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: July 14, 2004 | |||
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1-12609 1-02348 | PG&E Corporation Pacific Gas and | California California | 94-3234914 94-0742640 |
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Pacific Gas and Electric Company | PG&E Corporation | ||
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(Address of principal executive offices) (Zip Code) | |||
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Pacific Gas and Electric Company | PG&E Corporation | ||
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(Registrant's telephone number, including area code) | |||
Item 5. Other Events and Regulation FD Disclosure
On July 9, 2004, PG&E Corporation’s subsidiary, Pacific Gas and Electric Company (Utility), submitted its long-term integrated energy resource plan (LTP) for the 2005 through 2014 period to the California Public Utilities Commission (CPUC) in compliance with CPUC decisions and orders regarding electric resource planning. The LTP sets forth the policy framework, strategies and implementation steps for meeting customer electricity demand (or “load”) for the next 10 years. The LTP is consistent with the Energy Action Plan (EAP) adopted in 2003 by the CPUC, the Energy Resources Conservation and Development Commission, and the Consumer Power and Conservation Financing Authority to ensure that adequate, reliable, and reasonably-priced electrical power and natural gas is provided in a cost-effective and environmentally sound manner for California's consumers. The EAP establishes a “loading order” of energy resources under which conservation and energy efficiency programs are first used to minimize increases in electricity and natural gas demand, next followed by use of renewable energy resources and distributed generation to meet new generation needs, followed by support for the development of additional clean, fossil fuel, central-station generation.
In light of the future uncertainty regarding the extent to which the Utility’s residential and small commercial customers (or core customers) and its large commercial and industrial customers (or non-core customers) can procure electricity from non-utility load serving entities (such as local publicly owned electric utilities, community choice aggregators or energy service providers, collectively referred to as “LSEs”), the Utility noted that it was essential that the CPUC establish clearly articulated electricity reliability standards and cost responsibilities for all LSEs.
Despite this uncertainty, the Utility made certain assumptions regarding the level of retail load that the Utility will serve in the future to develop the “medium load” scenario on which the Utility’s LTP is based. The Utility has assumed that the current level of direct access participation would continue throughout the ten-year period. The Utility also has assumed that its customer load would be further reduced over the ten-year period through (i) a core/non-core program to be implemented through future legislation authorizing larger customers to participate in direct access on a phased-in basis starting as early as 2007, and (ii) robust participation among smaller customers in community choice aggregation starting as early as 2006. The Utility has assumed that by 2014 its load and corresponding procurement responsibility would be reduced by approximately 4,000 megawatts (MW).
To minimize the uncertainties regarding the level of future retail load, the Utility has requested that the CPUC establish five-year resource adequacy requirements for all LSEs that will ensure that these entities secure reliable electricity supplies for all of their customers far enough in advance to avoid a statewide shortage of power. Also, to assure recovery of the Utility’s costs of new long-term electricity resource commitments, the Utility has requested the CPUC adopt a non-bypassable charge to be collected from all customers on whose behalf the Utility makes these new commitments, including those who subsequently receive generation from LSEs.
To meet its net open position (i.e., that portion of the demand of the Utility's customers, plus applicable reserve margins, not satisfied from the Utility's own generation facilities and existing electricity contracts) over the 10-year planning horizon the Utility proposes:
- New customer energy efficiency (CEE) programs to reduce load with total potential expenditures of approximately $1 billion over the 10-year planning horizon. To achieve the assumed load reductions, the Utility has requested that the CPUC approve an incremental revenue requirement increase of $245 million for three additional years (2006 through 2008) of CEE programs based on the targets as proposed in the LTP. The Utility also has requested that the CPUC approve a CEE incentive mechanism to encourage program success in achieving the proposed CEE targets.
- The development of demand response programs in conjunction with the California Independent System Operator that will result in certain, predictable load reduction.
- An increase in the percentage of renewable energy resources in the Utility’s generation portfolio in accordance with the objective adopted in Senate Bill 1078. The LTP medium load scenario assumes that by 2010, 20% of the Utility’s retail load will be met by a combination of purchases from renewable energy providers and the re-powering of existing wind projects.
- Entry into short-and mid-term power purchase agreements over the next four years with existing market resources to ensure adequate supply of electricity in the period before new generation facilities are assumed to become operational. The Utility has requested immediate authority from the CPUC to execute short and mid term contracts under its existing short-term procurement plan.
- The development of new utility-owned generation and generation to be purchased under long-term contracts particularly for the period 2007 to 2010 when it is assumed that there will be a need for additional generation facilities. The Utility’s LTP assumes that power plants currently providing 2,000 MW of generation to the Utility will retire within the next five or six years. The Utility has requested that the CPUC approve the Utility’s solicitation of offers for utility-owned generation development and for generation to be provided under long-term contracts for approximately 1,200 MW by 2008 and an additional 1,000 MW by 2010. The Utility has proposed to release drafts of these two requests for offers (RFOs) for public comment in September 2004 and to issue the RFOs in October 2004. The Utility has requested that the CPUC issue a LTP decision by the end of 2004 and that the CPUC act to approve the proposed winning bidders from the RFOs no later than June 2005. The Utility also has requested that, at the time the CPUC approves a proposal for a new utility-owned generation facility, the CPUC also authorize a reasonable cost for the facility to be placed in rate base. If actual costs of construction are less than or equal to the amount placed in rate base, the Utility has requested that such costs would not be subject to an after‑the‑fact reasonableness review by the CPUC. The Utility’s target over the 10-year planning horizon is to own 50% of the new generation resources to be developed with the remaining 50% of such resources to be purchased under long-term contracts.
In addition to requesting that the CPUC adopt a non-bypassable charge as discussed above, the Utility, as a condition to its willingness to make these long-term commitments, has requested that the CPUC take the following steps:
- Extend Assembly Bill 57’s trigger mechanism that requires the CPUC to adjust procurement rates if the Utility’s Energy Resource Recovery Account, or ERRA, (a balancing account designed to track and allow recovery of the difference between the Utility’s recorded procurement revenues and actual costs incurred under the Utility's authorized procurement plans, excluding certain costs) becomes undercollected by more than 5% of the previous year’s generation revenues. As of January 1, 2006, the timing of such rate adjustments is left to the discretion of the CPUC. The Utility has requested that, at a minimum, the CPUC extend the trigger mechanism for the 10-year planning horizon covered by the LTP.
- Clarify that the CPUC’s maximum disallowance of utility administrative and dispatch costs applies to both the allocated California Department of Water Resources (DWR)’s power purchase contracts and administrative and dispatch costs related to utility-owned generation and other power purchase agreements. Currently, the maximum disallowance is equal to two times a utility’s administrative costs of managing procurement activities, or, for the Utility, approximately $36 million per year.
- Adopt a policy that recognizes and addresses the fact that credit rating agencies will consider obligations under long-term power purchase contracts to have debt-like characteristics that will adversely affect the Utility’s credit ratios which may, in turn, adversely affect the resulting credit ratings. The Utility has proposed that the CPUC evaluate the “debt equivalence” impacts when the Utility and the CPUC evaluate the bids for various long-term commitments and that the CPUC mitigate the resulting debt equivalence impacts in subsequent cost of capital proceedings through adjustments to the Utility’s authorized capital structure. For example, the Utility presented testimony that under certain future scenarios, estimated future shortfalls in certain minimum financial ratios used by the credit rating agencies to support various investment grade ratings could be offset by an increase in the Utility’s common equity ratio which would increase annual revenue requirements. The Utility noted that its goal was to improve the Utility’s credit ratings over time, as stated in the December 19, 2003 settlement agreement the Utility and PG&E Corporation entered into with the CPUC to resolve the Utility’s Chapter 11 proceeding.
On July 8, 2004, a CPUC administrative law judge issued a ruling requesting comments by July 22, 2004 about whether the CPUC should accelerate the phase-in of its planning reserve requirement to maintain a 15% to 17% reserve margin to June 1, 2006 from January 1, 2008. The medium load scenario described in the Utility’s LTP does not assume the accelerated phase-in. If the accelerated phase-in is adopted, the Utility’s net open position would increase.
Neither PG&E Corporation nor the Utility can predict when or whether the CPUC will approve the LTP or take any of the actions the Utility has requested in connection with the LTP, how the uncertainties discussed above will be resolved in the future, or whether the assumptions upon which the LTP is based will prove to be accurate.
| SIGNATURE |
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.
| PG&E CORPORATION |
| By: CHRISTOPHER P. JOHNS |
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| CHRISTOPHER P. JOHNS |
| PACIFIC GAS AND ELECTRIC COMPANY |
�� | By: DINYAR B. MISTRY |
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| DINYAR B. MISTRY |
Dated: July 14, 2004