On January 15, 1998, Pacific Gas and Electric (PG&E) applied (Application No. 98-01-008) to the California Public Utilities Commission (CPUC) for authority to divest (sell) four of its fossil-fueled power plants (Contra Costa, Pittsburg, Hunters Point, and Potrero) and its Geysers geothermal plant through a competitive auction. The four fossil-fueled plants are located in the Bay Area and the Geysers Power Plant is located in Sonoma and Lake counties, 90 miles north of San Francisco. On July 17, 1998, PG&E applied to the CPUC to amend its application, withdrawing the Hunters Point plant from the proposed sale. The divestiture of the Contra Costa, Pittsburg, Potrero, and Geysers plants is now the project proposed by PG&E and analyzed in this Draft EIR.

The divestiture of electric generation facilities (power plants) by state-regulated utilities is a component of the restructuring of the electric industry currently under way in California. Because the CPUC must determine whether the transfer of ownership of these plants would be in the public interest, pursuant to Section 851 of the Public Utilities Code, implementation of the proposed divestiture entails discretionary decision-making by the CPUC. The CPUC issued a Notice of Preparation on February 13, 1998 announcing it would be the Lead Agency for the divestiture project and would prepare an Environmental Impact Report (EIR). The NOP identified environmental areas to be examined in the EIR and requested agency views on the scope of the EIR. Four public meetings were also conducted in locations near the facilities to be divested, in order to obtain comments from residents and local agencies on the scope of the EIR.

Power plants and transmission lines in California historically have been constructed and operated by investor-owned utilities (IOUs) and municipal utilities with identified service areas. The three largest IOUs in California are PG&E, Southern California Edison, and San Diego Gas and Electric. As monopolies, these electric utilities are regulated by the CPUC, which must authorize or review most utility actions and operations. Electricity costs to utility customers are determined through regulatory rate-making decisions of the CPUC, which sets rates for the entire "bundle" of services the utility provides (including electric generation, transmission, distribution, metering, billing, and reliability). Historically, rates have been based principally on the costs of generating and delivering electricity.

Competition in the electric utility industry has developed over the past two decades. The federal Public Utility Regulatory Policy Act (PURPA) opened the electricity industry to competition in 1978. Emerging at a time when the availability of future energy supplies was in question, PURPA was designed to create a market for innovative electric generation technologies that were either renewable or more efficient than the existing large centralized power plants. In 1992, the Federal Energy Policy Act (EPAct) gave to states and regions the responsibility of implementing policies and programs aimed at achieving greater market competition.

In the early 1990s, the Federal Energy Regulatory Commission (FERC) mandated open access in wholesale electric transmission throughout the United States. This made it realistically possible for the first time for major U.S. electric customers to bypass their local utilities for cheaper providers, and encouraged efforts by large California customers to bypass prevailing high IOU electric prices. Meanwhile, the CPUC had undertaken a study of what could be done to lower utility rates in order to help stimulate the state’s economy.

On December 20, 1995, the CPUC issued its Preferred Policy Decision, D.95-12-063 as modified by D.96-01-009, describing its determination to embrace market competition in the provision of electric services and to offer retail customers choice and flexibility in energy services. The Preferred Policy Decision called for the establishment of a statewide independent system operator (ISO) to control and operate the state's electric transmission system, and the creation of a wholesale power pool, or "Power Exchange" (PX), as a market for electric power. The Preferred Policy Decision sought to reduce the high IOU electric rates in California by providing retail electric customers with greater choice and fostering price competition among energy generators, and called on the two largest IOUs, PG&E and Edison, voluntarily to divest at least 50 percent of their fossil-fueled generation assets.

Assembly Bill (AB) 1890, signed into law in September 1996 turns much of the CPUC's preferred market structure (described in the Preferred Policy Decision) into a legislative mandate to restructure the electric utility industry in California. AB 1890 mandates the separation ("unbundling") of generation, transmission, and distribution services, among other provisions. While AB 1890 does not mandate divestiture of any generating facilities, it authorizes the CPUC to allow plant divestiture to mitigate the utilities’ market power. The CPUC believes that increasing the number of electrical suppliers will foster competition in the electric industry. In the first round of plant divestitures following passage of AB 1890, PG&E divested three fossil-fueled plants and Southern California Edison divested 12 fossil-fueled plants.

Figure S.1 shows the overall electric system in California; this project involves the sale of specific power plants, not transmission or distribution systems.

As noted, PG&E applied to the CPUC in January 1998 to sell five of its electric generation facilities through a competitive auction. As modified in July 1998, PG&E is seeking to auction the Potrero Power Plant in San Francisco County, the Pittsburg and Contra Costa Power Plants in northern Contra Costa County, and the Geysers Power Plant in Sonoma and Lake Counties. The locations of these plants is shown in Figure S.2.

The three fossil-fueled plants, consisting of a mix of 10 steam boiler units and three combustion turbine (CT) units, have a combined net generating capacity of 3,065 megawatts (MW). (See Table 2.1 in the EIR for generating capacity and other information by plant.) Each of these plants generates electricity primarily from steam turbines with boilers fueled by natural gas. The Geysers Power Plant (which constitutes all of PG&E’s geothermal generation facilities) has 14 generating units (at 11 sites) with a total net generating capacity of 1,224 MW. Two of the Geysers units are in Lake County and 12 are in Sonoma County. The Lake County units have 246 MW of combined net generating capacity, while the Sonoma County units account for 978 MW of combined generating capacity. Over the last five years, generation from the three fossil-fueled plants accounted for about 45 percent of the PG&E's total fossil-fuel generation, while the Geysers Power Plant accounted for roughly 6.6 percent of the utility’s total generation and all of its geothermal energy.

PG&E proposes to sell the plants in four packages: the Pittsburg and Contra Costa plants together (the Delta plants), the Potrero Power Plant, the Geysers units in Sonoma County, and the Geysers units in Lake County. Prospective buyers may submit bids on one or more of the plants offered for divestiture, with the exception that they must bid on the Delta plants as one package, and must bid on each set of Geysers units (the Sonoma County units and the Lake County units) separately from the other set and from any other plant.

Upon approval of the sale by the CPUC, PG&E would transfer to the new owners all facilities, equipment, permits (e.g., air and water), land interests and other entitlements required for continued operation of the plants. PG&E will retain facilities and equipment at each site that pertain to transmission or distribution operations. PG&E will also retain certain liabilities for existing contamination of soil and groundwater and will be responsible for conducting remediation activities of such contamination after the sales. Other than minor construction activities that may be necessary to separate generation from transmission and distribution facilities, the proposed divestiture does not directly involve any planned expansion, modification or dismantling of existing facilities and structures. The Purchase and Sale agreement for each plant requires a deed restriction that prevents the new owner from using the site for residential or other sensitive uses. The buyers of the plants will be required to enter into suitable "must-run" contracts with the Independent System Operator (ISO). The proposed bidding, sale and regulatory approval process is designed to complete the divestiture of the plants by the fourth quarter of 1998 or as soon thereafter as possible.

This is PG&E’s second round of power plant divestitures. Last year, PG&E auctioned its Morro Bay (1,478 MW), Moss Landing (1,002 MW), and Oakland (165 MW) Power Plants to affiliates of Duke Energy Power Services, Inc. The sale of those three plants was approved by the CPUC on December 16, 1997, and closed on July 1, 1998. If PG&E’s current divestiture application is approved and the four plants sold, PG&E will still own 112 hydroelectric units (3,910 MW), Hunters Point Power Plant (423 MW), Humboldt Bay Power Plant (105 MW), three mobile combustion turbines (45 MW) and the Diablo Canyon Nuclear Power Plant (2,160 MW). In May 1998, PG&E announced its intention to sell or spin off to stockholders its hydroelectric assets, as well; no formal divestiture application has been filed to date.

This EIR does not analyze effects associated with the changes brought about by restructuring of the electric industry under AB 1890, since such changes have already been mandated and are occurring now. Rather, the EIR assumes the existence of the restructured market, and analyzes potential impacts associated with projected plant operations under new owners in the restructured market as compared to PG&E’s projected plant operations (if the plants were not sold) in the restructured market. The EIR considers whether PG&E’s proposed divestiture would likely lead to significant effects on the environment as a result of either (1) physical changes associated directly with the ownership transfer, or (2) distinguishable operational changes at the plants proposed for sale, that are different or greater than would occur solely due to restructuring. The following types of changes were considered in evaluating whether divestiture would result in changes that could produce environmental impacts:

• Amounts of Energy Generated at Each Divested Plant and Other Developed and Undeveloped Sites in California and the Western Region; Amount and Timing of Construction, Refurbishment, Repowering, or Retirements of Divested Plants, or Other Developed or Undeveloped Sites in California and the Western Region;
• Maintenance Practices at Each Divested Plant;
• Pollution Control Technologies Employed or Installed by New Owners;
• Employment Levels and Related Factors;
• Extent and Character of Land Use;
• Approach to Environmental Cleanup; and
• Permit Transfers for Divested Plants.

Having considered these potential changes, it was concluded that new owners of the fossil-fueled plants would tend to operate at higher levels than PG&E because of the following three factors: (1) the portfolio effect, which is the availability to PG&E of its portfolio of electricity-generating assets, (2) fuel procurement practices, such as the possibility that new owners would purchase natural gas at a lower cost per unit or in a different fashion than would PG&E, and (3) the ability of new owners immediately to participate in the direct access market while PG&E must initially sell all of its power through the PX.

The manner in which operations at the Geysers geothermal plant could change with divestiture depends on the identity of the new owners. PG&E has recently moved many Geysers units from a baseload (i.e. constant) mode to more cyclical operations. If a third-party entity with no ownership interest in the underlying steam field purchases the Geysers units, it is reasonably foreseeable that such new owner would pay a steam price similar to that paid by PG&E under its contracts with the steam field owners and operate the units in a manner similar to PG&E’s operation. If, on the other hand, the current steam field owners purchase the Geysers units, it is foreseeable that the plant would be operated more either in a baseload manner or during peak periods to increase dependable capacity, thereby increasing generation from the Geysers plant.

The manner in which PG&E would be expected to operate the plants in 1999 is considered to be the environmental baseline ("Baseline Scenario") for purposes of measuring the impacts of the project. In order conservatively to depict the greatest potential project impacts in 1999, the Baseline Scenario is compared to an analytically-derived maximum capacity (the "Analytical Maximum") at which each of the plants proposed to be sold could operate in 1999.

1999 Baseline

In most respects, the 1999 PG&E Baseline Scenario does not differ from the existing environmental setting. However, in order to reflect the ongoing changes in the electric industry resulting from restructuring (which changes will occur with or without the divestiture project), it is reasonable and informative to project the manner in which PG&E would operate the plants in 1999 if the plants were not sold. The major assumptions used in the computer simulation of the Baseline Scenario include the following:

1999 Analytical Maximum

The year 1999 was selected as the project impact year because (1) if the project is approved, the plants could be sold by 1999; (2) 1999 will be the first full year under restructuring of the electric industry in California; and (3) PG&E is currently precluded from selling power outside the Power Exchange and could be precluded from that activity until March 31, 2002. New owners, on the other hand, could immediately take advantage of the direct access market. The ability of new owners to participate immediately in the direct access market is a key factor in this EIR’s assumption that new owners will tend to operate at higher levels than would PG&E. Thus, a year prior to 2003—when PG&E also will be able to sell power directly, thereby moving its operational characteristics closer to those of a new owner—likely represents the greatest potential for environmental change caused by divestiture.

It is expected that divestiture of the power plants will create a tendency for new owners to operate the plants at higher levels than in the 1999 Baseline Scenario. However, it is not possible to determine with any precision at which plants operations would increase, or the degree to which operations would increase at any particular plant. The 1999 Analytical Maximum Scenario calculated by the computer model is intended to capture the maximum possible change in operations that could occur from divestiture.

The Analytical Maximum capacity factors for the four plants represent the highest capacities at which the plants could operate, taking into account limiting factors such as the rated capacities of the units; scheduled and forced outages of units for maintenance; contractual limitations, including must-take contracts that favor power generated by qualifying facilities (QFs); and demand constraints (i.e., the finite demand for electricity at any particular time on any given day). The 1999 Analytical Maximum Scenario reflects assumptions 2 through 8 outlined above for the 1999 Baseline Scenario and, additionally, assumes for the fossil-fueled plants that natural gas could be purchased in unlimited quantities at a 25 percent discount from the least expensive supply of gas assumed to be available to fuel California power plants (i.e., the natural gas supplied for the Cool Water plant). In order to be conservative, the EIR’s project impact analyses assume that the new owners would operate the divested plants at the 1999 Analytical Maximum capacities.

Table S.1 presents capacity factor estimates (the percentage of total plant capacity) for operations of the four plants in a restructured setting in 1999 if they were retained by PG&E ("1999 Baseline"), the capacity factor estimates for operation of the four plants in 1999 at their Analytical Maximum capacities, if they were sold, and the capacity factor estimates for the 2005 Cumulative Analytical Maximum Scenario.

Impacts Summary

Table S.2, beginning on page S-28 presents a summary of the project’s environmental impacts, the level of significance of the impacts, and identified mitigation measures. Impacts and mitigation measures are listed by environmental topic.

2005 Cumulative Analytical Maximum

This EIR analyzes cumulative impacts as of the year 2005. The year 2005 was selected for cumulative analysis primarily because all air quality controls for NOx, as required by Bay Area Air Quality Management District Regulation 9, Rule 11, would be in place by that year. The cumulative analysis continues to assume that the owners of the divested plants would operate the plants at their analytical maximum capacities, in order conservatively to depict the greatest potential cumulative impacts in 2005.

The EIR considers the cumulative effects of a multitude of projects and factors, including proposed new power plants, proposed upgrades in the electricity transmission system, projected increases in demand for electricity, planned or proposed wastewater injection projects at the Geysers plant, and local projects proposed in the vicinities of the power plants. Many of these projects involve separate, project-specific environmental review and require governmental permits and approvals in order to be implemented. Under the terms of a July 9, 1998, agreement between PG&E and the City and County of San Francisco, PG&E agreed to withdraw the Hunters Point Power Plant from the auction process by which it proposes to sell the other four plants, and agreed permanently to shut down the Hunters Point plant as soon as the facility is no longer needed to sustain electric reliability in San Francisco and the surrounding area, and the Federal Energy Regulatory Commission (FERC) has authorized PG&E to terminate PG&E’s Reliability Must Run Contract for the facility. The agreement provides that the City and PG&E will advocate the expeditious development of generation and/or transmission facilities to replace the Hunters Point plant, among other terms. In light of that agreement, the cumulative analysis also assumes that the Hunters Point Power Plant, located in the City of San Francisco, is no longer operating by 2005 and that new generation facilities (totaling 480 MW) have been constructed and are operating somewhere north of the Martin Substation (in San Mateo County) in order to replace the Hunters Point plant and to meet anticipated increases in electricity demand.

In order to portray the maximum cumulative potential for environmental change associated with the project, the cumulative impacts analysis compares the 2005 Cumulative Scenario to the 1999 Baseline Scenario. The modeled estimates of cumulative impacts were derived in the same manner as those of the 1999 Analytical Maximum Scenario, with the following additional key assumptions:

Modeled estimates were also developed for two cumulative variants. One of these assumes that the Hunters Point Power Plant is replaced by upgraded transmission facilities on the San Francisco Peninsula, together with construction of a new 240 MW generating facility to serve electricity needs within San Francisco. The other variant assumes that the proposed Pittsburg District Energy Facility is constructed in the City of Pittsburg.

Table S.3 presents annual plant capacity factor estimates for each of the four plants being divested under the various 2005 cumulative scenarios. The computer modeling of the 2005 Cumulative Analytical Maximum Scenario shows that the project, in conjunction with other cumulative projects, would reduce the operational levels at the Potrero, Contra Costa, and Pittsburg Power Plants from that of divestiture alone. This is because the assumed 480 MW facility would be efficient and would operate at a relatively high annual capacity factor (91 percent), thereby offsetting generation from the three fossil-fueled plants proposed for sale. Therefore, the project-specific impacts analyzed in Chapter 4 of this EIR would address the worst-case impacts that are related to operational levels at these plants.

Table S.4 summarizes the cumulative impacts of the project under the 2005 Cumulative Analytical Maximum, together with current and proposed projects in the communities and counties surrounding the power plants. Where the cumulative scenario would have no impacts different in degree or nature from the project itself, no impacts are identified (i.e., the project impacts analyzed in Chapter 4 of this EIR and summarized in Table S.2 are not restated).

This EIR considers three alternatives that provide a range of reasonable alternatives to the proposed project:

Table S.5 presents the capacity factor estimates for each of the four plants proposed to be sold under the 1999 and the cumulative 2005 scenarios, as well as for Alternatives 1 and 3. Modeling was not done for Alternative 2, fossil-fueled power plant bundling scenarios, as it was deemed unnecessary.

The computer modeling results show that under Alternatives 1 and 3, the fossil-fueled plants would operate considerably less than the Analytical Maximum derived for the project in both 1999 and 2005. The Geysers plant would operate more than the Analytical Maximum under both Alternatives 1 and 3, with the highest capacity factors under Alternative 3. Under Alternative 2A, the sale of the three plants to a single buyer, the new owner would have less tendency to operate the plants close to (or at) the Analytical Maximum than in the bundling scenario assumed for the project. Conversely, under Alternative 2B, each of the fossil-fueled plants sold to separate buyers, the new owners would have a greater tendency to operate toward the Analytical Maximum, but individual plant operations would not exceed the Analytical Maximum for either 1999 or 2005.

Table S.6 summarizes by topic area the environmental impacts of each alternative and compares the impacts of each of the alternatives with those of the project. The environmentally superior alternative to the project is a combination of Alternative 2A, the bundling of Potrero, Contra Costa and Pittsburg and Alternative 3, the sale of the Geysers plant to the steam field operators. The bundling of the three fossil fuel plants would have a tendency to lower overall generation of these plants compared to the project. The magnitude of the impacts would be less than with the project, but the levels of significance of the impacts would be identical to the project. Under Alternative 3, the sale of the Geysers units to the steam field owners would allow for coordination of generating unit operations with steam field characteristics and could effectively reduce or eliminate any steam stacking. In addition, the Geysers plant would operate at a higher capacity, which would lower somewhat the need for power generated by non-renewable fuels. These two alternatives coupled together are considered to be the environmentally superior alternative.

Areas of controversy have been identified from written responses to the Notice of Preparation, public meetings, and the agency scoping process. With respect to the three fossil-fueled plants, these areas of controversy include the degree (if any) to which new owners would increase operations over and above the levels at which PG&E would operate in the future if it retained the plants; health effects of potential increased operations resulting from divestiture; alternatives to the continued reliance on the Potrero and Hunters Point Power Plants to supply power within the City and County of San Francisco; the manner in which the Bay Area Air Quality Management Districts Regulation 9, Rule 11 (pertaining to utility-owned steam boilers) should be amended to apply to the new owners of the three fossil-fueled plants proposed for sale, as well as the Hunters Point plant; effects of the Contra Costa and Pittsburg plants with respect to fallout type particulates and boat-washing activities connected to these two plants; and whether dispatch requirements for the Pittsburg and Contra Costa plants require selling these two plants as a single package, as PG&E proposes.

With respect to the Geysers Power Plant, areas of controversy include concern for the financial strength and operational capabilities of the new owners; the potential for increased air emissions caused by steam stacking (leading to the release of unabated steam), if operations of the new plant owner(s) and the steam field owners were not well coordinated; effects of the sale on hydrogen sulfide emissions; the proper management of hazardous wastes (which result primarily from naturally occurring constituents of the geothermal steam); effects of the sales on microseismicity in the Geysers area; the potential for legal disputes between PG&E and the new owner over clean-up responsibility to delay timely remediation of contaminated areas; the potential for the sales to increase diversions from creeks in the Geysers area; the effect of the sales on current tax revenues collected from the Geysers Power Plant; the degree (if any) to which environmental benefits would result from the Geysers units being sold to the steam field owners; and the recovery of costs (by the counties) for their future efforts to value the properties being sold for taxation purposes and any subsequent litigation over those values and tax burdens.

Certain of these areas of controversy relate more to social/economic issues or project planning issues rather than to environmental impacts of the project, and will be addressed by the CPUC as appropriate in its decision-making process. Other areas of controversy may arise during the public comment period on the Draft EIR.