B1 Comment noted.

B2 Comment noted.

B3 Comment noted.

B4 The examination of green power in the Alternatives section (page 6-3) of the DEIR was done at the request of the City and County of San Francisco and members of the community near the Hunters Point and Potrero Power Plants, which had expressed a desire to close the power plants and replace that generation with green power resources. Such a proposal was not formally considered as a "project alternative," as defined by California Environmental Quality Act (CEQA), but was informally analyzed as part of the alternatives analysis, with an explanation of why such an alternative was not feasible. The California Energy Commission (CEC) is correct in that use of a mix of green power resources and distributed generating resources could conceivably allow the closure of Hunters Point and Potrero Power Plants (i.e., could meet load demand and the requirements of the San Francisco and Greater Bay Area Operating Criteria). However, such a scenario in the near-future is highly unlikely. Because of its relatively high cost, distributed generation technology (which is basically the use of many small generating units, such as utility-scale fuel cells, distributed throughout a service territory) is still nascent, especially non-polluting distributed generation technology, and is currently not used anywhere in North America. Such a mixture of resources may be considered as an option in the process for planning the closure of the Hunters Point Power Plant, whether by the City and County of San Francisco or PG&E. However, neither the complete nor the partial replacement of existing generation facilities with green power and distributed generating resources represents a true CEQA alternative to the proposed sale of the Pittsburg, Contra Costa, and Potrero Power Plants and the Geysers geothermal units. Thus, examining a "more realistic" alternative of using green power and distributed generation resources in the EIR would not change the EIR’s conclusions or add meaningful data to the current decision-making process.

B5 The issue of concern in this EIR is whether a greater environmental risk would exist under the new owner of the divested power plants compared to continued ownership by PG&E, whether referring to future decommissioning of the plants or any other facet of power plant ownership. Many factors affect the assessment of this risk. Concerning decommissioning, the new owner would be required to abide by all contractual requirements, including decommissioning requirements, that currently apply to PG&E because all leases, contracts, agreements, conditions, covenants, and requirements affecting the plants would be assigned to the new owners. In addition, all applicable federal, state and local laws, ordinances and regulations concerning decommissioning would continue to apply to new plant owners.

Regarding the fossil-fueled plants, PG&E is subject to the same decommissioning requirements as apply to any owner of similar facilities, such as the hundreds of power plants in California owned by non-utility companies. PG&E’s status as a regulated utility does not reduce or enlarge the scope of applicable requirements. In general, owners of fossil-fueled plants have discretion over the timing and method of decommissioning and dismantling a facility. However, a number of state and federal laws, local ordinances, and permit and lease conditions require demolition activities, site remediation, and handling and disposal of hazardous materials at industrial sites to be conducted in an environmentally responsible manner. Some requirements take effect upon cessation of operations, whereas others take effect when the decision is made to dismantle all or part of a facility.(1)

Regarding the Geysers Geothermal Plant, PG&E is subject to a number of contracts, agreements, leases, and regulatory conditions that impose obligations relating to unit decommissioning or retirement. These obligations will be transferred to the purchasers of the units. The majority of decommissioning obligations arise under the steam supply agreements for both the Sonoma and Lake County units. The Sonoma County steam supply agreements with Unocal/NEC/Thermal require PG&E to dismantle and remove its facilities, clean up the facility sites, and mitigate remaining environmental hazards within a reasonable time after the facilities are dismantled and within five years after termination of the agreements through closure of the last unit. The agreements require such removal activities to be conducted in a manner that is acceptable to governmental entities having jurisdiction and consistent with applicable provisions contained in certain real property agreements between Unocal/NEC/Thermal and third parties applicable to the sites. PG&E also has land-related agreements with other parties and certain local land use permits which contain unit removal or site restoration provisions. For the Lake County units, the steam agreement with Calpine requires that PG&E sell, remove, or dispose of its facilities within a reasonable time after termination of the agreement. Other land-related agreements between PG&E and other parties also require removal of structures and site restoration. For Unit 16, the CEC has imposed Conditions of Certification that require PG&E, after operations cease, to restore the site through recontouring and revegetation, and to prepare a decommissioning plan containing biological mitigation measures.(2) Units 17, 18 and 20 are also subject to CEC oversite during decommissioning.

Some parties have expressed concern that a new owner might be more likely than PG&E to go bankrupt and abandon a power plant, leaving behind significant environmental problems and cleanup liability. An examination of the purchasers of previously divested utility plants in California shows that these companies are all large, multi-faceted, financially secure energy service companies, with bond ratings similar to or better than PG&E’s. To ensure PG&E can recover its investment in the Geysers units through the sale, PG&E has a high incentive to choose a financially secure purchaser of the divested plants, and the CPUC will not approve a purchase by a company that does not have the expertise and resources needed to responsibly operate a power plant. The EIR preparers are unaware of any company similar to the purchasers of the previously divested plants that has gone bankrupt. Rather, because these companies own very valuable assets (i.e., power plants, which provide access to the transmission grid), when one becomes even remotely financially weak, it is more likely that other companies would offer to engage in a merger or other consolidation mechanism. Conversely, at least one regulated utility and several consumer-owned cooperative utilities in the Western Unites States have gone bankrupt in recent years, leaving significant liabilities unpaid, although all of their generation assets were assumed by other entities and continue to operate.

However, even if it is assumed that the sale of the plants to a new owner would increase the risk that a plant owner would become insolvent and abandon the plant, compared to the risks posed by PG&E (a regulated utility) continuing to own the plants, there is no basis to conclude that the eventual decommissioning of the plants would be affected in a manner that would result in environmental impacts. In cases where utilities or small cogeneration plant owners have gone bankrupt in the past, their power plants have continued to operate, either under a new owner or under the supervision of a bankruptcy trustee. For the plants in question in this project, especially concerning the Bay Area fossil-fueled plants, the sites alone would have a considerable market value because they offer access to the transmission grid in areas that need power plants, meaning that as long as the sites remain viable for construction of a power plant, energy service companies will aggressively pursue the chance to obtain them. Access to the grid may prove so valuable that companies would be willing to pay for any needed decommissioning costs related to abandoned facilities on the site. In addition, as long as the present facilities remain classified as "must-run," the ISO would offer class "C" reliability must-run agreements, which allow continued operation (and payments) even if the owner has filed for bankruptcy protection. The only way the plants that are presently designated as must-run could lose that status would be if some other facility could provide the same reliability support as the present plants. Most likely, this would involve construction of a new power plant or a new transmission line. Siting of such new facilities would require environmental review and, if it appeared that such new facilities could cause the closure of existing plants or threaten the must-run status of existing plants, those potential occurrences would be analyzed and subject to public debate. For the Geysers especially, that environmental review would include examination of the impact of replacing the generation of already viable renewable energy with energy generated elsewhere.

Even assuming that a power plant were abandoned and that no purchaser were interested in the remaining assets or the site, the potential for significant environmental impacts caused by abandonment is still very remote. As to the Geysers generating units, once the steam were shut off to the units, very little potential for environmental contamination would exist because of the relatively small amounts of toxic substances used, produced or stored at the generating units. Therefore, these facilities could remain in place indefinitely without causing significant environmental consequences. (If enough steam pressure still existed such that leaking piping systems would be a problem, then presumably enough steam pressure would still exist to generate power, making the existing assets valuable enough to attract new purchasers.) A similar situation exists for the unlikely event of abandonment of the fossil-fueled power plants, which are all securely fenced. Once the fuel were shut off to the plant, and the comparatively small amount of (still valuable) fuel oil were removed from the storage tanks, little potential would exist for ongoing environmental concerns. As well, the plant would no longer produce polluting air emissions or thermal impacts on local waterways.

Furthermore, if a power plant were abandoned, and the previous owner could not pay for cleanup and other decommissioning costs (such as was the case with the case of a Geysers steam field operator that walked away from 24 leaking wells, as detailed in the response to Comment T8), other resources are available to local agencies for any needed remediation or other decommissioning work.(3) These include EPA superfund monies and various grant programs from state and federal agencies.

Therefore, for all the reasons detailed above, implementation of the project would not result in any potentially significant environmental effects associated with decommissioning. Please also see response to Comment K1 for a discussion of the impact from decommissioning on local agencies.

B5 - Footnotes

B6 The DEIR has evaluated capacity factors and the resultant effects under a 2005 Analytical Maximum scenario for both the Pittsburg and Contra Costa Power Plants. In addition, the analysis includes an evaluation of the potential environmental impacts associated with operation of the proposed ENRON Pittsburg District Energy Facility (PDEF). The results of the capacity/generation analysis are available in Attachment G of the DEIR. An analysis of the potential cumulative impacts of the project with the PDEF is available in Chapter 5, Cumulative Impacts, Section 5.3.4, Cumulative Effects Under Variant 2. A detailed analysis of the potential cumulative effects of the Calpine-Pittsburg Power Plant, also referred to as the Delta Energy Center Project (DECP), together with the Pittsburg, Contra Costa and proposed PDEF plants, is provided in the response to Comment B15.

With respect to the commenter’s suggestion that the 2005 Analytical Maximum analysis should include an increase in the operations of both the Pittsburg and Contra Costa Power Plants, the maximum generation for these plants has been modeled and evaluated for a future date of 2005. It was determined that the new generation projected to become available locally and throughout the State of California would tend to lower the capacity at the plants being divested by PG&E as of 2005, including the Pittsburg and Contra Costa Power Plants.

In response to this comment and based on discussions with the CEC (Layton, 1998), it was determined that additional atmospheric dispersion modeling would be prepared for the PG&E Pittsburg and Contra Costa Power Plants together with the proposed new PDEF. Since the newly proposed Calpine DECP has not filed an application with the CEC, insufficient information is available to include the DECP in this analysis. The commenter has also suggested that potential industrial development also be considered in this analysis. As shown on Table 5.1 of the DEIR, none of the local cumulative projects for the Pittsburg/Contra Costa area are industrial in nature and, thus, there are no known potential industrial project to consider or include in this analysis.

The CEC has supplied to the EIR preparers atmospheric dispersion model input data taken from the PDEF’s permitting package recently submitted to the CEC. Such modeling data consists of model input and output of short-term and annual model analyses for PM-10 and NO_X. The CEC-supplied PDEF data has been assumed to be correct for the purposes of, and has been employed in, this analysis.

The purpose of this additional atmospheric dispersion modeling exercise was to determine, to the extent possible, what future cumulative air quality impacts could occur within the local Pittsburg-Antioch airshed from combined operation of the Pittsburg and Contra Costa Power Plants and the proposed PDEF. In order for this new analysis to be comparable with analyses already presented in the DEIR, the following parameters were followed in the modeling:

This analysis was conducted using the Industrial Source Complex Short Term 3 Model (ISC3), Version 97363. This model was developed and approved for use by the U.S. Environmental Protection Agency and represents the state of the art in atmospheric dispersion modeling. The model was used assuming standard regulatory default options and BAAQMD modeling guidelines.

The source parameter data for the Pittsburg and Contra Costa plants were provided by PG&E, while the PDEF parameters were provided by the CEC. Figure B6 shows the location of all three power plants and the approximate location of the unmodeled Calpine DECP. A receptor network grid of 975 individual points was used to evaluate the combined impact of all three modeled power plants. (Receptors are points where an atmospheric dispersion model predicts impacts from pollution sources being simulated by the model.) This receptor grid was 22.5 kilometers (14 miles) in the west-to-east direction by 6.5 kilometers (4 miles) in the north-to-south direction and was oriented so that all three power plants were located within the central portion of this region and all were a minimum of about 5 kilometers (3.1 miles) from either the east or west edge of the impact region. This grid provided adequate coverage of the local population areas of Pittsburg and Antioch. Receptor grid spacing was typically 500 meters (0.31 miles), except for the grid placed over the City of Pittsburg, where spacing was 250 meters (0.16 miles). Added to the receptor modeling grid were the locations of sensitive receptors close to both the Pittsburg and Contra Costa Power Plants, as identified by PG&E. In the case of Pittsburg Power Plant, this same set of sensitive receptors was used to evaluate local air quality impacts for the DEIR. Since each plant was analyzed separately in the DEIR, receptor points were not located within the physical plant boundary. When the three power plants were combined for this analysis, some receptors, as located on the regularly spaced grid, fell within plant boundaries. For the purpose of this conservative analysis, no attempt was made to exclude these in-plant receptors. This technique allowed for examination of combined impacts from two different plant operators (e.g., PG&E and ENRON) on each other’s property.

The results of the modeling analysis are presented in Table B6-1. The concentrations shown on the table represent the maximum concentrations for PM-10 and NO_X for short-term and long-term periods for all power plants combined and for each power plant’s stand-alone point of maximum concentration. For both the PM-10 and NO_X analyses, the maximum impact point are identical and occur at a point approximately 450 meters southeast of Pittsburg Power Plant’s Unit 1. This same point is also the point of maximum concentration for PM-10 and NO_X for the Pittsburg Power Plant alone. For the PDEF, the points of maximum concentration are located as follows: for PM-10 short-term, the maximum concentration is located approximately 800 meters east-southeast of the PDEF, the short-term NO_X maximum occurs at approximately 3.5 kilometers southwest of the PDEF, and the annual PM-10 and NO_X maximums occur between 700 to 800 meters east of the PDEF. For the Contra Costa plant, the points of maximum concentration for PM-10 and NO_X, both short and long-term, all coincide on the Contra Costa Power Plant fenceline’s northeast corner.

To clearly depict each individual plant’s contribution to the combined impact, Table B6-2 presents the model-predicted concentrations for each individual plant at the combined point of maximum concentration. As may be seen, for both the 24-hour PM-10 and the 1-hour NO_X concentrations, all of the combined impact results from Pittsburg Power Plant emissions (24- and 1-hour values shown for PDEF and Contra Costa represent the maximum model-predicted concentration for the entire year of modeling data and do not occur at the same time the maximum combined impact occurs). For the annual PM-10 and NO_X impacts, Pittsburg contributes nearly all of the maximum combined values, while the PDEF and Contra Costa plants contribute only a few percent to the maximums on the table.

The results of this analysis show that for the future cumulative case in 2005, combined air quality impact results for PM-10 and NO_X are dominated by the Pittsburg Power Plant. While there is some interaction of air quality impacts between the Pittsburg plant and the PDEF, the Contra Costa Power Plant, located about six miles east of the PDEF, is far enough away from both the Pittsburg plant and the PDEF that contributions from the Contra Costa plant are insignificant within the other two plants’ impact areas. The combined impacts presented in Table B6-1, although occurring at a slightly different location than those presented on revised Tables 4.5-31 and 4.5-32 (see response to Comment B11), are quite similar in magnitude and still represent a less-than-significant impact.

As a consequence of the results from the future cumulative 2005 case discussed above, the corresponding health risk assessment was updated to include a more detailed evaluation of the combined health risk in 2005 from all three power plants. Table B6-3 identifies the combined health risks for the PG&E power plants and the proposed PDEF plant at the cumulative maximum receptor under the 2005 Cumulative A-Max scenario. The table shows that the maximum cancer risk is estimated to be 0.62 in a million, which is less than the significance threshold of 10 in a million. Note that the major contribution to the maximum receptor is from the PDEF and that the relative contributions to health risks of the three plants are different than the local air quality impacts shown on Tables B6-1 and B6-2. Although this analysis is limited in scope, from data supplied by the CEC, it appears that while emissions of criteria pollutants from the PDEF are less than either the Pittsburg or the Contra Costa plants, emissions from the PDEF’s cooling towers are greater contributors to health risks than at the other two plants. The table also shows that the maximum chronic and acute hazardous indices from the combined plants are below the significance threshold of 1.0. Therefore, cumulative health risks would be less than significant.

Reference:

Layton, Matt, California Energy Commission, telephone communications, October 1998.

B7 The sentence referenced in the comment is an extremely condensed summary of the lengthy agreement between Thermal Power Company and PG&E for the provision of steam by the former to the latter. "Quantities of contaminants" generally refers to impurities in the geothermal steam. Such impurities can include liquid water, particulates, settleable solids, and noncondensable gases. Examples can include hydrogen sulfide, chlorides, boron, and amorphous silica. Thermal Power Company has an obligation, set forth in the agreement, to provide PG&E with steam that meets certain steam quality standards, including limitations on the contaminants described above. It should also be noted that contaminant levels are limited by various government regulations.

B8 Please see response to Comment B5.

B9 Page 2-6 of the DEIR is hereby amended (first paragraph under Geysers Power Plant heading, second sentence) by the addition of the following footnote to the end of the sentence:

The CEC certified Units 16, 17, 18, and 20 for construction and operation. Under Section 1769 of its Power Plant Site Certification Regulations, the CEC must approve any change in ownership of these units. Any new owner will be expected to comply with all existing conditions of certification, including decommissioning. Any new owner of these units must petition the CEC for authority to transfer ownership or operational control of each unit. The petition must contain: a discussion of any significant changes in the operational relationship between the owner and operator; a statement identifying the party responsible for compliance with the CEC’s conditions of certification; and, a statement that the new owner understands the conditions of certification and agrees to comply with those conditions.

Any owner would also face the prospect of even more extensive operational limitations associated with protection of the endangered fish species. The retirement incentive discussed above would be augmented by the expected imminent extension of the operational limits to cover an additional three months of each year during which Pittsburg Unit 7 must be dispatched fully before any of the other units at the Pittsburg or Contra Costa plants can be dispatched above their minimum operating levels. Such operating constraints would further increase the cost of retaining the 160 MW units.

Even if a new buyer were to retain these units (which appears unlikely), such a decision would necessitate extensive pollution equipment retrofit, substantially reducing any potential incremental emissions resulting from retention of one or both of Units 3 and 4.

Table 4.5-32 is hereby amended as shown in this response.

Table 4.5-31 of the DEIR is hereby amended as shown in this response.

The commenter expresses concern that the existing emissions of the Pittsburg plant may have been double counted in the analysis. The methods used to estimate total concentrations, including background levels, are consistent with conservative approaches that are commonly used for air quality analyses, even though a portion of the measured background levels may include existing plant emissions. This approach is followed because there is considerable uncertainty in how much of the background is actually contributed by the existing plant. When the maximum background levels exceeded the ambient air standard, more restrictive thresholds, described in significance criteria 2 on page 4.5-50 of the DEIR, were used to test for significance from project impacts.

As to the adequacy of the background data, the text on page 4.5-32 gives an explanation of the rationale for using measured data at Bethel Island as being representative of levels in the Delta. The text states that measured pollutant levels at this station reflect local pollutant sources as well as sources to the west and south, because the prevailing winds transport pollutants to the Delta region. Since this is the only station with adequate data for the region, and because pollutants such as PM-10 and ozone have usually been shown to be regional in nature, the measured levels at Bethel Island were considered to be representative.

Finally, the commenter requests that the EIR address overlapping impacts from both the Contra Costa and Pittsburg plants. An additional 2005 cumulative dispersion modeling study was carried out that includes emissions from the Contra Costa and Pittsburg plants, as well as the proposed Enron plant has been conducted. The results of this cumulative modeling analysis are discussed in response to Comment B6.

B12 Contributions of the Hunters Point plant are included in the existing maximum background levels that were added to the Potrero plant’s contribution in the analysis. The monitoring station on Arkansas Street is near both plants and is representative of ambient air levels for the region. Because the same maximum background levels are used in future years, when the Hunters Point plant will actually be shut down, the background levels that are used in the impacts analysis may be conservatively high.

B13 Page 4.8-1 of the DEIR (paragraph 2) is hereby revised to reflect the most recent energy consumption figures, as follows:

B14 While the analysis presented in Attachment C of the DEIR illustrates that contractual requirements, market forces, operating constraints, portfolio size, company financial characteristics, and other factors would affect the rate at which divested power plants are operated by new owners, a strong economic disincentive for inefficient use of nonrenewable energy resources would always be present, due to the simple fact that the more such resources are consumed by a plant owner, the more that owner would pay, thus reducing potential profits. Similarly, it is likely that more efficient plants would be better able to provide power at a lower price than less efficient plants and thus would not be displaced by less efficient plants.

The question of whether increased fossil-fueled generation resulting from divestiture would displace cleaner/renewable power is an important one however. It is noted that the Analytical Maximum scenario in the DEIR, which forecasts increased generation at the fossil-fueled plants, is an extremely conservative scenario and that actual increases in generation resulting from divestiture would likely be less. It is also noted that power plants designated as qualifying facilities under the Public Utilities Regulatory Powers Act (PURPA) having met fuel-type, efficiency, and other standards) were able to enter must-take contracts with local utilities, and thus would not be displaced by increased fossil-fueled generation. Finally, as noted on page 3-7 of the DEIR, physical and operational differences between restructuring with the proposed divestiture and without divestiture will, as a practical matter, be temporary. This is true because the utilities’ fossil plants must be market-valued (sometime before 2002), and as of March 31, 2002, PG&E could participate in the direct access market.

B15 The information provided by the commenter was unavailable at the time the DEIR was published. The information provided in Section 5.2.2 of the DEIR was obtained from CEC staff and was gathered after the Notice of Preparation was circulated. However, in order to incorporate the updated information provided by the commenter and obtained from Robert Haussler of the CEC during a telephone conversation on November 3, 1998, the following text changes have been made to the DEIR.

The second sentence of the last bullet on page 5-5 of the DEIR has been modified as follows:

The last sentence of the last bullet on page 5-5 of the DEIR has been replaced with the following text:

The last sentence of the second to last bullet on page 5-6 of the DEIR has been modified as follows:

The last sentence of the last bulleted item on page 5-6 of the DEIR is hereby amended as follows:

The following bulleted items are added at the end of the list of potential power plant siting cases in California on page 5-6 of the DEIR.

The first sentence of the last paragraph on page 5-6 of the DEIR has been revised as follows:

Though not specifically identified in the DEIR originally, the expected operational impacts of the Sunrise Cogeneration and Power Project, the Long Beach District Energy Facility, the Elk Hills Power Project, the Three Mountain Power Project and the Blythe Energy Project are considered in the overall discussion of cumulative impacts in Chapter 5 of the DEIR. Please see the response to Comment F57 for a detailed discussion of why these power plants, even if information was available prior to publication of the DEIR, would have been excluded from the detailed cumulative modeling and analysis. Similar to the other potential power plants identified in Section 5.2.2 of the DEIR, but not carried forward into the detailed cumulative analysis, these plants are geographically located at a considerable distance from the power plants being divested by PG&E and would not result in localized cumulative impacts. In summary, the inclusion of these power plants would not affect the conclusions in the DEIR regarding the level of significance of cumulative impacts.

Based on the proximity of the above-described DECP to both the existing Pittsburg and Contra Costa Power Plants and the proposed Pittsburg District Energy Facility (PDEF) (described on page 5-5 of the DEIR), a discussion of the potential for localized cumulative impacts to occur is germane. To the extent that information is available, the analysis below focuses on the potential for the addition of the DECP in the Bay-Delta region to affect the conclusions of the analysis completed for the cumulative Variant 2 scenario in Section 5.3.4 (pages 5-39 to 5-42), which considers the effects of the PDEF in conjunction with divestiture and other cumulative projects. When further defined, the DECP would be subject to separate environmental review and permitting by the CEC and other agencies with jurisdiction over the plant’s operations.

The addition of the DECP to the Variant 2 scenario would be expected to further drive down the annual plant capacity factors at each of the plants being divested, when compared to the 2005 Cumulative Analytical Maximum scenario considered in Section 5.3.2. Similarly, it is expected that operation of the DECP would decrease the annual plant capacity factor of the PDEF from what is shown in Table 5.2 on page 5-17 of the DEIR. Based on this reduction in generation, any impacts that could occur in the immediate vicinity of the plants being divested would be lessened further by the operation of the DECP. However, like in the case of the PDEF, construction and operation of the proposed DECP would have its own localized impacts and could result in some regional impacts in combination with the plants being divested.

Generally speaking, the localized impacts identified in Section 5.3.4 would be incrementally greater with the addition of the DECP to the Bay-Delta region. The inclusion of the DECP would not, however, alter the conclusions in the DEIR.

Operation of the DECP would increase the potential to adversely affect water resources in the Bay-Delta by incrementally increasing the potential for discharge impacts to marine water quality to occur beyond that identified for the cumulative Variant 2 scenario (see the response to Comment O3). This would still be considered a potentially significant cumulative impact on water resources, regardless of whether or not cooling towers were used at the DECP. Because the DECP would be subject to the same National Pollution Discharge Elimination System (NPDES) permitting process as was described for the PDEF, it is expected that any significant cumulative impact on water resources could be mitigated to a less than significant level.

The NPDES permit for the DECP would also be designed to protect the aquatic resources of the Bay-Delta. The addition of the DECP would also incrementally increase the total amount of water intake structures in the area, thereby increasing the potential for entrainment and impingement of sensitive aquatic resources during cooling water intake beyond that identified for the cumulative Variant 2 scenario. Because the four Delta plants (the DECP, the PDEF, and the Contra Costa and Pittsburg Power Plants) would likely be owned by three separate entities (Pittsburg District Energy, LLC, the joint venture of Calpine Corporation and Bechtel Enterprises, and the new owner of the Contra Costa and Pittsburg Power Plants) rather than only two separate entities, the coordination of power plant operations would be even more difficult and unlikely. Similar to the conclusions of the Variant 2 analysis, this would be cumulative impact on biological resources unless mitigated by similar measures as those recommended for the PDEF in the DEIR.

With respect to air quality, the addition of the DECP to the cumulative Variant 2 scenario could incrementally increase the potential for adverse air quality effects in the San Francisco Bay area to occur at both a local and regional level. Like the PDEF, the proposed plant would likely result in a minimal increase in employment levels (less than 100 persons). The commensurate increase in traffic and associated criteria air pollutant emissions would also be minimal and in combination with the PDEF and other projects, would not result in any cumulatively considerable emissions of criteria air pollutants. The main issue of concern would still relate to the stationary source emissions associated with the power generation process at the new plant.

The DEIR concludes that at a regional level, emissions of each criteria pollutant, except PM-10, would decrease under the Variant 2 scenario, when compared to the 2005 Cumulative Analytical Maximum. Subsequent analysis (see the responses to Comments O4 and U14) shows that PM-10 emissions would increase in 2005 by an estimated 9 tons per year regionally with the new PDEF, rather than the 20 tons per year cited in the DEIR. It is further concluded that there would be a net decrease in Bay Area power plant emissions of PM-10 and PM-10 precursors under Variant 2 in 2005 compared to 1999 baseline conditions. Therefore, Bay Area power plant emissions would not contribute to the cumulative effect of increased emissions from new development in the Bay Area on regional PM-10 concentrations.

Similar to the PDEF in Variant 2, operation of the new DECP could adversely affect air quality at the local level. Emissions of criteria air pollutants and toxic air contaminants that could potentially increase overall health risks would be incrementally higher than under Variant 2 alone. This would still be a potentially significant cumulative effect on local air quality. However, the DECP, like the PDEF, would be subject to separate project-specific environmental review and permitting by the CEC and other agencies with jurisdiction over the plants operation (including the BAAQMD), at which time the potential for these impacts to occur would be fully evaluated. Therefore, it is assumed that any significant impact on local concentrations of criteria air pollutants and toxic air contaminants associated with the new DECP would be mitigated to a less than significant level. It has also been assumed that the combined emissions from the Pittsburg and Contra Costa Power Plants and the new PDEF would be minimal relative to ambient concentrations associated with mobile sources. It is likely that the addition of the new DECP would not change this assumption. In light of the low health risks associated with the operation of the Pittsburg and Contra Costa Power Plants and the permitting process that would apply to both the new PDEF and the DECP, any localized significant cumulative air quality impacts could be mitigated to a less than significant level.

The inclusion of the DECP to the Variant 2 scenario would not affect the conclusions on
pages 5-41 and 5-42 regarding consistency with the ’97 Clean Air Plan.

B16 As described on page 5-16 of the DEIR, the cumulative impact discussion in Section 5.3.2 (pages 5-20 to 5-38) addresses the potential cumulative effects of PG&E’s proposed divestiture in combination with reasonably foreseeable projects identified in Section 5.2 (including a new 480 MW power plant in San Francisco, other potential future power plant projects, transmission line projects, and wastewater injection projects). (See the response to Comment F57 for a discussion of why certain cumulative projects were not carried forward into the detailed cumulative modeling and analysis.) The analysis in Section 5.3.2 also takes into account the local cumulative projects identified in Table 5.1 of the DEIR. The Variant 1 (pages 5-38 to 5-39) and Variant 2 (pages 5-39 to 5-42) analyses are based on the impact discussion in Section 5.3.2 and focus on how the potential for cumulative effects to occur may vary if a combination of new generation and transmission to replace the Hunters Point Power Plant (Variant 1) or the new PDEF (Variant 2) were added to the mix of cumulative projects being considered.

Please see response to Comment B15 above for a discussion of impacts associated with the DECP in combination with Variant 2. See response to comment B6 for air dispersion cumulative impacts for the Pittsburg, Contra Costa, and PDEF plants.

B17 The commenter is correct that the nominal rating of the PDEF is 500 MW. However, it is the understanding of the DEIR preparers that the "net" capacity of the PDEF is 450 MW. Net capacity is the amount of power a generating unit can put into the electric grid. A plant’s net generating capacity is equal to the rated generating capacity of the generators in the plant minus the amount of power needed for the various electric components of the plant, such as pumps and heaters. In the case of the PDEF, this difference is 50 MW. Net capacities were used in this DEIR because it is the net capacity that is simulated and analyzed in the electric dispatch modeling (see Attachments C and G of the DEIR). Thus, no change is needed in Table 5.2 or other similar references throughout the DEIR.

B18 The CEC’s final staff report cited in the comment was not available at the time of publication of the DEIR. According to the principal author and project manager of the report, the final document essentially constituted a management approval of the draft report cited in the DEIR, and nothing substantial was changed.(4) 1998 Baseline Energy Outlook contains energy consumption projections for 1995 to 2007. In the draft document, historical data was used through 1996, while in the final document, historical data was included for 1997 as well. With the exception of San Diego County, the actual data was very similar to the 1997 projections contained in the draft Outlook document. San Diego County consumption in 1997 was higher than anticipated due to hotter-than-normal weather and higher industrial consumption resulting from the unusually robust economy. However, there was insufficient time to run the forecast models again with the modified 1997 data. Consequently, the consumption forecasts presented in the July draft document and utilized in the DEIR analysis remained unchanged in the final document published in August.