H. Lake County Air Quality Management District

H1 Section 4.5 of the DEIR addresses air quality impacts of the Geysers Power Plant. The DEIR indicates on page 4.5-19 that Lake County is the only county in the state designated "attainment" for all state and federal air quality standards and state visibility standards. In response to the comment, the following sentence is added to the DEIR as the last sentence of the second paragraph on page 4.5-45:

Adverse air quality impacts in Lake County are recognized to be largely a result of the operations of the Geysers plant, and when the plants are not operating, the associated steam fields in Sonoma and Lake County.

H2 The CPUC is aware of the differences in age and technology among the Geysers units, and that the Sonoma County units are generally older and less technologically advanced than the Lake County units, though a few Sonoma County units are as advanced as the Lake County units. Those differences were fully accounted for in the DEIR analysis.

H3 It is true that air pollutant emissions at the Geysers come from a variety of sources, not just the controlled releases of unabated steam during steam stacking events. All possible emissions sources were considered in the DEIR analysis. Some of the data and conclusions of the DEIR were drawn from the results of the Geysers Air Monitoring Program (GAMP), which detects and measures actual emissions, regardless of the source or the factors that cause increases in emissions. The GAMP was in operation during the types of events the commenter refers to, so emissions from all sources during those events were detected and measured. It is this data that was used to reach the conclusions noted in the Impacts sections of Section 4.5 of the DEIR. Regardless, as detailed in the response to Comment H15, generation at the Geysers is likely to increase rather than decrease in the future, and any potential impact caused by generation curtailment at the Geysers will be the result of restructuring, and not divestiture.

H4 While the "must-run" contracts (Reliability Must Run Agreements, or RMRAs) will require that certain Geysers units will run during certain times, these do not provide a guarantee against curtailments because of low market prices caused by hydropower spill conditions or other economic factors. In fact, under the current contracts between PG&E and its steam suppliers, such economic curtailment is allowed.

In 1997, PG&E curtailed 19.8 percent of available steam deliveries from U-N-T, and 2.8 percent from Calpine, largely because of economic considerations. That the Geysers units run at relatively high availability factors (usually in excess of 60 percent since 1994, when such curtailment was first allowed) is a testament to the low costs for producing such power. The Calpine contract is particularly advantageous to PG&E, and this is reflected in the higher economic output levels from Units 13 and 16.

The new owners would likely have the same or similar contracts that place the Geysers units at an economic advantage compared to natural gas-fired units, which typically establish the market-clearing price in 70 percent to 90 percent of the hours. Also, as detailed in the response to Comment H15, the new owner will apparently have access to programs that offer financial incentives or give some preference for generation from renewable resources, and be eligible for tax incentives that PG&E is not eligible for, which should act to increase generation at the Geysers. In any event, potential impacts caused by economic curtailments are the result of restructuring, and would occur even if PG&E would continue to own the Geysers generating units.

H5 Please see response to Comment H4. The steam prices at the Geysers under both the U-N-T and Calpine steam supply contracts typically translate to bulk power prices that are below the market-clearing prices during most hours of the year. In other words, economic incentives already exist to encourage continued substantial generation at the Geysers. Under the restructured market, Geysers generation is rejected only when its bid price is above the market-clearing price. While this price likely will fall during hydro spill conditions, perhaps even to zero, there is no direct link between hydro conditions and Geysers generation.

PG&E is now in a dispute with U-N-T as to what is the minimum generation requirement for those units (see page C-8). If the Geysers units were not divested, this dispute would continue. Thus, the controversy over sustaining a minimum generation level to avoid significant steam venting at the Geysers is a result of restructuring and a contract dispute among the existing stakeholders, and not a result of divestiture. However, because the new owner is expected to maintain substantial operations at the Geysers generating units, as noted in the response to Comments H13 and H14 below, no increase in steam venting is expected at the Geysers after the sale to a new owner.

H6 Please see response to Comment H15 for a discussion of the incentives and programs available to new owners of the Geysers units and of the use of AB 1890 funds to stabilize the price of renewable energy.

The low market prices during off-peak hours in April through May of 1998 most likely reflected unusually abundant hydropower caused by the El Niño weather conditions of 1997-98. During that time, the abundance of hydropower, coupled with the low demand during the mild spring weather, resulted in a very low market clearing price at the Power Exchange (PX) compared to the rest of the year. This is a result of simple "supply and demand" economics. However, 1997-98 was a particularly wet season in California, and such an abundance of hydropower is not likely to occur often. Therefore, because of the transmission constraints and the economic incentives detailed in the response to Comment H15, the price of power from the Geysers units is likely to be at or under the market clearing price at the PX during the vast majority of the hours of the year, thus ensuring the Geysers will continue to generate substantial amounts of energy.

The commenter’s final question in this comment reads: "How significant is the loss of resources of PG&E whom still has a virtual monopoly on customers and extensive hydropower?" Under restructuring, either PG&E or a new owner of the Geysers generating units must recover their investment solely through revenues from direct sales from the units, whether to the PX or through the Direct Access market. PG&E can no longer cross-subsidize operations at the Geysers with revenues from hydropower generation or transmission and distribution operations. Therefore, either PG&E or a new owner of the units would face the same challenge of managing the units such that their operations remain economically viable on a stand-alone basis.

H7 Please see response to Comment H5. The scenario described by the commenter could occur whether or not PG&E continues to own the Geysers generating units, so the project examined in this EIR – the sale of four PG&E power plants – would have no effect on the likelihood of such a scenario occurring. The potential for all scenarios that would result in steam stacking already exists today under restructuring and would not be affected or exacerbated by divestiture. The environmentally superior alternative set forth in the DEIR (page 6-28) to sell the plants to the respective steam suppliers directly addresses this issue. The following numerical responses correspond to the commenter’s suggested mitigation measures and is provided for informational purposes only since none of these proposed measures relate to environmental impacts associated with the project analyzed in this EIR.

H8 The commenter is referring to Impact 4.5-1 on page S-30 of the DEIR. Impact 4.5-1 is further discussed on pages 4.5-51 to 4.5-61. As described in the "Conclusions" paragraph on page 4.5-61 of the DEIR, the emissions increases are from "direct" sources which are covered by air permits. Since the emissions increases that are discussed by the commenter would occur under air permits and would be consistent with all emissions limitations and standards, they are not considered to be significant. These emissions would only be significant if they were expected to result in any significant increase in local concentrations of criteria air pollutants (see Impact 4.5-2), a significant increase in health risks in the vicinities of the plants (see Impact 4.5-3), or significant increases relative to emissions projections used in regional air quality plants (see Impact 4.5-5). None of these other impacts were found to be significant at the Geysers plant.

The reference to single or several individual events is referring to steam venting episodes that could release large quantities of unabated steam. As indicated in response to Comment H5, divestiture is not expected to increase steam venting at the Geysers plant.

With the transfer of existing permits to a new owner, plants would continue to operate under reissued air permits that would be consistent with all emissions limitations and standards. These emissions limitations and standards are assumed to be sensitive to the preservation of air quality.

H9 Regarding increased emissions, please see response to Comment H8. As the commenter notes, a 40 percent increase in emissions is not likely unless the abatement systems were changed. The analysis presented in the DEIR (page 4.5-75) indicates that the project would not have a significant impact on either local health risks or nuisance odors, and therefore mitigation is not needed. A change of abatement systems is not part of the proposed project, and is not anticipated. With respect to mercury scrubbers, please see response to Comment H11.

H10 Regarding the resources of the new owner(s), PG&E requires that successful bidder(s) for the Geysers units have sufficient financial resources and technical expertise to properly operate and maintain the plant, and the CPUC is also responsible for ensuring that the new owners are financially responsible and viable entities to operate the plant.

The commenter is correct that participation specifically in the GAMP program is voluntary. However, as the DEIR states (page 4.5-45), air permits from both the Lake County Air Quality Management District and the Northern Sonoma County Air Pollution Control District require participation in an air monitoring program comparable to GAMP. According to the Northern Sonoma County Air Pollution Control Officer (Erdman, 1998, as cited in DEIR page 4.5-83), the mechanics of assigning PG&E’s participation in GAMP to a new owner, or owners in the event different units are sold to different parties, have been worked out. PG&E recently contractually committed itself to participating in GAMP for at least the next 4 years. Even though any new owner would have to participate in an air monitoring program and the DEIR indicates that emissions from the Geysers units would not result in significant environmental impacts, in light of the commenter’s preference, the DEIR on page 4.5-61 is amended to add the following mitigation measure:

H11 Regarding air quality monitoring, please see the response to Comment H10. With respect to seismic monitoring, PG&E does not do any seismic monitoring, nor does it participate in the seismic monitoring done by others. As described on page 4.3-13 of the DEIR, the Southeast Geysers Monitoring Advisory Committee was created by the Lake County Board of Supervisors. The continued existence of the committee would not be affected by the project, and neither the new owner nor the CPUC has authority over the composition of the committee.

With respect to the use of the chelate catalyst, it is noted that the economic costs of using the chelate would be similar for both PG&E and the new owner(s). Although a small portion of the chelate PG&E has used comes from boiler cleaning solution at its fossil plants, most of the chelate is purchased from non-PG&E power plants. Catalysts are used to make the processes in which they are used more efficient. Because the use of the chelate improves the efficiency of the abatement systems at the Geysers and the new owner’s economic constraints and incentives to use it would be similar to PG&E’s, it is assumed that the new owner(s) would continue to use it, unless a better system is developed.

Regarding the use of mercury scrubbers, as noted on page 4.9-13 of the DEIR, PG&E recently installed activated-carbon scrubbers to remove and collect the trace amounts of mercury. The scrubbing system minimizes mercury contamination in the sulfur waste, lowering overall operational costs by reducing the overall amount of hazardous waste generated. Since the mercury scrubbers are in place, and reduce overall operational costs, it is assumed, as stated in the DEIR, that the new operators would continue to use the equipment.

H12 Regarding continued participation in GAMP, please see response to Comment H10. With respect to the suggested mitigation measure that the seismic monitoring program continue, as noted in response to Comment H11, PG&E does not participate in a seismic monitoring program and does not have authority over the composition of Lake County’s Southeast Geysers Monitoring Advisory Committee.

H13 The CPUC strongly supports the continued viability of the Geysers as a geothermal generating resource, which includes continued coordination of operations between the steam field owners and the generating unit owners. The CPUC will not approve any transfer of a Geysers generating unit to an entity that is not qualified to operate those units in a responsible manner. The response to Comment H14 below addresses the issue of "green power" policy.

With regards to maintenance policies, the commenter may have misread Attachment C to the DEIR. The new owners would have a greater incentive to maintain the Geysers plants than would PG&E (see page C-29 of the DEIR). The new owners will have the benefit of PG&E labor and insight for at least two years after divestiture, and they are free to continue to employ valuable PG&E employees.

Also, it appears that the market will provide a very strong incentive to the new owners of the generating units to ensure the long-term viability of the units and the steam fields that supply them. One cannot sell power, or recover investment, from a plant that does not generate.

H14 The purpose of an EIR is to provide decision-makers and the public with information concerning the environmental impacts of a proposed governmental action. The project will not alter any policies concerning green power. Thus, this EIR is not the appropriate avenue for examining policy concerning green power production in the state. Please see the response to Comment H15 for further discussion of policy issues.

H15 The discussion of market forces and available subsidies and other incentives for the Geysers plant is largely mooted by the fact that the electric transmission system in Northern California is significantly constrained during much of the year, meaning that bringing in power from outside the region to serve local loads is often difficult, if not impossible. Because of this fact, the ISO has designated the Geysers plant as a "must-run" facility, meaning that PG&E (and any future owner) receives payments from the ISO over and above any revenues received from selling the power from the facility, merely for remaining available to serve local loads. (This contractual arrangement assures that an owner of a must-run facility would not charge exorbitant prices during times when that facility is the only resource available to serve certain loads.) Barring construction of a new major power plant near the Geysers, or a significant upgrade of the transmission system (which would most likely include obtaining new rights-of-way because existing rights-of-way are already at maximum capacity), this situation is likely to continue indefinitely. And because of the lead time needed to construct a new power plant or to upgrade the transmission system, the situation will likely continue for several years. Therefore, an evaluation of subsidies, tax benefits and other incentives for renewable power in this EIR is not needed and would not enhance the analysis. However, for discussion purposes, a brief examination of market and policy issues related to renewable energy resources is provided below.

The California Legislature and the CPUC have enacted the restructuring of the electric utility industry in the state following the tenet that consumer choice is a very powerful tool in guiding the electric power market in the years to come. By expressing their desire to use renewable energy to power their homes and businesses, even if they must pay a premium above the cost of power from conventional resources, California consumers can in effect make decisions on the makeup of the future generating portfolio available in the state. This process is apparently already occurring, as some consumers have switched to service providers who guarantee that all or a significant portion of the power they market comes from renewable sources. Since restructuring was initiated in March 1998, at least 69,000 residential customers in the state have switched their service provider from their local utility to independent suppliers. According to the Center for Energy Efficiency and Renewables Technology, the majority of those customers switched to green power providers. Several businesses have also publicized their switch to renewable energy service providers as a means of attracting customers (article, "Green power luring consumers," by Associated Press reporter Martha Bellisle, in the September 28, 1998 issue of the San Francisco Examiner).

While only time will tell if a large, robust market for renewable energy resources will develop in California, early indications show that the market is promising, and could become much larger than it was before restructuring, largely because of the innovation and creativity in marketing brought about by restructuring. For example, Green Mountain Energy Resources, LLC, an energy service provider registered with the CPUC, has promised to construct a new wind turbine for every 4,000 new customers that sign up under one of its Green Power programs. The company to date has committed to installing two new turbines in the Palm Springs area because of the marketing commitment. It recently stated the two turbines represent "the first new renewable generation ever built in the U.S. because of electric deregulation" ("‘Green energy’ sales build new turbines," by George Raine, San Francisco Examiner, October 15, 1998). Use of this type of marketing technique is a direct result of the CPUC’s restructuring effort, and shows that by bringing market forces to bear in the electric generation marketplace, companies will craft innovative and creative marketing techniques to become long-term players in the market. This is exactly what is envisioned in the sale of the Geysers geothermal plant. The CPUC believes that market forces will pressure the new owner(s) of the Geysers generating units to become similarly creative and innovative in marketing their non-polluting power to California consumers.

In addition to market forces, efforts by various agencies and non-profits are also acting to promote use of renewable resources in the state. For example, to help consumers in deciding whether and who to choose as a renewable energy service provider, AB 1890 (the California Legislature bill mandating restructuring) requires the CEC to implement a process for certifying renewable energy providers. In response, the CEC has established a program for certifying the renewable energy products offered by registered energy service providers in the state. The electric service industry, through the efforts of various associations and individuals, has also established a program, called the "Green-e Renewable Branding Program," for certifying renewable energy service products. Green-e certification is administered by the Center for Resources Solutions, a non-governmental non-profit organization. To receive the Green-e certificate or to qualify as a renewable energy service provider with the CEC, at least 50 percent of the energy offered through the product must come from qualifying renewable energy resources. Those include solar, wind, biomass, waste tire, municipal solid waste, small hydroelectric, digester and landfill gas, and all geothermal sources. As well, Senate Bill 1305 requires all energy suppliers to periodically disclose the sources of the energy resources they market, using a standard label created by the CEC. The CEC believes these labeling programs will become a powerful marketing tool for energy service providers.

The CEC itself is strongly promoting renewable energy to the state’s consumers. In its educational material available on the Internet, the CEC points out that although consumers may have to pay a premium for renewable energy, that premium is just a small portion of the consumer’s overall bill. The material also points out that the price of power from conventional sources does not include the cost to repair the environmental damage caused by the generation of that power, nor is the environmental benefit of renewable energy resources included in the pricing of the power they generate.

In relation to the various incentives available to renewable energy generators, many sections of the Energy Policy Act of 1992 (EPAct) address subsidies and tax incentives provided to renewable power producers. Section 1212 (e) specifies that qualified renewable energy facilities are eligible for a direct 1.5 cent/kWh energy production subsidy from the federal government for a period of 10 years. This credit will rise over time to account for inflation. However, the Geysers project does not appear to qualify for this direct subsidy under the EPAct. The subsidy applies only to projects owned by government and non-profit corporations or to private wind and closed-loop biomass projects, and any representation by a CPUC representative to the contrary was incorrect. If the Geysers plant was purchased by a government agency or government-owned corporation or non-profit organization, however, energy sales from the facility would apparently be eligible for the 1.5 cent/kWh subsidy under the Act.

The Geysers plant, like all renewable energy projects except hydroelectric facilities, is eligible for tax and other benefits under the EPAct and state law. The benefits vary depending on the nature of the new owner of the facilities. The EPAct (Public Law 102-486-Oct. 24, 1992) contains several provisions that encourage investment in renewable energy technologies by private and public entities. Under the act businesses can take a 10 percent business investment tax credit for purchases of solar and geothermal energy property under Sec. 1916, Permanent Extension of Energy Investment Credit for Solar and Geothermal Property.

Other applicable EPAct provisions include: Section 2111, Renewable Energy, and Section 1202, Demonstration and Commercial Application Projects for Renewable Energy and Energy Efficiency Technologies, which both offer funds, financial assistance and cost-sharing benefits to renewable energy generators for a variety of research and demonstration projects, including the demonstration of reliable generation from existing resources; Section 29, which grants a tax credit for producing fuel, including electricity, from a non-conventional source; Section 3001, Research, Development, Demonstration, and Commercial Application Activities; and Section 3002, Cost Sharing, which obliges the federal government to pay up to 50 percent of certain renewable energy research or demonstration projects.

In addition to the provisions of the EPAct, Section 168 of the Internal Revenue Code contains a Modified Accelerated Cost Recovery System (MACRS) by which businesses can recover investments in solar, wind, and geothermal property through depreciation deductions. The MACRS establishes a set of class lives for most property, ranging from 3 to 31.5 years, over which the property may be depreciated. The types of property covered by MACRS include equipment used to produce, distribute or use energy derived from a geothermal deposit, up to the electrical transmission stage.

Other potentially applicable federal laws giving preference, tax or other benefits to renewable energy generators include the Public Utilities Regulatory Policy Act (PURPA) of 1978, the Renewable Energy and Energy Efficiency Technology Competitiveness Act of 1989, the Energy Policy and Conservation Act, the Powerplant and Industrial Fuel Use Act of 1978, and the Stevenson-Wydler Technology Innovation Act of 1980.

At the state level, renewable energy policy has somewhat shifted away from using set-asides and other government mandates to ensure renewable resources were developed to help meet California’s electricity needs. Instead, in the new competitive electricity market, consumers will decide whether further development of renewable resources will continue. However, many state programs offering incentives for renewable energy generators still exist. Primary among those is a program run by the CEC under which consumers of renewable energy can receive a credit of up to 1.5 cents/kWh. Some electric service providers may reflect the value of this credit in their pricing scheme, while others may use the credit to give customers a monthly bonus.

To qualify for the program, the electric service provider must: register with the CEC as a renewable electricity product provider (having a Green-e certificate does not necessarily make a provider eligible for the credit because that program has slightly different criteria for determining eligibility); serve customers previously served by either PG&E, Southern California Edison or San Diego Gas & Electric; and, obtain the renewable energy from non-utility generators within the state. Power sold by the new owner of the Geysers to customers of PG&E, Edison and SDG&E would qualify for this credit. The credit is funded through a $0.0002/kWh surcharge an all electricity sold in the state (typically, about $8 million per year), which can and will be used for other programs that promote development of renewable resources.

Conversely, if PG&E would continue to own the Geysers, purchasers of power from the Geysers would not be eligible for this credit. Thus, through the divestiture project, the Geysers should become more competitive under a new owner. And if the Geysers plant was purchased by a government-owned entity, it apparently would be eligible for a total of at least 3 cents/kWh in generation subsidies or credits.

Other California incentives programs potentially available to a new owner of the Geysers include: the Geothermal Resources Development Account (GRDA); the Energy Technologies Advancement Program; the Geothermal Grant & Loan Program; Opportunity Technology Commercialization Program; and the Energy Technology Export Program. Most of those programs offer grant and/or loans for geothermal research, resource development, commercialization, planning and impact mitigation. The GRDA, however, is specifically aimed at finding ways to make existing geothermal generators, including the Geysers, more competitive in the restructured electric industry.

By mandating these programs in state law, including the 1.5 cent/kWh credit and the certification process, the California Legislature made clear it wants the renewable energy industry in the state to continue to flourish. Some municipal utilities, especially the Sacramento Municipal Utilities District, are also offering their customers the choice of having all or a portion of their power come from renewable sources, and are crafting ways to provide incentives to make that choice.

In any event, however, PG&E has successfully generated very large amounts of electrical energy from the Geysers plant over the years without the benefit of many of the subsidies and tax benefits available to other renewable project owners. The new owner(s) of the Geysers units will likely receive the same or better subsidies or tax benefits as PG&E has had. Therefore, given the constraint of the transmission system, and PG&E’s successful track record to date, any analysis of how market forces or government-mandated incentives for renewable power production will affect the viability of the Geysers would not change the conclusions of this EIR.

H16 Please see responses to Comments H14 and H15 above.

H17 Please see responses to Comments H14, H15, and J8.

H18 The term "Analytical Maximum scenario" used on the pages cited by the commenter is more relevant to the potential change in operations at the fossil-fueled plants proposed for divestiture than to future Geysers operations. Because of the potential adverse air quality impacts and damage to the steam fields, the theoretical "worst case" for the Geysers units is reduced generation. The capacity factors for Geysers units listed in the tables cited by the commenter represent the minimum expected output level under new ownership with no mitigation measures or minimum generation requirements beyond those already in place. (Please see response to Comment H7 on the appropriateness of mitigation measures.) The Analytical Maximum scenarios are not meant to capture realistic operations, but rather are artificial constructs used to analyze the maximum potential environmental impacts associated with the change of ownership for all the divested plants. The reduced capacity factors listed for the Geysers generating units in fact do not reflect any changes in behavior by the new owners of the Geysers units compared to PG&E; rather it reflects how increased generation at the other divested fossil-fueled plants depresses generation at the Geysers. In other words, under the Analytical Maximum scenario, generation from the Geysers units would fall even if they were still owned by PG&E. Thus, the change in capacity factors for the Geysers units is not a result of analyzing the effects of the divestiture of the Geysers units, but rather is an effect related to the predicted change in operations of the fossil-fueled plants at Pittsburg, Contra Costa, and Potrero after divestiture. As the DEIR states on page 4.5-55, the Analytical Maximum scenario is "extremely unlikely" to reflect a true operating scenario. The Analytical Maximum scenarios were used to provide a "conservative" analysis, as noted in the comment.

H19 To reflect the commenter’s clarification, the last sentence of fourth paragraph on page 2-26 of the DEIR is revised as follows:

H20 To reflect the commenter’s clarification, the second sentence of the fourth paragraph on page 2-35 of the DEIR is revised as follows:

H21 This comment number was not used.

H22 This topic is addressed in "Existing Emissions," which begins on page 4.5-46, and Impact 4.5-3, which begins on page 4.5-71 of the DEIR.

Page 2-38 of the DEIR (third full paragraph) is hereby amended as follows:

Figures 2.18 and 2.19 are intended to show only the general processes involved in power generation in a steam turbine generating unit. Specific details relating to any one of the processes were not included. However, to clarify where chemicals are put into the system, Figure 2.18 on page 2-40 is hereby amended to show that chemicals (i.e., Stretford Solution) are added to the process block labeled "Hydrogen Sulfide (H2S) Abatement System." No chemicals are added during the incinerator process of an Incinerator Abatement System and, therefore, no changes have been made to Figure 2.19.

H23 Please see response to Comments H5, H7, and H18. Not all future events can be anticipated in any modeling exercise, and for this reason capacity factors for individual generating units will periodically fall outside the ranges shown in this analysis.

As to the commenter’s concerns regarding maintenance done on the Geysers units, the new owners will have a greater incentive than PG&E to maintain the generating units because they must remain operational in order to recover their investments in the units. For this reason, short-term, event-driven outages and resultant emission impacts are no more likely to occur with a new owner than when PG&E owned the units. Please also see response to Comment H13.

H24 Page 4.1-1 of the DEIR (last paragraph, first sentence) is hereby amended as follows:

The Geysers Power Plant includes a series of geysers generating units dispersed throughout the northeastern portion of Sonoma County...

The last sentence of the first paragraph on page 4.1-2 is amended as follows:

Lake County’s economy is primarily based on tourism; resource extraction; retirement, residential and related services; and agriculture.

H25 To reflect the commenter’s clarification (here and in Comment H19), the third paragraph on page 4.1-4 of the DEIR is hereby amended as follows:

Other uses include recreational (primarily hunting clubs, camps, and retreats) and mining (e.g., gold, mercury). limited aggregate mining associated with geothermal development. The small towns of Anderson Springs, Cobb Mountain, and Whispering Pines are located adjacent to the Geysers area to the east.

H26 Page 4.2-10 of the DEIR, the second paragraph under Geysers Power Plant subheading is hereby amended as follows:

H27 Page 4.3-6, paragraph 2 is hereby amended as follows:

Impact 4.9-3, second bulleted item on Page 4.9-20 (Asbestos), is hereby amended to add the following:

The bedrock in the Geysers area is formed of, among other rock types, serpentine, which contains asbestos. In order for asbestos particles that are contained in the serpentine rock to become a hazard, it would have to be entrained into the air and transported by the wind to off-site receptors. For this to occur the exposed rock would have to be crushed through construction activities and clearing and grading operations. The project will not require construction operations at the Geysers plant; therefore, there would be no exposure to asbestos particles as a result of divestiture.

H28 The text referred to by the commenter is concerned with the broad overview of the regional climate and meteorological setting of the project. The commenter requests that specific text be added to point out that various communities are downwind of the Sonoma County Geyser units and thus are potentially impacted by these units. The DEIR addresses this issue in Section 4.5.3 and, thus, no modification of the DEIR text is necessary.

H29 Although concentrations of hydrogen sulfide in the gas stream may reach unsafe levels, similar to those identified in the comment, these levels have not been observed in the ambient air at offsite receptors, mainly because the pollutants are diluted in the atmosphere while being transported to downwind receptors. In order to ensure that releases of hydrogen sulfide do not occur when the levels are high in the gas stream, workers routinely measure the hydrogen sulfide concentrations in the gas stream, and when the levels are higher than normal, extra checks are performed on the hydrogen sulfide control systems, such as the Stretford units, to make sure that they are properly operating. Also, the concentrations of the analytes in the sulfur removal solutions are checked to optimize the H₂S control system.

H30 The commenter is correct that footnote "d" refers to the new federal PM-2.5 standard. As presented, the table conveys that the modified federal PM-10 standard was also retained, and the table lists the current attainment status for PM-10 (i.e., for Lake County it is "unclassified"). Footnote "d" simply reminds the reader that the attainment status for the new PM-2.5 standard has yet to be developed. The federal PM-10 standard is presented (with the new PM-2.5 standard) in Table 4.5-1.

H31 Page 4.5-20 of the DEIR (first full paragraph) is hereby revised as follows:

LCAQMD regulates emissions from geothermal power plants through its permitting authority over stationary sources. LCAQMD Rule 411 Local regulations limits emissions of particulate matter for each operating unit to 40 pounds per hour., and hydrogen sulfide emissions are limited to 15 pounds per hour. LCAQMD has general regulations limiting sulfur emissions from various sources, set at various concentration and mass emission limits. New power plants are subject to New Source Review and Best Available Control Technology (BACT). BACT is project-specific and, for the existing Lake County units, has been defined as emissions of not more than 5 pounds per hour of hydrogen sulfide per million pounds of steam used. LCAQMD’s ability to issue Authorities To Construct and Permits To Operate further refines and restricts project emissions based on the New Source Review assessment of project emission impacts on the closest receptor.

H32 Page 4.5-45 of the DEIR (second paragraph, second sentence) is hereby amended to read:

The PM-10 monitoring stations provide data that can be analyzed by X-ray Florescence (XRF) for various compounds, including arsenic, mercury, sulfur, vanadium, and others. Ambient radon concentrations are also measured at the Glenbrook and Anderson Springs sites.

H33 GAMP PM-10 data for the Anderson Springs station and for the Glenbrook station were obtained from PG&E and are added to the revised Table 4.5-19 given below. The text in the second paragraph, fourth sentence on page 4.5-45 is amended as follows:

Table 4.5-19 also presents ozone data from Lakeport and PM-10 data from Lakeport, Anderson Springs, and Glenbrook.

H34 Page 4.5-46 of the DEIR (last paragraph and then continuing onto the next page) is hereby revised as follows:

H35 Please see response to Comment H34.

H36 Though stacking can occur with a mere slowdown in the rate of steam use at a generating unit, the commenter is correct that stacking events are more likely to occur after an immediate 100 percent rejection of steam flowing to a Geysers generating units, such as when a generating unit is tripped off-line. For further clarification, the second sentence of the first full paragraph of page 4.5-47 is hereby revised as follows:

H37 As detailed in the response to Comment H18, the analytical maximum scenarios examined in the DEIR conclude that generation at the Geysers may decrease somewhat in the future, but such a scenario is an artificial construct designed to capture the maximum potential environmental from divestiture of the Geysers units. Because of the factors discussed in the response to Comment H15, incidences of shutting in the steam wells are not expected to increase under divestiture because the new owner(s) of the Geysers generating units will have significant incentives to operate the Geysers units at relatively high capacity factors. Thus, there would be no impacts expected from divestiture, even if generation decreased as described in the analytical maximum scenario. Also, the magnitude of a H₂S gas release during such an operation would be considerably lower than releases that may occur from a stacking event and would result in lower concentrations at off-site receptors, even though such a release may create less turbulence than a stacking event.

H38 Please see response to Comment T7.

H39 The DEIR’s air quality analysis concerning emissions from the Geysers Power Plant fully accounts for the fact that wind patterns in the Geysers area generally result in all emissions from both the Sonoma County and Lake County Geysers generating units flowing into the Lake County air basin. As detailed in the response to Comment H3, the Geysers air quality analysis relies mainly on the results of the Geysers Air Monitoring Program (GAMP), which detects existing emissions, regardless of their origin or destination. However, for further clarification, Page 4.5-47 of the DEIR (last paragraph and then continuing onto the next page) is hereby revised as follows:

Table 4.5-21 shows criteria air pollutant emissions from the plant units located in Lake County for 1995, 1996, and 1997 and compares the 1997 estimates with county-wide emissions for Lake County in that year. Table 4.5-22 shows the 1995, 1996, and 1997 criteria pollutant emissions from the Sonoma County units and compares 1997 emissions the values with county-wide and basin-wide emissions for Sonoma County. As indicated in Table 4.5-22, the Geysers Power Plant accounted for relatively large portions of Sonoma County’s 1997 inventory of PM-10. Given that prevailing winds tend to transport emissions from the Sonoma County units to the Lake County Air Basin, a comparison of the aggregate emissions from all of the Geysers Power Plant units with Lake County emissions is also appropriate. Table 4.5-22a provides such a comparison and shows that Geysers Power Plant emissions constitute a substantial fraction of total Lake County emissions of total organic gases and PM-10.

H40 The risk assessments that are in the DEIR reflect the latest reference dose information officially released by the Office of Environmental Health and Hazards Assessment (OEHHA). These reference doses are revised when new data are reported by the scientific community. For plants that emit pollutants with revised reference doses, the risks must be recalculated. Under AB 2588, the Air Toxics "Hot Spots" Information Act, all industrial facilities in the state must report any changes in emissions and/or any changes in risks from their plants on a biennial basis. Thus, if reference doses are revised, the owner(s) of the Geysers units would be required to update their risk assessments in accordance with AB 2588.

H41 The emission estimates reported in the air quality section (as well as the baseline and analytical maximum capacity factors used to derive them) are consistent with those reported in other parts of the EIR. With regard to the comment on emissions factors, the emissions reported in Tables 4.5-27 and 28 are based on factors that were derived from measurements for these systems and are not based on permitted levels. Actual production rates were used in combination with the emission factors to estimate the emissions reported in the tables. Please see the responses to Comments H8 and H9 for further discussion of the analytical maximum scenarios and air quality impacts.

H42 The DEIR refers to steam stacking as an example of a condition that can result in unabated releases. In order to include other factors besides steam stacking that can result in these releases, the text on page 4.5-75 (under "Geysers Power Plant") is hereby amended to read as follows:

The principal health risk that could be experienced from plant operations under the 1999 A-Max scenario would be the potential for increased acute exposure to toxic hydrogen sulfide emissions. For the Lake County units, emissions of hydrogen sulfide are estimated to remain the same (see Table 4.5-27) under the 1999 A-Max scenario as compared with the 1999 Baseline, while the corresponding emissions at the Sonoma County units under this scenario are estimated to increase by approximately 40 percent (see Table 4.5-28). The scenario analyzed in Tables 4.5-27 and 4.5-28 is the one that maximizes "controlled emissions" and not the scenario that depicts the minimum level of operations that has generally been used for the A-Max for the Geysers (see Table 3.1). Although steam stacking has been shown to cause exceedances of ambient air quality standards (AAQS), the same can be demonstrated for emissions from untreated well bleeds, normal and abnormal power plant operations. Steady state "controlled" emissions are capable of, and have been the source of both nuisance complaint generation (odors) and AAQS exceedances. These events are typically associated with episodes of regional air stagnation and a "flushing" of built up pollutant concentrations from the West Geysers area into Lake County during the early afternoon wind flow reversal from a westerly direction. However, this increase in hydrogen sulfide emissions would not be expected to result in a significant increase in health risk or nuisance odor complaints since the two phenomena are essentially independent of one another. This is because the peaks in hydrogen sulfide concentrations (and ensuing complaints) that have occurred in the past have been the result of uncontrolled releases of steam due to events like steam stacking rather than from the steady-state, "controlled" emissions released at the power plants. As discussed in the setting section, in addition to H₂S abatement systems to reduce controlled operations, an automated pipe manifold system has been installed, and this system has significantly reduced the incidents of steam stacking. Because the project would not affect operation of the H₂S abatement systems, or the manifold systems, steam wells and wellheads, or change the applicability of any air district rules or regulations, or affect the frequency of regional air stagnation, the project would not have a significant effect on the local health risks or the potential for nuisance odor complaints that are associated with controlled releases, or steam stacking and related uncontrolled releases of steam.

H43 The commenter is correct in that some of the Geysers units (5, 6, 7, 8, 11, and 12) utilize an incinerator system (a form of combustion) as an emission control system. It is also true (and is so stated on Table 2.2 of the DEIR) that emissions from this system contain SO₂. However, this abatement system is by no means comparable to the large boilers found in the Bay Area fossil-fueled plants, which release their emissions through a tall chimney via a generally hot, dry process, versus the Geysers incinerator abatement systems emissions being released through cooling towers (essentially a wet, cool process). Furthermore, one of the key features of fallout-type particulate (FTP) from the fossil-fueled plants (as described on pages 4.5-13-14 of the DEIR) is the formation of FeSO₄, which is a result of the interaction between the boiler exhaust gas and the boiler tube steel walls. While there are apparently similar chemical processes between the Geysers incinerator abatement systems and the fossil-fueled power plants, no data is available to suggest that FTP (as discussed beginning on page 4.5-13 of the DEIR) is emitted from the Geysers Power Plant. There are also great process differences between the two systems. Regardless, the commenter is correct that because the Geysers Power Plant location is far from any potentially impacted sources, the DEIR is correct in stating that, for the Geysers, this would be a less-than-significant impact. Thus, in response to this comment, the first sentence of the third paragraph of page 4.5-76 of the DEIR is hereby amended to read:

Unlike the three Bay Area fossil-fueled power plants, Because there are no combustion sources used in the process that can generate acidic particles at the Geysers; therefore, no measurable impact from FTP is expected at the Geysers. Geysers units 5, 6, 7, 8, 11, and 12 do utilize an incinerator based emission control system that emits exhaust gasses with similar chemistry to that causing FTP from the fossil-fueled power plants. However, the distance of these Geysers units from potential receptors that could experience any FTP-like nuisance effects from these units is far greater than that of the Bay Area fossil-fueled power plants and thus, further ensure that no FTP-like nuisance effects would be experienced.

H44 The issue of economic curtailment is mentioned in a footnote on page 4.8-2 of the DEIR instead of in the body of the text because it is an economic issue that is not directly related to plant ownership and therefore is not affected by divestiture. Economic curtailment has occurred at least in the U-N-T fields since 1994, and would likely continue under PG&E ownership. Divestiture would have little or no detrimental effect on economic curtailment, and in fact would be more likely to reduce curtailment as shown in the response to Comments H5, H7, and H13 through H17.

H45 The number of units that could be closed to better utilize the steam resource is quite limited by the fact that geothermal steam can only be transferred to another site less than a mile away. Both PG&E and the new owners would face the same decisions on plant closures and reconstructions, so that divestiture would not change this situation. The new owners will have a strong incentive to maintain the resource in a manner that is most economically efficient and beneficial. The alternative of selling the plants to the steam suppliers only reinforces this incentive.

While the commenter believes that operating the units at a sustainable, baseload flow rate would efficiently utilize the steam resource, the Legislature and the CPUC have decided to rely on the marketplace to the extent feasible as the best means of efficiently managing these resources. The CEC is charged with assessing the societal benefits and costs of pursuing different resource options. Nevertheless, restructuring is intended to decentralize resource planning so as to avoid the compounding of mistakes that can occur with one decision-maker overseeing all.

H46 There is no basis for concluding that Geysers units would be operated inefficiently after divestiture. Please see responses to Comments H7 and H45, where related issues of energy efficiency are addressed.

H47 A new paragraph on page 4.9-12 of the DEIR (following the fourth paragraph) is hereby added as follows:

PG&E maintains hygiene facilities (buildings with lockers, showers, and coverall storage areas) at each unit site. These facilities minimize worker exposure to the trace contaminants that are found in the steam, primarily arsenic.

The activated-carbon scrubbers that remove mercury from the geothermal steam are described in the DEIR on page 4.9-13 (second paragraph).

H48 The comment refers to the project setting, which is discussed starting on page 4.9-12 of the DEIR, and not to a project impact. Page 4.9-12 of the DEIR (fourth paragraph, second sentence) is hereby revised as follows:

Other constituents include ammonia, hydrogen, methane, nitrogen, carbon dioxide, and trace amounts of other gases, including radon, as well as trace amounts of various metals, including arsenic and mercury. Asbestos is present in serpentine rock and soils, which are common throughout the Geysers area.

The presence of trace metals arsenic and mercury in geothermal steam was also described in the DEIR on page 4.9-13 (second paragraph). Please see the response to Comment T18 for a discussion of mercury mining in the Geysers area, as well as further details on potential asbestos contamination.

H49 The North Geysers Unit Loading Instructions are instructions written by PG&E staff to ensure that system operators preserve system reliability. They are in a state of flux because another unit, Geysers Unit 11, is being "wired" into the north Geysers system to provide greater and more reliable voltage support in the Mendocino area. These instructions and the responsibility for observing them have now been transferred to the ISO and it is assumed in the DEIR that the ISO will continue to observe them as they are modified to reflect the completion of the Unit 11 interconnection.

These instructions do not consider economic or energy policy issues and would not be an appropriate document into which to insert such considerations. Such considerations are currently in the hands of PG&E and will in the future be in the hands of the new owner of the Geysers plant. The economics of the steam supplies will certainly affect how these units are operated. It may be possible that in the context of providing green power, the Geysers could be employed in a more baseloaded mode in order to firm up other sources of green power such as wind generation or hydro. That issue is appropriately left to the discretion of the new owner.

H50 Page 2-39 of the DEIR notes that the Lake County Sanitation District (LACOSAN) has a long-term contract to supply wastewater to the Geysers Power Plant where it is injected into the steam fields. A pipeline from the Southeast Regional Wastewater Treatment Plant (SERWTP) delivers up to 8 million gallons a day of treated wastewater or lake water to the Southeast Geysers geothermal field. This mutually beneficial arrangement provides LACOSAN with a means to dispose of SERWTP wastewater effluent and allows the steam field operators to increase recoverable steam pressure and improve the reliability of steam delivery. This information was not presented in the discussion on sanitary and storm sewers because that section of the DEIR examines potential impacts of the proposed project on sanitary and storm sewer systems and, in the case of the Geysers, there would be no such impacts, nor would there be any impacts on LACOSAN. CEQA does not require consideration or discussion of economic effects, except insofar as they may result in secondary environmental effects. Given that the proposed project would not affect LACOSAN, there is no reason to assume that there would be project-generated economic effects related to the continued provision of wastewater management services in Lake County.

H51 The source points, waste composition, quantity, and ultimate disposal method of each hazardous waste stream generated at the Geysers Power Plant are summarized in the DEIR on page E-5 of Attachment E.

PG&E has provided the following information on waste generation at the Geysers Power Plant for 1998 through September:

Unit	Hazardous Waste (Tons)	Nonhazardous Waste (Tons)
7&8	39	0
9&10	41	0
13	136	135
14	141	72
16	33	145
17	442	436
18	0	171
20	28	241
Various	146	23
Common	27	0
Total (1998 through September)	1,035	1,225

Note also that the amounts of hazardous and non-hazardous wastes generated each year can vary significantly, depending on whether special equipment or site upgrades or repairs are performed.

Page 4.12-15 of the DEIR (fifth paragraph, first sentence) is hereby amended to read:

Solid waste generated in Lake County is disposed of at the privately owned Eastlake Clearlake Highlands Landfill, located off State Route 53 in the City of Clearlake.

H52 The commenter is correct that the Geysers generating units do not have "black start" capability, meaning they must have off-site power available to start up, and that significant emissions occur during unexpected shutdowns and resultant startups. However, divestiture of the units will have no effect on the availability of off-site power, and therefore no impact on the reliability of the electric grid in California. As noted by the commenter, transmission outages are likely to decrease under restructuring due to the operation of the ISO, because its one and only task is to ensure reliability of the grid. In contrast, the previous grid operators (PG&E, Southern California Edison, and San Diego Gas & Electric) each operated only a portion of the state’s transmission grid and had a variety of motivations behind their transmission system operational decisions, such as protecting their generating assets. By having a single entity controlling all of the state’s transmission grid, with continued reliability as its only motivation, outage duration and frequency in the restructured electric utility industry are more likely to decrease rather than increase.

H53 Comment noted.

H54 The DEIR assumes that the Geysers units under new ownership would operate within the parameters of their existing permits, as stated on page 3-8, first paragraph. In its comment, the agency agrees that if this is the case, the noise impact would be less than significant.

H55 In response to comment, the third sentence of the second paragraph under Section 6.4.3 (page 6-23) is hereby amended to read:

This may reduce environmental effects that are of concern, namely steam stacking, well bleeds, and field maintenance problems.

The last sentence of the same paragraph (pages 6-23 – 6-24) is hereby amended to read:

As owners of the generating units, the steam field operators would be uniquely positioned to coordinate the operations of the units to maximize utilization of steam pressure and avoid steam stacking, well bleeds, and other problems associated with field maintenance.

H56 As noted on pages 2-4 to 2-5 of the DEIR, PG&E plans to transfer its rights and obligations under the existing steam supply contracts with U-N-T and Calpine to the new owner(s). Divestiture would not change the future need for maintenance at the units or shorten the useful life span of the units.

H57 Utility plants are not classified as "stranded assets" arbitrarily by the CPUC. Whether a plant is an "economic" or "uneconomic or stranded" asset is derived by comparing the remaining book value to the market value. The important factor is not the determination of whether an asset is economic, but rather the dollar amount representing the difference between the book and market values. That determination cannot be made until the asset is market valued in some fashion, including by an auction. No other special significance is attached to a "stranded asset." Please see responses to Comments H13, H14, and H15 for discussion of "green power" policies.

H58 The Lake County steam contract provides for prices as much as 50 percent lower than those in Sonoma County, partially because the steam from Calpine’s field is less contaminated than steam from other fields, thus reducing abatement costs. This lower price is sufficient incentive to dramatically reduce economic curtailments. Calpine does drill more intensively to supply its adjacent QF plants, which hold comparatively lucrative Interim Standard Offer 4 (ISO 4) contracts with PG&E, as mentioned on page C-8 of the DEIR. Please see response to Comment H2.

H59 Please see response to Comment N61.

H60 Attachment C of the DEIR concludes that divestiture is more likely to reduce cycling at the Geysers, not increase it. In any event, as noted in the responses to Comments H5, H7, H13, and H44, any increase in load cycling at the Geysers, and the resultant increase in emissions, would be a direct result of restructuring, and not of divestiture of the units.

H61 The first bullet on page C-8 of the DEIR, "Baseload to load-following operation," explains why Geysers generation has been economically curtailed and discusses how "fuel pricing and contracts affect power plant operations."

H62 Please see response to Comment H7.

H63 Please see responses to Comments H5 and H7. Cycling of the Geysers units already occurs under PG&E ownership, and is likely to decrease, rather than increase, under any new ownership scenario.

H64 Please see response to Comment H13. The commenter may have misinterpreted the discussion at C-29 to arrive at a completely opposite conclusion from the DEIR. The portfolio holder discussed there is PG&E, not the new owners, who will have a small portfolio of plants, if any. Therefore, assuming the new owners only have one or few generating plants from which to recover their investment, they would be more likely to ensure their units are well maintained.

H65 The commenter’s statement reflects the rationale behind the designation of the environmentally superior alternative in the DEIR. As well, if the steam field owners do not exercise their right of first refusal, the new owners will assume the existing steam contracts. Therefore, the project will have no effect on any potential impact related to the steam supply contracts.

H66 Please see responses to Comments H5, H7, H15 and J8.

H67 CPUC Decision 97-04-042 applies to those electrical utilities regulated by the CPUC. The new owner of the Geysers will presumably be a non-utility company, and therefore will not be regulated by the CPUC. As a result, the policies contained in D.97-04-042 will not apply to the new owner. New owners of the divested power plants will have the freedom to retire, repower, or replace the generation units. The recovery of stranded generation assets, legislated by AB 1890, is restricted only to utility companies regulated by the CPUC.

H68 The commenter references the Notice of Preparation (NOP), which is the public notice required by CEQA stating the lead agency’s intent to prepare an environmental impact report. The NOP provides a brief discussion of the project and the known potential environmental effects that will be addressed in the EIR. It was prepared before any of the analysis conducted for this EIR was even started, and does not reflect any of the conclusions reached in the DEIR. However, addressing the commenter’s concerns about the cumulative impact of emissions from all parts of the Geysers area, including the steam fields, the analysis conducted for the air quality section (Section 4.5) of the DEIR relied heavily on the data collected by the GAMP, which detects all pollutants coming from the Geysers units, steam fields and related equipment. That data confirmed the effectiveness of the pipe manifold network system installed at the Geysers in the mid-1980s, as noted on page 4.5-47 of the DEIR. Because of this technology, the GAMP has detected only one incidence of release of significant amounts of H₂S in recent years, as noted on page 4.5-45 of the DEIR. In any event, the DEIR concludes that malfunctions at any of the Geysers units leading to exceedance of ambient air quality standards are no more likely to occur under a new owner than under PG&E’s continued ownership. As well, existing air quality permits, with which the new owners of the Geysers units must comply, clearly specify that the new owner must not exceed ambient air quality standards, including H₂S concentration limits, and that they must participate in an air quality monitoring plan similar to the GAMP in order to ensure standards are not violated. Thus, with these permit requirements, the continued use of the manifold piping system and continued coordination between the steam field owners and the generating unit owners (as specified in the steam supply contracts), the DEIR concludes that the potential for the project to result in increased impacts associated with exceeding ambient air quality standards is less than significant.

H69 The footnote is correct. The geothermal purchase contracts governing payments by PG&E for geothermal generation from U-N-T and Calpine base payments on the number of kilowatt-hours produced. Thus, PG&E determines dispatch of Geysers generation based upon the incremental cost of generation, not on the amount of geothermal energy used. In the SERASYM™ modeling, the same behavior needed to be employed to forecast future Geysers operations. Because the incremental cost of generation for most utility generating units is determined by a combination of fuel cost and unit specific energy conversion efficiency, the same approach is followed in the SERASYM™ algorithms, thereby necessitating special procedures to accurately reflect the geothermal contracts. These adjustments involved normalizing the unit heat rates for each geothermal unit to a 10,000 Btu/kWh "pseudo-heat rate" so that the actual cost of geothermal steam was reflected in forecasted operations of the units. Once it was determined how much the units would run (using the above procedures), the actual heat rates were used to calculate the emissions.

H70 Page G-7 (last paragraph, first sentence) is hereby amended to read:

The Geysers geothermal plants (Nos. 13 and 16), supplied by Calpine, wells (Nos. 13 and 16) are already running at their steam-limited maximum levels; the remainder, supplied by UNT, are not.

H71 The source of emission rates in the SERASYM™ program for both units is the CEC Electricity Report 94 (page A-II-A-19, dated 12/8/94), wherein the column for hydrogen sulfide was understood to be 7 pounds per hour and 1.1 pounds per hour for Geysers Units 13 and 16, respectively, which is within permitted levels. The reason that the emissions do not differ by the full 7 to 1.1 factor of 6.36 is that the decline in capacity caused by steam supply reduction is more severe for Geysers Unit 13 than for Geysers Unit 16.

It is noted, however, that the emissions estimates for the Geysers units in Chapter 4.5 (Air Quality) of the DEIR relied upon the information contained in Attachment G for electricity generation estimates and for hydrogen sulfide only and that Title V application data was used as the basis for ROG, NO_X, and PM-10 emissions estimates. Based on Title V application data, ROG emissions factors used for the emissions estimates included in Chapter 4.5 of the DEIR were 10.9 pounds per GWh for Unit 13 and 8.0 pounds per GWh for Unit 16, which, incidentally, round to 0.01 pound per MWh. Since the footnotes to Tables 4.5-27 and 4.5-28 are not precise on this point, those two tables are hereby revised as follows:

Finally, it is noted that the hydrogen sulfide emissions data provided by the commenter substantially lowers the emissions estimates of that pollutant. Using the commenter’s data, emissions of hydrogen sulfide from the two Lake County units would be 5 tons per year under existing conditions, 1999 baseline, and 1999 Analytical Maximum, and would be 4 tons per year under the 2005 Analytical Maximum. The corresponding DEIR estimates were in the 30 to 40 ton-per-year range. However, since the DEIR concluded that even the higher emissions estimates included therein would not be significant, the conclusion would remain the same with respect to the lower estimates as well.