilitys regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on derivative instruments related to price risk for commodities are recorded in the cost of
electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.

The Utility elects the normal purchase and sale exception for qualifying commodity-related derivative instruments. Derivative instruments that require physical delivery, are probable of physical delivery
in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception.
The fair value of instruments that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

Electricity Procurement

The Utility obtains electricity from a
diverse mix of resources, including third-party power purchase agreements, amounts allocated to the Utilitys customers under power purchase contracts that have been entered into by the California Department of Water Resources
(DWR), and its own electricity generation facilities. The amount of electricity the Utility needs to procure to meet the demands of customers is subject to change for a number of reasons, including:



| |  |  | periodic expirations or terminations of existing electricity purchase contracts, including the DWRs contracts;
| | - |  | ---------------------------------------------------------------------------------------------------------------



| |  |  | the execution of new electricity purchase contracts;
| | - |  | ----------------------------------------------------



| |  |  | the amount of electricity generated by the Utilitys two nuclear generation units at the Diablo Canyon power plant (Diablo Canyon)
which can be affected by planned and unplanned outages, the availability of nuclear fuel, and regulatory or legislative actions that requires the temporary or permanent curtailment or cessation of nuclear operations;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | fluctuation in the output of hydroelectric and other renewable energy resource facilities owned or under contract;
| | - |  | ------------------------------------------------------------------------------------------------------------------



| |  |  | changes in the Utilitys customers electricity demands due to customer and economic growth or decline, weather, implementation of new energy
efficiency and demand response programs, direct access, and community choice aggregation;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the acquisition, retirement, or closure of generation facilities owned by the Utility or others; and
| | - |  | ----------------------------------------------------------------------------------------------------



| |  |  | changes in market prices that make it more economical to purchase power in the market rather than use the Utilitys existing or contracted
resources to generate power.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------



18



---

##### Table of Contents

The Utility enters into third-party power purchase agreements to ensure sufficient
electricity to meet customer needs. The Utilitys third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments. The Utility elects to use
the normal purchase and sale exception for eligible derivative instruments.

A portion of the Utilitys third-party power
purchase agreements contain market-based pricing terms. In order to reduce the volatility in customer rates, the Utility has entered into financial swap contracts to effectively fix the price of future purchases and reduce the cash flow variability
associated with fluctuating electricity prices under some of those power purchase agreements. These financial swaps are considered derivative instruments.

Electric Transmission Congestion Revenue Rights

The California
Independent System Operator (CAISO) controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of
transmission congestion. The congestion revenue rights (CRRs) allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. The CAISO releases CRRs
through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities are allocated CRRs at no cost based on the customer demand or load they serve) and an auction phase (in which CRRs are
priced at market and available to all market participants). The Utility participates in the allocation and auction phases of the annual and monthly CRR processes. The CRRs held by the Utility are considered derivative instruments.

Natural Gas Procurement (Electric Fuels Portfolio)

The Utilitys electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed
electricity procurement contracts. In order to reduce the volatility in customer rates, the Utility purchases financial instruments such as swaps and options to reduce future cash flow variability associated with fluctuating natural gas prices.
These financial instruments are considered derivative instruments.

Natural Gas Procurement (Core Gas Supply Portfolio)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its residential and smaller
commercial customers known as core customers. (The Utility does not procure natural gas for industrial and large commercial, or non-core, customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and
seasonally. Consequently, varying volumes of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot market to balance such seasonal supply and demand. The Utility purchases financial instruments such as swaps
and options as part of its core winter hedging program in order to manage customer exposure to high gas prices during peak winter months. These financial instruments are considered derivative instruments.



19



---

##### Table of Contents

Volume of Derivative Activity

At March 31, 2011, the volumes of PG&E Corporations and the Utilitys outstanding derivative contracts were as
follows:



|                             |  |                           |  |                     |             |  |                                          |  |             |                                           |  |  |                           |  |  |  |            | 
|---------------------------- |  | ------------------------- |  | ------------------- | ----------- |  | ---------------------------------------- |  | ----------- | ----------------------------------------- |  |  | ------------------------- |  |  |  | ---------- | 
|                             |  |                           |  | Contract Volume (1) |            
|Underlying Product           |  | Instruments               |  | Less Than 1  Year   |             |  | Greater Than  1 Year butLess Than 3Years |  |             | Greater Than  3 Years butLess Than 5Years |  |  | Greater Than  5 Years (2) | 
|Natural Gas(3) (MMBtus(4))   |  | Forwards and Swaps        |  |                     | 483,012,276 |  |                                          |  | 299,055,015 |                                           |  |  | 13,642,500                |  |  |  | -          | 
|                             |  | Options                   |  |                     | 215,050,000 |  |                                          |  | 203,350,000 |                                           |  |  | 21,000,000                |  |  |  | -          | 
|Electricity
(Megawatt-hours) |  | Forwards and Swaps        |  |                     | 4,738,243   |  |                                          |  | 6,526,712   |                                           |  |  | 3,297,199                 |  |  |  | 4,674,168  | 
|                             |  | Options                   |  |                     | 415,450     |  |                                          |  | 24,540      |                                           |  |  | 264,348                   |  |  |  | 371,604    | 
|                             |  | Congestion Revenue Rights |  |                     | 68,367,041  |  |                                          |  | 72,547,614  |                                           |  |  | 72,642,249                |  |  |  | 90,055,284 | 
|                             |  |                           |  |                     |             |  |                                          |  |             |                                           |  |  |                           |  |  |  |            | 

(1)
Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.

(2) Derivatives in this category expire between 2016 and 2022.

(3)Amounts shown are for the combined
positions of the electric and core gas portfolios.

(4)Million British Thermal Units.

Presentation of Derivative
Instruments in the Financial Statements

In PG&E Corporations and the Utilitys Condensed Consolidated
Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists under a master netting agreement. The net balances include outstanding cash collateral associated with derivative positions.

At March 31, 2011, PG&E Corporations and the Utilitys outstanding derivative balances were as follows:



|                                                 |  |                                 |       |  |             |  |       |                        |  |  |                                 |  |  |  |       | 
|------------------------------------------------ |  | ------------------------------- | ----- |  | ----------- |  | ----- | ---------------------- |  |  | ------------------------------- |  |  |  | ----- | 
|(in millions)                                    |  | GrossDerivative    Balance 
(1) |       |  | Netting (2) |  |       | Cash    Collateral (2) |  |  | Total    Derivative    Balances | 
|Commodity Risk(PG&E Corporation and the Utility) | 
|Current assets other                            |  |                                 | 59    |  |             |  | (47)  |                        |  |  | 128                             |  |  |  | 140   | 
|Other noncurrent assets  other                  |  |                                 | 139   |  |             |  | (100) |                        |  |  | 42                              |  |  |  | 81    | 
|Current liabilities  other                      |  |                                 | (371) |  |             |  | 47    |                        |  |  | 135                             |  |  |  | (189) | 
|Noncurrent liabilities  other                   |  |                                 | (431) |  |             |  | 100   |                        |  |  | 48                              |  |  |  | (283) | 
|                                                 |  |                                 |       |  |             |  |       |                        |  |  |                                 |  |  |  |       | 
|Total commodity risk                             |  |                                 | (604) |  |             |  | -     |                        |  |  | 353                             |  |  |  | (251) | 
|                                                 |  |                                 |       |  |             |  |       |                        |  |  |                                 |  |  |  |       | 
|                                                 |  |                                 |       |  |             |  |       |                        |  |  |                                 |  |  |  |       | 

(1)See Note 8 of the Notes to the Condensed Consolidated Financial Statements for a discussion of the valuation techniques used to calculate the fair value of these instruments.

(2) Positions and cash collateral, by
counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.



20



---

##### Table of Contents

At December 31, 2010, PG&E Corporations and the Utilitys outstanding
derivative balances were as follows:



|                                                  |  |                                |         |  |             |  |        |                        |  |  |                                 |  |  |  |         | 
|------------------------------------------------- |  | ------------------------------ | ------- |  | ----------- |  | ------ | ---------------------- |  |  | ------------------------------- |  |  |  | ------- | 
|(in millions)                                     |  | Gross    Derivative    Balance |         |  | Netting (1) |  |        | Cash    Collateral (1) |  |  | Total    Derivative    Balances | 
|Commodity Risk (PG&E Corporation and the Utility) | 
|Current assets other                             |  |                                | $ 56    |  |             |  | $ (45) |                        |  |  | $ 79                            |  |  |  | $ 90    | 
|Other noncurrent assets  other                   |  |                                | 77      |  |             |  | (62)   |                        |  |  | 96                              |  |  |  | 111     | 
|Current liabilities  other                       |  |                                | (388)   |  |             |  | 45     |                        |  |  | 119                             |  |  |  | (224)   | 
|Noncurrent liabilities  other                    |  |                                | (486)   |  |             |  | 62     |                        |  |  | 130                             |  |  |  | (294)   | 
|                                                  |  |                                |         |  |             |  |        |                        |  |  |                                 |  |  |  |         | 
|Total commodity risk                              |  |                                | $ (741) |  |             |  | $ -    |                        |  |  | $ 424                           |  |  |  | $ (317) | 
|                                                  |  |                                |         |  |             |  |        |                        |  |  |                                 |  |  |  |         | 
|                                                  |  |                                |         |  |             |  |        |                        |  |  |                                 |  |  |  |         | 

(1)Positions and cash collateral, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.

Gains and losses recorded on PG&E Corporations and the Utilitys derivative instruments were as follows:



|                                                                                                                                                                                                                                                                                |  |                                               |                                               |  |      |  |         | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------------------------------- | --------------------------------------------- |  | ---- |  | ------- | 
|                                                                                                                                                                                                                                                                                |  | Commodity Risk(PG&E 
Corporation and Utility) |                                              
|                                                                                                                                                                                                                                                                                | 
|                                                                                                                                                                                                                                                                                |  | Three months ended March 31,                  |                                              
|(in millions)                                                                                                                                                                                                                                                                   |  | 2011                                          |                                               |  | 2010 | 
|Unrealized gain/(loss) - Regulatory assets and liabilities(1)                                                                                                                                                                                                                   |  |                                               | $ 137                                         |  |      |  | $ (289) | 
|Realized loss - Cost of electricity(2)                                                                                                                                                                                                                                          |  |                                               | (136)                                         |  |      |  | (106)   | 
|Realized loss - Cost of natural gas(2)                                                                                                                                                                                                                                          |  |                                               | (55)                                          |  |      |  | (39)    | 
|                                                                                                                                                                                                                                                                                |  |                                               |                                               |  |      |  |         | 
|Total commodity risk instruments                                                                                                                                                                                                                                                |  |                                               | $ (54)                                        |  |      |  | $ (434) | 
|                                                                                                                                                                                                                                                                                |  |                                               |                                               |  |      |  |         | 
|                                                                                                                                                                                                                                                                                |  |                                               | Other Risk Instruments(PG&E Corporation Only) | 
|                                                                                                                                                                                                                                                                                |  |                                               |                                               |  |      |  |         | 
|Other expense (income), net                                                                                                                                                                                                                                                     |  |                                               | $ -                                           |  |      |  | $ 1     | 
|                                                                                                                                                                                                                                                                                |  |                                               |                                               |  |      |  |         | 
|Total other risk instruments                                                                                                                                                                                                                                                    |  |                                               | $ -                                           |  |      |  | $ 1     | 
|                                                                                                                                                                                                                                                                                |  |                                               |                                               |  |      |  |         | 
|                                                                                                                                                                                                                                                                                |  |                                               |                                               |  |      |  |         | 
|(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded
to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. | 
|(2) These amounts are fully passed through to customers in rates. Accordingly, net income was
not impacted by realized amounts on these instruments.                                                                                                                            | 

Cash inflows and outflows associated with the settlement of all derivative instruments are included in operating cash flows on PG&E Corporations and the Utilitys Condensed Consolidated
Statements of Cash Flows.

The majority of the Utilitys commodity commodity-related derivative instruments contain
collateral posting provisions tied to the Utilitys credit rating from each of the major credit rating agencies. As of March 31, 2011, the Utilitys credit rating was investment grade. If the Utilitys credit rating were to fall
below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.



21



---

##### Table of Contents

At March 31, 2011, the additional cash collateral that the Utility would be required to
post if its credit risk-related contingency features were triggered was as follows:



|                                                                                                                                                                        |  |  |       | 
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  |  | ----- | 
|(in millions)                                                                                                                                                           |  |  |       | 
|Derivatives in a liability position with credit risk-related contingencies that are not fully
collateralized                                                            |  |  | (487) | 
|Related derivatives in an asset position                                                                                                                                |  |  | 12    | 
|Collateral posting in the normal course of business related to these derivatives                                                                                        |  |  | 16    | 
|                                                                                                                                                                        |  |  |       | 
|Net position of derivative contracts/additional collateral posting requirements (1)                                                                                     |  |  | (459) | 
|                                                                                                                                                                        |  |  |       | 
|                                                                                                                                                                        |  |  |       | 
|(1) This calculation excludes the impact of closed but unpaid
positions, as their settlement is not impacted by any of the Utilitys credit risk-related contingencies. | 

NOTE 8: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value.
Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be
determined based on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in
measuring fair value:

Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or
liabilities in active markets.

Level 2 - Other inputs that are directly or indirectly observable in the
marketplace.

Level 3 - Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when
measuring fair value.



22



---

##### Table of Contents

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation
and the Utility are summarized below (money market investments and assets held in rabbi trusts are held by PG&E Corporation and not the Utility):



|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|------------------------------------------ |  | ----------------------- | ------- |  | -------------------- |  | ----- | ------- |  |  | ----- |  |  | ------- | ------- |  | ------- |  | ------- | ------- |  |  | ----- |  |  |  | ----- |  |  |  | ------- | 
|                                           |  | Fair Value Measurements |        
|                                           |  | At March 31, 2011       |         |  | At December 31, 2010 | 
|(in millions)                              |  | Level 1                 |         |  | Level 2              |  |       | Level 3 |  |  | Total |  |  | Level 1 |         |  | Level 2 |  |         | Level 3 |  |  | Total | 
|Assets:                                    |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Money market investments                   |  |                         | $ 187   |  |                      |  | $ -   |         |  |  | $ -   |  |  |         | $ 187   |  |         |  | $ 138   |         |  |  | $ -   |  |  |  | $ -   |  |  |  | $ 138   | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Nuclear decommissioning trusts             |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|U.S. equity securities(1)                  |  |                         | 861     |  |                      |  | 8     |         |  |  | -     |  |  |         | 869     |  |         |  | 1,029   |         |  |  | 7     |  |  |  | -     |  |  |  | 1,036   | 
|Non-U.S. equity securities                 |  |                         | 360     |  |                      |  | -     |         |  |  | -     |  |  |         | 360     |  |         |  | 349     |         |  |  | -     |  |  |  | -     |  |  |  | 349     | 
|U.S. government and agency securities      |  |                         | 647     |  |                      |  | 159   |         |  |  | -     |  |  |         | 806     |  |         |  | 584     |         |  |  | 40    |  |  |  | -     |  |  |  | 624     | 
|Municipal securities                       |  |                         | -       |  |                      |  | 109   |         |  |  | -     |  |  |         | 109     |  |         |  | -       |         |  |  | 119   |  |  |  | -     |  |  |  | 119     | 
|Other fixed income securities              |  |                         | -       |  |                      |  | 113   |         |  |  | -     |  |  |         | 113     |  |         |  | -       |         |  |  | 66    |  |  |  | -     |  |  |  | 66      | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Total nuclear decommissioning trusts(2)    |  |                         | 1,868   |  |                      |  | 389   |         |  |  | -     |  |  |         | 2,257   |  |         |  | 1,962   |         |  |  | 232   |  |  |  | -     |  |  |  | 2,194   | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Price risk management instruments (Note 7) |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Electric(3)                                |  |                         | 119     |  |                      |  | 11    |         |  |  | -     |  |  |         | 130     |  |         |  | 130     |         |  |  | -     |  |  |  | -     |  |  |  | 130     | 
|Gas(4)                                     |  |                         | 8       |  |                      |  | -     |         |  |  | -     |  |  |         | 8       |  |         |  | 3       |         |  |  | -     |  |  |  | -     |  |  |  | 3       | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Total price risk management instruments    |  |                         | 127     |  |                      |  | 11    |         |  |  | -     |  |  |         | 138     |  |         |  | 133     |         |  |  | -     |  |  |  | -     |  |  |  | 133     | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Rabbi trusts                               |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Fixed income securities                    |  |                         | -       |  |                      |  | 24    |         |  |  | -     |  |  |         | 24      |  |         |  | -       |         |  |  | 24    |  |  |  | -     |  |  |  | 24      | 
|Life insurance contracts                   |  |                         | -       |  |                      |  | 65    |         |  |  | -     |  |  |         | 65      |  |         |  | -       |         |  |  | 65    |  |  |  | -     |  |  |  | 65      | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Total rabbi trusts                         |  |                         | -       |  |                      |  | 89    |         |  |  | -     |  |  |         | 89      |  |         |  | -       |         |  |  | 89    |  |  |  | -     |  |  |  | 89      | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Long-term disability trust                 |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|U.S. equity securities(1)                  |  |                         | 4       |  |                      |  | 20    |         |  |  | -     |  |  |         | 24      |  |         |  | 11      |         |  |  | 24    |  |  |  | -     |  |  |  | 35      | 
|Non-U.S. equity securities                 |  |                         | -       |  |                      |  | 8     |         |  |  | -     |  |  |         | 8       |  |         |  | -       |         |  |  | -     |  |  |  | -     |  |  |  | -       | 
|Corporate debt securities(1)               |  |                         | -       |  |                      |  | 145   |         |  |  | -     |  |  |         | 145     |  |         |  | -       |         |  |  | 150   |  |  |  | -     |  |  |  | 150     | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Total long-term disability trust           |  |                         | 4       |  |                      |  | 173   |         |  |  | -     |  |  |         | 177     |  |         |  | 11      |         |  |  | 174   |  |  |  | -     |  |  |  | 185     | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Total assets                               |  |                         | $ 2,186 |  |                      |  | $ 662 |         |  |  | $ -   |  |  |         | $ 2,848 |  |         |  | $ 2,244 |         |  |  | $ 495 |  |  |  | $ -   |  |  |  | $ 2,739 | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Liabilities:                               |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Price risk management instruments (Note 7) |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Electric(5)                                |  |                         | $ -     |  |                      |  | $ -   |         |  |  | $ 382 |  |  |         | $ 382   |  |         |  | $ -     |         |  |  | $ 5   |  |  |  | $ 403 |  |  |  | $ 408   | 
|Gas(6)                                     |  |                         | -       |  |                      |  | 1     |         |  |  | 6     |  |  |         | 7       |  |         |  | -       |         |  |  | 1     |  |  |  | 41    |  |  |  | 42      | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 
|Total liabilities                          |  |                         | $ -     |  |                      |  | $ 1   |         |  |  | $ 388 |  |  |         | $ 389   |  |         |  | $ -     |         |  |  | $ 6   |  |  |  | $ 444 |  |  |  | $ 450   | 
|                                           |  |                         |         |  |                      |  |       |         |  |  |       |  |  |         |         |  |         |  |         |         |  |  |       |  |  |  |       |  |  |  |         | 



| | (1) | Level 2 balances include commingled funds, which are comprised primarily of securities traded publicly on exchanges. Price quotes for the assets held
by the funds are readily observable and available.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (2) | Excludes $203 million and $185 million at March 31, 2011 and December 31, 2010, respectively, primarily related to deferred taxes on
appreciation of investment value.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) | Balances include the impact of netting adjustments of $321 million and $359 million to Level 1 at March 31, 2011 and December 31, 2010,
respectively and $70 million to Level 2 at March 31, 2011. Includes natural gas for electric portfolio.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (4) | Balances include the impact of netting adjustments of $40 million and $44 million to Level 1 at March 31, 2011 and December 31, 2010,
respectively. Includes natural gas for core customers.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (5) | Balances include the impact of netting adjustments of $66 million to Level 2 at December 31, 2010 and $(73) million and $(48) million to Level 3
at March 31, 2011 and December 31, 2010, respectively. Includes natural gas for electric portfolio.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (6) | Balances include the impact of netting adjustments of $(5) million and $3
million to Level 3 at March 31, 2011 and December 31, 2010, respectively. Includes natural gas for core customers.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



23



---

##### Table of Contents

Money Market Investments

PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality,
short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporations investments
in these money market funds are generally valued using unadjusted quotes in an active market for identical assets and are thus classified as Level 1. Money market funds are recorded as cash and cash equivalents in PG&E Corporations
Condensed Consolidated Balance Sheets.

Trust Assets

The assets held by the nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation plans, and the long-term disability trust are comprised primarily of equity
securities and debt securities. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Equity investments primarily include investments in common stock and commingled funds comprised of equity securities across multiple industry sectors in the U.S. and other regions of the world. Equity
securities are generally valued based on unadjusted prices in active markets for identical transactions and are classified as Level 1.

Debt securities are comprised primarily of fixed income securities that include U.S. government and agency securities, municipal securities, and corporate debt securities. U.S. government and agency
securities consist primarily of treasury securities that are classified as Level 1 as the fair value is determined by observable market prices in active markets. A market based valuation approach is generally used to estimate the fair value of debt
securities classified as Level 2. Under a market approach, fair values are determined based on evaluated pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model
generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

Price Risk Management Instruments

Price risk management
instruments include physical and financial derivative contracts, such as forwards, swaps, options, and CRRs that are either exchange-traded or over-the-counter traded. (See Note 7 above.)

Forwards and swaps that are valued using observable market prices for the underlying commodity or an identical instrument and are
classified as Level 1 or Level 2. Forwards and swaps that are valued using unobservable data are considered Level 3. These contracts are valued using either estimated basis adjustments from liquid trading points or techniques including extrapolation
from observable prices when a contract term extends beyond a period when market data is available.

All energy-related options
are classified as Level 3 and are valued using a standard option pricing model with various assumptions, including forward prices for the underlying commodity, time value at a risk free rate, and volatility. For periods in which market data is not
available, the Utility extrapolates these assumptions using internal models.

The Utility holds CRRs to hedge financial risk
of CAISO-imposed congestion charges in the day-ahead markets. CRRs are valued based on auction prices discounted at the risk free rate. Limited market data is available between auction dates; therefore, CRRs are classified as Level 3.

Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting
period. There were no significant transfers between levels for the three months ended March 31, 2011.



24



---

##### Table of Contents

Level 3 Reconciliation

The following table presents reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis for PG&E Corporation and the Utility (money market investments and
dividend participation rights are held by PG&E Corporation and not the Utility), using significant unobservable inputs (Level 3):



|                                                                    |  |                                      |         |  |               |  |     |                                 |  |  |                                     |  |  |                    |         |  |       |  |       |  |  |  |         | 
|------------------------------------------------------------------- |  | ------------------------------------ | ------- |  | ------------- |  | --- | ------------------------------- |  |  | ----------------------------------- |  |  | ------------------ | ------- |  | ----- |  | ----- |  |  |  | ------- | 
|                                                                    |  | For the three months ended March 31, |        
|                                                                    |  | 2011                                 |         |  | 2010          | 
|(in millions)                                                       |  | Price Risk  Management  Instruments  |         |  | Money  Market |  |     | Dividend  Participation  Rights |  |  | Price Risk  Management  Instruments |  |  | Other  Liabilities |         |  | Total | 
|                                                                    |  |                                      |         |  |               |  |     |                                 |  |  |                                     |  |  |                    |         |  |       |  |       |  |  |  |         | 
|Asset (liability) balance as of December 31                         |  |                                      | $ (444) |  |               |  | $ 4 |                                 |  |  | $ (12)                              |  |  |                    | $ (217) |  |       |  | $ (3) |  |  |  | $ (228) | 
|                                                                    |  |                                      |         |  |               |  |     |                                 |  |  |                                     |  |  |                    |         |  |       |  |       |  |  |  |         | 
|Realized and unrealized gains (losses):                             |  |                                      |         |  |               |  |     |                                 |  |  |                                     |  |  |                    |         |  |       |  |       |  |  |  |         | 
|Included in earnings                                                |  |                                      | -       |  |               |  | -   |                                 |  |  | -                                   |  |  |                    | -       |  |       |  | -     |  |  |  | -       | 
|Included in regulatory assets and liabilities or balancing accounts |  |                                      | 56      |  |               |  | -   |                                 |  |  | -                                   |  |  |                    | (119)   |  |       |  | 2     |  |  |  | (117)   | 
|                                                                    |  |                                      |         |  |               |  |     |                                 |  |  |                                     |  |  |                    |         |  |       |  |       |  |  |  |         | 
|Purchases, issuances, sales and settlements                         |  |                                      | -       |  |               |  | (4) |                                 |  |  | 5                                   |  |  |                    | -       |  |       |  | -     |  |  |  | 1       | 
|Transfers into Level 3                                              |  |                                      | -       |  |               |  | -   |                                 |  |  | -                                   |  |  |                    | -       |  |       |  | -     |  |  |  | -       | 
|Transfers out of Level 3                                            |  |                                      | -       |  |               |  | -   |                                 |  |  | -                                   |  |  |                    | -       |  |       |  | -     |  |  |  | -       | 
|                                                                    |  |                                      |         |  |               |  |     |                                 |  |  |                                     |  |  |                    |         |  |       |  |       |  |  |  |         | 
|Asset (liability) balance as of March 31                            |  |                                      | $ (388) |  |               |  | $ - |                                 |  |  | $ (7)                               |  |  |                    | $ (336) |  |       |  | $ (1) |  |  |  | $ (344) | 
|                                                                    |  |                                      |         |  |               |  |     |                                 |  |  |                                     |  |  |                    |         |  |       |  |       |  |  |  |         | 

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:



| |  |  | The fair values of cash, restricted cash and deposits, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the
Utilitys variable rate pollution control bond loan agreements approximate their carrying values at March 31, 2011 and December 31, 2010.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The fair values of the Utilitys fixed rate senior notes and fixed rate pollution control bond loan agreements, PG&E Corporations fixed
rate senior notes, and the ERBs issued by PERF were based on quoted market prices at March 31, 2011 and December 31, 2010.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The carrying amount and fair value of PG&E Corporations and the Utilitys debt instruments were as follows (the table below excludes financial instruments with carrying values that
approximate their fair values):



|                                                                              |  |                    |       |  |                      |  |        |                    |  |  |              |  |  |  |        | 
|----------------------------------------------------------------------------- |  | ------------------ | ----- |  | -------------------- |  | ------ | ------------------ |  |  | ------------ |  |  |  | ------ | 
|                                                                              |  | At March 31, 2011  |       |  | At December 31, 2010 | 
|(in millions)                                                                 |  | Carrying    Amount |       |  | FairValue(1)         |  |        | Carrying    Amount |  |  | FairValue(1) | 
|Debt (Note 4):                                                                |  |                    |       |  |                      |  |        |                    |  |  |              |  |  |  |        | 
|PG&E Corporation                                                              |  |                    | $ 349 |  |                      |  | $ 382  |                    |  |  | $ 349        |  |  |  | $ 383  | 
|Utility                                                                       |  |                    | 9,945 |  |                      |  | 10,524 |                    |  |  | 10,444       |  |  |  | 11,314 | 
|Energy recovery bonds (Note 4)                                                |  |                    | 730   |  |                      |  | 757    |                    |  |  | 827          |  |  |  | 862    | 
|(1)  Fair values are determined using readily available quoted market prices. | 



25



---

##### Table of Contents

Nuclear Decommissioning Trust Investments

The Utility classifies its investments held in the nuclear decommissioning trust as available-for-sale. As the day-to-day
investing activities of the trusts are managed by external investment managers, the Utility is unable to assert that it has the intent and ability to hold investments to maturity. Therefore, all unrealized losses are considered other-than-temporary
impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of
ARO. There is no impact on the Utilitys earnings or accumulated other comprehensive income. (See Note 3 above for further discussion.)

The following table provides a summary of available-for-sale investments held in the Utilitys nuclear decommissioning trusts:



|                                      |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|------------------------------------- |  | --------------- | ------- |  | ------------------------ |  | ----- | ------------------------- |  |  | ---------------------- |  |  |  | ------- | 
|(in millions)                         |  | Amortized  Cost |         |  | Total  Unrealized  Gains |  |       | Total  Unrealized  Losses |  |  | Estimated(1)Fair Value | 
|As of March 31, 2011                  |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|Equity securities                     |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|U.S.                                  |  |                 | $ 308   |  |                          |  | $ 562 |                           |  |  | $ (1)                  |  |  |  | $ 869   | 
|Non-U.S.                              |  |                 | 182     |  |                          |  | 179   |                           |  |  | (1)                    |  |  |  | 360     | 
|Debt securities                       |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|U.S. government and agency securities |  |                 | 759     |  |                          |  | 50    |                           |  |  | (3)                    |  |  |  | 806     | 
|Municipal securities                  |  |                 | 108     |  |                          |  | 1     |                           |  |  | -                      |  |  |  | 109     | 
|Other fixed income securities         |  |                 | 113     |  |                          |  | 1     |                           |  |  | (1)                    |  |  |  | 113     | 
|                                      |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|Total                                 |  |                 | $ 1,470 |  |                          |  | $ 793 |                           |  |  | $ (6)                  |  |  |  | $ 2,257 | 
|                                      |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|As of December 31, 2010               |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|Equity securities                     |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|U.S.                                  |  |                 | $ 509   |  |                          |  | $ 529 |                           |  |  | $ (2)                  |  |  |  | $ 1,036 | 
|Non-U.S.                              |  |                 | 180     |  |                          |  | 170   |                           |  |  | (1)                    |  |  |  | 349     | 
|Debt securities                       |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|U.S. government and agency securities |  |                 | 571     |  |                          |  | 55    |                           |  |  | (2)                    |  |  |  | 624     | 
|Municipal securities                  |  |                 | 119     |  |                          |  | 1     |                           |  |  | (1)                    |  |  |  | 119     | 
|Other fixed income securities         |  |                 | 65      |  |                          |  | 1     |                           |  |  | -                      |  |  |  | 66      | 
|                                      |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|Total                                 |  |                 | $ 1,444 |  |                          |  | $ 756 |                           |  |  | $ (6)                  |  |  |  | $ 2,194 | 
|                                      |  |                 |         |  |                          |  |       |                           |  |  |                        |  |  |  |         | 
|                                      | 

|    |  |                                                                                                                                                                       
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) |  | Excludes $203 million and $185 million at March 31, 2011 and December 31, 2010, respectively,
primarily related to deferred taxes on appreciation of investment value.

The debt securities mature on the
following schedule:



|                                    |  |                      |         | 
|----------------------------------- |  | -------------------- | ------- | 
|(in millions)                       |  | As of March 31, 2011 |        
|Less than 1 year                    |  |                      | $ 72    | 
|15 years                           |  |                      | 325     | 
|510 years                          |  |                      | 286     | 
|More than 10 years                  |  |                      | 345     | 
|                                    |  |                      |         | 
|Total maturities of debt securities |  |                      | $ 1,028 | 
|                                    |  |                      |         | 

The following table provides a summary of activity for the debt and equity securities:



|                                                                                |  |                    |       |  |                |  |       | 
|------------------------------------------------------------------------------- |  | ------------------ | ----- |  | -------------- |  | ----- | 
|                                                                                |  | Three Months Ended |      
|(in millions)                                                                   |  | March 31, 2011     |       |  | March 31, 2010 | 
|Proceeds from sales and maturities of nuclear decommissioning trust investments |  |                    | $ 726 |  |                |  | $ 337 | 
|Gross realized gains on sales of securities held as available-for-sale          |  |                    | 20    |  |                |  | 15    | 
|Gross realized losses on sales of securities held as available-for-sale         |  |                    | (4)   |  |                |  | (5)   | 



26



---

##### Table of Contents

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utilitys Chapter 11 Settlement Agreement seeking payment for energy supplied to
the Utilitys customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (PX) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various
FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and
the PX wholesale electricity markets between May 2000 and June 2001. At March 31, 2011 and December 31, 2010, the Utility held $384 million and $512 million in escrow, respectively, including interest earned, for payment of the remaining
net disputed claims. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

While
the FERC and judicial proceedings have been pending, the Utility entered into a number of settlements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utilitys refund claims against these
electricity suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. The
proceeds from these settlements, after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, will continue to be refunded to customers in rates. Additional settlement
discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers through resolution of the remaining disputed claims, either through settlement or the
conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

The following table presents the
changes in the remaining net disputed claims liability:



|                             |  |  |       | 
|---------------------------- |  |  | ----- | 
|(in millions)                |  |  |       | 
|Balance at December 31, 2010 |  |  | $ 934 | 
|Interest accrued             |  |  | 7     | 
|Less: supplier settlements   |  |  | (86)  | 
|                             |  |  |       | 
|Balance at March 31, 2011    |  |  | $ 855 | 
|                             |  |  |       | 

At March 31, 2011, the Utilitys net disputed claims liability was $855 million, consisting of
$691 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable  disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $658 million (classified on the
Condensed Consolidated Balance Sheets within interest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within accounts receivable  other).

Interest accrues on the net liability for disputed claims at the FERC-ordered rate, which is higher than the rate earned by
the Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers, this amount is not held in escrow. If the amount of interest accrued at the FERC-ordered
rate is greater than the amount of interest ultimately determined to be owed with respect to disputed claims, the Utility would refund to customers any excess net interest collected from customers. The amount of any interest that the Utility may be
required to pay will depend on the final amounts to be paid by the Utility with respect to the disputed claims and when such interest is paid.

PG&E Corporation and the Utility are unable to predict when the FERC or judicial proceedings that are still pending will be resolved, and the amount of any potential refunds that the Utility may
receive or the amount of disputed claims, including interest that the Utility will be required to pay.

NOTE 10: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the
Utilitys operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, environmental
compliance and remediation, tax matters, and legal matters.



27



---

##### Table of Contents

Commitments

Utility

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price
of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase.

At March 31, 2011, the undiscounted future expected power purchase agreement payments were as follows:



|              |  |  |          | 
|------------- |  |  | -------- | 
|(in millions) |  |  |          | 
|2011          |  |  | $ 2,076  | 
|2012          |  |  | 2,553    | 
|2013          |  |  | 3,004    | 
|2014          |  |  | 3,276    | 
|2015          |  |  | 3,478    | 
|Thereafter    |  |  | 54,390   | 
|              |  |  |          | 
|Total         |  |  | $ 68,777 | 
|              |  |  |          | 

Costs incurred by the Utility under power purchase agreements amounted to $587 million and $201 million for
the three months ended March 31, 2011 and 2010, respectively.

Some of the power purchase agreements that the Utility
entered into are treated as capital leases. The following table shows the future fixed capacity payments due under the contracts that are treated as capital leases. The fixed capacity payments are discounted to their present value in the table below
using the Utilitys incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.



|                                         |  |  |      |  
|---------------------------------------- |  |  | ---- | -
|(in millions)                            |  |  |      |  
|2011                                     |  |  | $ 43 |  
|2012                                     |  |  | 50   |  
|2013                                     |  |  | 50   |  
|2014                                     |  |  | 42   |  
|2015                                     |  |  | 38   |  
|Thereafter                               |  |  | 124  |  
|                                         |  |  |      |  
|Total fixed capacity payments            |  |  | 347  |  
|Less: amount representing interest       |  |  | (68  | )
|                                         |  |  |      |  
|Present value of fixed capacity payments |  |  | $279 |  
|                                         |  |  |      |  

Minimum lease payments associated with the lease obligation are included in cost of electricity on PG&E
Corporations and the Utilitys Condensed Consolidated Statements of Income. The timing of the recognition of the lease expense conforms to the ratemaking treatment for the Utilitys recovery of the cost of electricity. The contracts
that are treated as capital leases expire between April 2014 and September 2021.

At March 31, 2011 and December 31,
2010, current liabilities  other included $34 million and $34 million, respectively, and noncurrent liabilities  other included $245 million and $248 million, respectively. The corresponding assets at March 31, 2011 and
December 31, 2010 of $279 million and $282 million including accumulated amortization of $129 million and $126 million, respectively are included in property, plant, and equipment on PG&E Corporations and the Utilitys Condensed
Consolidated Balance Sheets.



28



---

##### Table of Contents

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers
and to fuel its owned-generation facilities. The contract lengths and quantities of the Utilitys portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation
from the points at which the Utility takes delivery (typically in Canada and the southwestern United States) to the points at which the Utilitys natural gas transportation system begins. In addition, the Utility has contracted for gas storage
services in northern California in order to better meet core customers winter peak loads. At March 31, 2011, the Utilitys undiscounted obligations for natural gas purchases, natural gas transportation services, and natural gas
storage were as follows:



|                                                                                                                                                                                                                                                                                                          |  |  |          | 
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  |  | -------- | 
|(in millions)                                                                                                                                                                                                                                                                                             |  |  |         
|2011                                                                                                                                                                                                                                                                                                      |  |  | $   659  | 
|2012                                                                                                                                                                                                                                                                                                      |  |  | 514      | 
|2013                                                                                                                                                                                                                                                                                                      |  |  | 258      | 
|2014                                                                                                                                                                                                                                                                                                      |  |  | 209      | 
|2015                                                                                                                                                                                                                                                                                                      |  |  | 195      | 
|Thereafter                                                                                                                                                                                                                                                                                                |  |  | 1,141    | 
|                                                                                                                                                                                                                                                                                                          |  |  |          | 
|Total(1)                                                                                                                                                                                                                                                                                                  |  |  | $  2,976 | 
|                                                                                                                                                                                                                                                                                                          |  |  |          | 
|                                                                                                                                                                                                                                                                                                         
|(1) Amounts above include firm transportation contracts for the Ruby Pipeline (a 1.5 billion
cubic feet per day (bcf/d) pipeline which is currently under construction and expected to become operational in the summer of 2011. The Utility has contracted for a capacity of approximately 0.4 bcf/d). | 

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $433 million and $553
million for the three months ended March 31, 2011 and March 31, 2010, respectively.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from one to 14
years and are intended to ensure long-term fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2016, while contracts for fuel fabrication services provide for
100% coverage of reactor requirements through 2017. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from
market-based prices to base prices that are escalated using published indices. New agreements are primarily based on forward market pricing.

At March 31, 2011, the undiscounted obligations under nuclear fuel agreements were as follows:



|              |  |  |        | 
|------------- |  |  | ------ | 
|(in millions) |  |  |       
|2011          |  |  | $  65  | 
|2012          |  |  | 83     | 
|2013          |  |  | 125    | 
|2014          |  |  | 143    | 
|2015          |  |  | 200    | 
|Thereafter    |  |  | 1,065  | 
|              |  |  |        | 
|Total         |  |  | $1,681 | 
|              |  |  |        | 

Payments for nuclear fuel amounted to $29 million and $53 million for the three months ended March 31,
2011 and March 31, 2010, respectively.

Contingencies

PG&E Corporation

PG&E Corporation retains a
guarantee related to certain obligations of its former subsidiary, National Energy and Gas Transmission, Inc. (NEGT), that were issued to the purchaser of an NEGT subsidiary company in 2000. PG&E Corporations primary remaining
exposure relates to any potential environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150 million. PG&E Corporation has not received any claims nor does it consider it
probable that any claims will be made under the guarantee. PG&E Corporation believes that its potential exposure under this guarantee would not have a material impact on its financial condition or results of operations.



29



---

##### Table of Contents

Utility

Energy Efficiency Programs and Incentive Ratemaking

On November 15,
2010, a proposed decision was issued that if, adopted by the CPUC, would modify the incentive mechanism that would apply to the 2010 through 2012 program cycle. Among other changes, the proposed modification would limit the total amount of the
incentive award or penalty that could be awarded to, or imposed on, all the investor-owned utilities to $189 million. If the proposed decision is adopted, the Utilitys opportunity to earn incentive revenues would be limited compared to the
mechanism that was in place for the 2006-2008 program cycle.

Spent Nuclear Fuel Storage Proceedings

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (DOE) and
electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in
exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utilitys two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay
(Humboldt Bay Unit 3).

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit
from the Nuclear Regulatory Commission (NRC) to build an on-site dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024. The construction of the dry cask storage facility is complete. During 2009 and 2010,
the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRCs issuance of the permit, which claimed that the NRC failed to adequately consider environmental impacts of a potential
terrorist attack at Diablo Canyon, was denied by the U.S. Court of Appeals for the Ninth Circuit on February 15, 2011.

As a
result of the DOEs failure to build a repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to
recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010.
The appeal was argued in the



30



---

##### Table of Contents

Federal Circuit Court of Appeals on March 10, 2011. Additionally, on August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to
recover all costs incurred since 2005 to build on-site storage facilities. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear operating units at Diablo Canyon and for its retired nuclear generation facility at Humboldt Bay Unit 3. The Utility has insurance
coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business
interruption coverage of up to $3.2 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL
suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $42 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of terrorism cause damages covered under any of the nuclear insurance policies issued by
NEIL to any NEIL member, the maximum recovery under all those nuclear insurance policies may not exceed NEILs policy limit of $3.2 billion within a 12-month period plus any additional amounts recovered by NEIL for these losses from
reinsurance. Certain acts of terrorism may be certified by the Secretary of the Treasury. For damages caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy
limit of $3.2 billion for each insured loss caused by these certified acts of terrorism. The $3.2 billion amount would not be shared as is described above for damages caused by acts of terrorism that have not been certified.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur
during the transportation of material to and from Diablo Canyon are limited to $12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The
balance of the $12.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $235 million per nuclear incident under this program, with payments in each year
limited to a maximum of $35 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

The Price-Anderson Act does not apply to public liability claims that arise from nuclear incidents that occur during shipping
of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricators facility. Such claims are covered by nuclear liability policies purchased by the enricher and the fuel fabricator as well as by
separate suppliers and transporters (S&T) insurance policies. The Utility has a S&T policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident. The
Utility could incur losses that are either not covered by insurance or exceed the amount of insurance available.

In addition,
the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53 million of liability
insurance.

Legal Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and
lawsuits. In addition, the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations.

PG&E Corporation and the Utility record a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. PG&E
Corporation and the Utility evaluate the range of reasonably estimated costs and record a liability based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates
of any additional reasonably possible losses, are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a
particular matter. In assessing such contingencies, PG&E Corporations and the Utilitys policy is to exclude anticipated legal costs.

The accrued liability associated with claims and litigation, regulatory proceedings, and other legal matters (other than third-party liability claims related to the San Bruno accident as discussed below)
totaled $87 million at March 31, 2011 and $55 million at December 31, 2010 and is included in PG&E



31



---

##### Table of Contents

Corporations and the Utilitys current liabilities  other in the Condensed Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not
believe that losses associated with legal matters would have a material adverse impact on their financial condition, results of operations, or cash flows after consideration of the accrued liability at March 31, 2011.

Explosion and Fires in San Bruno, California

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility, ruptured in a residential area located in the City of San Bruno,
California (San Bruno accident). The ensuing explosion and fire resulted in the deaths of eight people, injuries to numerous individuals, and extensive property damage. The NTSB has issued several public statements regarding its
investigation of the San Bruno accident but has not yet determined the cause of the pipeline rupture. During the quarter ended March 31, 2011, the CPUC initiated an investigation pertaining to safety recordkeeping for the Utilitys gas
transmission pipeline that ruptured in San Bruno, as well as for its entire gas transmission system, which is discussed below.

In addition to these investigations, as of March 31, 2011, 74 tort lawsuits on behalf of approximately 224 plaintiffs, including two
class action lawsuits, have been filed against PG&E Corporation and the Utility. Five of the lawsuits on behalf of 11 plaintiffs were filed in the San Francisco County Superior Court; the rest were filed in San Mateo County Superior Court. These
tort lawsuits seek compensation for personal injury and property damage and seek other relief. The class action lawsuits allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. Several
other residents of San Bruno also have submitted damage claims to the Utility. These lawsuits have been coordinated and assigned to one judge in the San Mateo County Superior Court.

The Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident, including
personal injury and property damage claims, damage to infrastructure, and other damage claims. The provision also included estimated liabilities to reimburse the City of San Bruno for costs it incurred related to the fires caused by the pipeline
rupture. As of March 31, 2011 and December 31, 2010, $198 million and $214 million, respectively, was accrued as a liability in PG&E Corporations and the Utilitys Condensed Consolidated Balance Sheets. The change in the
liability from December 31, 2010 was due to payments made to third parties.

The Utility currently estimates that it may
incur as much as $400 million for third-party claims. As more information becomes known, including information resulting from the NTSB and CPUC investigations, managements estimates and assumptions regarding the amount of third-party liability
incurred in connection with the San Bruno accident may change. It is possible that a change in estimate could have a material adverse impact on PG&E Corporations and the Utilitys financial condition, results of operations, or cash
flows.

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10
million deductible. Although PG&E Corporation and the Utility currently consider it likely that a significant portion of the costs the Utility incurs for third-party claims relating to the San Bruno accident will ultimately be covered through
this insurance, no amount for insurance recoveries has been recorded as of March 31, 2011. PG&E Corporation and the Utility are unable to predict the amount and timing of insurance recoveries.

CPUC Investigations

On
February 24, 2011, the CPUC issued an order instituting a formal investigation (OII) pertaining to safety recordkeeping for the Utilitys gas transmission pipeline that ruptured in San Bruno on September 9, 2010, as well
as for its entire gas transmission system. The CPUC stated that in deciding to issue the OII, it had relied on the NTSBs public preliminary reports issued in connection with its investigation of the San Bruno accident, the NTSBs
January 3, 2011 urgent safety recommendations regarding the importance of accurate pipeline records in calculating maximum safe operating pressures, and other NTSB statements. After the NTSB has completed its investigation and issued a final
report, the CPUC also will consider other possible violations of law, besides recordkeeping, associated with the Utilitys transmission lines and with Line 132 in particular.

If the CPUC determines that the Utility violated safety law standards with respect to its gas system recordkeeping, the CPUC will
schedule a later phase or phases to determine whether penalties are warranted, and if so the amount of such penalties. It is anticipated that the administrative law judge will set the procedural schedule after a second pre-hearing conference is held
during the week of May 9, 2011.



32



---

##### Table of Contents

The CPUC also is investigating a natural gas explosion and fire that occurred on
December 24, 2008 in a house located in Rancho Cordova, California (Rancho Cordova accident). On February 17, 2011, the Utility submitted its report to the CPUC to provide extensive information, from as far back as
January 1, 2000, about the Utilitys natural gas operating and maintenance practices and procedures. The Utilitys report agrees with the NTSBs conclusions about the probable cause of the accident and explains what process
improvements the Utility has made to prevent a similar accident in the future. The CPUC has scheduled an evidentiary hearing in mid-July.

If the CPUC determines that the Utility violated applicable laws in connection with the San Bruno or Rancho Cordova accidents, the CPUC could impose penalties of up to $20,000 per day, per violation
which, in the aggregate, could have a material adverse impact on PG&E Corporations and the Utilitys financial condition, results of operations, or cash flows. Estimated liabilities associated with the Rancho Cordova investigation are
included in the accrual for legal matters discussed above. In addition, law enforcement authorities could begin proceedings that could result in the imposition of civil or criminal fines or penalties on the Utility. PG&E Corporation and the
Utility are unable to predict the ultimate outcome of the investigations discussed above or whether additional investigations or proceedings will be instituted.

Environmental Matters

The Utility has been, and may be required to pay
for environmental remediation at sites where it has been, or may be, a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant (MGP) sites, power plant sites, gas
gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Under federal and California laws, the Utility may be responsible
for remediation of hazardous substances even if it did not deposit those substances on the site.

Given the complexities of
the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records
an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts.

The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an amount within the range is a better estimate than any other amount. Amounts
recorded are not discounted to their present value.

The Utility had an undiscounted and gross environmental remediation
liability of $627 million at March 31, 2011 and $612 million at December 31, 2010. The following table presents the changes in the environmental remediation liability from December 31, 2010:



|                                            |  |  |       | 
|------------------------------------------- |  |  | ----- | 
|(in millions)                               |  |  |       | 
|Balance at December 31, 2010                |  |  | $ 612 | 
|Additional remediation costs accrued:       |  |  |       | 
|Transfer to regulatory account for recovery |  |  | 33    | 
|Amounts not recoverable from customers      |  |  | 9     | 
|Less: Payments                              |  |  | (27)  | 
|                                            |  |  |       | 
|Balance at March 31, 2011                   |  |  | $ 627 | 
|                                            |  |  |       | 



33



---

##### Table of Contents

The $627 million accrued at March 31, 2011 consists of the following:



| |  |  | $45 million for remediation at the Utilitys natural gas compressor site located near Hinkley, California;
| | - |  | ----------------------------------------------------------------------------------------------------------



| |  |  | $180 million for remediation at the Utilitys natural gas compressor site located on the California border, near Topock, Arizona;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------



| |  |  | $83 million related to remediation at divested generation facilities;
| | - |  | ---------------------------------------------------------------------



| |  |  | $117 million related to remediation costs for the Utilitys generation and other facilities and for third-party disposal sites;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------



| |  |  | $142 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that
are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | $60 million related to remediation costs for fossil decommissioning sites.
| | - |  | --------------------------------------------------------------------------

Of the $627 million environmental remediation liability, the Utility expects to recover $327 million through the CPUC-approved ratemaking
mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs without a reasonableness review (excluding any remediation associated with the Hinkley natural gas compressor site) and $135 million through the ratemaking
mechanism that authorizes the Utility to recover 100% of remediation costs for decommissioning fossil-fueled sites and certain of the Utilitys transmission stations (excluding any remediation associated with divested generation facilities).
The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utilitys ultimate obligations may be subject to refund to customers.

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may
vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utilitys undiscounted future costs could increase to as much as $1.2
billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to
remediate beyond regulatory requirements. Recovery of these amounts would be subject to CPUC approval.

Tax Matters

In tax year 2008, PG&E Corporation began participating in the Compliance Assurance Process (CAP), a real-time Internal
Revenue Service (IRS) audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating their acceptance of the return. The IRS partially accepted the 2008 return, withholding two issues
for further review. The most significant of these relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. While the IRS approved PG&E Corporations request for a change in
method, the IRS will audit the methodology to determine the proper deduction. This audit has not progressed significantly because the IRS is working with the utility industry to resolve this matter in a consistent manner for all utilities before
auditing individual companies. In December 2010, the IRS accepted PG&E Corporations 2009 tax return. PG&E Corporation is currently under audit for the 2010 CAP year.

PG&E Corporation and the Utility expect the IRS to release new guidance clarifying the treatment of deductible repairs within the
next 12 months. This guidance may result in a change in unrecognized tax benefits. PG&E Corporation and the Utility are unable to determine the potential impact of this change to the unrecognized tax benefits at this time.

The California Franchise Tax Board (FTB) is auditing PG&E Corporations 2004 and 2005 combined California income tax
returns, as well as the 1997-2007 amended income tax returns reflecting IRS settlements for these years and claim filings that apply only to California. PG&E Corporation expects the FTB to complete the 1997 to 2004 audit by the end of 2011. It
is uncertain when the FTB will complete the remaining audits.

PG&E Corporation believes that the final resolution of the
federal and California audits will not have a material adverse impact on its financial condition or results of operations. PG&E Corporation is neither under audit nor subject to any material risk in any other jurisdiction.



34



---

##### Table of Contents

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND

RESULTS OF OPERATIONS

OVERVIEW

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

The Utility
served 5.2 million electricity distribution customers and 4.3 million natural gas distribution customers at March 31, 2011. The Utility had $45.9 billion in assets at March 31, 2011 and generated revenues of $3.6 billion in the
three months ended March 31, 2011.

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, including the Diablo Canyon power plant (Diablo Canyon). 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 authorize the annual amount of revenue (revenue requirements) that the Utility is authorized to collect
from its customers to recover its reasonable operating and capital costs of providing utility services. The authorized revenue requirements also provide the Utility an opportunity to earn a return on rate base (i.e., the Utilitys
net investment in facilities, equipment, and other property used or useful in providing utility service to its customers.) The CPUC requires the Utility to maintain a certain capital structure (i.e., the relative weightings of common equity,
preferred equity, and debt) when financing its rate base and authorizes the Utility to earn a specific rate of return on each capital component.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each companys separate Condensed Consolidated Financial Statements and the Notes to
the Condensed Consolidated Financial Statements included in this quarterly report. In addition, this quarterly report should be read in conjunction with PG&E Corporations and the Utilitys combined Annual Report on Form 10-K for the
year ended December 31, 2010 which incorporates by reference each companys audited Consolidated Financial Statements, the Notes to the Consolidated Financial Statements, and other information (2010 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:



| |  |  | The Outcome of Matters Related to the Utilitys Natural Gas Pipeline System. The National Transportation Safety Board (NTSB) is
continuing its investigation of the rupture of a Utility-owned natural gas pipeline on September 9, 2010 in San Bruno, California (the San Bruno accident). The NTSB has issued several public statements regarding its investigation of
the San Bruno accident but has not yet determined the cause of the pipeline rupture. The CPUC is also investigating a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California (the
Rancho Cordova accident). If the CPUC finds that the Utility violated applicable law in connection with these accidents, the CPUC may impose substantial penalties on the Utility. (See Natural Gas Pipeline Matters below).
During the quarter ended March 31, 2011, the CPUC opened a rule-making proceeding and initiated a formal investigation of the Utilitys gas transmission pipeline recordkeeping. The Utility currently estimates that in 2011 it will incur
incremental costs associated with its natural gas transmission business, including costs to comply with CPUC orders and NTSB recommendations, ranging from $350 million to $550 million. (See Operating and Maintenance and Natural Gas
Pipeline Matters below.) These cost estimates could change depending on a number of factors, including the outcome of regulatory proceedings and pending investigations, as well as future rulemaking, ratemaking, or other investigatory
proceedings that may be commenced at the CPUC. If state or federal legislation is enacted to address natural gas transmission operations and maintenance, the Utility may incur additional costs to comply with such new statutory requirements. It is
uncertain how much of the costs the Utility incurs to comply with orders, recommendations, new CPUC regulations, or new legislation, will be recoverable through rates. 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
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



35



---

##### Table of Contents

| | the San Bruno accident. The Utility currently estimates that it may incur as much as $400 million for third-party claims, including the $220 million provision recorded for the year ended
December 31, 2010. (See Note 10 to the Notes of the Condensed 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 a significant portion 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 March 31, 2011. The resolutions of the various regulatory matters and the outcome of the pending investigations and
third-party claims may have a material adverse impact on PG&E Corporations and the Utilitys financial condition, results of operations, or cash flows.
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The Timing and Outcome of Ratemaking and Other Regulatory Proceedings. The majority of the Utilitys base revenue requirements for 2011 and
several years thereafter are determined in various rate cases at the CPUC and the FERC. On April 14, 2011, the CPUC issued a decision in the Utilitys 2011 Gas Transmission and Storage rate case (GT&S) authorizing the
Utility to collect increased revenue requirements from January 1, 2011. In the Utilitys 2011 General Rate Case (GRC) the CPUC will authorize a change in revenue requirements beginning on January 1, 2011, but the CPUC has
not yet issued a decision. These and other regulatory proceedings are discussed under Regulatory Matters below. 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. 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 in the 2010 Annual Report.)
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 a return on equity
(ROE). Actual costs may differ from forecasts, or the Utility may incur significant unanticipated costs, such as costs related to storms, outages, catastrophic events, or costs incurred to comply with regulatory orders or legislation.
For example, during the three months ended March 31, 2011, the Utility incurred comparatively higher expenses to respond to winter storms, as shown in the table below. As noted above, the Utility expects to incur material costs during 2011 to
comply with CPUC orders and NTSB recommendations that have been issued in connection with the investigations of the San Bruno accident. (See Operating and Maintenance and Natural Gas Pipeline Matters below.) Differences in
the amount or timing of forecasted or authorized 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. 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.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 is scheduled to remain in effect through 2012. The Utilitys CPUC-authorized ROE of 11.35% is scheduled to remain in effect
through 2012 but is subject to change based on an annual adjustment mechanism as described in the 2010 Annual Report. The timing and amount of the Utilitys future debt financing will depend primarily on the timing and amount of its capital
expenditures. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. As the Utility incurs costs to perform pipeline safety-related work as described above, the amount of
equity needed by the Utility to maintain its capital structure is anticipated to increase. PG&E Corporation anticipates issuing equity in the future to meet the Utilitys additional equity needs. (See Liquidity and Financial
Resources below.)
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



36



---

##### Table of Contents

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the
Three Months Ended March 31, 2011

PG&E Corporations income available for common shareholders decreased by
$59 million, or 23%, from $258 million for the three months ended March 31, 2010 to $199 million for the three months ended March 31, 2011. The following table is a summary reconciliation of the key changes in income available for common
shareholders and earnings per common share for the three months ended March 31, 2011:



|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |  |          |       |  |                                        |  |        | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | -------- | ----- |  | -------------------------------------- |  | ------ | 
|(in millions)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |  | Earnings |       |  | Earnings Per    Common 
Share(Diluted) | 
|Income Available for Common Shareholders  March 31, 2010                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  |          | $ 258 |  |                                        |  | $ 0.67 | 
|Natural gas pipeline matters(1)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |  |          | (31)  |  |                                        |  | (0.08) | 
|Delay in rate case decisions(2)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |  |          | (27)  |  |                                        |  | (0.07) | 
|Storm and outage expenses(3)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |  |          | (18)  |  |                                        |  | (0.05) | 
|Statewide ballot initiative(4)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |  |          | 25    |  |                                        |  | 0.07   | 
|Federal healthcare law(5)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  |          | 20    |  |                                        |  | 0.05   | 
|Other(6)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |  |          | (28)  |  |                                        |  | (0.06) | 
|Increase in shares outstanding(7)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |          | -     |  |                                        |  | (0.03) | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |  |          |       |  |                                        |  |        | 
|Income Available for Common Shareholders  March 31, 2011                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  |          | $ 199 |  |                                        |  | $ 0.50 | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |  |          |       |  |                                        |  |        | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |  |          |       |  |                                        |  |        | 
|(1)  During the three months
ended March 31, 2011, the Utility incurred costs of $31 million, after-tax, to comply with CPUC orders and NTSB recommendations that have been issued in connection with investigations related to the San Bruno accident. These costs are primarily
associated with an extensive review of the Utilitys pipeline records, as well as other activities associated with the accident and pending investigations.
(2)  During the three months ended March 31, 2011, the Utility incurred an unfavorable variance of $27 million, after-tax, representing expenses that would have been
offset by increased revenues if the CPUC had issued final decisions in the Utilitys Gas Transmission and Storage Case and 2011 General Rate Case before March 31, 2011.
(3)  During the three months ended March 31, 2011, the Utility incurred higher expenses of $18 million, after-tax, due to more severe winter storms as compared to the
same period in 2010. (4)  During the three month period ended March 31, 2010, PG&E Corporation contributed $25 million to support Proposition 16 - The Taxpayers Right to Vote Act. (5)  During the three months ended March 31, 2010, the Utility recorded a charge of $20 million triggered by the elimination of the tax deductibility of Medicare Part
D federal subsidies. (6)  During the three months ended March 31, 2011, the Utility incurred higher legal expenses, environmental remediation expenses, and other operating and maintenance
expenses, partially offset by an increase in rate base earnings for electric transmission and separately funded projects, as compared to the same period in 2010.
(7)  Represents the impact of a higher number of shares outstanding at March 31, 2011, compared to the number of shares outstanding at March 31, 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, 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:



| |  |  | 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;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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-
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



37



---

##### Table of Contents

| | party liability claims or to comply with regulatory or legislative mandates that 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;
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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, the availability of nuclear fuel, the outcome
of seismic studies the Utility is conducting in the area near Diablo Canyon that could affect the Utilitys ability to operate Diablo Canyon or renew the operating licenses for Diablo Canyon, and the ability of the Utility to procure
replacement electricity if nuclear generation from Diablo Canyon were unavailable;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the impact that the recent earthquake and tsunami in Japan may have on the Utilitys ability to continue its nuclear operations at Diablo Canyon
or to renew the operating licenses for Diablo Canyon as a result of new legislation that may be adopted, or new orders or regulations that may be issued by the NRC or environmental agencies with respect to the operations, decommissioning, 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);
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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, that are not recoverable
through insurance, rates, or from other third parties;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



38



---

##### Table of Contents

| |  |  | 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 section entitled
Risk Factors in the 2010 Annual Report and Item 1.A. 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.



39



---

##### Table of Contents

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three months ended
March 31, 2011 and 2010:



|                                                                                |  |                              |         |  |      |  |         | 
|------------------------------------------------------------------------------- |  | ---------------------------- | ------- |  | ---- |  | ------- | 
|                                                                                |  | Three Months ended March 31, |        
|(in millions)                                                                   |  | 2011                         |         |  | 2010 | 
|Utility                                                                         |  |                              |         |  |      |  |         | 
|Electric operating revenues                                                     |  |                              | $ 2,616 |  |      |  | $ 2,510 | 
|Natural gas operating revenues                                                  |  |                              | 980     |  |      |  | 965     | 
|                                                                                |  |                              |         |  |      |  |         | 
|Total operating revenues                                                        |  |                              | 3,596   |  |      |  | 3,475   | 
|                                                                                |  |                              |         |  |      |  |         | 
|Cost of electricity                                                             |  |                              | 888     |  |      |  | 920     | 
|Cost of natural gas                                                             |  |                              | 508     |  |      |  | 495     | 
|Operating and maintenance                                                       |  |                              | 1,226   |  |      |  | 990     | 
|Depreciation, amortization, and decommissioning                                 |  |                              | 490     |  |      |  | 451     | 
|                                                                                |  |                              |         |  |      |  |         | 
|Total operating expenses                                                        |  |                              | 3,112   |  |      |  | 2,856   | 
|                                                                                |  |                              |         |  |      |  |         | 
|Operating income                                                                |  |                              | 484     |  |      |  | 619     | 
|Interest income                                                                 |  |                              | 2       |  |      |  | 2       | 
|Interest expense                                                                |  |                              | (171)   |  |      |  | (156)   | 
|Other income (expense), net                                                     |  |                              | 17      |  |      |  | (6)     | 
|                                                                                |  |                              |         |  |      |  |         | 
|Income before income taxes                                                      |  |                              | 332     |  |      |  | 459     | 
|Income tax provision                                                            |  |                              | 131     |  |      |  | 195     | 
|                                                                                |  |                              |         |  |      |  |         | 
|Net Income                                                                      |  |                              | 201     |  |      |  | 264     | 
|Preferred stock dividend requirement                                            |  |                              | 3       |  |      |  | 3       | 
|                                                                                |  |                              |         |  |      |  |         | 
|Income available for common stock                                               |  |                              | $ 198   |  |      |  | $ 261   | 
|                                                                                |  |                              |         |  |      |  |         | 
|PG&E Corporation, Eliminations, and Other (1)                                   |  |                              |         |  |      |  |         | 
|Operating revenues                                                              |  |                              | $ 1     |  |      |  | $ -     | 
|Operating expenses                                                              |  |                              | 1       |  |      |  | 1       | 
|                                                                                |  |                              |         |  |      |  |         | 
|Operating loss                                                                  |  |                              | -       |  |      |  | (1)     | 
|Interest income                                                                 |  |                              | -       |  |      |  | -       | 
|Interest expense                                                                |  |                              | (6)     |  |      |  | (12)    | 
|Other expense, net                                                              |  |                              | -       |  |      |  | -       | 
|                                                                                |  |                              |         |  |      |  |         | 
|Loss before income taxes                                                        |  |                              | (6)     |  |      |  | (13)    | 
|Income tax benefit                                                              |  |                              | (7)     |  |      |  | (10)    | 
|                                                                                |  |                              |         |  |      |  |         | 
|Net (loss) gain                                                                 |  |                              | $ 1     |  |      |  | $ (3)   | 
|                                                                                |  |                              |         |  |      |  |         | 
|Consolidated Total                                                              |  |                              |         |  |      |  |         | 
|Operating revenues                                                              |  |                              | $ 3,597 |  |      |  | $ 3,475 | 
|Operating expenses                                                              |  |                              | 3,113   |  |      |  | 2,857   | 
|                                                                                |  |                              |         |  |      |  |         | 
|Operating income                                                                |  |                              | 484     |  |      |  | 618     | 
|Interest income                                                                 |  |                              | 2       |  |      |  | 2       | 
|Interest expense                                                                |  |                              | (177)   |  |      |  | (168)   | 
|Other income (expense), net                                                     |  |                              | 17      |  |      |  | (6)     | 
|                                                                                |  |                              |         |  |      |  |         | 
|Income before income taxes                                                      |  |                              | 326     |  |      |  | 446     | 
|Income tax provision                                                            |  |                              | 124     |  |      |  | 185     | 
|                                                                                |  |                              |         |  |      |  |         | 
|Net Income                                                                      |  |                              | 202     |  |      |  | 261     | 
|Preferred stock dividend requirement of subsidiary                              |  |                              | 3       |  |      |  | 3       | 
|                                                                                |  |                              |         |  |      |  |         | 
|Income available for common shareholders                                        |  |                              | $ 199   |  |      |  | $ 258   | 
|                                                                                |  |                              |         |  |      |  |         | 
|                                                                                |  |                              |         |  |      |  |         | 
|(1) PG&E Corporation eliminates all intercompany transactions in consolidation. |  |                              |         |  |      |  |         | 



40



---

##### Table of Contents

Utility

The following presents the Utilitys operating results for the three months ended March 31, 2011 and 2010. These operating results do not reflect the increase in revenues that is expected to
occur upon authorization of the 2011 GRC by the CPUC. Revenues will be adjusted retroactively once a final decision is approved for the 2011 GRC. Revenues will also be retroactively adjusted during the second quarter of 2011 as a result of the
CPUCs final decision in the 2011 GT&S rate case which authorizes an increase in the Utilitys natural gas transmission and storage revenues effective as of January 1, 2011. (See Regulatory Matters below.)

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 Condensed Consolidated Statements of Income.

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



|                                              |  |                             |         |  |      |  |         | 
|--------------------------------------------- |  | --------------------------- | ------- |  | ---- |  | ------- | 
|                                              |  | Three months endedMarch 31, |        
|(in millions)                                 |  | 2011                        |         |  | 2010 | 
|Revenues excluding pass-through costs         |  |                             | $ 1,523 |  |      |  | $ 1,443 | 
|Revenues for recovery of passed-through costs |  |                             | 1,093   |  |      |  | 1,067   | 
|                                              |  |                             |         |  |      |  |         | 
|Total electric operating revenues             |  |                             | $ 2,616 |  |      |  | $ 2,510 | 
|                                              |  |                             |         |  |      |  |         | 

The Utilitys total electric operating revenues, including revenues intended to recover costs that are
passed through to customers, increased by $106 million, or 4%, in the three months ended March 31, 2011, as compared to the same period in 2010. Costs that are passed through to customers and do not impact net income increased by $26 million,
primarily due to increases in the cost of public purpose programs and pension contributions which were partially offset by decreases in the cost of electricity procurement. (See Cost of Electricity below.) Electric operating revenues,
excluding costs passed through to customers, increased by $80 million. This was primarily due to increases in authorized rate base for separately funded projects and an increase in electric transmission revenues as authorized by the FERC in an
electric transmission owner (TO) rate case.

The Utilitys future electric operating revenues are expected to
be impacted by the CPUCs authorized decision in the 2011 GRC and the FERC in other TO rate cases. (See Regulatory Matters below.) The Utility also expects to continue to collect revenue requirements outside of the GRC that are
related to capital expenditures that have already been approved by the CPUC or that may be approved by the CPUC in the future. Finally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism.

Cost 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, the cost of fuel supplied to
other facilities under tolling agreements and realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed 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 Condensed Consolidated Statements of
Income.



41



---

##### Table of Contents

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



|                                           |  |                             |         |  |      |  |         | 
|------------------------------------------ |  | --------------------------- | ------- |  | ---- |  | ------- | 
|                                           |  | Three months endedMarch 31, |        
|(in millions)                              |  | 2011                        |         |  | 2010 | 
|Cost of purchased power                    |  |                             | $ 821   |  |      |  | $ 842   | 
|Fuel used in own generation facilities     |  |                             | 67      |  |      |  | 78      | 
|                                           |  |                             |         |  |      |  |         | 
|Total cost of electricity                  |  |                             | $ 888   |  |      |  | $ 920   | 
|                                           |  |                             |         |  |      |  |         | 
|Average cost of purchased power per kWh(1) |  |                             | $ 0.094 |  |      |  | $ 0.083 | 
|                                           |  |                             |         |  |      |  |         | 
|Total purchased power (in kWh)             |  |                             | 8,779   |  |      |  | 10,117  | 
|                                           |  |                             |         |  |      |  |         | 
|                                           |  |                             |         |  |      |  |         | 
|(1)Kilowatt-hour                           |  |                             |         |  |      |  |         | 

The Utilitys total cost of electricity decreased by $32 million, or 3%, in the three months
ended March 31, 2011 as compared to the same period in 2010. This was caused by decreases in the volume of purchased power and the cost of fuel used in the Utilitys own generation facilities. The volume of purchased power is driven by
customer demand, 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 availability of Utility-owned generation, and changes in
customer demand. Additionally, the cost of electricity is expected to be impacted by 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 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 below.)

Natural Gas Operating Revenues

The Utility sells natural gas and natural gas transportation services. The Utility transports gas throughout its service territory, both
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 following table provides a summary of the Utilitys natural gas operating revenues:



|                                              |  |                             |       |  |      |  |       | 
|--------------------------------------------- |  | --------------------------- | ----- |  | ---- |  | ----- | 
|                                              |  | Three months endedMarch 31, |      
|(in millions)                                 |  | 2011                        |       |  | 2010 | 
|Revenues excluding pass-through costs         |  |                             | $ 404 |  |      |  | $ 414 | 
|Revenues for recovery of passed-through costs |  |                             | 576   |  |      |  | 551   | 
|                                              |  |                             |       |  |      |  |       | 
|Total natural gas operating revenues          |  |                             | $ 980 |  |      |  | $ 965 | 
|                                              |  |                             |       |  |      |  |       | 

The Utilitys natural gas operating revenues, including revenues intended to recover costs that are
passed through to customers, increased by $15 million, or 2%, in the three months ended March 31, 2011 as compared to the same period in 2010. This reflects a $25 million increase in the costs which are passed through to customers and do not
impact net income, primarily due to an increase in the costs of natural gas procurement, public purpose programs, and pension contributions. Natural gas operating revenues, excluding costs passed through to customers, decreased by $10 million,
primarily due to a decrease in natural gas storage revenues.

The CPUCs final decision in the 2011 GT&S rate case
provides for an overall increase in the revenue requirements and rates for the Utilitys gas transmission and storage services for 2011 through 2014. Natural gas operating revenues also will be impacted by the CPUCs expected decision in
the 2011 GRC. (See Regulatory Matters below.) Additionally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism. (See Regulatory Matters below.)



42



---

##### Table of Contents

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 Condensed Consolidated Statements of Income. The Utilitys cost of natural gas also includes realized gains and losses on price risk
management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

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



|                                            |  |                                  |        |  |      |  |        | 
|------------------------------------------- |  | -------------------------------- | ------ |  | ---- |  | ------ | 
|                                            |  | Three months ended    March 
31, |       
|(in millions)                               |  | 2011                             |        |  | 2010 | 
|Cost of natural gas sold                    |  |                                  | $  461 |  |      |  | $  444 | 
|Transportation cost of natural gas sold     |  |                                  | 47     |  |      |  | 51     | 
|                                            |  |                                  |        |  |      |  |        | 
|Total cost of natural gas                   |  |                                  | $  508 |  |      |  | $  495 | 
|                                            |  |                                  |        |  |      |  |        | 
|Average cost per Mcf(1)of natural gas sold  |  |                                  | $ 4.52 |  |      |  | $ 4.67 | 
|                                            |  |                                  |        |  |      |  |        | 
|Total natural gas sold (in millions of Mcf) |  |                                  | 102    |  |      |  | 95     | 
|                                            |  |                                  |        |  |      |  |        | 
|                                            | 
|(1) One thousand cubic feet                 | 

The Utilitys total cost of natural gas increased by $13 million, or 3%, in the three months ended March 31, 2011 as compared
to the same period in 2010. The increase was primarily due to the absence in 2011 of the $49 million the Utility received 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 increase resulting from the settlement was partially offset by a decrease in procurement costs due to decreases in the average market price of natural gas purchased.

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.

The Utilitys operating and maintenance expenses (including costs passed through to customers) increased by $236 million, or 24%, in the three months ended March 31, 2011, as compared to the
same period in 2010. Increases in pass-through costs include a $23 million increase in pension plan contributions and a $52 million increase in the cost of public purpose programs due to an increase in the level of program spending. Excluding costs
passed through to customers, operating and maintenance expenses increased by $161 million, primarily due to costs of $51 million that the Utility incurred to comply with CPUC orders and NTSB recommendations that have been issued in connection with
the investigation of the San Bruno accident (see Natural Gas Pipeline Matters below), $31 million in higher costs related to more severe winter storms in 2011, and increases in other expenses, including legal, regulatory, and
environmental items.

The Utility currently estimates that it will incur incremental costs associated with its natural gas
transmission business ranging from $350 million to $550 million in 2011, including costs to complete its review and validation of pipeline records, to perform pressure tests and other tests on portions of its natural gas transmission system, to
respond to regulatory proceedings, and to perform other activities related to the safety of its gas pipeline system. These cost estimates could change depending on a number of factors, including the outcome of the regulatory proceedings and
investigations discussed below under Natural Gas Pipeline Matters and new state and federal laws that may be adopted. PG&E Corporation and the Utility are uncertain what 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.

Future operating and maintenance expenses also may be affected by the amount of third party liability the Utility incurs as a result of the San Bruno accident as well as by the amount of fines the CPUC
may impose on the Utility in connection with the pending investigations discussed below. (See Natural Gas Pipeline Matters below and Note 10 of the Notes to the Condensed Consolidated Financial Statements.) If the CPUC determines in the
investigations discussed below that the Utility violated laws, rules, regulations or orders, the CPUC may impose fines or penalties on the Utility, which may be material.



43



---

##### Table of Contents

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 $39 million, or 9%, in the three months ended March 31, 2011, as compared to
the same period in 2010, primarily due to an increase in authorized capital additions.

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 expense in subsequent years will be determined based on rates
to be set by the CPUC in the 2011 GRC and by the FERC in future TO rate cases.

Interest Income

The Utilitys interest income increased by less than $1 million in the three months ended March 31, 2011, as compared to the
same period in 2010, due to fluctuations in various regulatory balancing accounts.

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. (See Note 9 of the Notes to
the Condensed Consolidated Financial Statements.)

Interest Expense

The Utilitys interest expense increased by $15 million, or 10%, in the three months ended March 31, 2011, as compared to the
same period in 2010. The increase resulted from higher interest costs due to an increase in outstanding senior notes and was partially offset by a decrease in the outstanding balance of the energy recovery bonds (ERBs). (See Note 4 of
the Notes to the Condensed Consolidated Financial Statements.)

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 Note 9 of the Notes to the Condensed Consolidated Financial Statements and Liquidity and Financial Resources below.)

Other Income, Net

The Utilitys other income, net increased
by $23 million in the three months ended March 31, 2011, as compared to the same period in 2010. The increase was primarily due to a $25 million decrease in other expenses as a result of costs the Utility incurred in 2010 to support a
California ballot initiative that appeared on the June 2010 ballot, with no similar activity in the current year. This expense was partially offset by an $8 million decrease in allowance for equity funds used during construction due to lower average
balances of construction work in progress.

Income Tax Provision

The Utilitys income tax provision decreased by $64 million, or 33%, in the three months ended March 31, 2011, as compared to
the same period in 2010. The effective tax rates were 38% and 42% for 2011 and 2010, respectively. The effective tax rate decreased in the three months ended March 31, 2011, as compared to the same period in 2010 when the Utility incurred non
tax deductible lobbying expenses associated with a ballot initiative and reversed a deferred tax asset 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 healthcare legislation passed during 2010.

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 its 5.8% Senior Notes, and is not allocated to affiliates.



44



---

##### Table of Contents

There were no material changes to PG&E Corporations operating income in the three
months ended March 31, 2011, as compared to the same period in 2010.

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.

Credit Facilities

The following table summarizes PG&E Corporations and the Utilitys revolving credit facilities at March 31, 2011:



|                                                                                                                                                                                                                                                                                                                                                                                                   |  |                 |               |         |                |  |           |                             |  |  |                |    |  |                       |    |         |              |  |            |         |  |  |          | 
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------- | ------------- | ------- | -------------- |  | --------- | --------------------------- |  |  | -------------- | -- |  | --------------------- | -- | ------- | ------------ |  | ---------- | ------- |  |  | -------- | 
|(in millions)                                                                                                                                                                                                                                                                                                                                                                                      |  | TerminationDate |               |         | Facility Limit |  |           | Letters ofCreditOutstanding |  |  | CashBorrowings |    |  | CommercialPaperBackup |    |         | Availability | 
|PG&E Corporation                                                                                                                                                                                                                                                                                                                                                                                   |  |                 | February 2012 |         |                |  | $    
187 | (1)                         |  |  | $      -       |    |  |                       | $- |         |              |  | $        - |         |  |  | $    187 | 
|Utility                                                                                                                                                                                                                                                                                                                                                                                            |  |                 | February 2012 |         |                |  | 1,940     | (2)                         |  |  | 315            |    |  |                       | -  |         |              |  | 1,019      |         |  |  | 606      | 
|Utility                                                                                                                                                                                                                                                                                                                                                                                            |  |                 | February 2012 |         |                |  | 750       | (3)                         |  |  | N/A            |    |  |                       | -  |         |              |  | -          |         |  |  | 750      | 
|                                                                                                                                                                                                                                                                                                                                                                                                   |  |                 |               |         |                |  |           |                             |  |  |                |    |  |                       |    |         |              |  |            |         |  |  |          | 
|Total credit facilities                                                                                                                                                                                                                                                                                                                                                                            |  |                 |               | $ 2,877 |                |  |           | $ 315                       |  |  |                | $- |  |                       |    | $ 1,019 |              |  |            | $ 1,543 | 
|                                                                                                                                                                                                                                                                                                                                                                                                   |  |                 |               |         |                |  |           |                             |  |  |                |    |  |                       |    |         |              |  |            |         |  |  |          | 
|                                                                                                                                                                                                                                                                                                                                                                                                   |  |                 |               |         |                |  |           |                             |  |  |                |    |  |                       |    |         |              |  |            |         | 
|(1)  Includes an $87 million sublimit for letters of credit and a $100 million commitment for swingline
loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days. (2)  Includes a $921 million sublimit for letters of credit and a $200 million commitment for swingline
loans.
(3)  Includes a $75 million
commitment for swingline loans. | 

For the three months ended March 31, 2011, the average outstanding commercial paper balance was $735
million and the maximum outstanding balance during the quarter was $1.2 billion. There were no cash borrowings on the revolving credit facilities in the three months ended March 31, 2011.

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 March 31, 2011, PG&E Corporation and
the Utility were in compliance with all covenants under each of the revolving credit facilities listed in the table above.



45



---

##### Table of Contents

2011 Financings

During the three months ended March 31, 2011, PG&E Corporation issued 2,032,223 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 $82 million of cash.

During the three months ended March 31, 2011, the
Utility received cash contributions of $65 million from PG&E Corporation to ensure that the Utility had adequate capital 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 by the CPUC;
| | - |  | --------------------------------------------------------------------------------



| |  |  | 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 timing and amount of payments related to costs incurred to comply with CPUC orders and NTSB recommendations that have been issued in connection
with the San Bruno accident (see Operating and Maintenance above and Natural Gas Pipeline Matters below);
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the amount of future tax payments (see the discussion of the Tax Relief Act below under Utility  Operating Activities); and
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



| |  |  | the conditions in the capital markets, and other factors. (See Notes 9 and 10 of the Notes to the Condensed Consolidated Financial Statements.)
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------

PG&E Corporations future 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. PG&E Corporation anticipates issuing equity in the future to meet the Utilitys additional equity needs as it performs pipeline
safety-related work (see Natural Gas Pipeline MattersImpact on Operations below). PG&E Corporation also may issue debt or equity in the future to fund future tax equity investments to the extent that internally generated funds
are not sufficient. (See PG&E Corporation below).

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, make payments related to costs incurred to comply with CPUC orders and NTSB recommendations, and finance future capital expenditures and investments.

Dividends

The following table summarizes PG&E Corporations and the Utilitys dividends paid during the three months ended
March 31, 2011:



|                               |  |   |     | 
|------------------------------ |  | - | --- | 
|(in millions)                  |  |   |    
|PG&E Corporation               |  |   |     | 
|Common stock dividends paid    |  | $ | 174 | 
|Utility                        |  |   |     | 
|Common stock dividends paid    |  | $ | 179 | 
|Preferred stock dividends paid |  |   | 4   | 



46



---

##### Table of Contents

On February 16, 2011, the Board of Directors of PG&E Corporation declared a
dividend of $0.455 per share, totaling $181 million, of which $175 million was paid on April 15, 2011, to shareholders of record on March 31, 2011. The remaining $6 million was reinvested in the Dividend Reinvestment and Stock Purchase
Plan.

On February 16, 2011, the Board of Directors of the Utility declared a dividend totaling $3 million on its
outstanding series of preferred stock, payable on May 15, 2011, to shareholders of record on April 29, 2011.

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 the three months ended March 31, 2011 and 2010
were as follows:



|                                                                                  |  |                             |         |  |      |  |       | 
|--------------------------------------------------------------------------------- |  | --------------------------- | ------- |  | ---- |  | ----- | 
|                                                                                  |  | Three Months EndedMarch 31, |        
|(in millions)                                                                     |  | 2011                        |         |  | 2010 | 
|Net income                                                                        |  |                             | $ 201   |  |      |  | $ 264 | 
|Adjustments to reconcile net income to net cash provided by operating activities: |  |                             |         |  |      |  |       | 
|Depreciation, amortization, and decommissioning                                   |  |                             | 534     |  |      |  | 491   | 
|Allowance for equity funds used during construction                               |  |                             | (20)    |  |      |  | (28)  | 
|Deferred income taxes and tax credits, net                                        |  |                             | 99      |  |      |  | 138   | 
|Other                                                                             |  |                             | (15)    |  |      |  | 26    | 
|Effect of changes in operating assets and liabilities:                            |  |                             |         |  |      |  |       | 
|Accounts receivable                                                               |  |                             | 69      |  |      |  | 114   | 
|Inventories                                                                       |  |                             | 65      |  |      |  | 59    | 
|Accounts payable                                                                  |  |                             | 190     |  |      |  | 94    | 
|Income taxes receivable/payable                                                   |  |                             | 34      |  |      |  | 77    | 
|Other current assets and liabilities                                              |  |                             | (196)   |  |      |  | (325) | 
|Regulatory assets, liabilities, and balancing accounts, net                       |  |                             | (10)    |  |      |  | (376) | 
|Other noncurrent assets and liabilities                                           |  |                             | 144     |  |      |  | (126) | 
|                                                                                  |  |                             |         |  |      |  |       | 
|Net cash provided by operating activities                                         |  |                             | $ 1,095 |  |      |  | $ 408 | 
|                                                                                  |  |                             |         |  |      |  |       | 

In the three months ended March 31, 2011, net cash provided by operating activities increased by $687
million compared to the same period in 2010 primarily due to a decrease of $321 million in net collateral paid by the Utility related to price risk management activities. Collateral payables and receivables are included in other changes in
noncurrent assets and liabilities and other current assets and liabilities. The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as power purchases and
customer billings.

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 allowing qualified property placed into service in 2012 to be eligible for 50% bonus depreciation for tax
purposes. As a result, the Utility expects that it will not make a federal tax payment in 2011. The Utility also expects that its 2012 federal tax payment will be reduced depending on the amount and timing of the Utilitys qualifying capital
additions. (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.



47



---

##### Table of Contents

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.

The Utilitys cash flows from investing activities for the three months ended
March 31, 2011 and 2010 were as follows:



|                                                                                |  |                             |         |  |      |  |         | 
|------------------------------------------------------------------------------- |  | --------------------------- | ------- |  | ---- |  | ------- | 
|                                                                                |  | Three Months EndedMarch 31, |        
|(in millions)                                                                   |  | 2011                        |         |  | 2010 | 
|Capital expenditures                                                            |  |                             | $ (945) |  |      |  | $ (855) | 
|Decrease in restricted cash                                                     |  |                             | 132     |  |      |  | 4       | 
|Proceeds from sales and maturities of nuclear decommissioning trust investments |  |                             | 726     |  |      |  | 337     | 
|Purchases of nuclear decommissioning trust investments                          |  |                             | (735)   |  |      |  | (343)   | 
|Other                                                                           |  |                             | 7       |  |      |  | 5       | 
|                                                                                |  |                             |         |  |      |  |         | 
|Net cash used in investing activities                                           |  |                             | $ (815) |  |      |  | $ (852) | 
|                                                                                |  |                             |         |  |      |  |         | 

Net cash used in investing activities decreased by $37 million in the three months ended March 31, 2011
compared to the same period in 2010. This decrease was primarily due to $128 million in restricted cash that was released from escrow in 2011 for settled or withdrawn Chapter 11 disputed claims with no similar release in 2010. This decrease was
partially offset by an increase in capital expenditures due to the timing of payments.

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 the three months ended March 31, 2011 and 2010 were as follows:



|                                                                         |  |                             |         |  |      |  |       | 
|------------------------------------------------------------------------ |  | --------------------------- | ------- |  | ---- |  | ----- | 
|                                                                         |  | Three Months EndedMarch 31, |        
|(in millions)                                                            |  | 2011                        |         |  | 2010 | 
|Net issuances of commercial paper, net of discount of $1 million in 2011 |  |                             | $ 415   |  |      |  | $ 418 | 
|Long-term debt matured                                                   |  |                             | (500)   |  |      |  | -     | 
|Energy recovery bonds matured                                            |  |                             | (97)    |  |      |  | (93)  | 
|Preferred stock dividends paid                                           |  |                             | (4)     |  |      |  | (4)   | 
|Common stock dividends paid                                              |  |                             | (179)   |  |      |  | (179) | 
|Equity contribution                                                      |  |                             | 65      |  |      |  | 20    | 
|Other                                                                    |  |                             | 21      |  |      |  | 8     | 
|                                                                         |  |                             |         |  |      |  |       | 
|Net cash provided by (used in) financing activities                      |  |                             | $ (279) |  |      |  | $ 170 | 
|                                                                         |  |                             |         |  |      |  |       | 

In the three months ended March 31, 2011, net cash used in financing activities increased by $449
million compared to the same period in 2010. 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 March 31, 2011, 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 agreed to provide lease payments and investment contributions of up to $300 million to these companies in exchange for the
right to receive the benefits of local rebates, federal investment tax credits or grants, and a share of the customer payments made to these



48



---

##### Table of Contents

companies. As of March 31, 2011, PG&E Corporation had made total payments of $216 million under these tax equity agreements. On April 14, 2011, PG&E Corporation borrowed $75
million under its $187 million credit facility to fund the obligations under the tax equity agreements. On April 28, 2011, PG&E Corporation increased its commitment under one of the existing tax equity agreements by $98 million. Lease
payments and investment contributions are included in cash flows from operating and investing activities, respectively, within the Condensed 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 three
months ended March 31, 2011 and 2010: dividend payments, common stock issuance, and transactions between PG&E Corporation and the Utility.

CONTRACTUAL COMMITMENTS

PG&E Corporation
and the Utility enter into contractual commitments in connection with business activities. These future obligations primarily relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing),
purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and the purchase of fuel and transportation to support the Utilitys generation activities. (Refer to the 2010 Annual
Report, the Liquidity and Financial Resources section above and Notes 4 and 10 of the Notes to the Condensed Consolidated Financial Statements.)

CAPITAL EXPENDITURES

Most
of the Utilitys revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO rate cases, and GT&S rate cases. (See Regulatory Matters below.) The Utility also collects additional revenue
requirements to recover capital expenditures related to projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric distribution projects, and the SmartMeterTMadvanced metering infrastructure.

The Utilitys proposals for significant capital projects that have been submitted for CPUC approval are discussed in the 2010 Annual
Report. The GT&S rate case reflects a negotiated capital expenditure plan for 2011, 2012, 2013, and 2014 of $177 million, $202 million, $168 million, and $151 million, respectively. No other recent developments in authorized or proposed capital
projects have occurred since the 2010 Annual Report was filed.

OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any other off-balance sheet arrangements that have had, or are reasonably likely to
have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 2
(PG&E Corporations tax equity financing agreements) and Note 10 (the Utilitys commodity purchase agreements) of the Notes to the Condensed Consolidated Financial Statements.

CONTINGENCIES

PG&E Corporation and the
Utility have significant contingencies; including those related to Chapter 11 disputed claims, claims arising from the San Bruno accident, tax matters, legal matters (including regulatory investigations), and environmental matters, which are
discussed in Notes 9 and 10 of the Notes to the Condensed Consolidated Financial Statements.

NATURAL GAS
PIPELINE MATTERS

Following the San Bruno accident on September 9, 2010, several regulatory investigations and
proceedings have been initiated involving aspects of the Utilitys natural gas transmission operations, as discussed in the 2010 Annual Report. The following proceedings are currently pending:



49



---

##### Table of Contents

| |  |  | The NTSB began its formal investigation of the San Bruno accident on September 10, 2010. The NTSB is responsible for investigating the San Bruno
accident, determining the probable cause of the pipeline rupture, and making recommendations to prevent similar accidents from occurring. The NTSB has issued several public statements and reports regarding its investigation, but has not yet
determined the cause of the pipeline rupture. The NTSB held fact-finding hearings in Washington D.C. in early March. PG&E Corporation and the Utility are currently unable to predict the outcome of the investigation and when the NTSB will issue a
final report.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The CPUC appointed an independent review panel to gather and review facts, make a technical assessment of the San Bruno accident and its root cause,
and make recommendations for action by the CPUC to ensure such an accident is not repeated. The report of the independent review panel is expected in the second quarter of 2011.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The CPUC also began an investigation of the Rancho Cordova accident. See Pending CPUC Investigations below.
| | - |  | -------------------------------------------------------------------------------------------------------------



| |  |  | On February 24, 2011, the CPUC initiated a formal investigation to determine whether the Utilitys gas transmission pipeline recordkeeping
and its knowledge of its own gas transmission system, particularly the pipeline involved in the San Bruno accident, was deficient. See Pending CPUC Investigations below.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | On February 24, 2011, the CPUC also opened a rulemaking proceeding in order to develop and adopt safety-related changes to its regulation of
natural gas transmission and distribution pipelines in California. See CPUC Rulemaking Proceeding below.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In addition to the pending investigations and proceedings, 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. These lawsuits seek compensation for personal injury and property damage claims, damage to infrastructure, and other damage claims. See Pending Lawsuits and Claims below. Finally, each of the Boards of
Directors of PG&E Corporation and the Utility has appointed a special review committee, composed solely of independent directors, to review the circumstances surrounding the San Bruno accident, natural gas transmission and distribution practices
used in the industry and by the Utility, and such other matters as the committees deem appropriate. The committees reviews, which commenced in late 2010, are expected to be completed by the third quarter of 2011. PG&E Corporation and the
Utility are unable to predict the outcome of the pending investigations, regulatory proceedings, and legal matters associated with the San Bruno accident and the Utilitys natural gas operations.

The Utility currently expects that it will incur a material amount of costs to comply with CPUC orders and NTSB recommendations regarding
the Utilitys natural gas operations. It is uncertain what portion of these costs, if any, the Utility will be able to recover through rates and the timing of any such recovery. See Impact on Operations below.

Pending CPUC Investigations

Utilitys Facilities Records for its Natural Gas Pipelines

On February 24, 2011, the CPUC issued an order instituting a formal investigation (OII) pertaining to safety recordkeeping for the Utilitys gas transmission pipeline that ruptured
in the San Bruno accident, as well as for its entire gas transmission system. The CPUC stated that in deciding to issue the OII, it had relied on the NTSBs public preliminary reports issued in connection with its investigation of the San Bruno
accident, the NTSBs January 3, 2011 urgent safety recommendations regarding the importance of accurate pipeline records in calculating maximum safe operating pressures, and other NTSB statements. After the NTSB has completed its
investigation and issued a final report, the CPUC also will consider other possible violations of law, besides recordkeeping, associated with the Utilitys transmission lines and with Line 132 in particular.

The first phase of the CPUCs investigation will be limited to (1) whether the Utilitys gas transmission pipeline
recordkeeping and its knowledge of its own transmission gas system (and, in particular, the San Bruno pipeline) was deficient and unsafe, and (2) whether the Utility thereby violated applicable law and safety standards. In particular, this
phase will determine, among other matters, whether the San Bruno tragedy would have been preventable by the exercise of safe procedures and/or accurate and effective technical recordkeeping in compliance with the law. The CPUC will consider whether
the Utilitys approach to recordkeeping stems from corporate-level management policies and practices and, if so, whether those management practices and policies contributed to recordkeeping violations that adversely affected safety.



50



---

##### Table of Contents

On April 18, 2011, the Utility provided information to the CPUC about the regulatory
history applicable to gas transmission and recordkeeping practices, the records related to the San Bruno accident, and other information as directed by the CPUC.

By June 18, 2011, the Utility must provide the CPUC with additional information including information about the Utilitys recordkeeping policies and practices, actions the Utility has taken
since 1955 to promote safety on its gas transmission pipeline system, and safety risk assessments.

If the CPUC determines
that the Utility violated safety law standards with respect to its gas system recordkeeping, the CPUC will schedule a later phase or phases to determine whether penalties are warranted, and if so the amount of such penalties.

Rancho Cordova Accident

Additionally, the CPUCs investigation of the Rancho Cordova accident is pending. On February 17, 2011, the Utility submitted its report to the CPUC to provide extensive information, from as far
back as January 1, 2000, about the Utilitys natural gas operating and maintenance practices and procedures. The Utilitys report agrees with the NTSBs conclusions about the probable cause of the accident and explains what
process improvements the Utility has made to prevent a similar accident in the future. The CPUC has scheduled an evidentiary hearing in mid-July.

If the CPUC determines that the Utility violated applicable laws in connection with the San Bruno or Rancho Cordova accidents, the CPUC could impose penalties of up to $20,000 per day, per violation,
which, in the aggregate, could have a material adverse impact on PG&E Corporations and the Utilitys financial condition, results of operations, and cash flows. (See Note 10 of the Notes to the Condensed Consolidated Financial
Statements.) In addition, law enforcement authorities could begin proceedings that could result in the imposition of civil or criminal fines or penalties on the Utility. PG&E Corporation and the Utility are unable to predict the ultimate outcome
of the investigations discussed above or whether additional investigations or proceedings will be instituted.

CPUC Rulemaking Proceeding

On February 24, 2011, the CPUC opened a rulemaking proceeding in order to develop and adopt safety-related changes
to its regulation of natural gas transmission and distribution pipelines, including requirements for construction, especially shut-off valves, maintenance, inspections, operation, record retention, ratemaking, and the application of penalties. Among
other objectives, the CPUC stated that it intends to use the proceeding to:



| |  |  | provide the public with the expert recommendations of the independent review panel appointed by the CPUC to conduct an investigation into the San Bruno
accident;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | consider ways that the CPUC can undertake a comprehensive risk assessment for all natural gas pipelines regulated by the CPUC;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



| |  |  | consider available options for the CPUC to better align ratemaking policies, practices, and incentives to elevate safety considerations, and maintain
utility management focus on the nuts and bolts details of prudent utility operations; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | consider whether additional whistleblower protections are needed.
| | - |  | -----------------------------------------------------------------

On March 15, 2011, the Utility submitted a report in response to the CPUCs order to (1) search the Utilitys records
for all as-built drawings, alignment sheets, and specifications, and all design, construction, inspection, testing, maintenance, and other related records, relating to pipeline system components (such as pipe segments, valves, fittings, and weld
seams) for all of the Utilitys natural gas transmission pipelines located in class 3 and class 4 locations and class 1 and class 2 high consequence areas (HCA) that have not been subject to hydrostatic pressure testing to determine
the pipelines maximum allowable operating pressure (MAOP) and (2) use the located records to determine the MAOP of these pipelines, based on the weakest section of the pipeline or component. (The CPUCs order was
originally issued on January 3, 2011 following the NTSBs urgent safety recommendations regarding the importance of accurate pipeline records in calculating maximum safe operating pressures.) The Utility reported that it had been able to
locate complete or partial records of pressure tests for approximately 1,200 miles of the 1,805 miles of pipelines, including pipelines whose MAOP was not required to be established through pressure-testing by state or federal regulations.

On March 24, 2011, the CPUC issued an order to show cause (OSC) why the Utility should not be penalized for
failing to present evidence that it aggressively and diligently searched its records. On April 11, 2011, the CPUC held oral arguments related to a proposed stipulation between the CPUCs Consumer Protection and Safety Division
(CPSD) and the Utility to resolve the OSC by establishing a detailed compliance plan including specific milestones for the Utility to meet as it completes its records review and MAOP validation. The plan would require the Utility to
(1) complete any additional record collection for 705 miles of pipeline that do



51



---

##### Table of Contents

not have pressure test records and (2) validate the MAOP based on the records, by August 31, 2011. The proposed compliance plan is based on an MAOP validation methodology that would
supplement specific documentation with an engineering analysis, excavation and field testing, and assumptions about certain pipeline components, such as fittings and elbows, based on the material specifications at the time those materials were
procured. On April 26, 2011, the CPSD notified the Utility that the proposed methodology was not sufficient and that it believes the CPUC should require pressure testing or pipe replacement whenever assumptions would be used in the
Utilitys validation efforts. If the CPUC concurs with the CPSD, the Utility believes that the proposed compliance plan should be revised based on a new, longer-term strategy for pressure testing and pipeline replacement.

Under the proposed stipulation the Utility would pay a penalty of $3 million. If there is an unexcused failure by the Utility to meet any
of the milestones, the Utility would be required to pay additional penalties, up to $3 million, as the CPUC determines. The penalties would not be recoverable through rates. The proposed stipulation does not constitute an admission by the Utility of
any fact alleged in the OSC or of any non-compliance or other violation of any order, rule, regulation or law. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the proposed stipulation.

By the end of June 2011, the Utility plans to submit its Pipeline 2020 program of initiatives, first announced in October 2010, to the
CPUC for consideration in the rulemaking proceeding. Through the program, the Utility intends to work with regulators and industry experts to strengthen the natural gas system over the next decade. The program would focus on the modernization of
critical pipeline infrastructure, the use of automatic or remotely operated shut-off valves, the development of industry-leading best practices, and enhancing public safety. On December 1, 2010, the Utility requested the CPUC to permit the
Utility to establish a memorandum account so the Utility can track costs incurred under the program for possible future recovery through rates. On April 4, 2011, a draft resolution was issued which, if adopted by the CPUC, would deny the
Utilitys request to establish the memorandum account. Instead, the resolution proposes to allow the Utility to seek approval of the memorandum account in the rulemaking proceeding. The CPUC has indicated that the rulemaking process will be the
vehicle for addressing ratemaking and cost recovery for the costs incurred by all the California gas utilities to comply with and meet the new standards.

The CPUC will hold public hearings and conduct a pre-hearing conference by the end of the second quarter of 2011. After the pre-hearing conference, a ruling will be issued to define the scope of the
proceeding and set a procedural schedule.

Pending Lawsuits and Other Claims

In addition to the pending investigations and proceedings discussed above, as of March 31, 2011, 74 tort lawsuits on behalf of
approximately 224 plaintiffs, including two class action lawsuits, have been filed against PG&E Corporation and the Utility. Five of the lawsuits on behalf of 11 plaintiffs were filed in the San Francisco County Superior Court; the rest were
filed in San Mateo County Superior Court. These tort lawsuits seek compensation for personal injury and property damage and seek other relief. The class action lawsuits allege causes of action for strict liability, negligence, public nuisance,
private nuisance, and declaratory relief. Several other residents of San Bruno also have submitted damage claims to the Utility. Another lawsuit was filed in San Mateo Superior Court as a purported shareholder derivative lawsuit to seek recovery on
behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. All of these cases have been coordinated and assigned to one judge in the San Mateo County Superior Court.

The Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident,
including personal injury and property damage claims, damage to infrastructure, and other damage claims. The Utility currently estimates that it may incur as much as $400 million for third-party claims. (See Note 10 of the Notes to the Condensed
Consolidated Financial Statements.) As more information becomes known, including information resulting from the NTSB and CPUC investigations, managements estimates and assumptions regarding the amount of third-party liability incurred in
connection with the San Bruno accident may change. Although PG&E Corporation and the Utility currently consider it likely that a significant portion 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 March 31, 2011.

On February 23,
2011, PG&E Corporation rejected a shareholder demand that had been made following the San Bruno accident demanding that the PG&E Corporation Board of Directors (1) institute an independent investigation of the San Bruno accident and
related alleged safety issues; (2) seek recovery of all costs associated with such issues through legal proceedings against those determined to be responsible, including board members, officers, other employees, and third parties; and
(3) adopt corporate governance initiatives and safety programs. The PG&E Corporation Board of Directors authorized PG&E Corporation to reject the demand as had been recommended by the Evaluation Committee, a committee composed of
outside Board members that had been appointed to evaluate the demand and recommend how the Board should respond. In rejecting the demand, the Board reserved the right to commence further investigation or litigation regarding the San Bruno accident
if the Board deems such investigation or litigation appropriate. In April 2011, the shareholders counsel wrote to the Evaluation Committees counsel requesting materials that would evidence the Boards action. The Evaluation
Committee is currently considering the request.



52



---

##### Table of Contents

Impact on Operations

The Utility currently estimates that it will incur incremental costs associated with its natural gas transmission business, ranging from $350 million to $550 million in 2011, increased from the $200
million to $300 million estimated range disclosed in the 2010 Annual Report. These costs are expected to include costs to complete the Utilitys review and validation of pipeline records, to perform pressure tests and other tests on portions of
its natural gas transmission system, to respond to regulatory proceedings, and to perform other activities related to the San Bruno accident.

These cost estimates could change depending on a number of factors, including the outcome of the regulatory proceedings and pending investigations discussed above, the outcome of the safety
phase of the Utilitys 2011 GT&S rate case (see 2011 Gas Transmission and Storage Rate Case below), and the outcome of future rulemaking, ratemaking, or other investigatory proceedings that may be commenced at the CPUC. If
state or federal legislation is enacted to address natural gas transmission operations and maintenance, the Utility may incur additional costs to comply with such new statutory requirements. Such legislation may establish operating practice
standards for natural gas transmission operations and safety, which may require the use of certain types of inspection methods and equipment, and to require the installations of certain types of valves.

PG&E Corporation and the Utility are uncertain what portion of the costs, if any, 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. The CPUC is expected to decide in the future whether the Utilitys ratepayers or shareholders, or both, will pay for the
Utilitys costs incurred in testing, pipe replacement, or other costs. As the Utility incurs these costs, the amount of equity needed by the Utility to maintain its capital structure is anticipated to increase. (See Liquidity and Capital
Resources above.)

Future operating and maintenance expenses also may be affected by the amount of third party liability
the Utility incurs as a result of the San Bruno accident. The Utility estimates that it may incur as much as $180 million for third-party claims related to the San Bruno accident, in addition to the $220 million provision recorded in 2010. (See Note
10 of the Notes to the Condensed Consolidated Financial Statements.) Finally, if the CPUC determines in the pending investigations discussed above that the Utility violated laws, rules, regulations or orders, the CPUC may impose fines or penalties
on the Utility, which may be material.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies.
Significant regulatory developments that have occurred since the 2010 Annual Report was filed with the SEC are discussed below.

2011
General Rate Case Application

On February 22, 2011, a proposed decision (PD) and an
alternate proposed decision (APD) were issued in the Utilitys 2011 GRC at the CPUC. In the GRC, the CPUC will authorize the Utilitys revenue requirements for 2011 through 2013 for its costs to own and operate its electric and
natural gas distribution and electric generation operations. The PD and the APD would approve the unopposed October 15, 2010 settlement agreement among the Utility, the CPUCs Division of Ratepayer Advocates (DRA), The Utility
Reform Network (TURN), Aglet Consumer Alliance, and nearly all other intervening parties. The 2011 revenue requirement increase associated with the settlement agreement is $395 million. In addition, the PD and the APD would resolve the
one issue not covered in the settlement agreement, which is the Utilitys request for additional revenues to recover financing costs and the return of capital related to the Utilitys unrecovered investment in conventional meters that have
been replaced by SmartMeterTMdevices.

As shown in the table below, the Utility originally had requested an additional $44 million in revenues in 2011 to recover the financing
costs associated with its remaining $341 million investment in conventional electric meters, based on the weighted average after-tax cost of capital of 8.79% (12.93% on a pre-tax basis) and an 18-year average remaining life for these meters. The PD
would authorize an additional $53 million in revenues in 2011, while the APD would result in an additional $59 million in revenues.

The settlement agreements proposed $395 million revenue requirement increase for 2011, combined with the Utilitys original request of $44 million in revenues for the recovery of financing
costs associated with conventional meters, would have resulted in an increase of $439 million for 2011. In comparison, the PD would result in an increase of $448 million for 2011. The APD would provide an increase of $454 million. If either the PD
or the APD is adopted, the Utilitys related 2011 revenues are projected to be approximately $3.2 billion for electric distribution, $1.1 billion for natural gas distribution, and $1.7 billion for electric generation operations.



53



---

##### Table of Contents

|                                                             |  |            |       |  |                   |  |       |                             |  |  |       | 
|------------------------------------------------------------ |  | ---------- | ----- |  | ----------------- |  | ----- | --------------------------- |  |  | ----- | 
|(in millions)                                                |  | Settlement |       |  | Proposed Decision |  |       | Alternate Proposed Decision | 
|                                                             |  |            |       | 
|Settlement Revenue Requirement Increase                      |  |            | $ 395 |  |                   |  | $ 395 |                             |  |  | $ 395 | 
|Return on Undepreciated Meters                               |  |            | 44    |  |                   |  | 25    |                             |  |  | 35    | 
|Impact of Change in Amortization Period                      |  |            | -     |  |                   |  | 38    |                             |  |  | 38    | 
|Levelization Adjustment                                      |  |            | -     |  |                   |  | (10)  |                             |  |  | (14)  | 
|                                                             |  |            |       | 
|Total Revenue Requirement Increase Incremental to Settlement |  |            | 44    |  |                   |  | 53    |                             |  |  | 59    | 
|                                                             |  |            |       | 
|Total Revenue Requirement Increase                           |  |            | $ 439 |  |                   |  | $ 448 |                             |  |  | $ 454 | 
|                                                             |  |            |       | 

Both the PD and the APD authorize the attrition increases proposed in the settlement agreement: an
additional increase of $180 million to the authorized 2011 revenues in 2012 and an additional increase of $185 million in 2013. In addition, while the Utility originally had requested recovery of $113 million for meter reading costs in 2011, both
the PD and the APD authorize recovery of these costs via a new balancing account as proposed in the settlement agreement. After a final decision is issued, future revenues will be adjusted to allow the Utility to recover the authorized revenue
requirements as of January 1, 2011.

Additionally, on April 5, 2011, the CPUC issued both a PD and an APD in the
residential rate design portion of the Utilitys 2011 GRC proceeding. If either the PD or APD are adopted, there would be less disparity between tiers which is expected to result in less volatility for customers in higher tiers.

PG&E Corporation and the Utility are unable to predict whether the CPUC will approve either the PDs or APDs, or an alternative.

Electric Transmission Owner Rate Cases

On April 28, 2011, the Utility filed with the FERC a request to approve an uncontested settlement of the Utilitys electric TO rate case. The settlement, if approved, will increase the annual
retail revenue requirement from $875 million to $934 million with rates effective as of March 1, 2011. The Utility has held adequate reserves for refund for the difference between revenues collected at the higher as-filed rates and the rates
included in the settlement since March 1, 2011. It is expected that FERC will act on the settlement before the end of 2011.

2011 Gas
Transmission and Storage Rate Case

On April 14, 2011, the CPUC issued a final decision that approves the settlement
agreement, known as the Gas Accord V Settlement Agreement (Gas Accord V), entered into among the Utility and other parties to determine the rates and terms and conditions of the Utilitys gas transmission and storage services for a
four-year period beginning January 1, 2011. The decision also resolves several objections raised by the other two California gas utilities.

The CPUC authorized a 2011 natural gas transmission and storage revenue requirement of $514 million, an increase of $52 million over the 2010 adopted revenue requirement. With attrition increases, the
Utilitys revenue requirements for 2012, 2013, and 2014 will be $541 million, $565 million, and $582 million, respectively. The Utility also has been authorized to recover (through natural gas transmission and storage rates) revenue
requirements for other costs, such as the cost of electricity used to operate natural gas compressor stations and other costs, that are determined in the Utilitys 2011 General Rate Case or other Utility regulatory proceedings. Customer rates
for the remainder of 2011 will be adjusted to allow the Utility to recover the authorized revenue requirements from January 1, 2011.

The decision also requires the Utility to file a semi-annual safety report, beginning October 1, 2011, with the CPUCs Energy Division and the CPSD to provide details about the Utilitys
use of funds budgeted for pipeline safety, reliability and integrity projects and activities, including an explanation of whether the Utility has under-spent or over-spent funds. The reports will provide CPUC staff with the necessary details to:
(1) monitor what storage and pipeline-related safety, reliability, and integrity capital projects and maintenance activities are being undertaken by the Utility and the amounts spent on such activities, (2) determine whether projects that
have been identified by the Utility with high risk assessments are being carried out or whether other higher risk projects have been undertaken instead, (3) determine the Utilitys rationale for reprioritization of projects, and
(4) monitor the status of the Utilitys compliance with federal regulations.



54



---

##### Table of Contents

The CPUC also established a safety phase of the GT&S case to address
safety-related concerns involving actions that can be taken during the rate cycle period covered by the GT&S rate case. PG&E Corporation and the Utility anticipate that the CPUC will issue a final decision in the safety phase
before the end of the second quarter of 2011.

Energy Efficiency Programs and Incentive Ratemaking

On November 15, 2010, a proposed decision was issued that if, adopted by the CPUC, would modify the incentive mechanism that would
apply to the 2010 through 2012 program cycle. Among other changes, the proposed modification would limit the total amount of the incentive award or penalty that could be awarded to, or imposed on, all the investor-owned utilities to $189 million. If
the proposed decision is adopted, the Utilitys opportunity to earn incentive revenues would be limited compared to the mechanism that was in place for the 2006-2008 program cycle. The proposed decision notes that the CPUC may establish a new
rule-making proceeding to determine what mechanism, if any, will apply to programs beginning in 2013 and later.

Additionally,
on March 17, 2011, the California Legislature adopted Senate Bill 69 (SB 69) which proposes the transfer of up to $155 million from the gas-consumption surcharge fund to the California General State Fund to help close the
states fiscal-year 2011-2012 budget gap. The surcharge is collected to help fund gas public purpose programs, including energy efficiency programs. If the methodology adopted by the CPUC for allocating the split amongst the IOUs is based on
energy efficiency programs, the Utilitys share is estimated to be up to $64 million. The Utilitys two year 2011-2012 budget for gas energy efficiency programs is $892 million, of which approximately $160 million was expected to be funded
by the gas surcharge funds. If SB 69 is signed by the Governor and becomes effective, PG&E Corporations and the Utilitys results of operations could be adversely affected if the CPUC does not permit the Utility to curtail spending on
some of the programs or to recover the shortfall in program funding through rates. In addition, it is unclear how SB 69 would affect the proposal to modify the incentive mechanism for the 2010 through 2012 program cycle.

CPUC Resolution Regarding the Tax Relief Act

On April 14, 2011, the CPUC adopted a resolution establishing a one-way memorandum account for certain rate-regulated utilities, including the Utility, to record the net change in the cost of
providing utility service associated with the Tax Relief Act. For qualified property placed into service after September 8, 2010 and before January 1, 2012, the Tax Relief Act allows the Utility to take a tax deduction for the entire cost
of its investment in the same year that the property was placed into service. For qualified property placed into service in 2012 (as well as a portion of the investment on certain property placed into service in 2013 if construction had begun before
January 1, 2013) the Utility may take a deduction for one-half of the cost of the investment in the same year that the property was placed into service with the remaining investment cost recovered over a normal depreciation period. As a result
of the accelerated depreciation the Utilitys federal tax payments are expected to be lower allowing the Utility to use the increased cash for additional capital investments. The memorandum account will track: (1) the reduction in revenue
requirements that is due to lower rate base resulting from deferred tax liabilities related to the accelerated federal tax depreciation, (2) the increase in revenue requirements associated with incremental capital investments that are made on
behalf of Utility customers, and (3) other applicable reductions and increases in revenue requirements.

The memorandum
account will be applicable to CPUC-jurisdictional assets only; however, it is expected to exclude investments that have separate ratemaking treatment such as the Utilitys program to install an advanced metering system. The net benefits of
the Tax Relief Act related to those excluded investments will automatically flow to customers under existing balancing account mechanisms. The memorandum account will be in effect for capital investments (other than those related to natural gas
transmission operations) until 2014, the test year of the Utilitys next general rate case. The memorandum account will be in effect for capital investments related to natural gas transmission operations until 2015, the test year for the
Utilitys next gas transmission and storage rate case. In each rate case, the CPUC will determine the disposition of the memorandum account.



55



---

##### Table of Contents

Deployment of SmartMeterTMTechnology

The CPUC has authorized the Utilitys program to install approximately 10 million advanced electric and gas meters throughout the Utilitys service territory by the end of 2012. Advanced
electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a
wireless communication network and transmitted to the Utilitys information system where the data is stored and used for billing and other Utility business purposes. Advanced electric meters enable the implementation of dynamic
pricing rates for customers that reflect the higher cost of electricity during periods of high demand. As of March 31, 2011, the Utility has installed 7.8 million meters. The CPUC has authorized the Utility to recover a maximum of
$2.3 billion in estimated project costs. Costs that exceed $2.3 billion will not be recoverable through rates. As of March 31, 2011, the Utility has incurred costs of $2.1 billion. The Utility has also recorded a provision of $36 million as of
March 31, 2011 and December 31, 2010, representing the current forecast of capital-related costs that are expected to exceed the CPUC-authorized cost cap and therefore will not be recoverable through rates. The Utility will update its
forecasts as the project continues and may incur additional non-recoverable costs.

On March 24, 2011, the Utility filed
an application with the CPUC to seek approval of the Utilitys proposal to provide residential customers the option to turn off the radios in their gas and electric SmartMeter devices to disable the radio frequency (RF)
communications used in the wireless meters. The Utility requested that the CPUC authorize electric and gas revenue requirements totaling $84.4 million through 2013 to recover the Utilitys estimated costs to provide the radio-off
option which would be collected through fees charged to customers who choose the radio-off option. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the Utilitys proposal.

Additionally, on April 11, 2011, the Kern County Superior Court in Bakersfield, California dismissed the pending class action
complaint that had alleged that the SmartMeter system generated inaccurate bills and led to overcharges, among other allegations.

Diablo Canyon Relicensing Application

The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. On November 24, 2009, the Utility filed an
application to request the NRC to renew each of the operating licenses for Diablo Canyon for 20 years, until November 2044 for Unit 1 and August 2045 for Unit 2. The license renewal process is expected to take several years as the NRC holds public
hearings and conducts safety and environmental analyses and site audits. The Utilitys application has been challenged by local environmental and anti-nuclear power organizations and the NRC is considering whether to admit their contentions for
further review in the renewal process. Further, in response to the significant damage to the nuclear facilities in Japan caused by the recent earthquake and tsunami, there has been increased public concern expressed about the seismic safety of
Diablo Canyon. On April 11, 2011, the Utility requested that the NRC delay final action on the Utilitys renewal application until after the Utility completes additional seismic studies and submits a report to the NRC addressing the
results of those studies. The Utility also announced that it is seeking to obtain required permits from various local regulatory agencies on an expedited basis to accelerate the completion of the seismic studies. Finally, on April 14, 2011,
petitions were filed with the NRC requesting that the NRC immediately suspend all nuclear licensing and re-licensing activities until it completes a thorough investigation into the adequacy of federal safety and environmental standards and the NRC
determines whether new regulations are required. Additionally, on April 14, 2011, a motion was filed with the CPUC requesting the dismissal of the Utilitys application to recover the costs associated with renewal of the Diablo Canyon
operating licenses. The Utility estimates that these costs will total $85 million.

PG&E Corporation and the Utility are
unable to predict how long the NRC process will be delayed, whether the NRC will approve the license renewal application, or whether the NRC will suspend the license renewal process. (See Item 1A. Risk Factors, below.)



56



---

##### Table of Contents

ENVIRONMENTAL MATTERS

The Utilitys operations are subject to extensive federal, state, and local laws and permits relating to the protection of the
environment and the safety and health of the Utilitys personnel and the public. (See Risk Factors in the 2010 Annual Report.) These laws and requirements relate to a broad range of the Utilitys activities, including the
discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions. Significant
developments that have occurred since the 2010 Annual Report was filed with the Securities and Exchange Commission are discussed below.

Climate Change

The
California Global Warming Solutions Act of 2006 (also known as Assembly Bill 32 or AB 32) requires the gradual reduction of GHG emissions in California to the 1990 levels by 2020 on a schedule beginning in 2012. In December 2008, the
California Air Resources Board (CARB) adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target, including a proposed
cap-and-trade program. On March 18, 2011, the San Francisco County Superior Court ruled that the CARB had failed to comply with the California Environmental Quality Act (CEQA) because the CARB did not adequately review and analyze
alternatives to the measures identified in its scoping plan. The court prohibited the CARB from implementing any of the measures contained in the scoping plan until it complies with the CEQA requirements. As a result, the implementation of the
CARBs proposed cap-and-trade system may be delayed beyond the planned effective date of January 1, 2012.

Renewable Energy
Resources

On April 12, 2011, the California Governor signed new legislation establishing a new renewable portfolio
standard (RPS) that increases the amount of renewable energy that retail sellers of electricity, such as the Utility, must deliver to their customers from at least 20% of their total retail sales by the end of 2010, as required by the
prior law, to 33% of their total retail sales by the end of 2020. The new legislation will become effective 90 days after the current special session of the California Legislature ends. In response to the enactment of the new RPS law, the CARB
is expected to abandon its regulatory efforts to establish a 33% renewable energy standard.

Under the new RPS law the amount
of electricity delivered from renewable energy resources must equal an average of 20% of total retail sales in 2011, 2012 and 2013, at least 25% of total retail sales by December 31, 2016, and at least 33% of total retail sales by
December 31, 2020. The CPUC is authorized to set interim procurement targets for all other intervening years to reflect reasonable progress toward the statutory goals. The CPUC must determine by no later than January 1, 2012, the total
procurement requirement (expressed as a percentage of total retail sales) for each retail seller, including the Utility, in each future compliance period (i.e., 2011-2013, 2014-2016, 2017-2020, and each year thereafter). The Utility expects that the
CPUCs rulemaking in response to the new legislation will more definitively establish the Utilitys RPS compliance obligations, including a cap on the Utilitys total mandated RPS compliance expenditures.

The new RPS legislation creates three distinct categories of renewable energy products and imposes minimum or maximum procurement targets
for each of these product categories that must be met in each future compliance period. With certain exceptions, these categorical requirements will only apply to contracts that are entered into after June 1, 2010. The new law imposes limits on
the types of tradable renewable energy credits (RECs) that can be used to satisfy the categorical requirements and contains new restrictions on the Utilitys ability to carry forward (or bank) RPS volumes from contracts
with terms of less than ten years. The new legislation requires that the CPUC approve applications for utility-owned renewable generation up to a certain energy-based cap, provided that the CPUC finds that the cost of the application is reasonable
and meets other conditions. The costs of utility-owned renewable generation projects will be subject to traditional cost-of-service ratemaking treatment.

Under the new RPS law, the CPUC must waive enforcement of the RPS requirements as to any particular retail seller if it finds that certain specified circumstances beyond the control of the retail seller
will prevent compliance and the retail seller has met certain other conditions, including demonstrating that the retail seller has taken all reasonable actions under its control to achieve full compliance.

Until the CPUC adopts regulations to implement the new law, it is uncertain how the CPUCs regulations and decisions issued pursuant
to the former 20% RPS statute will apply to the new RPS requirements.



57



---

##### Table of Contents

Water Quality

Section 316(b) of the federal Clean Water Act requires that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best
technology available to minimize adverse environmental impacts. On March 28, 2011, the U.S. Environmental Protection Agency (EPA) issued draft regulations that propose specific reductions for impingement (which occurs when larger
organisms are caught on water filter screens) and provide a case-by-case site specific assessment to establish compliance requirements for entrainment (which occurs when organisms are drawn through the cooling water system). The proposed site
specific assessment allows for the consideration of a variety of factors including social costs and benefits, energy reliability, land availability, and non-water quality adverse impacts. The draft regulations are subject to public comment and final
regulations are not expected until July 2012.

The California Water Resources Control Board (Water Board) also has
adopted a policy on once-through cooling. The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities
by at least 85%. However, with respect to the states nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are wholly out of proportion to the costs
considered by the Water Board in developing its policy or if the installation of cooling towers would be wholly unreasonable after considering non-cost factors such as engineering and permitting constraints and adverse environmental
impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the wholly out of proportion test. The Utility also believes that the installation of cooling
towers at Diablo Canyon would be wholly unreasonable. If the Water Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at
Diablo Canyon and may incur a material charge. Assuming the Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make
payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utilitys Diablo Canyon operations must be in compliance with the Water Boards policy by December 31, 2024.

Remediation

The Utility has been, and may be, required to pay for environmental remediation costs at sites where it is identified as a potentially
responsible party under federal and state environmental laws. These sites include former manufactured gas plant (MGP) sites, current and former power plant sites, former gas gathering and gas storage sites, sites where natural gas
compressor stations are located, current and former substations, service center and general construction yard sites, and sites currently and formerly used by the Utility for the storage, recycling, or disposal of hazardous substances. Under federal
and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements, for a discussion of
estimated environmental remediation liabilities and Legal Proceedings of Part II, Item 1 for discussion of related legal proceedings.)

LEGAL MATTERS

In addition to the provision made for claims related to the San Bruno accident, PG&E Corporations and the Utilitys Condensed Consolidated Financial Statements also include provisions for
claims and lawsuits that have arisen in the ordinary course of business, regulatory proceedings, and other legal matters. See Legal Matters in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

RISK MANAGEMENT ACTIVITIES

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

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



58



---

##### Table of Contents

On July 21, 2010, President Obama signed into law new federal financial reform
legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act. PG&E Corporation and the Utility are evaluating the new legislation, and will review future regulations to assess compliance requirements as well as potential impacts on
the Utilitys procurement activities and risk management programs.

Price Risk

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

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

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

The Utilitys value-at-risk calculated under the methodology described above was $9
million at March 31, 2011. The Utilitys high, low, and average values-at-risk during the 12 months ended March 31, 2011 were $20 million, $8 million, and $13 million, respectively. (See Note 7 of the Notes to the Condensed
Consolidated Financial Statements for further discussion of price risk management activities.)

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of
assumed changes in market interest rates. At March 31, 2011, if interest rates changed by 1% for all current PG&E Corporation and the Utility variable rate and short-term debt and investments, the change would affect net income for the next
12 months by $11.8 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

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

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



59



---

##### Table of Contents

The following table summarizes the Utilitys net credit risk exposure to its
counterparties, as well as the Utilitys credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of March 31, 2011 and December 31, 2010:



|                                                                                                                                                                                                                                                                                                             |  |                                                |       |  |                  |  |      |                        |  |  |                                                     |  |  |                                                           |   |  |  |  |       | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ---------------------------------------------- | ----- |  | ---------------- |  | ---- | ---------------------- |  |  | --------------------------------------------------- |  |  | --------------------------------------------------------- | - |  |  |  | ----- | 
|(in millions)                                                                                                                                                                                                                                                                                                |  | GrossCredit
ExposureBeforeCreditCollateral (1) |       |  | CreditCollateral |  |      | Net CreditExposure (2) |  |  | Number of
Wholesale
Customers orCounterparties >10% |  |  | Net Exposure to
Wholesale
Customers orCounterparties >10% |  
|                                                                                                                                                                                                                                                                                                             |  |                                                |       | 
|March 31, 2011                                                                                                                                                                                                                                                                                               |  |                                                | $ 307 |  |                  |  | $ 17 |                        |  |  | $ 290                                               |  |  |                                                           | 2 |  |  |  | $ 192 | 
|December 31, 2010                                                                                                                                                                                                                                                                                            |  |                                                | $ 269 |  |                  |  | $ 17 |                        |  |  | $ 252                                               |  |  |                                                           | 2 |  |  |  | $ 187 | 
|                                                                                                                                                                                                                                                                                                             |  |                                                |       |  |                 
|(1) Gross credit exposure equals mark-to-market value on physically and financially settled
contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity. | 
|(2) Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit
Collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.                                                                    | 

CRITICAL ACCOUNTING POLICIES

The preparation of
Condensed Consolidated Financial Statements in accordance with U.S. generally accepted accounting principles involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial
statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies, due, in part, to their complexity and because their application is
relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. In addition, management has made significant estimates
and assumptions about accruals related to the San Bruno accident as well as accruals for various legal matters. Actual results may differ substantially from these estimates. These policies and their key characteristics are discussed in detail in the
2010 Annual Report. They include:



| |  |  | regulatory assets and liabilities;
| | - |  | ----------------------------------



| |  |  | loss contingencies associated with legal matters and environmental remediation liabilities;
| | - |  | -------------------------------------------------------------------------------------------



| |  |  | retirement obligations; and
| | - |  | ---------------------------



| |  |  | pension and other postretirement plans.
| | - |  | ---------------------------------------

For the three months ended March 31, 2011, there were no changes in the methodology for computing critical accounting estimates and no material changes to the important assumptions underlying the
critical accounting estimates.



60



---

##### Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK

PG&E Corporations and the Utilitys primary market risk results from changes in energy prices.
PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options,
and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates (see Risk Management Activities above under Item 2: Managements Discussion and Analysis of Financial Condition and Results of
Operations).

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporations and the Utilitys disclosure controls and procedures as of March 31,
2011, PG&E Corporations and the Utilitys respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective to ensure that information required to be disclosed by
PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 (1934 Act) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules
and forms. In addition, PG&E Corporations and the Utilitys respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required
to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporations and the Utilitys management,
including PG&E Corporations and the Utilitys respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended March 31, 2011
that have materially affected, or are reasonably likely to materially affect, PG&E Corporations or the Utilitys internal control over financial reporting.



61



---

##### Table of Contents

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding
PG&E Corporations and the Utilitys liability for legal matters, see Note 10 of the Notes to the Consolidated Financial Statements, which discussion is incorporated into this Item 1 by reference.

Diablo Canyon Power Plant

In April 2011, the United States Environmental Protection Agency (EPA) issued revised proposed regulations under Section 316(b) of the Clean Water Act, which requires that cooling water
intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. Final regulations are expected to be issued in mid-2012, and could affect future negotiations between the state Water Board
and the Utility regarding the status of the 2003 settlement agreement concerning a proposed draft Cease and Desist Order issued by the Water Board against the Utility. For more information about the settlement agreement and federal and state water
quality regulations affecting Diablo Canyon, see PG&E Corporations and the Utilitys joint Annual Report on Form 10-K for the year ended December 31, 2010.

PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on the Utilitys financial condition or results of operations.

Hinkley Natural Gas Compressor Station

As previously disclosed, groundwater at the Utilitys Hinkley natural gas compressor station contains hexavalent chromium as a result of the Utilitys past operating practices. At the Hinkley
site, the Utility is cooperating with the Regional Water Quality Control Board (RWQCB) to evaluate and remediate the chromium groundwater plume. Measures have been implemented to control movement of the plume, while full-scale in-situ
treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures, as well as possible future measures, is underway as part of the development of a final remediation plan. In March 2011, the
RWQCB advised the Utility that it is considering assessing administrative penalties of up to $5,000 per day due to the Utilitys alleged violation of an administrative order issued in 2008 requiring the Utility to control the spread of the
chromium groundwater plume beyond boundaries described in the order. The Utility does not believe it is in violation of the order and is working with the RWQCB to resolve its concerns. PG&E Corporation and the Utility believe that the ultimate
outcome of this matter will not have a material adverse impact on the Utilitys financial condition or results of operations.

Litigation Related to the San Bruno Accident

As of March 31, 2011, 74 tort lawsuits on behalf of approximately 224 plaintiffs, including two class action lawsuits, have been filed against PG&E Corporation and the Utility. Five of the
lawsuits were filed in San Francisco County Superior Court; the rest were filed in San Mateo County Superior Court. These lawsuits seek compensation for personal injury and property damage and seek other relief. The class action lawsuits allege
causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. Several other residents of San Bruno also have submitted damage claims to the Utility. The Utilitys petition to coordinate these
lawsuits in San Mateo County Superior Court has been granted.

Another lawsuit was filed in San Mateo County Superior Court as
a purported shareholder derivative lawsuit to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. This case has been included in the coordinated
proceedings described above.

The Utility maintains liability insurance for damages in the approximate amount of $992 million
in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that a significant portion of the costs the Utility incurs for third-party claims relating to the San Bruno accident will ultimately be
covered by this insurance, no amounts for insurance recoveries have been recorded as of March 31, 2011. PG&E Corporation and the Utility are unable to predict the amount and timing of insurance recoveries.

For more information regarding the San Bruno accident and the related NTSB and CPUC investigations, see Managements
Discussion and Analysis of Financial Condition and Results of Operations  Natural Gas Pipeline Matters and Note 10 of the Notes to the Condensed Consolidated Financial Statements.



62



---

##### Table of Contents

ITEM 1A. RISK FACTORS

The risk factors appearing in the 2010 Annual Report under the headings set forth below are supplemented and updated as follows:

The ultimate amount of loss the Utility bears in connection with the San Bruno accident could have a material adverse impact on PG&E
Corporations and the Utilitys financial condition and results of operations.

On February 24, 2011,
the CPUC initiated a formal investigation pertaining to safety recordkeeping for the Utilitys gas transmission pipeline that ruptured in San Bruno on September 9, 2010, as well as for its entire gas transmission system. If the CPUC
determines that the Utility violated safety law standards with respect to its gas system recordkeeping, the CPUC may impose penalties on the Utility. If supported by the evidence, the CPUC stated that it will consider ordering daily fines for a
significant period of time. (See the section of this report entitled Managements Discussion and Analysis of Financial Condition and Results of Operations  Natural Gas Pipeline Matters above for more information.)

PG&E Corporation and the Utility are unable to predict whether the outcome of the investigation will have a material adverse effect
on PG&E Corporations and the Utilitys financial condition, results of operations, or cash flows.

If the Utility cannot
timely meet the applicable resource adequacy or renewable energy requirements, the Utility may be subject to penalties. Further, the CPUC may disallow costs incurred by the Utility under power purchase agreements it enters into to
meet applicable resource adequacy and renewable energy requirements if the CPUC finds that the costs are unreasonably above-market in the future.

On April 12, 2011, the California Governor signed new legislation that increases the amount of renewable energy that retail sellers of electricity, such as the Utility, must deliver to their
customers from at least 20% of their total retail sales by the end of 2010, as required by the prior law, to 33% of their total retail sales by the end of 2020. (See the section of this report entitled Managements Discussion and Analysis
of Financial Condition and Results of Operations  Environmental Matters  Renewable Energy Resources above.) PG&E Corporation and the Utility are unable to predict how or when the CPUC may fully implement the requirements in the
new law. Until the CPUC adopts regulations to implement the new law, it is uncertain how the CPUCs regulations and decisions issued pursuant to the former 20% RPS statute will apply to the new RPS requirements. In particular, it is uncertain
whether the CPUC will continue to limit penalties for noncompliance to $25 million per year as had applied under the prior RPS regulatory program.

The operation and decommissioning of the Utilitys nuclear power plants expose it to potentially significant liabilities and capital expenditures that it may not be able to recover from its
insurance or other sources, adversely affecting its financial condition, results of operations, and cash flow.

As a
result of the earthquake and tsunami that occurred in Japan that seriously damaged nuclear generation facilities there has been increased legislative, regulatory, and public scrutiny of the safety of nuclear power plants in the United States. The
NRC has begun to review the industrys preparedness for events similar to the events that occurred in Japan and has established a senior level agency task force to conduct a systematic review of NRC processes and regulations and evaluate
whether enhancements or new regulations are needed. There has been increased public concern expressed about the safety of the Utilitys Diablo Canyon nuclear generation facilities located along the coastline in San Luis Obispo, California,
which is in close proximity to active earthquake fault lines. On April 11, 2011, the Utility requested that the NRC delay final action on the Utilitys application to renew the operating licenses for Diablo Canyon Units 1 and 2 that are
scheduled to expire in 2024 and 2025 until after the Utility completes new seismic studies and submits a report to the NRC addressing the results of those studies.

The Utility may be required to incur additional capital expenditures and other expenses to address any new seismic safety requirements, backup power requirements, or other requirements that the NRC may
impose following its regulatory review or following the submission of the completed seismic studies for Diablo Canyon. The NRC may order the Utility to cease its nuclear operations until any such safety concerns are addressed or the NRC may
determine that the safety concerns cannot be addressed and order the Utility to cease operating Diablo Canyon. Alternatively, the Utility may determine that the safety concerns cannot be remedied in a feasible and economic manner and voluntarily
cease operations at Diablo Canyon. Further, depending on the results of the license renewal process, the NRC could deny the license renewal applications requiring nuclear operations to cease when the current licenses expire.

In addition the Utility may incur significant additional expense to comply with more stringent laws and regulations that may be adopted
by the NRC regarding the storage, handling, security, and disposal of radioactive materials, including spent nuclear fuel. If the Utility determines that it cannot comply with such new laws or regulations in a feasible and economic manner it may
voluntarily cease operations at Diablo Canyon.



63



---

##### Table of Contents

If the Utility is unable to recover costs it incurs to respond to safety concerns or if the
Utility ceased its nuclear operations, PG&E Corporations and the Utilitys financial condition, results of operations and cash flows could be materially and adversely affected.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the quarter ended March 31, 2011, PG&E Corporation made equity contributions totaling $65 million to the Utility in order
to maintain the 52% common equity component of its CPUC-authorized capital structure and to ensure that the Utility has adequate capital to fund its capital expenditures. Neither PG&E Corporation nor the Utility made any sales of unregistered
equity securities during the quarter ended March 31, 2011.

Issuer Purchases of Equity Securities

During the quarter ended March 31, 2011, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding.
During the quarter ended March 31, 2011, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed
Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

The Utilitys earnings to
fixed charges ratio for the three months ended March 31, 2011 was 2.56. The Utilitys earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2011 was 2.51. The statement of the
foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utilitys Registration
Statement Nos. 33-62488 and 333-172394 relating to various series of the Utilitys first preferred stock and its senior notes, respectively.

PG&E Corporations earnings to fixed charges ratio for the three months ended March 31, 2011 was 2.44. The statement of the foregoing ratio, together with the statement of the computation of
the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporations Registration Statement No. 333-172393 relating to its senior notes.



64



---

##### Table of Contents

ITEM 6. EXHIBITS



|           |  |                                                                                                                                                                            
|---------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1        |  | Bylaws of PG&E Corporation amended as of May 1, 2011                                                                                                                       
|           | 
|3.2        |  | Bylaws of Pacific Gas and Electric Company amended as of May 1, 2011                                                                                                       
|           | 
|*10.1      |  | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan                                                           
|           | 
|*10.2      |  | Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan                                                               
|           | 
|12.1       |  | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company                                                                                    
|           | 
|12.2       |  | Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company                                             
|           | 
|12.3       |  | Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation                                                                                                    
|           | 
|31.1       |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002                
|           | 
|31.2       |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of
2002
|           | 
|**32.1     |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002                
|           | 
|**32.2     |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of
2002
|           | 
|***101.INS |  | XBRL Instance Document                                                                                                                                                     
|           | 
|***101.SCH |  | XBRL Taxonomy Extension Schema Document                                                                                                                                    
|           | 
|***101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document                                                                                                                      
|           | 
|***101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document                                                                                                                       
|           | 
|***101.LAB |  | XBRL Taxonomy Extension Labels Linkbase Document                                                                                                                           
|           | 
|***101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document                                                                                                                     



|* | Management contract or compensatory agreement.
|- | ----------------------------------------------



|** | Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
|-- | -------------------------------------------------------------------------------------------------------------------



|*** | Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of
Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its
subsidiary, Pacific Gas and Electric Company.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



65



---

##### Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q
to be signed on their behalf by the undersigned thereunto duly authorized.



| |  |                                                                                                                            |  | 
| |  | -------------------------------------------------------------------------------------------------------------------------- |  | 
| |  | PG&E CORPORATION                                                                                                           |  | 
| |  |                                                                                                                           
| |  | KENT M. HARVEY                                                                                                             |  | 
| |  | Kent M. Harvey Senior Vice
President and Chief Financial Officer (duly authorized officer and principal financial officer) |  | 



| |  |                                                                                                                              |  | 
| |  | ---------------------------------------------------------------------------------------------------------------------------- |  | 
| |  | PACIFIC GAS AND ELECTRIC COMPANY                                                                                             |  | 
| |  |                                                                                                                             
| |  | SARA A. CHERRY                                                                                                               |  | 
| |  | Sara A. Cherry Vice President,
Finance and Chief Financial Officer (duly authorized officer and principal financial officer) |  | 

Dated: May 4, 2011



66



---

##### Table of Contents

EXHIBIT INDEX



|           |  |                                                                                                                                                                            
|---------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1        |  | Bylaws of PG&E Corporation amended as of May 1, 2011                                                                                                                       
|           | 
|3.2        |  | Bylaws of Pacific Gas and Electric Company amended as of May 1, 2011                                                                                                       
|           | 
|*10.1      |  | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan                                                           
|           | 
|*10.2      |  | Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan                                                               
|           | 
|12.1       |  | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company                                                                                    
|           | 
|12.2       |  | Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company                                             
|           | 
|12.3       |  | Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation                                                                                                    
|           | 
|31.1       |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002                
|           | 
|31.2       |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of
2002
|           | 
|**32.1     |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002                
|           | 
|**32.2     |  | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of
2002
|           | 
|***101.INS |  | XBRL Instance Document                                                                                                                                                     
|           | 
|***101.SCH |  | XBRL Taxonomy Extension Schema Document                                                                                                                                    
|           | 
|***101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document                                                                                                                      
|           | 
|***101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document                                                                                                                       
|           | 
|***101.LAB |  | XBRL Taxonomy Extension Labels Linkbase Document                                                                                                                           
|           | 
|***101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document                                                                                                                     



|* | Management contract or compensatory agreement.
|- | ----------------------------------------------



|** | Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
|-- | -------------------------------------------------------------------------------------------------------------------



|*** | Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of
Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its
subsidiary, Pacific Gas and Electric Company.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



67