10-Q 1 q1form10q.htm FORM 10-Q q1form10q.htm
 
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, 2010
 
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 30, 2010:
 
   
PG&E Corporation
372,345,954
Pacific Gas and Electric Company
264,374,809
   
 
 
 

 
PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010
TABLE OF CONTENTS

PART I.
FINANCIAL INFORMATION
PAGE
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
PG&E Corporation
 
   
3
   
4
   
6
 
Pacific Gas and Electric Company
 
   
8
   
9
   
11
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
Organization and Basis of Presentation
13
 
New and Significant Accounting Policies
13
 
Regulatory Assets, Liabilities, and Balancing Accounts
15
 
Debt
18
 
Equity
19
 
Earnings Per Share
20
 
Derivatives and Hedging Activities
22
 
Fair Value Measurements
26
 
Related Party Agreements and Transactions
32
 
Resolution of Remaining Chapter 11 Disputed Claims
32
 
Commitments and Contingencies
33
 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
 
 
39
 
41
 
42
 
47
 
51
 
51
 
52
 
52
 
52
 
53
 
55
 
56
 
58
 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
58
CONTROLS AND PROCEDURES
58
 
PART II.
OTHER INFORMATION
 
 
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
59
OTHER INFORMATION
59
EXHIBITS
60


 
2

 

PART I.  FINANCIAL INFORMATION

PG&E CORPORATION
 
 
   
(Unaudited)
 
   
Three Months Ended
 
   
March 31,
 
(in millions, except per share amounts)
 
2010
   
2009
 
Operating Revenues
           
Electric
  $ 2,510     $ 2,426  
Natural gas
    965       1,005  
Total operating revenues
    3,475       3,431  
Operating Expenses
               
Cost of electricity
    920       883  
Cost of natural gas
    495       557  
Operating and maintenance
    991       1,059  
Depreciation, amortization, and decommissioning
    451       419  
Total operating expenses
    2,857       2,918  
Operating Income
    618       513  
Interest income
    2       9  
Interest expense
    (168 )     (181 )
Other (expense) income, net
    (6 )     18  
Income Before Income Taxes
    446       359  
Income tax provision
    185       115  
Net Income
    261       244  
Preferred dividend requirement of subsidiary
    3       3  
Income Available for Common Shareholders
  $ 258     $ 241  
Weighted Average Common Shares Outstanding, Basic
    371       364  
Weighted Average Common Shares Outstanding, Diluted
    389       366  
Net Earnings Per Common Share, Basic
  $ 0.69     $ 0.65  
Net Earnings Per Common Share, Diluted
  $ 0.67     $ 0.65  
Dividends Declared Per Common Share
  $ 0.46     $ 0.42  
   
See accompanying Notes to the Condensed Consolidated Financial Statements.
 

 
3

 
PG&E CORPORATION

   
(Unaudited)
 
   
Balance At
 
   
March 31,
   
December 31,
 
(in millions)
 
2010
   
2009
 
ASSETS
           
Current Assets
           
Cash and cash equivalents
  $ 258     $ 527  
Restricted cash
    629       633  
Accounts receivable:
               
Customers (net of allowance for doubtful accounts of $69 million in 2010 and $68 million in 2009)
    1,528       1,609  
Accrued unbilled revenue
    638       671  
Regulatory balancing accounts
    1,468       1,109  
Inventories:
               
Gas stored underground and fuel oil
    59       114  
Materials and supplies
    196       200  
Income taxes receivable
    112       127  
Prepaid expenses and other
    733       667  
Total current assets
    5,621       5,657  
Property, Plant, and Equipment
               
Electric
    30,918       30,481  
Gas
    10,823       10,697  
Construction work in progress
    1,993       1,888  
Other
    14       14  
Total property, plant, and equipment
    43,748       43,080  
Accumulated depreciation
    (14,371 )     (14,188 )
Net property, plant, and equipment
    29,377       28,892  
Other Noncurrent Assets
               
Regulatory assets
    5,602       5,522  
Nuclear decommissioning funds
    1,929       1,899  
Income taxes receivable
    596       596  
Other
    415       379  
Total other noncurrent assets
    8,542       8,396  
TOTAL ASSETS
  $ 43,540     $ 42,945  

See accompanying Notes to the Condensed Consolidated Financial Statements.

 
4

 
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

   
(Unaudited)
 
   
Balance At
 
   
March 31,
   
December 31,
 
(in millions, except share amounts)
 
2010
   
2009
 
LIABILITIES AND EQUITY
           
Current Liabilities
           
Short-term borrowings
  $ 1,251     $ 833  
Long-term debt, classified as current
    842       342  
Energy recovery bonds, classified as current
    390       386  
Accounts payable:
               
Trade creditors
    882       984  
Disputed claims and customer refunds
    772       773  
Regulatory balancing accounts
    312       281  
Other
    481       349  
Interest payable
    795       818  
Income taxes payable
    268       214  
Deferred income taxes
    506       332  
Other
    1,281       1,501  
Total current liabilities
    7,780       6,813  
Noncurrent Liabilities
               
Long-term debt
    9,882       10,381  
Energy recovery bonds
    730       827  
Regulatory liabilities
    4,190       4,125  
Pension and other postretirement benefits
    1,968       1,773  
Asset retirement obligations
    1,603       1,593  
Deferred income taxes
    4,656       4,732  
Other
    2,110       2,116  
Total noncurrent liabilities
    25,139       25,547  
Commitments and Contingencies
               
Equity
               
Shareholders’ Equity
               
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued
    -       -  
Common stock, no par value, authorized 800,000,000 shares, issued 371,222,918 common and 480,848 restricted shares in 2010 and issued 370,601,905 common and 670,552 restricted shares in 2009
    6,307       6,280  
Reinvested earnings
    4,302       4,213  
Accumulated other comprehensive loss
    (240 )     (160 )
Total shareholders’ equity
    10,369       10,333  
Noncontrolling Interest – Preferred Stock of Subsidiary
    252       252  
Total equity
    10,621       10,585  
TOTAL LIABILITIES AND EQUITY
  $ 43,540     $ 42,945  
   
See accompanying Notes to the Condensed Consolidated Financial Statements.
 

 
5

 
PG&E CORPORATION
 
 
   
(Unaudited)
 
   
Three Months Ended
 
   
March 31,
 
(in millions)
 
2010
   
2009
 
Cash Flows from Operating Activities
           
Net income
  $ 261     $ 244  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, amortization, and decommissioning
    506       463  
Allowance for equity funds used during construction
    (28 )     (25 )
Deferred income taxes and tax credits, net
    137       235  
Other changes in noncurrent assets and liabilities
    (113 )     (51 )
Effect of changes in operating assets and liabilities:
               
Accounts receivable
    114       301  
Inventories
    59       166  
Accounts payable
    87       (116 )
Income taxes receivable/payable
    69       209  
Regulatory balancing accounts, net
    (377 )     (180 )
Other current assets
    35       32  
Other current liabilities
    (381 )     (390 )
Other
    26       2  
Net cash provided by operating activities
    395       890  
Cash Flows from Investing Activities
               
Capital expenditures
    (855 )     (1,079 )
Decrease in restricted cash
    4       11  
Proceeds from sales of nuclear decommissioning trust investments
    337       387  
Purchases of nuclear decommissioning trust investments
    (343 )     (412 )
Other
    9       7  
Net cash used in investing activities
    (848 )     (1,086 )
Cash Flows from Financing Activities
               
Borrowings under revolving credit facility
    -       300  
Repayments under revolving credit facility
    -       (300 )
Net issuance of commercial paper, net of discount of $2 million in 2009
    418       96  
Proceeds from issuance of long-term debt, net of discount and issuance costs
of $16 million in 2009
    -       884  
Long-term debt matured or repurchased
    -       (600 )
Energy recovery bonds matured
    (93 )     (89 )
Common stock issued
    10       96  
Common stock dividends paid
    (157 )     (138 )
Other
    6       (1 )
Net cash provided by financing activities
    184       248  
Net change in cash and cash equivalents
    (269 )     52  
Cash and cash equivalents at January 1
    527       219  
Cash and cash equivalents at March 31
  $ 258     $ 271  
 
 
6

 
Supplemental disclosures of cash flow information
           
Cash received (paid) for:
           
Interest, net of amounts capitalized
  $ (193 )   $ (190 )
Income taxes, net
    -       294  
Supplemental disclosures of noncash investing and financing activities
               
Common stock dividends declared but not yet paid
  $ 169     $ 154  
Capital expenditures financed through accounts payable
    215       235  
Noncash common stock issuances
    -       33  
                 
See accompanying Notes to the Condensed Consolidated Financial Statements.
 

 
7

 

PACIFIC GAS AND ELECTRIC COMPANY
 
 
   
(Unaudited)
 
   
Three Months Ended
 
   
March 31,
 
(in millions)
 
2010
   
2009
 
Operating Revenues
           
Electric
  $ 2,510     $ 2,426  
Natural gas
    965       1,005  
Total operating revenues
    3,475       3,431  
Operating Expenses
               
Cost of electricity
    920       883  
Cost of natural gas
    495       557  
Operating and maintenance
    990       1,059  
Depreciation, amortization, and decommissioning
    451       419  
Total operating expenses
    2,856       2,918  
Operating Income
    619       513  
Interest income
    2       9  
Interest expense
    (156 )     (173 )
Other (expense) income, net
    (6 )     21  
Income Before Income Taxes
    459       370  
Income tax provision
    195       131  
Net Income
    264       239  
Preferred dividend requirement
    3       3  
Income Available for Common Stock
  $ 261     $ 236  
   
See accompanying Notes to the Condensed Consolidated Financial Statements.
 

 
8

 
PACIFIC GAS AND ELECTRIC COMPANY

   
(Unaudited)
 
   
Balance At
 
   
March 31,
   
December 31,
 
(in millions)
 
2010
   
2009
 
ASSETS
           
Current Assets
           
Cash and cash equivalents
  $ 60     $ 334  
Restricted cash
    629       633  
Accounts receivable:
               
Customers (net of allowance for doubtful accounts of $69 million in 2010 and $68 million in 2009)
    1,528       1,609  
Accrued unbilled revenue
    638       671  
Related parties
    1       1  
Regulatory balancing accounts
    1,468       1,109  
Inventories:
               
Gas stored underground and fuel oil
    59       114  
Materials and supplies
    196       200  
Income taxes receivable
    121       138  
Prepaid expenses and other
    732       662  
Total current assets
    5,432       5,471  
Property, Plant, and Equipment
               
Electric
    30,918       30,481  
Gas
    10,823       10,697  
Construction work in progress
    1,993       1,888  
Total property, plant, and equipment
    43,734       43,066  
Accumulated depreciation
    (14,358 )     (14,175 )
Net property, plant, and equipment
    29,376       28,891  
Other Noncurrent Assets
               
Regulatory assets
    5,602       5,522  
Nuclear decommissioning funds
    1,929       1,899  
Related parties receivable
    24       25  
Income taxes receivable
    610       610  
Other
    326       291  
Total other noncurrent assets
    8,491       8,347  
TOTAL ASSETS
  $ 43,299     $ 42,709  

See accompanying Notes to the Condensed Consolidated Financial Statements.

 
9

 
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

   
(Unaudited)
 
   
Balance At
 
   
March 31,
   
December 31,
 
(in millions, except share amounts)
 
2010
   
2009
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
           
Current Liabilities
           
Short-term borrowings
  $ 1,251     $ 833  
Long-term debt, classified as current
    595       95  
Energy recovery bonds, classified as current
    390       386  
Accounts payable:
               
Trade creditors
    882       984  
Disputed claims and customer refunds
    772       773  
Related parties
    24       16  
Regulatory balancing accounts
    312       281  
Other
    478       347  
Interest payable
    779       813  
Income tax payable
    283       223  
Deferred income taxes
    511       334  
Other
    1,079       1,307  
Total current liabilities
    7,356       6,392  
Noncurrent Liabilities
               
Long-term debt
    9,534       10,033  
Energy recovery bonds
    730       827  
Regulatory liabilities
    4,190       4,125  
Pension and other postretirement benefits
    1,912       1,717  
Asset retirement obligations
    1,603       1,593  
Deferred income taxes
    4,686       4,764  
Other
    2,080       2,073  
Total noncurrent liabilities
    24,735       25,132  
Commitments and Contingencies
               
Shareholders’ Equity
               
Preferred stock without mandatory redemption provisions:
               
Nonredeemable, 5.00% to 6.00%, outstanding 5,784,825 shares
    145       145  
Redeemable, 4.36% to 5.00%, outstanding 4,534,958 shares
    113       113  
Common stock, $5 par value, authorized 800,000,000 shares, issued 264,374,809 shares in 2010 and 2009
    1,322       1,322  
Additional paid-in capital
    3,076       3,055  
Reinvested earnings
    6,786       6,704  
Accumulated other comprehensive loss
    (234 )     (154 )
Total shareholders’ equity
    11,208       11,185  
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
  $ 43,299     $ 42,709  

See accompanying Notes to the Condensed Consolidated Financial Statements.

 
10

 

PACIFIC GAS AND ELECTRIC COMPANY
 
 
   
(Unaudited)
 
   
Three Months Ended
 
   
March 31,
 
(in millions)
 
2010
   
2009
 
Cash Flows from Operating Activities
           
Net income
  $ 264     $ 239  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, amortization, and decommissioning
    491       456  
Allowance for equity funds used during construction
    (28 )     (25 )
Deferred income taxes and tax credits, net
    138       234  
Other changes in noncurrent assets and liabilities
    (98 )     (48 )
Effect of changes in operating assets and liabilities:
               
Accounts receivable
    114       298  
Inventories
    59       166  
Accounts payable
    94       (107 )
Income taxes receivable/payable
    77       95  
Regulatory balancing accounts, net
    (377 )     (180 )
Other current assets
    35       34  
Other current liabilities
    (387 )     (386 )
Other
    26       1  
Net cash provided by operating activities
    408       777  
Cash Flows from Investing Activities
               
Capital expenditures
    (855 )     (1,079 )
Decrease in restricted cash
    4       11  
Proceeds from sales of nuclear decommissioning trust investments
    337       387  
Purchases of nuclear decommissioning trust investments
    (343 )     (412 )
Other
    5       2  
Net cash used in investing activities
    (852 )     (1,091 )
Cash Flows from Financing Activities
               
Borrowings under revolving credit facility
    -       300  
Repayments under revolving credit facility
    -       (300 )
Net issuance of commercial paper, net of discount of $2 million in 2009
    418       96  
Proceeds from issuance of long-term debt, net of discount and issuance costs of $12 million in 2009
    -       538  
Long-term debt matured or repurchased
    -       (600 )
Energy recovery bonds matured
    (93 )     (89 )
Preferred stock dividends paid
    (4 )     (3 )
Common stock dividends paid
    (179 )     (156 )
Equity contribution
    20       528  
Other
    8       2  
Net cash provided by financing activities
    170       316  
Net change in cash and cash equivalents
    (274 )     2  
Cash and cash equivalents at January 1
    334       52  
Cash and cash equivalents at March 31
  $ 60     $ 54  

 
11

 
Supplemental disclosures of cash flow information
           
Cash received (paid) for:
           
Interest, net of amounts capitalized
  $ (193 )   $ (190 )
Income taxes, net
    -       163  
Supplemental disclosures of noncash investing and financing activities
               
Capital expenditures financed through accounts payable
  $ 215     $ 235  
                 
See accompanying Notes to the Condensed Consolidated Financial Statements.
 

 
12

 

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)


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 primarily 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.  Therefore, 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, as well as, the accounts of variable interest entities (“VIEs”) for which the Utility is the primary beneficiary.  All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with U.S. generally accepted accounting principles (“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 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, 2009 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 2009 Annual Report on Form 10-K filed on February 19, 2010.  PG&E Corporation’s and the Utility’s combined 2009 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 “2009 Annual Report.”

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 2009 Annual Report.  Any significant changes to those policies or new significant policies are described in Note 2 below.

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, environmental remediation liability, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters.  Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable.  A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

This quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s audited Consolidated Financial Statements and related notes included in the 2009 Annual Report.


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.

 
13

 
The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three months ended March 31, 2010 and 2009 were as follows:

   
Pension Benefits
   
Other Benefits
 
   
Three Months Ended
March 31,
   
Three Months Ended
March 31,
 
(in millions)
 
2010
   
2009
   
2010
   
2009
 
Service cost for benefits earned
  $ 69     $ 66     $ 10     $ 8  
Interest cost
    161       155       23       21  
Expected return on plan assets
    (156 )     (145 )     (18 )     (17 )
Amortization of transition obligation
    -       -       6       6  
Amortization of prior service cost
    13       11       6       4  
Amortization of unrecognized (gain) loss
    11       25       1       1  
     Net periodic benefit cost
    98       112       28       23  
     Less: transfer to regulatory account (1)
    (58 )     (71 )     -       -  
     Total
  $ 40     $ 41     $ 28     $ 23  
                                 
(1) The Utility recorded $58 million and $71 million for the three month periods ended March 31, 2010 and 2009, 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, 2010 and 2009.

On February 16, 2010, the Utility amended its defined benefit medical plans for retirees to provide for additional contributions towards retiree premiums.  The plan amendment was accounted for as a plan modification that required re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs.  The inputs and assumptions used in re-measurement did not change significantly from December 31, 2009 and did not have a material impact on the funded status of the plans.  The re-measurement of the accumulated benefit obligation and plan assets resulted in an increase to pension and other postretirement benefits and a decrease to other comprehensive loss of $148 million as of February 16, 2010.  The impact to net periodic benefit cost for the three months ended March 31, 2010 was not significant.
 
Adoption of New Accounting Pronouncements

Consolidations (Topic 810) - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

On January 1, 2010, PG&E Corporation and the Utility adopted Accounting Standards Update (“ASU”) No. 2009-17, “Consolidations (Topic 810) - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU No. 2009-17”).  ASU No. 2009-17 amends the Consolidation Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) regarding when and how to determine, or re-determine, whether an entity is a VIE, which could require consolidation.  In addition, ASU No. 2009-17 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach.  Furthermore, ASU No. 2009-17 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE.

PG&E Corporation and the Utility are required to consolidate any entities which the companies control.  In most cases, control can be determined based on majority ownership or voting interests.  However, for certain entities, control is difficult to discern based on voting equity interests alone.  These entities are referred to as VIEs.  A VIE is an entity which does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest.  An enterprise has a controlling financial interest if it has (1) the obligation to absorb expected losses or receive expected gains that could potentially be significant to the VIE and (2) the power to direct the activities that are most significant to the VIE’s economic performance.  The enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is the enterprise that will consolidate the VIE.

 
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The Utility’s exposure to VIEs relates primarily to entities with which it has a power purchase agreement.  When determining whether a controlling financial interest exists, the Utility must first assess whether it absorbs any of a VIE’s expected losses or receives portions of the expected residual returns as a result of the arrangement.  This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders.  Power plants typically are exposed to credit risk, production risk, commodity price risk, and any applicable tax incentive risks, among others.  The Utility analyzes the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin to determine whether the Utility absorbs variability.  Factors that may be considered when assessing the impact to the VIE’s gross margin include the pricing structure of the agreement and the cost of inputs and production, depending on the technology of the power plant.

For each variable interest, the Utility evaluates the activities of the power plant that most directly impact the VIE’s economic performance.  The Utility’s assessment of the activities that are economically significant to the VIE’s performance often include decision making rights associated with designing the VIE, operating and maintenance activities, and re-marketing activities of the power plant after the end of its power purchase agreement with the Utility.

As of March 31, 2010, the Utility held a variable interest in VIEs as a result of power purchase agreements with entities that are single power plant owners of power plants.  Each of these entities were designed to generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, hydroelectric, and other technologies.  Under each of the power purchase agreements that represent a variable interest, the Utility is obligated to purchase electricity or capacity, or both, from the VIEs.  The Utility does not provide any other financial or other support to these VIEs and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity.  (See Note 11 below for further discussion.)  As of March 31, 2010, the Utility was not the primary beneficiary of any power plant VIEs.

The Utility continues to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at March 31, 2010, as the Utility held a controlling financial interest and is the primary beneficiary.  The Utility was the primary beneficiary as it was involved in the design of PERF and has exposure to losses and returns through its equity investment.  The Utility consolidated PERF’s assets of $1.2 billion and liabilities of $1.1 billion (see Note 4 below for further discussion).  The assets of PERF are only available to settle the liabilities of PERF.
 
                The adoption of ASU 2009-17 did not have an impact on the Condensed Consolidated Financial Statements.
 
Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements

On January 1, 2010, PG&E Corporation and the Utility adopted ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements” (“ASU No. 2010-06”).  ASU No. 2010-06 requires disclosures regarding (1) significant transfers into and out of Levels 1 and 2 of the fair value hierarchy and (2) fair value measurement inputs and valuation techniques.  Furthermore, ASU No. 2010-06 requires presentation of disaggregated activity within the reconciliation for fair value measurements using significant unobservable inputs (Level 3), beginning in the first quarter of 2011.  The adoption of ASU No. 2010-06 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements

On March 31, 2010, PG&E Corporation and the Utility adopted ASU No. 2010-09, “Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements” (“ASU No. 2010-09”).  ASU No. 2010-09 does not significantly change the prior accounting for subsequent events but eliminates the requirement to disclose the date through which an SEC filer has evaluated subsequent events and the basis for that date.  The adoption of ASU No. 2010-09 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.


Regulatory Assets

Current Regulatory Assets

At March 31, 2010 and December 31, 2009, the Utility had current regulatory assets of $568 million and $427 million, respectively, consisting primarily of the current portion of price risk management regulatory assets.  Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less.  (See Note 7 below for further discussion.)  Current regulatory assets are included in Prepaid expenses and other in the Condensed Consolidated Balance Sheets.

 
15

 
Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:
 
   
Balance at
 
(in millions)
 
March 31, 2010
   
December 31, 2009
 
Pension benefits
  $ 1,421     $ 1,386  
Deferred income taxes
    1,067       1,027  
Energy recovery bonds
    1,039       1,124  
Utility retained generation
    719       737  
Price risk management
    484       346  
Environmental compliance costs
    397       408  
Unamortized loss, net of gain, on reacquired debt
    197       203  
Other
    278       291  
Total long-term regulatory assets
  $ 5,602     $ 5,522  

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 13 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.)

The regulatory assets for deferred income taxes represent deferred income tax benefits previously passed through to customers offset by deferred income tax liabilities.  The CPUC requires the Utility to pass through certain tax benefits to customers, ignoring the effect of deferred taxes on rates.  Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income taxes related to regulatory assets over periods ranging from 1 to 45 years.

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

In connection with the 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 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 15 years.

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 environmental compliance costs represent the portion of estimated environmental remediation expense that the Utility expects to recover in future rates as actual remediation costs are incurred.  The Utility expects to recover these costs over the next 30 years.  (See Note 11 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 remaining original amortization period of the reacquired debt over the next 17 years, and these costs will be fully recovered by 2026.

At March 31, 2010 and December 31, 2009, “Other” consisted of regulatory assets relating to ARO expenses recorded in accordance with GAAP that are probable of future recovery through the ratemaking process, and removal costs associated with the replacement of the steam generators in the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), as approved by the CPUC for future recovery.  “Other” also consisted of costs that the Utility incurred in terminating a 30-year power purchase agreement, which are being amortized and collected in rates through September 2014, as well as costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004.

In general, the Utility does not earn a return on regulatory assets in which the related costs do not accrue interest.  Accordingly, the Utility earns a return only on the Utility’s retained generation regulatory assets; unamortized loss, net of gain, on reacquired debt; and regulatory assets associated with the plan of reorganization.
 
 
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Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2010 and December 31, 2009, the Utility had current regulatory liabilities of $138 million and $163 million, respectively, primarily consisting of the current portion of electric transmission wheeling revenue refunds and amounts that the Utility expects to refund to customers for over-collected electric transmission rates and the current portion of price risk management regulatory liabilities.  Price risk management regulatory liabilities represent the deferral of unrealized gains related to price risk management derivative instruments with terms of one year or less. 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, 2010
   
December 31, 2009
 
Cost of removal obligation
  $ 2,991     $ 2,933  
Public purpose programs
    566       508  
Recoveries in excess of ARO
    508       488  
Other
    125       196  
Total long-term regulatory liabilities
  $ 4,190     $ 4,125  

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.

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.  For example, these regulatory liabilities include revenues collected from customers to pay for costs that the Utility expects to incur in the future under the California Solar Initiative to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.

The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the ARO expenses recorded in accordance with GAAP.  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.

“Other” at March 31, 2010 and December 31, 2009 included the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year, 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 with Mirant Corporation, as well as insurance recoveries for hazardous substance remediation.

Regulatory Balancing Accounts

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.

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.
 
 
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Current Regulatory Balancing Accounts, net

   
Receivable (Payable)
 
   
Balance at
 
(in millions)
 
March 31, 2010
   
December 31, 2009
 
Utility generation
  $ 572     $ 355  
Distribution revenue adjustment mechanism
    287       152  
Public purpose programs
    128       83  
Energy procurement costs
    115       128  
Gas fixed cost
    (15 )     93  
Energy recovery bonds
    (163 )     (185 )
Other
    232       202  
Total regulatory balancing accounts, net
  $ 1,156     $ 828  

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 periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates.  During the warmer months of summer, there is generally an over-collection due to higher rates and electric usage that cause an increase in generation revenues.

The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program revenue requirements, the actual costs of such programs, 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.

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 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.  The under-collected or over-collected position of this account is dependent on seasonality and volatility in gas volumes.

The ERB balancing accounts record certain benefits and costs associated with ERBs that are provided to, or received from, customers.  In addition, these accounts ensure 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, 2010 and December 31, 2009, “Other” included the California Department of Water Resources (“DWR”) power charge collection balancing account, which ensures amounts collected from customers for DWR-delivered power are remitted to the DWR; balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeterTM advanced metering project; and the transition access charge balancing account, which is used to pass through transmission high voltage access charges and credits.


Utility

Senior Notes

On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037.
 
Pollution Control Bonds

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds series 2010E due on November 1, 2026 and loaned the proceeds to the Utility.  The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008.  The series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest.  Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode.

 
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Credit Facility and Short-Term Borrowings

At March 31, 2010, the Utility had $265 million of letters of credit outstanding under the Utility’s $1.94 billion revolving credit facility.

The revolving credit facility also provides liquidity support for commercial paper offerings.  At March 31, 2010, the Utility had $751 million of commercial paper outstanding at an average yield of 0.31%.

Energy Recovery Bonds

In 2005, PERF, a wholly owned consolidated subsidiary of the Utility, 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 $1.1 billion at March 31, 2010.

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.


PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2010 were as follows:

   
PG&E Corporation
   
Utility
 
(in millions)
 
Total
Equity
   
Total
Shareholders’ Equity
 
Balance at December 31, 2009
  $ 10,585     $ 11,185  
Net income
    261       264  
Common stock issued
    10       -  
Share-based compensation amortization
    15       -  
Common stock dividends declared and paid
    -       (179 )
Common stock dividends declared but not yet paid
    (169 )     -  
Preferred stock dividend requirement
    -       (3 )
Preferred stock dividend requirement of subsidiary
    (3 )     -  
Tax benefit from employee stock plans
    2       1  
Other comprehensive income
    (80 )     (80 )
Equity contribution
    -       20  
Balance at March 31, 2010
  $ 10,621     $ 11,208  

For the three months ended March 31, 2010, PG&E Corporation contributed equity of $20 million to the Utility in order to maintain the 52% common equity target 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 accumulated other comprehensive income, which includes certain changes in equity that are excluded from net income.  Specifically, cumulative adjustments for employee benefit plans, net of tax, are included in accumulated other comprehensive income.   

   
PG&E Corporation
   
Utility
 
   
Three Months Ended
March 31,
   
Three Months Ended
March 31,
 
(in millions)
 
2010
   
2009
   
2010
   
2009
 
Net income
  $ 261     $ 244     $ 264     $ 239  
Employee benefit plan adjustment, net of tax
    (80 )     7       (80 )     7  
Comprehensive Income
  $ 181     $ 251     $ 184     $ 246  
 
 
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Dividends

During the three months ended March 31, 2010, PG&E Corporation paid common stock dividends totaling $157 million.  On February 17, 2010, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, totaling $169 million, which was paid on April 15, 2010 to shareholders of record on March 31, 2010.

During the three months ended March 31, 2010, the Utility paid common stock dividends totaling $179 million to PG&E Corporation.

During the three months ended March 31, 2010, the Utility paid dividends totaling $4 million to holders of its outstanding series of preferred stock.  On February 17, 2010, the Board of Directors of the Utility declared a dividend totaling $3 million on its outstanding series of preferred stock, payable on May 15, 2010, to shareholders of record on April 30, 2010.


Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period.  In applying the two-class method, undistributed earnings are allocated to both common shares and participating securities.  PG&E Corporation’s 9.50% Convertible Subordinated Notes are entitled to receive pass-through dividends and meet the criteria of participating securities.  All of the participating securities participate in dividends on a 1:1 basis with shares of common stock.

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 Ended
 
   
March 31,
 
(in millions, except per share amounts)
 
2010
   
2009
 
Basic
           
Income Available for Common Shareholders
  $ 258     $ 241  
Less: distributed earnings to common shareholders
    169       154  
Undistributed earnings
  $ 89     $ 87  
Allocation of undistributed earnings to common shareholders
               
Distributed earnings to common shareholders
  $ 169     $ 154  
Undistributed earnings allocated to common shareholders
    85       83  
Total common shareholders earnings
  $ 254     $ 237  
Weighted average common shares outstanding, basic
    371       364  
Convertible Subordinated Notes
    16       17  
Weighted average common shares outstanding and participating securities
    387       381  
Net earnings per common share, basic
               
Distributed earnings, basic (1)
  $ 0.46     $ 0.42  
Undistributed earnings, basic
    0.23       0.23  
Total
  $ 0.69     $ 0.65  
   
(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.

 
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In calculating diluted EPS, PG&E Corporation applies the “if-converted” method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS.  In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.  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 for three months ended March 31, 2010:

   
Three Months Ended
 
(in millions, except per share amounts)
 
March 31, 2010
 
Diluted
     
Income Available for Common Shareholders
  $ 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
  $ 262  
         
Weighted average common shares outstanding, basic
    371  
Add incremental shares from assumed conversions:
       
Convertible subordinated notes
    16  
Employee share-based compensation
    2  
Weighted average common shares outstanding, diluted
    389  
Total earnings per common share, diluted
  $ 0.67  

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 for the three months ended March 31, 2009:

   
Three Months Ended
 
(in millions, except per share amounts)
 
March 31, 2009
 
Diluted
     
Income Available for Common Shareholders
  $ 241  
Less: distributed earnings to common shareholders
    154  
Undistributed earnings
  $ 87  
         
Allocation of undistributed earnings to common shareholders
       
Distributed earnings to common shareholders
  $ 154  
Undistributed earnings allocated to common shareholders
    83  
Total common shareholders earnings
  $ 237  
         
Weighted average common shares outstanding, basic
    364  
Convertible subordinated notes
    17  
Weighted average common shares outstanding and participating securities, basic
    381  
Weighted average common shares outstanding, basic
    364  
Employee share-based compensation
    2  
Weighted average common shares outstanding, diluted
    366  
Convertible subordinated notes
    17  
Weighted average common shares outstanding and participating securities, diluted
    383  
Net earnings per common share, diluted
       
Distributed earnings, diluted
  $ 0.42  
Undistributed earnings, diluted
    0.23  
Total earnings per common share, diluted
  $ 0.65  

Securities that were antidilutive and excluded from the calculation of diluted shares outstanding were insignificant for the periods presented above.

 
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Use of Derivative Instruments

The Utility faces market risk primarily related to electricity and natural gas commodity prices.  All of the Utility’s risk management activities involving derivatives occur to reduce the volatility of commodity costs on behalf of its customers.  The CPUC and the FERC allow 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.  As these costs are passed through to customers in rates, the Utility’s earnings are not exposed to the commodity price risk inherent in the purchase and sale of 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;

·  
option contracts that provide the Utility with the right to buy a commodity at a predetermined price; and

·  
futures contracts that are exchange-traded contracts that commit the Utility to purchase a commodity or make a cash settlement at a specified price and future date.

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

Commodity-Related Price Risk

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 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.

The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk for its customers.

Electricity Procurement

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities.  The amount of electricity the Utility needs to meet the demands of customers and that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR contracts allocated to the Utility’s 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;
   
    · 
fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract;
 
 
22

 
   
    · 
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; and
   
    · 
changes in market prices that make it more economical to purchase power in the market rather than use the Utility’s existing resources.

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 cash flow variability associated with fluctuating electricity prices, the Utility has entered into financial swap contracts to effectively fix the price of future purchases 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 CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Update on April 1, 2009.  The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new 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).  CRRs are considered derivative instruments.

Natural Gas Procurement (Electric 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 future cash flow variability associated with fluctuating natural gas prices, the Utility purchases financial instruments such as futures, swaps, and options.  These financial instruments are considered derivative instruments.

Natural Gas Procurement (Small Commercial and Residential Customers)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its small commercial and residential, or “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 markets to balance such seasonal supply and demand.

Other Risk

At March 31, 2010, PG&E Corporation had $247 million of Convertible Subordinated Notes outstanding that will mature on June 30, 2010.   The holders of the Convertible Subordinated Notes are entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion prices.  The dividend participation rights associated with the Convertible Subordinated Notes are embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements.  Changes in fair value of the dividend participation rights are recognized in PG&E Corporation’s Condensed Consolidated Statements of Income as non-operating expense or income (in Other (expense) income, net).

 
23

 
Volume of Derivative Activity

At March 31, 2010, the volume of PG&E Corporation’s and the Utility’s outstanding derivative contracts was as follows:

     
Contract Volume (1)
 
Underlying Product
Instruments
 
Less Than 1 Year
   
Greater Than 1 Year But Less Than 3 Years
   
Greater Than 3 Years But Less Than 5 Years
   
Greater Than 5 Years (2)
 
Natural Gas (3) (MMBtus (4))
Forwards, Futures, and Swaps
    354,147,125       211,026,845       17,875,000       -  
 
Options
    198,987,080       104,650,000       11,100,000       -  
                                   
Electricity (Megawatt-hours)
Forwards, Futures, and Swaps
    4,050,541       8,296,859       4,274,287       4,082,736  
 
Options
    389,000       7,450       156,588       503,904  
 
Congestion Revenue Rights
    75,220,639       66,937,314       66,870,770       111,554,263  
                                   
PG&E Corporation Equity
(Shares)
Dividend Participation Rights
    16,370,789       -       -       -  
                                   
(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 2015 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.  The net balances include outstanding cash collateral associated with derivative positions.

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

(in millions)
 
Gross Derivative Balance (1)
   
Netting (2)
   
Cash Collateral (2)
   
Total Derivative Balances
 
Commodity Risk (PG&E Corporation and Utility)
 
Current Assets – Prepaid expenses and other
  $ 27     $ (10 )   $ 46     $ 63  
Other Noncurrent Assets – Other
    53       (34 )     55       74  
Current Liabilities – Other
    (332 )     10       168       (154 )
Noncurrent Liabilities – Other
    (518 )     34       161       (323 )
Total commodity risk
  $ (770 )   $ -     $ 430     $ (340 )
                                 
Other Risk Instruments (3) (PG&E Corporation Only)
 
Current Liabilities – Other
  $ (7 )   $ -     $ -     $ (7 )
Total derivatives
  $ (777 )   $ -     $ 430     $ (347 )
                                 
(1) See Note 8 below for a discussion of the valuation techniques used to calculate the fair value of these instruments.
 
(2) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.
 
(3) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.
 
 
 
24

 
At December 31, 2009, 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 Utility)
 
Current Assets – Prepaid expenses and other
  $ 76     $ (12 )   $ 77     $ 141  
Other Noncurrent Assets – Other
    64       (44 )     13       33  
Current Liabilities – Other
    (231 )     12       54       (165 )
Noncurrent Liabilities – Other
    (390 )     44       44       (302 )
Total commodity risk
  $ (481 )   $ -     $ 188     $ (293 )
                                 
Other Risk Instruments (2) (PG&E Corporation Only)
 
Current Liabilities – Other
  $ (13 )   $ -     $ -     $ (13 )
Total derivatives
  $ (494 )   $ -     $ 188     $ (306 )
                                 
(1) Positions, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.
 
(2) This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.
 

Expenses related to the dividend participation rights are not recoverable in customers’ rates.  Therefore, changes in the fair value of these instruments are recorded in PG&E Corporation’s Condensed Consolidated Statements of Income.

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)
 
2010
   
2009
 
Unrealized gain/(loss) - Regulatory assets and liabilities (1)
  $ (289 )   $ (307 )
Realized gain/(loss) - Cost of electricity (2)
    (106 )     (202 )
Realized gain/(loss) - Cost of natural gas (2)
    (39 )     (23 )
Total commodity risk instruments
  $ (434 )   $ (532 )
   
Other Risk Instruments (3)
(PG&E Corporation Only)
 
Other expense (income), net
  $ 1     $ (2 )
Total other risk instruments
  $ 1     $ (2 )
   
(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.
(3) This category relates to dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes.
 
Cash inflows and outflows associated with the settlement of all derivative instruments are recognized in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

 
25

 
The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies.  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.

At March 31, 2010, the additional cash collateral the Utility would be required to post if its credit-risk-related contingent features were triggered was as follows:

(in millions)
     
Derivatives in a liability position with credit-risk-related contingencies that are not fully collateralized
  $ (551 )
Related derivatives in an asset position
    -  
Collateral posting in the normal course of business related to these derivatives
    81  
Net position of derivative contracts/additional collateral posting requirements (1)
  $ (470 )
         
(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.
 

 
PG&E Corporation and the Utility measure their cash equivalents, trust assets, dividend participation rights, 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—Include 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 also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  (See Note 12 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for further discussion of fair value measurements.)

 
26

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

Fair Value Measurements at March 31, 2010
 
(in millions)
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Assets:
                       
Money market investments
  $ 195     $ -     $ -     $ 195  
Nuclear decommissioning trusts
                               
     U.S. equity securities (1)
    813       30       -       843  
     Non-U.S. equity securities
    328       -       -       328  
     U.S. government and agency securities
    664       73       -       737  
     Municipal securities
    4       86       -       90  
     Other fixed income securities
    -       76       -       76  
Total nuclear decommissioning trusts (2)
    1,809       265       -       2,074  
Price risk management instruments
                               
     Electric (3)
    47       -       -       47  
Total price risk management instruments
    47       -       -       47  
Rabbi trusts
                               
     Equity securities
    22       -       -       22  
     Life insurance contracts
    -       62       -       62  
               Total rabbi trusts
    22       62       -       84  
Long-term disability trust
                               
     U.S. equity securities (1)
    3       28       -       31  
     Corporate debt securities (1)
    -       148       -       148  
Total long-term disability trust
    3       176       -       179  
Total assets
  $ 2,076     $ 503     $ -     $ 2,579  
Liabilities:
                               
Dividend participation rights
  $ -     $ -     $ 7     $ 7  
Price risk management instruments
 
                               
     Electric (4)
    -       50       295       345  
     Gas (5)
    -       1       41       42  
             Total price risk management instruments
 
    -       51       336       387  
Other liabilities
    -       -       1       1  
Total liabilities
  $ -     $ 51     $ 344     $ 395  
                                 
(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 deferred taxes on appreciation of investment value.
 
(3) Balances include the impact of netting adjustments of $214 million to Level 1. Includes natural gas for electric portfolio.
(4) Balances include the impact of netting adjustments of $129 million to Level 2, and $53 million to Level 3. Includes natural gas for electric portfolio.
(5) Balances include the impact of netting adjustments of $34 million to Level 3. Includes natural gas for core customers.
 

 
27

 
Fair Value Measurements at December 31, 2009
 
(in millions)
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Assets:
                       
Money market investments
  $ 189     $ -     $ 4     $ 193  
Nuclear decommissioning trusts
                               
       U.S. equity securities (1)
    762       6       -       768  
       Non-U.S. equity securities
    344       -       -       344  
       U.S. government and agency securities
    653       51       -