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UNITED STATES
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SECURITIES AND EXCHANGE COMMISSION
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Washington, D.C. 20549
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FORM 8-K
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CURRENT REPORT
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Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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Date of Report:
October 15, 2010
(Date of earliest event reported)
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PG&E CORPORATION
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(Exact Name of Registrant as specified in Charter)
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California
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1-12609
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94-3234914
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(State or other jurisdiction of incorporation)
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(Commission File Number)
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(IRS Employer
Identification No.)
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One Market, Spear Tower, Suite 2400, San Francisco, CA
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94105
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(Address of principal executive offices)
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(Zip code)
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415-267-7000
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(Registrant’s Telephone Number, Including Area Code)
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N/A
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(Former Name or Former Address, if Changed Since Last Report)
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PACIFIC GAS AND ELECTRIC COMPANY
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(Exact Name of Registrant as specified in Charter)
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California
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1-2348
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94-0742640
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(State or other jurisdiction of incorporation)
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(Commission File Number)
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(IRS Employer
Identification No.)
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77 Beale Street, P. O. Box 770000, San Francisco, California
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94177
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(Address of principal executive offices)
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(Zip code)
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(415) 973-7000
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(Registrant’s Telephone Number, Including Area Code)
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N/A
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(Former Name or Former Address, if Changed Since Last Report)
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
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[ ]
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Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
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[ ]
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Soliciting Material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
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[ ]
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Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
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Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
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Item 8.01 - Other Events
On October 15, 2010, Pacific Gas and Electric Company (“Utility”), together with the California Public Utilities Commission’s (“CPUC”) Division of Ratepayer Advocates, The Utility Reform Network (“TURN”), Aglet Consumer Alliance and nearly all other intervening parties, filed a motion with the CPUC seeking approval of a settlement agreement to resolve almost all of the issues raised by the parties in the Utility’s 2011 General Rate Case (“GRC”). The proposed settlement agreement will be subject to public comment in the GRC proceeding and then considered by the full CPUC. In the GRC, the Utility requested an overall increase in electric distribution, gas distribution and utility-owned generation revenue requirements of $1,064 billion over currently authorized amounts effective January 1, 2011.
Revenue Requirements: The settlement agreement proposes that the Utility’s total 2011 revenue requirements be increased by $395 million, including $103 million related to depreciation rate changes. In addition, the settlement agreement proposes to (1) establish a new balancing account for meter reading costs outside of the GRC that offsets $113 million requested in the GRC application and (2) remove $30 million of costs from the GRC for consideration in other ratemaking proceedings. Furthermore, approximately $44 million of the revenue requirement the Utility requested in the GRC application remains subject to litigation in the GRC.
The following table shows the differences, based on cost category, between the amount of revenue requirements included in the GRC application and the amount proposed in the settlement agreement:
Table 1: Summary of Revenue Requirements by Cost Category ($’s in Millions)
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Cost category
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Amounts included in the GRC application
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Amounts proposed in the settlement agreement
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Difference
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Increase/Decrease over amounts currently authorized for 2011 based on amounts proposed in settlement agreement
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Increase/Decrease over amounts currently authorized for 2011 based on amounts included in GRC application
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Operations and maintenance (“O&M”)
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1,437 |
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1,308 |
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(129 |
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80 |
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209 |
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Customer services
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498 |
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329 |
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(169 |
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(143 |
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26 |
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Administrative and general (“A&G”)
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857 |
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768 |
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(89 |
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95 |
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184 |
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Less: Revenue credits
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(151 |
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(149 |
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2 |
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(18 |
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(19 |
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Franchise fees and uncollectible customer accounts (“FF&U”), taxes (other than income taxes), and other adjustments
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188 |
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120 |
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(68 |
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(37 |
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31 |
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Depreciation, return, and income taxes
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3,816 |
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3,601 |
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(215 |
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418 |
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634 |
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Total revenue requirements
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6,646 |
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5,977 |
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(669 |
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395 |
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1,064 |
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The following paragraphs describe the revenue requirement reductions proposed in the settlement agreement compared to the amounts included in the GRC application:
The $129 million reduction in revenue requirements for O&M costs reflects a lower forecast of costs for among other things, customer assistance services related to new customer connections, vegetation management, and development of utility-owned renewable generation.
The $169 million reduction in revenue requirements for customer services costs reflects the reduction of costs related to customer retention and economic development efforts, information technology, dynamic pricing, and meter reading. While the Utility’s GRC application requested recovery of $113 million for meter reading costs in 2011, the settlement agreement proposes that these costs will instead be recovered via a new balancing account. The balancing account would track and recover incurred meter reading costs, subject to a cap of $76 million, and the Utility also would retain the cost savings attributable to decreased meter reading costs due to the installation of SmartMeter™ devices. The total of the balancing account recovery plus retained cost savings is estimated to approximate the $113 million originally requested.
The $89 million reduction in A&G reflects lower funding for various PG&E Corporation and Utility corporate service functions and lower funding for employee incentive compensation. The Utility also agreed to seek recovery of $5 million of costs incurred in connection with the sale of property in another proceeding rather than the GRC.
The $68 million reduction in revenue requirements relating to FF&U, taxes (other than income) and other adjustments, includes $44 million related to return and income taxes on the Utility’s unrecovered investment in conventional electric meters that have been replaced by SmartMeterTM devices. The parties have agreed that this part of the Utility’s request will be litigated as part of the GRC proceeding. If the Utility is successful, the $44 million will be added back to the Utility’s 2011 electric distribution revenue requirement. The settlement agreement also would adopt a higher uncollectible revenue factor that would be used in another CPUC proceeding to determine the amount of revenue the Utility can collect to offset uncollectible customer accounts. This is expected to result in additional revenues of approximately $4 million.
The $215 million reduction in revenue requirements for depreciation, return and income taxes consists of a $105 million decrease driven by lower depreciation rates and a $110 million decrease related to lower capital expenditures and other rate base adjustments. About $49 million of the $110 million reduction is related to the treatment of nuclear fuel and fuel oil inventory balances. Under the settlement agreement, the Utility agreed to continue recovering carrying costs on these balances at short-term interest rates (estimated to be $1 million per year based on current rates) through the energy resource recovery balancing account (“ERRA”) in accordance with the current regulatory treatment of these costs, rather than as part of the authorized GRC rate base. Another $20 million of the reduction relates to costs to implement the California Independent System Operator’s Market Redesign and Technology Update (“MRTU”). Consistent with the settlement agreement, the Utility plans to seek recovery of MRTU-related costs through the ERRA or other proceedings.
The following table shows the differences between the amount of revenue requirements included in the GRC application and the amount proposed in the settlement agreement for each business function:
Table 2: Summary of Revenue Requirements by Function ($’s in Millions)
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Function
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Amounts included in the GRC application
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Amounts proposed in the settlement agreement
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Difference between amounts included in the GRC application and proposed in the settlement agreement
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Increase/Decrease over amounts currently authorized for 2011 based on amounts proposed in settlement agreement
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Increase/Decrease over amounts currently authorized for 2011 based on amounts included in the GRC application
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Electric distribution
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3,534 |
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3,190 |
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(344 |
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183 |
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527 |
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Natural gas distribution
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1,293 |
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1,131 |
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(161 |
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47 |
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208 |
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Electric generation operations
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1,820 |
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1,656 |
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(164 |
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166 |
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329 |
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Total:
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6,646 |
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5,977 |
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(669 |
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395 |
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1,064 |
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Attrition Year Revenues: The settlement agreement provides for an attrition increase of $180 million to the authorized 2011 revenues in 2012 and an additional increase of $185 million in 2013. On a comparable basis, the Utility had requested an attrition mechanism estimated to provide increases of approximately $262 million in 2012 and approximately $334 million in 2013.
Balancing Accounts: The settlement agreement proposes to establish a new “one-way” balancing account for the Utility to recover up to approximately $20 million per year for costs associated with the Utility’s natural gas distribution integrity management program. If these costs are not spent during the GRC period, the unspent funds must be returned to customers. With the exception of this proposed new one-way balancing account and the proposed meter reading balancing account discussed above, the settlement agreement proposes to retain the existing balancing account structure without any substantial changes.
Capital Additions and Rate Base: The settlement agreement is consistent with capital expenditures for 2011-2013 averaging $2.2 billion to $2.3 billion per year for the portions of the Utility’s business addressed in the GRC. Proposed capital expenditures are lower than the amount included in the Utility’s GRC application, which averaged $2.7 billion per year, based on a lower forecast for new customer connections and lower capital expenditures for hydroelectric generation facilities, information technology systems, and fleet replacement. The ultimate amounts of capital expenditures will depend on a number of factors, including the level of O&M, A&G, and other costs.
The settlement agreement proposes a 2011 annual average rate base of $16.6 billion for the portions of the Utility’s business reviewed in the GRC compared with the Utility’s request of $17.2 billion. The $0.6 billion difference is based on the capital expenditure reductions described above, the removal of MRTU-related capital expenditures, the continued funding of nuclear fuel and fuel oil inventory through the ERRA proceeding rather than through rate base, and the adjustment of deferred taxes to reflect the Utility’s updated estimate of the impact of 2009 bonus depreciation.
In order to allow settlement discussions to proceed, the CPUC suspended the procedural schedule for the GRC, which had previously provided for a final decision in December 2010. It is possible that the CPUC will not issue a decision until after the end of the year. On August 6, 2010, the Utility filed a motion requesting that, regardless of the timing of a CPUC decision, any revenue requirement change be effective on January 1, 2011. That motion remains pending before the CPUC.
PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the settlement agreement.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned hereunto duly authorized.
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PG&E CORPORATION
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Dated: October 15, 2010
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By:
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LINDA Y.H. CHENG
Vice President, Corporate Governance and
Corporate Secretary
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PACIFIC GAS AND ELECTRIC COMPANY
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Dated: October 15, 2010
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By:
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LINDA Y.H. CHENG
Vice President, Corporate Governance and
Corporate Secretary
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