Meeting Summary for the California Public Utilities Commission’s Workshop on Southern California Edison Company’s Application to Divest 12 Power Plants
June 30, 1997, Pasadena.

The following is a summary of a technical workshop on the California Public Utilities Commission's (CPUC) Draft Initial Study regarding Southern California Edison Company's application to divest 12 of its fossil-fueled power plants. This document is not an official record of the event, which was not subject to the CPUC's recording rules. Wherever possible, speakers are identified by name. However, many participants did not identify themselves when speaking, or they submitted anonymous questions in writing. Many of the answers have been truncated and paraphrased, and clarifications have been added in brackets.

Scott Steinwert of Public Affairs Management (PAM) opened the workshop at 10:05 a.m. He said the purpose of the workshop was to allow Edison to respond, to propose modifications for and take comments and questions about the Draft Initial Study (DIS) prepared by the CPUC for Edison’s divestiture application.

Bruce Kaneshiro of the CPUC provided a brief explanation of the electric utility restructuring effort, stating that the CPUC's goal is to begin competitive retail sales of electric service on January 1, 1998. A possible barrier to a competitive market is the exercise of market power in the generation sector. As a way to remove this barrier, the Commission proposed that Edison and Pacific Gas & Electric Company (PG&E) voluntarily "divest" or sell a portion of their in-state fossil-fueled power generation capacity. As a result, Edison applied to divest nearly 100 percent of its in-state fossil-fueled capacity. [Edison will continue to own a small fossil-fueled plant on Catalina Island.] Kaneshiro emphasized that restructuring will occur with or without divestiture.

Kaneshiro explained that the Draft Initial Studies conducted for the two divestiture applications are "decision point documents." The CPUC will use these 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 for CPUC staff, its consultants and subcontractors is to prepare the "appropriate document."

Steinwert then directed attention to a panel of speakers employed by Edison: Margaret Cheng, a Manager in Edison's corporate financial planning and analysis group; Bill Ostrander, Manager of Environmental Services; Tom Burhenn, Manager of Regulatory Affairs; Robin Walther, Manager of Regulatory Policy; and Jeff Koch, an attorney in the law department.

Koch began by announcing that the Ventura County Air Pollution Control District (APCD) now agrees with Edison that divestiture of plants in the district will not have a significant impact on air quality. Koch introduced Dick Baldwin, an Air Pollution Control Officer with the Ventura APCD, to confirm the agreement. Baldwin stated that when the district first met with CPUC and Edison personnel, it left with an inaccurate perception of the differences between restructuring and divestiture. The APCD also was unfamiliar with CPUC procedures. With a more thorough understanding of the issues gained through further meetings with Edison, Baldwin said, the district now agrees that divestiture alone will not have significant impact on air quality.

Under state law, Baldwin said, APCDs are prohibited from changing the terms of a permit because of a change in ownership. The only responsibility the district has is to update standards in the permits, he said, which occurs once each year. Unlike the CPUC, the district has no discretionary authority to approve or disapprove the sale. The Ventura APCD currently processes five to 10 permits per month because of changes of ownership, Baldwin said, and has never added new permit requirements in any case.

However, if the new owner of a plant wants to make physical changes, then a new process begins, Baldwin said. During this process, called "new source review," the applicants must propose actions, such as obtaining emissions offsets credits, that would more than offset any increased emissions; applicants must also utilize best available control technology (BACT) to minimize emissions. The district also intends to modify Rule 59, which specifies emission standards for nitrogen oxides and other compounds from utility boilers, to ensure the rule applies to the new owners. The district is currently going through an advisory process regarding Rule 59, Baldwin said, in preparation for amending the rule.

Baldwin said the district remains concerned with the potential impacts of restructuring, and would have liked to have seen an environmental analysis for that issue. However, he noted, the state Legislature in Assembly Bill 1890 removed the CPUC’s discretion in conducting an environmental analysis regarding restructuring. He emphasized again that the APCD's position is that changes of ownership for the divested plants will not require changes in permits.

Baldwin then answered some clarifying questions from the audience.

Q: (an unknown audience member) The new source review that you mentioned, what exactly is that?
A: (Baldwin) It is a permitting process for any facility in California that involves new construction, or adding to or modifying existing equipment. It’s a permit review process to ensure that this new or modified equipment uses BACT, and, for sources greater than 500 tons [of emissions] per year, that any emissions are more than fully offset.
Q: (from Martha Sullivan of the CPUC) When do you expect that [change to Rule 59] to be complete?
A: (Baldwin) July 15, 1997.
Q: (unknown audience member) Is Rule 59 exclusively an emission rate rule?
A. (Baldwin) No, it’s based on net pounds of nitrogen oxides per net megawatt-hour (MWh). It also includes total quantity, as mandated by the permit.
Q: (unknown audience member) So that is the rate and not the total quantity of emissions?
A: (Baldwin) That’s correct. The total quantity of emissions would be that in the permit, which is basically the full generating capacity of the plant—about 750 MW for Ormond Beach and roughly 200 MW for Mandalay. Edison, or any other owner, can operate up to the capacity of the facility under the current permit.

Koch then provided an explanation of Edison’s internal process for filing the divestiture application in November 1996. It began with a thorough review of the potential environmental impacts related to the sale. Edison concluded that the proposal in itself would not have potential foreseeable environmental impacts, and that the application probably is not even a "project" as described in CEQA. Even if it was a "project," Koch added, Edison determined that any CEQA review should conclude that there is no potential impact, thereby allowing the CPUC to issue a Negative Declaration.

According to Koch, Edison was surprised that the CPUC’s DIS not only identified potential environmental impacts, but also, based on a preliminary review of the document, seemed to identify very large environmental impacts. Since consulting with the study team, Edison understands the DIS is not meant to reflect an aggregate picture of what could happen in the future, but rather is meant as a preliminary assessment of the worst conceivable situation at each plant. For example, with respect to the aggregate capacity increases predicted in the study, Edison would contend those increases are impossible, Koch said, and believes the CPUC staff would agree such a scenario is unlikely.

Koch said his understanding is that CPUC staff still believes there could be substantial impact from Edison’s proposal. We just cannot agree with that conclusion, Koch said. We still see no potential environmental impacts from the project, certainly none that are reasonably foreseeable, and certainly none that are nearly as large as those identified in the DIS. So, we are here today not so much to offer possible mitigations measures, or to propose an EIR process, rather we are here just to state why we disagree with the conclusions in the DIS.

Koch continued, we think the DIS makes two very fundamental CEQA-type errors and these are the basis of our disagreement with the document’s conclusions. The first is the baseline—the picture of the world without the project, the environmental conditions that would exist if the proposal is not approved by the agency. It’s our belief that the draft study should be focused just on divestiture, he said, rather than on the broader restructuring that is also taking place.

The second error we believe the study engages in, Koch said, is that the level of speculation and unsupported assumptions is inconsistent with the purposes of CEQA. [A CEQA review] is supposed to compare the environmental conditions that would exist if the Commission approves the project, with those that would exist if the project is not approved. A CEQA review is a forward-looking process that tries to make reasonable projections of what will happen in the future with the project, versus without the project, he continued. And none of us, neither the Commission nor anybody else, can predict with certainty what the future will be.

An Initial Study is not intended to be precise look at the future, Koch said, but it is supposed to be a fact-based effort. Unsupported evidence is not permissible under CEQA, even in a DIS, he said. To proceed to an EIR, or requirements for mitigation, you need substantial evidence—facts or reasonable assumptions based on facts—of potential significant environment impacts. Koch asserted Edison’s belief that a number of assumptions critical to the study’s conclusion are at best speculative and unsupported by fact, while others are incorrect or are contradictory to others.

Concerning the baseline assessment—the legal and regulatory conditions that we would expect to be in place if the project is not approved—the DIS incorrectly concludes that Edison would retain all 12 plants, and would be in position to exercise market power, Koch said. One way to do that would be to reduce production, which may have market impact, but interestingly enough, may reduce environmental impacts. In reality, even if the divestiture application is not approved, state law [AB 1890] mandates that all utility owned fossil-fueled plants must be deregulated no later than the end of 2001, Koch said. For a variety of reasons, we can assume that will happen sooner rather than later.

The plants will not be removed from regulation by APCDs or other agencies with environmental regulatory authority, Koch emphasized, but will be removed from CPUC regulation. They will simply have to survive like any other facility in any other industry. A slight wrinkle exists with those plants identified as "must-run" for reliability reasons, Koch said. These plants will not be able to shut down unless other things occur. They won’t be regulated by CPUC, but rather by a set of contracts and the Independent System Operator (ISO). This will be the case whether or not the plants are divested. The fundamental point is that all of these plants will be removed from CPUC regulatory authority, Koch said, including CPUC authority over any future sale of those plants.

Koch asserted that the most defensible assumption is that utilities, once restructuring occurs, will divest all or a large portion of their plants because mechanisms will exist that create strong incentives for them to do so. But even if Edison retains all plants, there are a variety of mechanisms in place that would prevent Edison from exercising market power on the scale predicted in the study. The most important is the Federal Energy Regulatory Commission (FERC), This is not speculation about the future, Koch added. FERC has made it very clear that it is watching the competitive market in California, and that it will [enforce market power rules].

Edison has filed an application with FERC proposing bidding restrictions that would be employed if the market opens up before we divest the plants, Koch said. They haven’t been approved yet. However, in comments filed regarding our proposal, many of the complaints do not assert that Edison would use market power to reduce production and raise prices, but rather express concern that Edison would behave too competitively by underbidding its wholesale power. We think that’s a logical response by our competitors, and we think FERC will approve our proposal, Koch said. But the point is, FERC would prevent Edison from exercising market power, and we believe that for the study to assume the contrary is not defensible under CEQA.

The other main error the study engages in is use of speculation, or assumptions that are unsupported by the facts, Koch said. An example is in the determination of whether or not the new owners would have the incentive and the ability to generate more power than Edison at all the plants. Here the authors assumed a fixed price and tried to determine how the new owners would behave at that fixed price. They determined that some generators could make money at that price by increasing operations. However, they did not include a feedback process, which examines how the increased generation will affect price, Koch said. Failing to take this into account leaves a very flawed result. Edison’s concern is that the study doesn’t conclude that pricing cannot be addressed because of insufficient information. Instead, it continues to make other conclusions based on the fixed price scenario, leading to further inaccuracies, Koch said.

In another example, Koch said, the study concludes that because the new owners will initially be able to participate in the Direct Access market, while utilities cannot, the divested plants may be operated at significantly greater levels than if the utility continued to own the plants. A far more plausible assumption, Koch said, is that the new plant owners will not fulfill supply obligations with their own generation if the Power Exchange (PX) market price is significantly below their price of generation. They would buy the power on the open market. Customers do not care where they are getting their power, Koch said, as long as they are getting power; so we believe that the Direct Access market will be dictated by PX market.

Another error occurred because the study authors failed to use the same assumptions on both sides of the equation—on the non-divestiture side and the divestiture side, Koch said. It’s not discussed in depth in the study, but through conversations with staff, Koch said he understands that one of the authors’ claims is that there are significant advantages to owning a portfolio of plants, as opposed to owning a single plant. But Koch does not think it’s fully explained in the study exactly what these advantages entail, Koch said. While Edison believes there will be advantages of shared ownership and shared management, they will be modest advantages at best, Koch said. So if you’re going to make that assumption, you have to make it on the divestiture side as well: that the new owners will recognize these advantages and purchase more plants in a manner that suits them best.

Koch added that the logical conclusion one would reach from the DIS is that after restructuring and divestiture, the market would be much more inefficient, because relatively high-cost, low-efficiency plants actually increase generation. So, unless there is an explosion in demand, these gas-fired plants are either replacing lower-cost generation or running needlessly, burning fuel for no purpose, Koch said. The report’s perceived decrease in efficiency is in direct contradiction with the CPUC’s own conclusions that restructuring will increase efficiency, he said.

Koch stated that it’s more likely that operations will continue more or less like they do today—there’s bound to be some changes because of restructuring—but we don’t expect anything on the scale that the study predicts.

Basically, he continued, the potential impacts identified in the DIS depend on three things: increased generation, repowering and property transfer. Edison believes the prediction of increased generation is: speculative and implausible; subject to existing rules and permits; and inconsistent with the DIS’s repower assumptions. In addition, the prediction is carried through to the air quality chapter, Koch said, where it translates into predictions of very large increases in air emissions.

Regarding repowering, Koch added, my understanding is that other portions of the study assume that units that are shut down will be repowered; but that will trigger a CEQA process and a new source review process at the APCD. We think it’s implausible that the plants will be repowered on the scale predicted in the study, Koch said. Even if Edison were the owner, it would have the same incentives to repower.

Concerning property transfer, we do agree that because of our divestiture proposal, and the way we’ve structured it, there can be impacts that are not speculative, Koch said, such as building fences to separate property. What we do disagree with is that any of these are significant impacts under CEQA, he said.

The one area of potential significance is that NOx rules are very specific to the industry they apply to. On appearances, he said, the rules in the Ventura and Mojave Districts seem to apply only to utility owned facilities. Therefore, the plants would cease to be subject to the NOx rule after divestiture, either because there is no rule, or because the plants fall under a different rule. In Ventura, however, the emission limits in the rule are stated in the permits, which the new owners would inherit. In any case, the districts, including Mojave and Ventura, are in the process right now of changing the rules so they apply to all owners, Koch concluded.

Koch then took several oral questions from the audience.

Q: (Marc Joseph, Coalition of Utility Employees) In your slide stating that the end result is an expectation that divestiture will cause market inefficiencies, was that statement based on the table in the DIS that shows that all the plants would greatly increase generation, or was there something else behind that?
A: (Koch) It was based on that table, but also on certain economic discussion in Attachment C in the DIS.
Q: (Joseph) What are the inefficiencies you’re talking about?
A: (Koch) Basically what I was trying to identify was relatively high cost generation somehow replacing lower cost generation or just being wasted.
Q: (Joseph) From any of the plants, or all plants together?
A: (Koch) Well, certainly from all the plants together, but, in addition, from any significant number of them. Now, it’s certainly true that some of these plants may see increased generation, while others would decrease, but we view that as a result of restructuring, not divestiture, because the same would happen under Edison ownership.

After a short break, CPUC and Edison officials answered a few written questions. Koch said Edison would provide written answers to other submitted questions, and provide those answers with Edison's comments on July 3, 1997.

Q: (Marc Joseph) Who at the Commission will decide whether to prepare an EIR or a Negative Declaration: the ALJ [Administrative Law Judge], the Assigned Commissioners or the full Commission?
A: (Martha Sullivan, CPUC) The Energy Division will complete its analysis and come to a recommendation in July. If the Assigned Commissioners, President Conlon and Commissioner Bilas, are able to reach a unanimous decision, then their decision will stand. If they feel they need to take the decision before the full commission, the first available meeting is August 1; the next one is in the first week of September.

Q: (Bob Fisher, consultant to the City of Long Beach) If the lot splits at plant sites (e.g., Huntington Beach) are addressed by an EIR or Negative Declaration in CPUC action, does this affect either the Coastal Commission or local agency determination of need for a Coastal Development Permit and/or for parcel maps? If the resulting use pattern is inconsistent with zoning, is that an item to be addressed in the EIR?
A: (Cynthia Burch, Outside Counsel for Edison) In our technical resources document we did evaluate any zoning issues. Since there are no changes in use patterns being proposed by divestiture alone, there was no problem there. With respect to whether, if there is an issue, it is to be addressed by this process, we concluded: Yes, to the extent that the CEQA process is part of any agency action that’s needed to effectuate divestiture, this process covers it. The CPUC is the lead agency. So your comments would have to be provided in this process.
Q: (Fisher) Would an EIR provide more information on air quality impacts near individual plant sites (e.g., Huntington Beach) and more consideration of alternatives and potential mitigation measures? If so, why and how? If not, why not?
A: (Koch) To some extent that question may be more for the Commission as the lead agency. It’s our position that the pollutants that we are talking about here, the criteria pollutants, do not really have local impacts; they have regional or basin-wide impacts. Of course an EIR would address air quality impacts in more detail than an Initial Study. But we believe it’s clear, just from an adequate Initial Study, that there are not air impacts necessitating an EIR. An EIR does consider alternatives to the project put forth, but they are only alternatives that would accomplish the same objective as the project. In this case, our proposal is the sale and transfer of ownership through an auction procedure. So an EIR would look at other ways of accomplishing that.
Q: (Fisher) Does your proposal not also include the termination of bundles?
A: (Koch) Yes.
Q: (Fisher) Is there new information on Edison’s transmission upgrade proposal and on the must-run designations of the plants [local reliability bundles]? Does that require additional environmental analysis or change existing analysis?
A. (Koch) There have been developments since the divestiture application was filed in November. What we were hoping for at that time was that the determination of must-run plants would be made by now, and that we would receive some sort of rate-making mechanisms for those upgrades. We were expecting that by about this time, the must-run plants would be identified, and that it would have been shown that the number of must-run plants could be reduced through upgrades. The result of that is that as of today, we have a larger number of must-run plants than we would have if our transmission upgrades had taken place, and we don’t know exactly what those stations are. We expect that by this summer or early fall, the number of must-run plants will be identified; and expect it will be more than the two identified after the transmission upgrades. In our initial application, we proposed to sell off the plants in certain bundles. Now it looks like each bundle would have a must-run plant. That complicates the sale because no one will be interested in buying a must-run plant until they have the regulatory certainty of an approved ISO must-run contract. Until those contracts are more precisely determined, we can’t sell those must-run plants, so we are unbundling the plants and we will sell the non-must-run plants first, then the must-run plants after the contracts are determined.
Q: (Fisher) The reason I addressed that question to staff and consultants was that I wondered, Would that new information [regarding bundling] have an effect on how the consultants, in their assessment of operators’ perceptions about markets and behavior and decisions about repowering, derive the air quality conclusions?
A: (Koch) Edison’s position is that divestiture itself does not cause any significant impacts whether a plant is must-run or not. For a must-run plant, there will be some floor of generation level, but that would be true whether it's owned by Edison or somebody else.
A: (Edison's Robin Walther) My understanding is that the study coming out today will identify generation options, but it won’t necessarily identify the minimal set for generation options that are required to be must-run. For example, if we have two plants in the Ventura area that could both be must-run, but only one is needed, this study may specify that both stations are must-run options. But ultimately there will be a screening analysis used to determine which of the two is most appropriate for designation as must-run.
Q: (anonymous) RECLAIM [air emissions offset] credits are allocated annually to facilities in the South Coast Air Quality Management District. Will additional credits held by Edison be assigned or transferred to the new owners of these SCAQMD plants?
A: (Koch) Edison’s proposal is that all the RECLAIM Credits allocations, including future year allocations, for each generating station will be sold along with the station.
Q: (the study team’s Richard McCann of M.Cubed) We haven’t seen a specific plant-by-plant allocation of the RECLAIM credits. Is Edison going to provide that?
A: (Koch) I believe it’s in our permits, but we can certainly provide that. It’s also in the Plant Description section of our November application, showing in a bar graph the future allocation for each plant.

Koch then said he would answer one question submitted in writing by members of the study team, and that Edison would later provide written answers to the other questions in its written comments due July 3rd.

Q: (McCann) At what point in time would the 12 plants be deregulated and market-valued? What guarantee is Edison giving that this will occur before the December 31, 2001, date stated in AB 1890 and assumed in the Initial Study? Please provide any documentation [showing] that Edison plans to market-value these plants without divestiture before December 31, 2001, and that Edison is planning to sell these or any other plants.
A: (Koch) Edison is in no position to guarantee exactly when these plants will be market-valued and deregulated; that’s up to the Commission more than Edison. The documentation that we plan to sell and market-value these plants as soon as possible is the application that is before the commission now. It’s a fair statement that we’ve been pressing for a determination of that application as soon as possible. We can’t say when the plants will be market-valued without that process because we have devoted all our efforts to proceeding with that application.
Q: (McCann) What’s happening with market-valuing the Mohave and Four Corners generating stations [the out-of-state coal-fired plants partially or wholly owned by Edison]?
A: (Koch) All of our fossil-fueled plants must be market-valued before 2001. Most of our resources have been devoted to this application, to market-valuing the gas-fired plants. Market-valuing the coal plants will come later. We can only guarantee that they will be valued by 12/31/01.

Q: (the study team’s Bob Logan) You state that after restructuring, certain mechanisms will exist that will create a strong incentive to divest. Please explain how these mechanisms will work. Please provide citations [in your comments due to the CPUC on July 3] supporting this position so we might include them in the study.
A: (Walther) One of the incentives that has been discussed is that in a competitive environment, the power plant would want to be able to have market-based pricing, and FERC would determine if each facility is eligible for market-based pricing. The assumption is that FERC would not approve market-based pricing [if Edison owned enough plants to exert market power]. So there is a strong incentive for us to divest the plants, even after the market-valuation process, in order to get market-based pricing.

Scott Steinwert then closed the workshop at 11:45 a.m., urging parties to submit formal comments in the proceeding to the CPUC by 5 p.m. on July 3rd.