Draft Meeting Summary
First Technical Workshop Concerning the Draft Initial Study for Pacific Gas & Electric Divestiture Application
Monterey, California; June 13, 1997
The following is a summary of a technical workshop on the California Public Utilities Commission's Draft Initial Study conducted for the application by Pacific Gas & Electric Company to divest four of its fossil-fueled power plants. The summary is not an official record of this informal event, which was not subject to the CPUC's recording rules; it is intended to give parties information about the assumptions and methodologies used in the Draft Initial Study. Wherever possible, speakers are identified by name. However, many speakers did not identify themselves, or they submitted anonymous questions in writing. Many of the answers were truncated and paraphrased, and clarifications were added in parenthesis.
The meeting began at 10:10 am with introductions of all parties in attendance. Bonnie Nixon of Public Affairs Management (PAM) explained the agenda, as well as the procedure for asking questions and submitting comments. She noted that each speaker would make a short presentation, after which audience members could ask clarifying questions about the material presented. She requested that audience members submit detailed questions in writing; these questions were answered in the afternoon session.
Bruce Kaneshiro of the California Public Utilities Commission (CPUC) provided a brief explanation of the electric utility restructuring effort, stating that the commission's goal is to begin competitive retail sales of electric service starting on January 1, 1998. One of the barriers to a competitive market is the possible exercise of market power in the generating sector. As a way to remove this barrier, the commission proposed that Pacific Gas & Electric (PG&E) and Southern California Edison voluntarily "divest" or sell a large portion of their in-state fossil-fueled power generation capacity. PG&E then applied to divest roughly 50 percent of its gas-fired capacity, and Edison applied to divest nearly 100 percent of its in-state fossil-fueled capacity. Kaneshiro emphasized that restructuring will occur with or without divestiture.
Kaneshiro explained that the draft initial environmental studies conducted for the two divestiture applications are "decision point documents." The commission will use the studies to determine whether to conduct a full Environmental Impact Report (EIR), as defined in the California Environmental Quality Act (CEQA), or issue a Negative Declaration or a mitigated Negative Declaration. He stated that the ultimate goal of commission staff, its consultant and subcontractors is to prepare the "appropriate document."
Q: An audience member representing the Southeast Alliance for Environmental Justice (SAEJ) asked about how the meeting would be recorded.
A: (Kaneshiro) The workshop is an informal meeting and is not subject to the recording requirements of a formal CPUC proceeding. The workshop will be recorded and notes will be taken only for the production of a meeting summary, which would later be available for distribution and public review.
Anna Shimko of Cassidy Cheatham Shimko & Dawson then laid out the responsibilities of the CPUC in complying with CEQA. She explained that the CPUC is the "lead agency" that is being asked to "approve" the divestiture applications; thus, the approval would constitute an "entitlement from a public agency." This would require the commission to decide whether or not to conduct a CEQA review. Shimko said that because the new owners may operate the plants differently than PG&E, some level of environmental review is required.
Shimko also described the differences between direct and indirect environmental impacts. For example, a direct impact might be an increase in air emissions resulting from increasing power generation at a plant; an indirect impact might be environmental degradation resulting from the loss of funding for a monitoring program. For instance, as part of an agreement with a Regional Water Quality Control Board, PG&E currently funds a local environmental monitoring program; but there is no guarantee that the new plant owner will fund that program.
Shimko noted that the basis for CEQA review is the difference between how PG&E would operate the plant in the restructured marketplace compared to how the new owners might operate them. Essentially, CEQA analysis is to be based on facts and "reasonably foreseeable events." Among other things, the purposes of the Initial Study are: to provide information for determining whether to prepare an EIR, a Negative Declaration or a Mitigated Negative Declaration; to allow PG&E, the CPUC, other agencies and the public to comment on the analysis and assumptions of the study and to suggest mitigation measures that would enable the project to qualify for a Negative Declaration; to focus the EIR, if required, on effects that may be significant; and to document the factual basis to support a Negative Declaration, if appropriate. The CPUC will use the Final Initial Study as a "decision point" document to conclude whether to proceed with an EIR, a Negative Declaration or a Mitigated Negative Declaration.
Q: An audience member asked, Was the CPUC's decision on whether or not to conduct an EIR quasi-judicial or quasi-legislative in nature?
A: (Shimko) It typically does not make a difference, because the standard of review is the same either way.
Q: Another audience member, who represents SAEJ, asked Shimko, Can you clarify the difference between a mitigated negative declaration, a negative declaration, and the role of the Applicant in the process?
A: (Shimko) For a Negative Declaration, the lead agency determines that there are no impacts that require mitigation. For a Mitigated Negative Declaration, the agency determines all impacts can be reduced to insignificant levels. The applicant can propose mitigation measures, and comment on the assumptions and methodologies used in the Initial Study; but it does not participate in the study.
Q: The same person asked in a follow-up, "Must mitigation measures come from the applicant, or from the CPUC?"
A: (Shimko) It does not matter where the proposed mitigation measures come from, but the applicant must accept them before the Mitigated Negative Declaration is released for public review.
John Hathaway of Environmental Science Associates (ESA), Bob Weatherwax and Bob Logan of Sierra Energy & Risk Assessment Incorporated (SERA), and Richard McCann of M.Cubed then described the process of framing and conducting the Draft Initial Studies. The process began with devising a detailed description of the "project" under review, followed by setting baseline conditions, establishing an Agency Outreach Program, and conducting economic, financial and operational analyses. Hathaway reiterated during the project description that the objective of divestiture is to enhance competition in the restructured marketplace. This is intended to decrease electricity costs for consumers.
Logan introduced the economic, financial and operational aspects of the Draft Initial Study. He explained that the basic premises of the study are that restructuring will go forward, and that divestiture will benefit ratepayers. Because the plants proposed for divestiture currently run at relatively low levels, he said, they have potential for significant increases in generation, and resulting environmental impacts.
Logan then addressed the primary environmental issue: Will the power plants operate differently under independent ownership than under utility ownership? Because the utilities will operate the plants as part of a portfolio that includes other forms of generation, including hydro and nuclear, while the independent owners will rely only on the plants they purchase to generate profits, the Draft Initial Study concludes that the divested plants will have greater generation under independent ownership.
McCann cautioned that the various parties involved with the application speak four different languages: CEQA (by environmental specialists), environmental regulation (e.g., by the Air Quality Management Districts and Water Quality Review Boards), rate regulation (by the CPUC), and economese (by economists). Miscommunication can occur, he said, because terms used in the study process often mean different things in these four different languages.
The extent of environmental impact hinges on the incentives of the new owners to operate the plants at maximum capacity, McCann said. Many of the plants currently run at low levels, but the new owners could increase operations substantially, resulting in greater environmental impact.
The policy proposal in question is not just divestiture, he added; the underlying policy question is, "How will reduction of market power affect the environment?" If it did not divest the four plants, PG&E would be precluded from participating in the direct-access market until 2002 (the transition period), and would sell power from the plants only through the Power Exchange (PX).
The new owners, and the utilities themselves, will be taking different kinds of risks in this new market, McCann said, but the risk is higher for one "stand-alone plant" than for a plant that is part of a large portfolio. The new owners also would likely have different fuel purchasing practices than PG&E, he added.
McCann then addressed the potential for plant retirement/repowering by the new owners. He stated that a basic assumption of the study is that if its costs were not recovered through Power Exchange sales or Independent System Operator contracts by 2002, PG&E would retire those plants not classified as must-run . Another assumption was that the new owners would likely repower the plants as soon as practical to enter the new marketplace. However, in the Initial Study, this issue was only relevant to Edison.
Q: Marc Joseph of the Coalition of California Utility Employees asked Bob Logan, Did you say it was the unanimous opinion of the study team that divestiture should go forward?
A: Logan clarified that he had said it was the opinion of the economic study team that divestiture would benefit ratepayers, but the environmental impacts are yet to be considered, and only the commission will decide whether divestiture should go forward.
Bob Weatherwax gave a basic description of the preliminary production cost modeling conducted for the studies by SERA, which utilized their copyrighted SERAM and SERASYM computer models. SERA assumed that both the Los Angeles Department of Water & Power (LADWP) and the Sacramento Municipal Utility District (SMUD) would participate fully in the restructured marketplace. The analysis included both Edison and PG&E, he said, because Sierra had to "model the entire state in order to get an accurate picture."
Modeling limitations in the then-current model structure, and scoping limitations inherent in an Initial Study, very much limited the use of modeling, Weatherwax said. Because the study team did not then have the capability to simulate the bidding process, it did not attempt to craft a model that would compare the environmental impacts of a restructured California electric industry with or without divestiture. Results from this simulation case, along with selected input data, were also employed in the repowering analysis presented in Attachment C, "Data mining" from the SERASYM dataset provided the basis for determining the capacity factors and emission levels found in the "Environmentally Conservative" scenarios reported in Table 3.1, and in the individual plant and unit results found in Table 4.5.4, et seq.
Q: Mark Meldgin of PG&E asked, Does the SERASYM model produce an hourly marginal cost for the system as a whole?
A: (Weatherwax) An hourly marginal cost for the whole system can be extracted from the model run, but was reported for each of the six aggregated time periods covering the years.
Q: (Meldgin) Would the marginal cost figure produced by the model be a reasonable proxy for the market price in the new world?
A: (Weatherwax) I think it is during the non-divestiture transition period, but not necessarily after 2001.
Q: An air district representative asked, Are the computer models capable of projecting emissions according to air pollution seasons?
A: (Weatherwax) The models can account for seasonal changes in air pollution, much like they can project hourly changes in pollution levels.
Q: A representative of the California Energy Commission (CEC) asked, What are the assumptions made concerning must-run units?
A: (Weatherwax) The study assumes must-run operations for weekday peak period for six plants in Edison territory (Huntington Beach, Alamitos, Mandalay, Etiwanda, Redondo Beach and El Segundo), and noted that at least one of either Hunters Point 4 or Potrero 3 in San Francisco were required to meet local reliability criteria in the Bay Area. A Morro Bay unit was also assumed to be must-run.
Q: The CEC representative asked, Is the study team aware of the must-run study being conducted by the state's independent system operator?
A: (Weatherwax) The team is in the process of obtaining all available data from the ongoing study.
Q: The CEC representative asked, if electricity prices go down, will demand go up (as is predicted in classic economics studies)?
A: (Weatherwax) The team assumed demand would not change significantly. McCann added that total demand was not relevant to the Draft Initial Studies, which assumed, in the most environmentally conservative case, that each individual plant would run at maximum power, regardless of overall demand.
Paul Miller of ESA then went over Sections 3 and 5 of the Draft Initial Study, showing the eight factors that could lead to possible significant impacts (see study). Miller identified 11 areas that could potentially have significant environmental impacts as a result of divestiture:
* The phrase "Unless mitigation incorporated" was assigned to areas that the analysts felt that feasible mitigation measures clearly are available to reduce the impacts to less than significant levels, but these mitigation measures have not yet been incorporated into the project. There may be feasible mitigation in the other areas as well, and a purpose of releasing the Draft Initial Study is to begin the process of identifying suitable mitigation measures.
The "factors" of divestiture that could contribute to potentially significant impacts include: amounts of energy generated; amount and timing of construction; refurbishment; repowering or retirement of the plants; maintenance practices at the divested plants; pollution control technology installed by the new owners; employment levels, and related indirect factors; extent and character of land use; approach to decommissioning, repowering and environmental clean-up; and, permit transfers for divested plants.
For example, increased generation would potentially have an impact on: air quality, because of the increased emissions of air pollutants; and on noise, because generators are run longer at higher power levels.
Q: (Bob Carr of the San Luis Obispo Air Pollution Control District (SLOAPCD)) Does the study assume that pollution controls would be added as presently scheduled?
A: (Miller) Yes. Hathaway clarified that the study primarily relied on 1998 emissions levels, as estimated by the CEC, which considered all pollution control installations planned for completion by 1998.
Q: (Monterey Bay Unified Air Pollution Control District (MBUAPCD) representative) How did the study team arrive at its conclusion concerning cumulative impacts?
A: (Miller) The limited conclusion on cumulative impacts was based on an overview of the whole system, not on modeling. The cumulative impact portion of the Draft Initial Study was only conducted to determine whether divestiture could have cumulative effects on global climate. This was done primarily by determining how divestiture would affect carbon dioxide emissions. The study team concluded that divestiture could have cumulative impacts.
After a lunch break, panel members answered several questions that were submitted before the break.
SAEJ representative Jennifer Dhillon submitted several questions:
Q: Why was a "no project" alternative not considered for Hunters Point ? Why was "no sale because of closure" and "no sale because it was retained" not considered as alternatives?
A: (Shimko) It is very important to differentiate between the Initial Study and the EIR process. Only if it goes forward with an EIR is the commission required to analyze alternatives and consider the "no project" alternative.
Q: CEQA guidelines require consultation with responsible agencies, yet it appears many important agencies were not consulted, for example, the Department of Fish and Game, and the Association of Bay Area Governments. Why weren't these agencies consulted?
A: (Martha Sullivan of the CPUC) The CPUC did two versions of agency consultations. One was face-to-face with regional water quality control boards, air districts, planning agencies, and other agencies with local permitting authority. The CPUC also contacted dozens of regional, state and federal agencies to inform them of the Draft Initial Studies, and is in the process of identifying representatives from municipal governments and agencies located near the plants targeted for divestiture. Those parties will receive notice or copies of the Final Initial Studies.
Q: Why was there no consideration of Hunters Point as a unique community resulting in substantially greater impacts - to human health and also with respect to cumulative effects?
A: (Miller) The Draft Initial Study does indicate the potential for significant cumulative impacts, so it has been identified preliminarily.
Q: Why was the San Francisco Department of Health's study [on the health of Hunters Point residents] not incorporated and the San Francisco Department of Health not consulted regarding Hunters Point?
A: (Miller) The Department of Health's study was not released until after we had completed our analysis. We'd appreciate getting a copy of the study. We did not consult with the department because within our Initial Study we thought we had enough information to complete our tentative analysis.
(The department was contacted as part of the outreach effort, and they will receive a copy of the Final Initial Study; but, during the Draft Initial Study, the CPUC directly consulted only with those agencies with local permitting authority.)
Q: Will there be an opportunity to submit documentation now? We believe our documents are essential to the completion of a proper Initial Study and must be considered as soon as possible.
A: (Sullivan) You can submit documentation now, or at any time up to July 3, when written comments are due to the CPUC.
Q: (Bob Carr of the SLOAPCD) "What is the preferred mitigation for the air quality impacts resulting from divestiture? How do you propose that the mitigations be implemented?"
A: (Sullivan) Possible mitigation measures were not identified in the Draft Initial Studies, and added that the purpose of the technical workshops is to collect suggestions, proposals and ideas for how mitigation could be implemented.
Q: (Carr) Should people with mitigation ideas contact PG&E directly?
A: (Sullivan) Yes, and parties can express those ideas in the technical workshops as well.
Q: (Carr) Is PG&E going to propose mitigation in the next workshop (in San Francisco on June 27), and can parties see the proposals before the workshop?
A: (Joseph Malkin of PG&E) We do not know when we will have materials available, but other parties have specifically asked to meet a week in advance of the second technical workshop. Written materials will be available at the second technical workshop.
Jeanne Sole, representing the City and County of San Francisco, submitted several questions:
Q: You mentioned that if the area becomes a redevelopment zone, Hunters Point will become subject to redevelopment jurisdiction. For which factors (water, air, etc.), does this change have impacts?
A: (Shimko) The Hunters Point plant is in a redevelopment survey area, and a redevelopment plan is currently being prepared, in conjunction with an EIR. The change in jurisdiction does not directly impact the environmental impact that divestiture may have, with an exception: if the redevelopment plan would alter what is proposed for the area compared to what is proposed now, an EIR would examine that. For instance, if the redevelopment plan proposed building housing right next to the plant, an EIR would account for that.
Q: Traditionally, has the impact [of a change to redevelopment zone jurisdiction] tended toward relaxation or tightening of regulations?
A: (Shimko) Neither, to my knowledge.
Q: Does the answer change if the plant is owned by a utility or a non-utility?
A: (Shimko) No.
Q: You assumed that the Hunters Point Power Plant will be repowered. You also noted the potentially significant increase in capacity factors. What is the likely net effect of these two possibilities?
A: (Weatherwax) That would require an empirical answer, and we would have to look at that in further studies.
Q: Could you expand on the limits regarding thermal outputs at Hunters Point Power Plant? The Draft Initial Study notes the difficulty of meeting the standards now. How have the standards been met by PG&E?
A: (Hathaway) The information in the Draft Initial Study on the difficulty in meeting the thermal output standards came from a telephone conversation we had with the Regional Water Quality Control Board, which is typical for the level of review done for Initial Studies. PG&E has met the standards for the past 10 years, but the standards are difficult, and that's all we know. If we go further in our studies, we would investigate this more.
Q: In what stage is the process for amending air rules? How long is the process expected to take? What are the procedural requirements?
A: (Miller) In general, in a CEQA analysis, we don't rely on possible changes to present rules.
Bob Carr of the SLOAPCD added: I assume the question is referring to the change from a regulated public utility boiler to [standard, non-utility] generation facility. In our district, we're moving ahead to change that language to apply it to any generating unit. We usually go through a workshop process, then a 30-day review process, then take it to a hearing and finally to the board. It looks like we'll take it to the board in September.
(The San Francisco Bay Area AQMD representatives said they had no comment on the process. The MBUAPCD representative had already left the workshop.)
Q: (Bob Carr of the San Luis Obispo County Air Pollution Control District) The key issue for the SLOAPCD is whether PG&E or a new owner of the Morro Bay Power Plant will be able to recover costs for future emissions reductions through the competitive transition charge (CTC). The requirements for future emissions reductions exists in our current rule 429. The environmental review process should result in assurance that the CTC will apply to these emission reduction projects, unless there is a better process for assuring this. What is the CPUC staff's position on the application of the CTC for such cases, and what other process or processes are still open for public input?
A: (Kaneshiro) The CTC was mandated by Assembly Bill 1890, which enables utilities over time to recover uneconomic assets. Electric restructuring is a series of proceedings before the CPUC. The CTC is the subject of one of them. Future emissions reductions would probably fall under the CTC proceeding; whether emissions reductions projects are eligible for CTC recovery or not is being addressed in hearings now. Parties can still become involved in the CTC proceedings. The commission is conducting workshops on July 14-16 regarding the applications of the guidelines adopted in the commission's CTC Phase 1 decision (D97-06-060). Copies of the decision are available on the commission's World Wide Web home page (www.cpuc.ca.gov), under the "proposed and final decisions" section.
Dave Maul of the CEC said a CPUC Administrative Law Judge is currently drafting a proposed decision on whether future pollution controls are eligible for CTC recovery or not. Marc Joseph, representing the Coalition of California Utility Employees, noted that CTC applies only if PG&E owns the plant.
Q: Carr then asked, Why shouldn't it apply to a new owner? Emissions reduction projects already done or scheduled for plants in San Diego Gas & Electric and Edison territory were approved for CTC recovery. Just because we came along a few years later, we shouldn't be shut out of the process.
A: (Kaneshiro) I am not aware of the specifics of the CTC proceeding, but AB 1890 currently specifies that CTC recovery is only for the utilities' costs. Allowing CTC recovery for the new owner may require legislation.
Dave Maul of the CEC noted that approval of CTC recovery would add value to the facility, thus allowing PG&E to recover more of its costs through the sale.
Q: Marc Joseph of the Coalition of California Utility Employees asked, "Why, in the no-project case, would the utility wait until 2002 to retire a plant not needed for reliability?"
A: (McCann) We assumed that all utility plants would continue to operate. It's a conservative assumption about the need for plants to maintain their classification as "used and useful" in order to recover their rate-base investment. Then, after 2002, the owner could retire the plant, if revenues were not sufficient to continue operating.
Joseph stated that a CPUC decision states that the utilities may retire the plants earlier, and that he would forward a copy of the decision to the team.
Q: A SAEJ representative asked whether the CPUC would consider information about PG&E contemplating closure of the Hunters Point plant?
A: (McCann) We would consider that information and weigh it against other foreseeable scenarios.
Q: The SAEJ representative asked about the definition of a project "alternative."
A: (Shimko) The purpose of the Draft Initial Study was to project out what was expected and what was reasonably foreseeable. If an EIR is prepared, the CPUC would try to come up with a proposal that is different than the project -- an alternative that would satisfy the same objective and goals as the divestiture project, but have fewer impacts -- and would study such alternatives.
Q: Robert Nunes of the Monterey Bay Unified Air Pollution Control District asked, It was mentioned that unit outputs were modeled. How was the maximum feasible output derived for the Moss Landing Power Plant, and how was that translated to emissions, particularly NOx?
A: (Weatherwax) The maximum feasible outputs were calculated by ESA staff by using plant level data and assuming the plant operated at all times throughout the year. We also made "environmentally conservative" estimates, as shown in table 3.1 and Tables 4.5.X. What we did was look at individual units. The emissions data for Moss Landing 6 & 7 was extracted from the SERASYM dataset for maximum power output.
Q: Matt Layton of the CEC asked, Did the air emissions factors (EFs) for the 1998 cases include air emissions controls (both current in-place and those required by 1998)? Some of the CEC dataset EFs are uncontrolled.
A: (Weatherwax) The dataset used is a very current set of assumptions regarding emission factors and controls devices. We chose to use several sets of sources of data, including the CEC's.
Q: (Anonymous) The cumulative impacts section refers to proposed projects that have not been specifically identified. What are these projects, i.e., types? Since the only air quality plans in the region are for ozone, [did you] assume that the cumulative impacts analysis is for ozone as well as carbon dioxide?
A. Paul Miller: The Initial Study does identify a potential for cumulative impact. If the CPUC goes forward with an EIR, we would look at other projects, which come out of general plans. We don't know what those projects would be yet, that's why they're unidentified.
Q: An employee and a consultant to PG&E each submitted two questions that essentially asked why the study team believed the plants would operate differently under independent ownership rather than PG&E continuing to own and operate the plants, given the nature of the Power Exchange under restructuring.
A: (Logan) PG&E could not operate the plants as intensively as an independent owner because it owns a large portfolio of plants and would run its more efficient plants first, and there would be insufficient load to run all its plants at maximum load. Electricity is different from all other products in that demand must be present to allow generation; it cannot be stored for later use. The independent owner has no such constraints from overall system load behavior, and has a unique advantage in that only independent owners can sell into the direct access market as soon as the restructured industry takes effect in January 1998. (Utilities are barred from the direct access market until 2002.) Given the profit incentive, it is realistic that independent owners will sell close to the maximum potential output from one or more of the plants proposed for divestiture.
Q: (Joe Malkin, PG&E) There was concern expressed in the Independent System Operator's FERC filing about hydro-dumping driving prices down. In your modeling, how did you treat BPA [the Bonneville Power Administration] and northwest hydro in general?
A: (Weatherwax) In general, we feel there has been market power exerted by BPA for a very long time. In the modeling we have done, there's special price provisions that were set in effect to capture the way BPA tends to operate based upon the level of their hydro conditions and the state of their intertie as determined by their Long Term Intertie Access Policy. This policy tends to raise BPA's price, and also tends to raise operating prices out of the Southwest US as well.
Q: (Malkin) If I have a Direct Access contract for sales at $20/MWh and the market happens to drop down to $10/MWh, is there anything preventing me from shutting down and buying the power at $10 and selling it at $20?
A: (Logan) No. That may happen during a few hours of the year, when you have very high hydro production during the Spring run-off, for example.
There were several written questions by another anonymous audience member.
Q. Does the project team expect the market price of electricity to go up or down upon divestiture, or will there be no change?
A: (Logan) That was not a factor we looked at -- the mere fact of divestiture having an effect on the market price of electricity, up or down -- because it wasn't necessary for our analysis to determine whether or not there would be incentives for independent operators to increase the intensity of operations of their units.
Q: Table 3.1 (in the Draft Initial Study) indicated that the Morro Bay Power Plant, if sold, might operate at a 78.1 capacity factor. Does this figure mean round-the-clock operation, except during breakdowns and maintenance?
A: (Logan) Not quite, because in addition to the shutdowns for forced outages and scheduled maintenance, there are some environmental restrictions that affect the operation of the plant.
Q: Do you expect that the market price of electricity, during the hours that the Morro Bay plant would be operating, will always be greater that the short-run cost of running Morro Bay?
A: (Logan) It depends on who is operating the plants. If PG&E owns the unit and is bidding into the Power Exchange (PX), then we would expect that PG&E would only run the unit when it is profitable to do so. An independent operator may not care what the market price is because it may not be bidding into the PX. It may go the direct access route, in which case whether the market price is above or below the price it costs to operate the plant is immaterial. That means PG&E would keep the plant shut-down only if it thought that the PX price would not rebound rapidly enough to more than compensate for the costs of re-startup and the loss of opportunity to generate because of unit "downtime" and "ramping" constraints.
When audience members had no further questions, Bonnie Nixon closed the workshop by thanking all participants, asking them to submit written comments on the Draft Initial Study by July 3, and inviting them to participate in the next technical workshop on the study, in San Francisco on June 27. The meeting closed at 3:10 p.m.