UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report: August 26, 2011
(Date of earliest event reported)
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Commission File Number
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Exact Name of Registrant
as specified in its charter
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State or Other Jurisdiction of Incorporation or Organization
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IRS Employer Identification Number
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1-12609
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PG&E CORPORATION
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California
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94-3234914
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1-2348
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PACIFIC GAS AND ELECTRIC COMPANY
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California
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94-0742640
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One Market, Spear Tower
Suite 2400
San Francisco, California 94105
(Address of principal executive offices) (Zip Code)
(415) 267-7000
(Registrant's telephone number, including area code)
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77 Beale Street
P.O. Box 770000
San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
(415) 973-7000
(Registrant's telephone number, including area code)
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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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Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
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Soliciting Material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
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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
CPUC Rulemaking Proceeding to Adopt New Safety and Reliability Regulations for Natural Gas Transmission and Distribution Pipelines and Related Ratemaking Mechanisms
As directed by the California Public Utilities Commission (“CPUC”), on August 26, 2011, Pacific Gas and Electric Company (“Utility”) filed its proposed implementation plan to either pressure test or replace those natural gas pipeline segments in its service territory that have never been pressure tested or that lack sufficient documentation related to the performance of a test. On June 9, 2011, the CPUC issued a decision that required each California natural gas transmission pipeline operator to submit a proposed implementation plan by August 26, 2011. In addition, the CPUC directed the Utility to include a ratemaking proposal to allocate costs between ratepayers and
shareholders.
The Utility’s proposed implementation plan contains two phases. In the first phase, to be completed over a four-year period (2011 through 2014), the Utility would focus on older pipeline segments in highly populated areas that have not been strength tested previously. The Utility plans to replace at least 186 miles of pipeline (plus additional mileage, as determined based on inspection and testing), conduct strength testing on 783 miles of pipeline, conduct in-line inspections of 234 miles of pipeline, and retrofit 199 miles of pipeline to accommodate in-line inspections. In the second phase, beginning in 2015, the Utility would focus on pipeline segments that have been previously
strength tested or are in rural areas. The Utility has requested that the CPUC approve the proposed work scope for both phases and authorize recovery of certain phase 1 costs in rates, as described below. The Utility proposes to address phase 2 timing and cost recovery in a separate filing for the period starting January 1, 2015. (The Utility’s proposed plan is available on its website at www.pge.com and may be accessed directly through this link:
http://apps.pge.com/regulation/SearchResults.aspx?NewSearch=True&CaseID=1099&DocType=&PartyID=4&fromDate=08%2F26%2F11&toDate=08%2F26%2F11&sortOrder=FileName¤tPage=1&recordsPerPage=100&searchDocuments=Search
The Utility forecasts that its total expenditures over the four-year period of phase 1 will be approximately $2.2 billion, which includes $1.4 billion in capital expenditures and $750 million in expenses. The expense forecast includes approximately $221 million that the Utility estimates it will incur in 2011 to validate the maximum allowable operating pressure (“MAOP”) of pipeline located in highly populated areas, to conduct hydrostatic pressure tests, and to replace pipeline. The Utility has proposed that shareholders absorb these 2011 expenses as well as capital-related expenses of $1.4 million for capital projects that became operational in 2011. In addition, the
Utility will not seek recovery of approximately $98 million that it forecasts it will incur during phase 1 to validate the MAOP of pipelines installed after 1970 and to conduct pressure tests if needed to determine the MAOP. Further, the plan states that the Utility will not seek to recover pipeline-related costs that have been incurred in 2010 and 2011 that are outside the scope of the implementation plan, such as emergency response costs related to the pipeline accident that occurred in San Bruno, California on September 9, 2010 (the “San Bruno accident”), costs to gather pipeline documents, conduct additional leak surveys and inspections, engage in customer outreach, test in-line camera inspection technologies, and participate in the ongoing legal and regulatory proceedings and investigations involving the San Bruno accident and natural gas pipeline
matters. The Utility forecasts that these costs will total $215 million by the end of 2011. In sum, the Utility’s plan proposes that shareholders absorb approximately $535 million of costs.
(In addition, the shareholders will absorb the Utility’s future costs associated with natural gas pipeline-related regulatory and legal proceedings and investigations, potential future fines or penalties, other natural gas pipeline-related activities that are outside the scope of the implementation plan, and the amount of third-party liability incurred in connection with the San Bruno accident that is not recovered through insurance.)
The Utility has proposed that implementation plan-related costs incurred after 2011, except as noted above, be recovered through rates. To increase accountability and ensure that the Utility only receives funding for capital projects or expenses that are completed, the Utility has proposed that the CPUC approve a forecast capital and expense budget for phase 1 that would be binding on the Utility unless the CPUC authorizes a modification to the budget as requested by the Utility. To the extent the CPUC does not authorize a requested modification, the Utility would be required to manage and reprioritize the remaining work scope within the approved forecast, potentially resulting in a shift of some projects
to phase 2. The Utility would recover capital costs in rates only after specific projects have been placed into operation and the actual costs of the projects are known. Under this approach, the Utility would track the revenue requirements associated with capital expenditures after their project in-service dates in a balancing account and adjust rates on January 1 of the following year through the Utility’s annual gas true-up advice letter process. For non-capital-related expenses, the Utility would recover in rates its forecast of annual expenses subject to true-up at the end of each year to reflect actual costs incurred by the Utility. Any forecasted amounts that the Utility does not spend by the end of phase 1 would be refunded to ratepayers. The Utility has requested authority to collect revenue requirements of
approximately of $247.3 million, $220.8 million, and $300.6 million, for 2012, 2013, and 2014, respectively, to recover these costs (including capital-related costs).
Finally, the Utility has proposed to submit semi-annual progress reports to the CPUC that would include information about expenditures; budget forecasts; construction status of projects; the number of pipeline miles tested, inspected with in-line technologies, and replaced; and changes in scope and prioritization for projects. The Utility has selected a third-party construction management firm to lead the overall program management effort. In addition, the Utility plans to assemble an external advisory board, including industry experts, to assist in the monitoring and oversight of program performance and to consult in connection with proposed changes in scope, schedule, or project
budget.
The procedural schedule calls for hearings to consider the implementation plans to be held in November 2011. The Utility’s cost estimate and project schedule assumes that the CPUC issues a decision early in 2012 authorizing the Utility to proceed with phase 1. If there is a significant delay in issuing the CPUC decision or if the CPUC requires material modifications to the plan, the Utility may need to change the scope of work or schedule which could result in changes to cost estimates.
National Transportation Safety Board Investigation
The National Transportation Safety Board (“NTSB”), which has been investigating the San Bruno accident, will hold a public meeting at its headquarters in Washington, D.C. on August 30, 2011 beginning at 9:30 a.m. (Eastern Daylight Time) to discuss the NTSB’s determination of the probable cause of the accident and to consider proposed safety recommendations. The NTSB has stated that a synopsis of its final report will appear on the NTSB’s website after the conclusion of the meeting and that the entire report will be available on its website in several weeks. More information about the hearing can be found on the
NTSB’s website at www.ntsb.gov.
Hinkley Natural Gas Compressor Station
As previously disclosed, the Utility is responsible for remediating groundwater contamination caused by hexavalent chromium used by the Utility in the past at the Utility’s natural gas compressor station located near Hinkley, California. Since the early 1990’s the Utility has been engaged in remediation efforts in cooperation with the Lahontan Regional Water Quality Control Board (“Control Board”) and has been working with the Control Board on the development of a final remediation plan. While a final remediation plan is being developed, the Utility has been taking interim remedial measures to reduce the mass of the underground plume of chromium and to monitor and
control movement of the plume. The Utility has recently expanded its program to drill new monitoring wells beyond the northern boundary of the plume as previously mapped to better understand the plume configuration. In mid-August 2011, the Utility reported to the Control Board that water samples from some of the new monitoring wells contain elevated levels of hexavalent chromium well above background levels of 3 parts per billion (“ppb”). Although the highest level detected in a sample was 57.5 parts ppb, subsequent re-samples show levels of between 11 and 12 ppb which are below the state of California’s drinking water standard of 50 ppb. The Utility has notified all residents within 3,000 feet of the expanded boundary defined by the new findings and has offered to sample their personal wells and provide bottled
water.
The Utility is working with the Control Board to explore potential additional remediation measures, including an expansion of the groundwater testing and monitoring program, water supply alternatives, and an expansion of the Utility’s current program to purchase properties in the affected area. Future costs will depend on many factors, including the extent of the groundwater chromium plume, the levels of hexavalent chromium, changes in applicable environmental standards, and the scope and nature of the additional interim remedial measures that the Utility undertakes. As the Utility is unable to recover remediation costs for the Hinkley site through rates, any additional costs would impact
future financial results.
In addition, on August 12, 2011, the Utility was served with a complaint filed against it in Los Angeles County Superior Court on June 7, 2011 on behalf of 11 plaintiffs who live near the vicinity of the Hinkley plume. They allege that groundwater contamination from elevated hexavalent chromium levels has caused them personal injury and has caused their property to lose value. They seek compensatory damages for personal injury and the loss of property value. A status conference has been scheduled on August 31, 2011. PG&E Corporation and the Utility are unable to predict the outcome of this matter.
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 thereunto duly authorized.
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PG&E CORPORATION
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By:
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LINDA Y.H. CHENG
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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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By:
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LINDA Y.H. CHENG
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Linda Y.H. Cheng
Vice President, Corporate Governance and Corporate Secretary
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Dated: August 26, 2011