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April 12, 2002 Special Meeting

Meeting Information


Special Meeting
Friday, April 12, 2002, 9:30 a.m.
City Hall, Legislative Chambers, Room 250

Chair: Commissioner Gonzalez; Vice-Chair: Commissioner McGoldrick
Members: Commissioners Ammiano, Hall, and Schmeltzer
Alternates: Commissioners Peskin and Fellman
Clerk: Monica Fish


(There will be public comment on each item)

1. Call to Order and Roll Call

The meeting was called to order by Vice-Chair McGoldrick at 9:35 a.m.

Members Present: Chair Gonzalez was noted present at 9:47 a.m.; Vice-Chair McGoldrick; Commissioner Ammiano, Commissioner Hall, Commissioner Schmeltzer, and Commissioner Fellman.

Members Absent: None

Vice-Chair McGoldrick noted that Gloria L. Young, Executive Officer, Donald Maynor, Esquire, and Nancy Miller, Esquire were present.

2. San Francisco Local Agency Formation Commission (SFLAFCo) Public Hearing on Electric Service Options.

Morning Session: 9:30 - 12:30 p.m. Representatives of Pacific Gas and Electric Company (PG&E).

Donald Maynor, Esquire stated that the two speakers today from PG&E would be answering questions that were prepared for them. One of the questions dealt with the bankruptcy issue and because of the sensitivity of that issue, the legal department prepared a response, a copy of which had been provided to the Commissioners. If the Commissioners have questions on a particular subject that the two speakers are talking about, the speakers agreed to answer the Commission’s questions. We’ll get started with David Rubin. David Rubin is a director in the Rates and Accounts Services. He has been with PG&E for eleven years. He has a Bachelor of Arts from University of Maryland in Engineering, a Master of Science in Mechanical Engineering from MIT, and he has spent a few years working with the City of San Francisco in City Planning and Bureau of Energy Conservation.

Commissioner Ammiano apologized and stated that Commissioner Hall and he would be leaving in the next twenty minutes in order to attend a Golden Gate Bridge District meeting and then will return. There are three Commissioners here and that would constitute a quorum.

Donald Maynor, Esquire concurred that three Commissioners would constitute a quorum.


David Rubin, Director, Service Analysis, Pacific Gas and Electric Company stated that PG&E appreciates the opportunity to address the Commissioners this morning, to respond to the questions that you have provided so far in writing, and then whatever other questions you would like to bring up in the course of the discussion. What they intend to do is use some overhead material in order to address the questions that you have provided so far. So they will speak to those questions. We estimate approximately 15-20 minutes of discussion time on those points and obviously to the extent that you have questions on our responses, please feel free to bring them up either as we go along or after we’ve walked through the material. The first slide. What we’ve done here is put the questions that you have provided to us to the top of the slide and provided some summary points that Mr. Kevin Dasso and I will both speak to. The first question has to do with PG&E’s position on community aggregation, specifically whether we support the concept and proposed legislation that would enable community aggregation. The answer in both cases is yes. We support the proposal for cities to be able to aggregate the load of customers within their jurisdiction and to become the default provider of power for those customers. There is a bill that is currently before the legislature now, AB 117 from Member Migden that would enable this concept to take place. It would provide the City with an opportunity to address some of the energy issues. As far as the legislation, as he understands it, it is in the second house in the Senate. He understands it may come up for hearing some time in May and June. He is not sure if there is a particular scheduled date at this point, but we do support the legislation. Next slide: The next slide gets to a technical issue around aggregation. If San Francisco were to assume the responsibility for power purchases, should it be concerned with the transmission bottlenecking in San Francisco and the fact that there is essentially one large owner of generation in the City? Mr. Dasso will speak to the transmission issue in just a moment. As far as this particular set of circumstances and how it might impact aggregation, as I understand it, there are still a lot of moving parts in terms of what the market design will be going forward. The California ISO is in the process of preparing a market design proposal before the Federal Energy Regulatory Commission. So it is a little bit difficult at this point to speculate exactly what that design will look like and whether that design will have implications for any particular aggregation proposal that the City might develop if the Migden bill would be enacted and signed into law.

Donald Maynor, Esquire asked if Mr. Rubin had a sense of what the general proposal is for California.

David Rubin stated as I understand it, I believe that the ISO is looking at a greater number of so-called zones or nodes that might make them a little bit more geographically specific. Mr. Dasso, please feel free to chime in if you want to amend my comment. To the extent that they are more geographically defined and assuming that the City would then take on the procurement responsibility to the extent that there is a congestion path, and by that meeting, some type of a deficiency in the upstream side of the path. There may be some cost consequences associated with pricing across that zone. That probably covers the extent of my knowledge. Now, I know that the ISO again is developing this proposal that would ultimately need to be approved by the Federal Regulatory Energy Commission. There are still several steps between now and when that is ultimately approved that would govern how this specific design might impact procurement decisions made by the City. The same would hold true with respect to in-City generation.

Commissioner Schmeltzer asked Mr. Rubin if he could give the Commission a better idea of some design features that might signal particular congestion problems for San Francisco versus design features that wouldn’t and what you might expect to see.

David Rubin stated the model is, as we understand it is as David mentioned implements more zones than the ISO currently has in its congestion market. The real key issue for San Francisco and other participants in the market would be where those nodes and zones are designated. As of this point, the ISO hasn’t identified that specifically. They’ve really presented a framework and a concept that is generally consistent with one of the ISO’s that has been operating fairly effectively in the East Coast. At this point, there really isn’t much we can comment on because we don’t know the specifics of how those zones are set up. How those zones are drawn would really be the factor that will determine whether there are any cost consequences or congestion issues that could arise.

Donald Maynor, Esquire stated let’s assume that the ISO did place San Francisco in a market area or a zone that was deemed to be heavily congested-what is the proposal in terms of rates? Are you talking about transmission costs? That is essentially what the ISO gets involved in. How does that work when you said that there may be some cost consequences under the ISO proposal? Let’s assume that you are in a heavily congested zone, how does that work?

David Rubin stated I don’t know the details of how they would mitigate that congestion. Right now, actually in the current market design, the ISO runs what they call a congestion model. Essentially, they ask for generators and scheduling coordinators who are scheduling load for their customers to identify where they would like to send and which paths they would like to send that energy across. If they identify any congested paths, they then ask those schedule coordinators and marketers to readjust their schedules. In some cases, that can be done without cost. In other cases, it may require some type of incentive to have those parties readjust their schedule. Again, unfortunately, I am not familiar enough with what the ISO is proposing to know exactly how they would propose to mitigate any of that type of congestion.

Donald Maynor, Esquire stated whether or not you are going to have aggregation, San Francisco would be in the same position whether it was PG&E or if San Francisco were to assume aggregation, bringing power in from the outside, importing it over a path that was congested. And let’s assume the FERC would approve some rates that would be high priced in order to encourage the correction of the congestion. Isn’t that the idea--to place some higher costs on those congested areas so it generates some monies to improve those areas?

David Rubin stated I will address the first part of the question first which is would there be in fact a difference in the cost responsibility for San Francisco whether it were aggregating or not. My understanding is that, in fact, if PG&E were to continue to procure power, our costs generally are rolled in among all of the customers within our service territory. To the extent that PG&E is still procuring power and to the extent that there are costs associated with the particular congestion path wherever it may reside within the service territory those costs are paid for as part of the distribution rates that all customers pay. What’s not clear is whether or not that paradigm would then change under a City procurement model. I guess there is a possibility that it may end up then becoming more of a direct cost responsibility for San Francisco if it were taking on the responsibility for procuring power. But again, that’s really speculation at this stage without really knowing more about this specific design proposal.

Mr. Kevin Dasso stated that with respect to the cost and the design, the objective of the design would not necessarily be to increase cost, to address that. It would be to resolve that congestion. In many cases the congestion can be resolved just by changes in schedule and or market participants that are participating there taking those constraints into consideration. They would want to avoid any type of opportunity to just basically reduce that congestion cost either way. It wouldn’t necessarily result in higher costs, but you would have to factor in those constraints into your schedules. Largely, one of the objectives is to encourage more long-term contracts and other types of things that allow you to avoid that congestion ahead of time, as opposed to waiting for it to materialize in the real-time market, which can create havoc.

Vice-Chair McGoldrick pointed out that we are joined by our Chair, Commissioner Matt Gonzalez.

Commissioner Fellman asked, if in your presentation, are you going to address the physical transmission system coming into the Peninsula and some of the inherent constraints from an engineering perspective?

David Rubin stated that is our next question.

Commissioner Fellman stated that she would hold her questions until then.

David Rubin stated that if there are no further questions on this particular response, we will move on to the next question, which in fact does address the transmission system.

Kevin Dasso stated that I would happily take any additional questions if I don’t cover it in my remarks here.

Commissioner Schmeltzer asked if you are finished talking about everything you meant to mention on there. I was wondering what other regulatory decisions in particular you were referring to on that slide.

David Rubin stated that as a general matter, there are still decisions that would need to be implemented vis-a-vis how aggregation is actually played out because the bill that would currently enable aggregation, AB 117, still has the Public Utilities Commission making certain decisions vis-a-vis its implementation. So this is more or less a categorical. There are still some other pending decisions that could end up impacting exactly how aggregation would play out within San Francisco.

Commissioner Fellman asked, from PG&E’s perspective, can you give us a thumb-nail sketch of how you would see aggregation working should this bill pass?

David Rubin stated as I understand the legislation, the City per the bill would have the opportunity, through an ordinance, to implement aggregation on behalf of the citizens of San Francisco. The basic concept of aggregation would be consistent with the direct access rules that were in place up to the point where the Public Utilities Commission suspended direct access as of September 20th. So what that would mean, is that the City would be able to procure power, and the power would be delivered over PG&E’s system. And, there are certain rules within various sections of the Public Utilities Code as well as Public Utilities Commission rules, specifically, Rule 22, that relates to direct access. So City aggregation, as I see it would essentially be a sub-set of direct access. The City, after having passed the ordinance, would then provide notification of its intent to procure power on behalf of the citizens within San Francisco. And the way that the bill was currently drafted, there would be, I believe, at least one notification so that any customer had by receiving advanced notification chose not to have the City become the default supplier of power, they would be able to opt out. There would also be subsequent notifications, I believe, even after the procurement took effect so that customers would still have the opportunity if they so chose, to select PG&E as the default provider of power. But absent any type of affirmative decision by customers, they would then become power procurement customers of the City.

Commissioner Fellman asked what costs would be paid by the City to PG&E under an aggregation program?

David Rubin stated the costs that would be paid to PG&E under an aggregation program would be the costs associated with the delivery of the power from whatever sources the City were to choose to procure power from. There would also be the responsibility to pay the so-called non by-passable charges, which are those associated, for example, with the contracts that we have with qualifying facilities that were negotiated back in the mid to late 1980’s, as well as whatever additional cost the Commission might include that are associated with the procurement costs that were incurred over the course of the last eighteen months, most notably by the Department of Water Resources. In fact, there is a Commission proceeding that is ongoing now relating specifically to the direct access customers that were taking direct access as of September 20, 2001, which was when direct access was suspended in terms of what their costs responsibility would be for those procurement costs. And there would also be public purpose program charges that are again a non by-passable charge for all customers.

Donald Maynor, Esquire asked, essentially the costs to the aggregator would be your distribution charge, the ISO charge that would be paid directly to the ISO, and then the non by-passable charges?

David Rubin stated that was correct, distribution, transmission, the public purpose program charges, plus the other non by-passable charges as implemented by the Public Utilities Commission. Onto the next slide which does discuss the transmission issue. I will turn it over to Mr. Dasso to address transmission.

Donald Maynor, Esquire stated that Kevin Dasso is the Director of electric transmission in the Distribution Engineering Department. One of his responsibilities is transmission and distribution system planning, which includes identifying and developing system upgrade and reliability improvement projects. Kevin received a Bachelor of Science degree in electrical engineering from Iowa State University in 1981 and a Master of Science degree in electric engineering from Santa Clara University in 1991. He is a registered professional electrical engineer in California and he joined PG&E in 1981. He has held various positions in transmission and distribution planning, engineering, operations, maintenance and construction and he has held his current position since November of 1999.

Kevin Dasso stated that by way of introduction, I want to reiterate that PG&E is committed to providing safe, reliable electric service to the citizens of San Francisco. With respect to the distribution system to assure this, PG&E invests about $50,000,000 annually to maintain and expand its distribution system. In a recent survey that was released by the Salt River project in Phoenix, PG&E’s electric service reliability in San Francisco rank in the top 1/3 of thirty major U.S. cities. With respect to transmission, PG&E has invested approximately $30,000,000 over the last three years and plans to invest another $27,000,000 over the next two years to expand the transmission system by approximately 200 megawatts. In February of this year, PG&E requested that the California ISO approve the construction of a project called the Jefferson Martin project, which is a major new transmission line coming up the Peninsula, which will expand the transmission system capacity by about 400 megawatts at a cost of approximately $200,000,000. This project was considered and discussed in the City’s draft energy plan, which was recently issued for comment and review. With respect to Hunter’s Point, just to reiterate, PG&E is committed to closing Hunter’s Point as soon as possible. The timing of that decision would really depend on the California ISO and their valuation of the need for that plant for the reliability of San Francisco and the Bay Area. PG&E believes that the Jefferson Martin project, that we recently requested approval from the ISO, that completion of that project would allow the Hunter’s Point power plant to be closed without any adverse impact on the reliability of San Francisco or the northern San Mateo county.

Commissioner Schmeltzer asked, how long is the Jefferson Martin project expected to last-when is it expected to be complete?

Kevin Dasso stated we are currently expecting to have it completed by the fall of 2005. All of that would depend on the permitting process. That project requires a specific permit by the California Public Utilities Commission in order for construction to begin. That process will start with an application that PG&E will file in about September of this year.

Donald Maynor, Esquire asked what the status is with the FERC process on your project. Has it been approved or is it in the approval process?

Kevin Dasso stated that with respect to FERC on transmission expansion projects, they don’t actually consider those projects until after they are constructed, so we don’t receive any prior approval. However, we generally have assurances that if the expenditures were made prudently and for purposes of benefits of the grid that those costs would be recovered in FERC rates.

Donald Maynor, Esquire, asked if the only regulatory hurdle that you have to go through is the PUC process?

Kevin Dasso stated that is correct.

Commissioner Fellman asked, has that line been discussed in the CPUC’s transmission system reliability investigation?

Kevin Dasso stated actually, it has been discussed a couple of times in an investigation that the CPUC has had into transmission, basically the transmission system in California twice. The Commission has elected to allow PG&E to proceed on the schedule and hasn’t determined that any additional efforts are needed on their part in order to move that project forward or investigate. We have met recently with, I believe, someone who will be addressing the Commission later this afternoon, Barbara Hale, regarding ways in which we can assure an expedited or just effective and timely permitting process and members of the City staff, the Attorney’s Office, and the San Francisco PUC joined us in that discussion.

Commissioner Schmeltzer asked, what is the relationship between the filing of the ISO that you made two months ago, is that right, and the filing of the PUC in the fall?

Kevin Dasso stated that for transmission projects of this type, we have to, under the current tariff that we operate under with the ISO, we have to gain their approval for any type of grid expansion like this. So we have to seek their approval. We are currently assuming and moving under the basis that they will approve the Jefferson Martin project so we are preparing our environmental assessment that we need to file in September. We need to get the ISO’s approval, but we are also moving forward on developing all of the environmental work and preparing what’s called a "Proponent’s Environmental Assessment" that we need to file along with our application for a certificate this Fall at the CPUC.

Commissioner Schmeltzer asked, so you need an approval from the ISO before you can file with the PUC?

Kevin Dasso stated that is correct.

Commissioner Schmeltzer asked, and you expect to get that this summer?

Kevin Dasso stated it’s currently on the ISO’s agenda for April 25th. We hope that they will consider it and advise us about that project at this time.

Donald Maynor, Esquire asked, is there any objection or opposition to the project?

Kevin Dasso stated at this point, we are not aware of any. Typically, where the real issues begin to come out as you begin to look at the actual routing and the neighborhoods that will be effected and so on, that is beginning now as we are preparing our environmental assessments. So far, if I could take a step back, the California ISO conducted a transmission planning stakeholders group that was intended to develop a long-term transmission system plan for the San Francisco Peninsula in 1999. That study group worked for about a year in a very open and public forum, sought comments from lots of interested parties, and the recommendation from that study group was to proceed with this Jefferson Martin project. So far, we have not seen any major objections to that; however, oftentimes the objections come in the actual routing of the project.

Donald Maynor, Esquire asked, what is the size of the improvement? What is the current transmission capacity and what will it become as a result of the project?

Kevin Dasso stated that the project will add about 400 megawatts of additional capacity into San Francisco. We also believe that once that 400 megawatts capacity is added, we believe that the Hunter’s Point power plant can be shut down without impacting reliability in San Francisco.

Donald Maynor, Esquire asked, is that path the only path importing generation outside of San Francisco?

Kevin Dasso stated actually one of the benefits of the project that we are proposing and one of the things that the stakeholder group saw as a benefit to this project was that in fact it provides an energy path from another source. Currently, the transmission facility serving San Francisco come up essentially parallel Highway 101 from the San Mateo Coyote Point area past the airport and into a substation right on the edge of the City’s borders. This project actually starts in a substation near Redwood City and Woodside so it essentially parallels I-280 so we get a second source into San Francisco, which we believe further enhances reliability.

Donald Maynor, Esquire asked, what would be the total capacity of both sources then?

Kevin Dasso stated the transmission system in San Francisco is somewhat unique in that it there is actually a combination of in-city generation and transmission system capacity that you have to consider. The capacity is also driven largely by planning by the next contingency to the loss of one of those transmission elements or generation facility or whatever. So, the actual capacity varies depending on the actual circumstances. But, it is our projection that with the Jefferson Martin project there would be adequate transmission capacity for at least the next five to seven years. Much of that will depend on the load growth here in San Francisco and additional generation or any generation development that occurs here as well.

Donald Maynor, Esquire asked, theoretically, what is the capacity on both the lines recognizing that operationally you may not be able to bring it all in?

Kevin Dasso stated that after the project it would be approximately 1400 megawatts.

Donald Maynor, Esquire asked, with both lines?

Kevin Dasso stated with actually more than two lines. Right now there is one 230,000 volt line that comes up the Peninsula and five 115KB lines that come up. There are actually six lines that are currently serving San Francisco. This would add an additional 230,000-volt line on a different route.

Donald Maynor, Esquire, asked, when you finish the project, who owns the project and how do you get it paid?

Kevin Dasso stated this project would be owned by PG&E and the cost associated with the project would be recovered with rates that are set by the Federal Energy Regulatory Commission and would be paid for by all users of the California ISO grid. Because of the size of this project and because it is a regional project, those costs would be spread across northern and southern California. Projects in excess of 200,000 volts are considered regional projects and therefore recovered by all users, essentially all customers in California.

Donald Maynor, Esquire, asked, so currently the PUC basically spreads the costs system-wide?

Kevin Dasso stated that is correct. In addition to that, for this project, it would actually spread those costs across not just PG&E’s customers, but also customers of Southern California Edison and San Diego.

Commissioner Fellman asked, are the costs something that the bankruptcy court would have to approve?

Kevin Dasso stated that would depend on the timing of the project and what PG&E’s status is in regards to the bankruptcy court. The current rules with capital expenditures in the bankruptcy court require approval for expenditures in excess of $50,000,000. However, we are not planning to actually spend large amounts of capital on that project until probably about 2004, and the degree to which the bankruptcy court would be involved in any decisions would be a function of what PG&E’s status is at that time. Mr. Dasso asked if there are any other questions on this topic.

David Rubin stated if not, then we can move onto the next slide/question. This next question addresses how electricity will be purchased in the future. In terms of what some of the outcomes are, we have identified really two; there may be others. At least initially, either the City continues to receive a power mix of resources that are available today, which include Hetch Hetchy power for the City load; PG&E procurement which is what I will address in a later slide, which includes generation assets that PG&E owns as well as the qualifying facility contracts. Also included here would be the procurement by the State Department of Water Resources and then whatever in-city generation there is. Meaning specifically, generation on the customer side of the meter. That is one scenario. The other scenario would be that the City would in fact implement aggregation based on the pending legislation, which would essentially displace the PG&E procurement portion so there would still be Hetch Hetchy power for the City load and whatever onsite generation there is within the City. Under either one of those two scenarios, there probably will be additional on-site generation for customers to choose to put what is called distributed generation on their side of the meter. And so for example, Propositions B and H that enable funding for various types of say renewable projects, would produce additional generation on site. In that regard, PG&E did voice support for those propositions. We have been working over the course of the last two to three years as part of a Public Utilities Commission and California Energy Commission process to streamline the interconnection rules, meaning the rules that govern how our system interconnects with generators on the customer side of the meter. And we also make available financial incentives for different types of clean distributed generation projects that were provided under AB 970 from a couple of years ago. So, through our service territory we spent about $60,000,000 a year over the next four years as financial incentives for various types of distributed generation projects. There are additional funds that are made available by for example, the California Energy Commission and the California Power Authority is now looking at spending money for different types of distributed generation projects. So, we anticipate and we have seen over the course of the last year an increase in the number of projects that customers are installing on their side of the meter. Obviously, all of the things being equal, on site generation would then reduce the amount that has to be procured from other sources.

Commissioner Schmeltzer asked, could you tell us what AB 970 monies PG&E has used so far and what is left?

David Rubin stated the AB 970 money is provided statewide $125,000,000 a year for the next four years. Actually, AB 970 provided the authority for the Commission to then implement and the Public Utilities Commission then issued a decision that provided those amounts. Of that $125,000,000, $60,000,000 is spent by PG&E. So that’s $60,000,000 for four years. As I understand it so far, and this was put into place I believe in June of last year, we’ve provided funding or at least approval for funding for about $45,000,000 worth of projects in our service territory. I believe there had been four applications in San Francisco that have received funding of approximately $2,000,000 representing about 2 ½ megawatts of on-site generation so far.

Commissioner Schmeltzer asked, what types of generation?

David Rubin stated they fall into three different so-called tiers of funding, and the tiers differ according to the dollar per kilowatt that could be provided per project as well as the total cap on the project. So, I may be a little bit off on the facts. But generally speaking the tier, I believe is three projects, which are the top tier receive $4.50 per watt or $4500 per kilowatt up to 50 percent of the cost of the project. I can get more details on this program that provide the precise numbers. I am providing this off the top of my head. These would be renewable projects, generally solar projects, wind projects. I believe fuel cells using renewable fuels fit within this category as well. The second tier would be fuel cells not using renewable fuels, meaning using natural gas and they receive up to $2500 a kilowatt and I believe roughly up to 40 percent of the project cost. Then the last tier would be different types of say combustion turbine, micro-turbines, internal combustion engine projects that use waste heat recovery. So these are really meant to induce different types of clean technologies, either renewables or projects operating in a combined heat and power mode. The project size I believe is limited to 1 to 1½ megawatts maximum size per project.

Commissioner Schmeltzer asked, so the four applications in San Francisco, do you know which tiers they fell into or is this too much detail?

David Rubin asked, you mean which categories they fell into?

Commissioner Schmeltzer asked, were those Tier 1?

David Rubin stated I believe one was a fuel cell and I believe the other three were internal combustion engines.

Donald Maynor, Esquire stated that we had some speakers at our last public hearing that talked on distributed generation, energy efficiency. And one of the things that they all spoke on was the need for audits to find out what the potential was in a San Francisco. For example, does PG&E have an ongoing audit program to find out potential co-generation users? If not, is this 970 money that you spoke about, is that available for San Francisco to perform those types of audits to try and find out what the potential might be?

David Rubin stated my understanding is that the monies, that at least I have discussed here so far, which are provided under a particular sub-section of AB 970; unfortunately, I cannot remember the exact subsection. AB 970 actually provided a lot. I am referring to a particular program element of 970 and those monies again, per the Public Utilities Commission decision, were really meant to provide financial inducements for specific projects. Now there is some amount of the $60,000,000 that is set aside to do audits of or measurement evaluation of the projects that are installed under the program. In terms of actually stepping back and trying to ascertain what the potential penetration for distributed generation in San Francisco is, I don’t believe those monies would be usable for that purpose. That having been said, and I will confess I am not familiar with the details. There may be other provisions under the AB 970 that are available. For example, as I will speak to in a later slide, I believe the City received monies that the Public Utilities Commission dispersed that were made available essentially per AB 970 for different types of energy efficiency projects. So, I know that AB 970 provided a wide range of different types of programs to help again for purposes of increasing the efficiency of energy use or increasing the amount of distributed generation. I am going off on a whim to speculate that there may be some authority under that bill perhaps to provide that type of evaluation.

Donald Maynor, Esquire asked, you don’t have an ongoing audit program that performs that kind of audit work?

David Rubin stated when you refer to audit, what I tend to think of as audit is actually auditing the results of programs that are put in place, which would be a somewhat different function than evaluating what the penetration possibilities are.

Donald Maynor, Esquire stated that I may have used the wrong word, but you do not have a program that does that analysis of the potential in San Francisco, for example.

David Rubin stated I would need to confirm my understanding. There may have been some of that work that was done when we were given the authority to go ahead and spend these monies. I know that generally speaking we have made information available across the service territory that these dollars are available. I don’t know whether in fact before having done that we did any market assessment, which I think is probably what you are referring to.

Chair Gonzalez asked, I want to back up and ask you perhaps to give me a little bit of the context for how we can do things in the future with how things were done in the past. Specifically, I am wondering if you could kind of break down for me how PG&E’s role in this business has changed once deregulation happened.

David Rubin asked, role in the power procurement business specifically?

Chair Gonzalez stated also any other issue that you think was significant related to deregulation.

David Rubin stated stepping back our obligation had been for a hundred years before 1995 or really 1998 had been to invest in generation facilities. Now obviously the transmission distribution obligations remain, but the Commission started a process back in 1992 continued it up until 1995 to look at getting utilities out of the business for being responsible for power generation. Up until that point we had an obligation to plan for and make investment or procurement decisions to serve all the load within our service territory. As part of the Public Utilities Commission process, they were looking at different industry models and ultimately in late 1995 issued a decision that provided for us to get out of that business. So we were provided as part of the Commission’s policy decision, the transition period to have us step back out of the role and have independent providers step in. And that process really you can sort of argue began back in 1978 with the Public Utility Regulatory Policy Act, a federal law that provided independent power producers an opportunity to sell power to utilities. As a consequence of that law as it was implemented in California, quite a bit of our power portfolio was then provided by independent producers qualifying facilities selling power to us under various types of long-term contracts.

Chair Gonzalez asked, what was the primary rationale for believing that this was necessary?

David Rubin stated as I understand, I was away from PG&E and away from the country during the period when this all began. It was driven by a concern that rates in California were higher than in any other parts of the country. One of the reasons was that regulation was the cause, that regulatory system was in some way shape or form broken. By providing a competitive market opportunity to replace regulation for generation, we would end up seeing additional services and lower prices. That is my understanding of what prompted the Commission to move down this path.

Chair Gonzalez stated that when you say that though the idea of getting the utilities out of generation was that the effect or was that the purpose? In other words, was it simply to allow for independent providers who could come in and also engage in the act of generation, or was it mandating that you not be involved in that?

David Rubin stated it was both an opportunity for independent providers to provide power, and it was also through the various provisions of the policy decision a desire to have us divest power plants and not build new ones. So, there were both pieces to it. They were opening the market to independent power providers to then develop generation plants and really giving us very strong signals that we were to divest ours and not construct new ones. And also as I will get to in a minute in the explanation, not engage in long-term contracting to procure power. So not only not build new power plants, but also not continue the responsibility of contracting long for power.

Chair Gonzalez asked I take it PG&E was in favor of this?

David Rubin stated no we were not. In fact we filed for an application for rehearing on the Commission’s policy decision that was issued in late 1995.

Chair Gonzalez asked, from the point of your industry though, wouldn’t this take out the greatest risk component to what it was that you were engaged in? Doesn’t it relegate essentially to being concerned with transmission?

David Rubin stated I can’t really speak to whether it would take out the greatest risk component of our business because the business was at that point and time regulated on a cost of service basis. There were always risks. Our rate of return was set based on the risk profile of the business. But, I don’t know that generation necessarily presented any greater or lesser risk than any part of the business. But certainly to the extent that we would no longer be in generation then it would have narrowed the focus of what our business model would remain which was transmission and distribution.

Chair Gonzalez asked, now the opposition that you had to this proposal was it based on the fact that you would be participating in less components of the market, or what was the argument that you put out?

David Rubin stated I have to go back and review exactly what the elements of our objection were. We just didn’t believe that the Commission’s proposal was a workable one and or work for us. I just don’t have a full recall of exactly all the pieces of our objection--but we did object. With the Commission’s policy decision and then subsequently the legislature passed a bill AB 1890, that codified some elements of the Commission’s plan, changed a few elements of it, but by and large kept the major pieces intact. We did, by the way, support AB 1890. The reasoning behind our support for AB 1890, as opposed to the Public Utilities Commission decision, was really a recognition that something was going to happen whether we fought it or not, and that AB 1890 represented a better balance of some of the elements than the Commission’s policy decision. That bill was passed in the Summer Fall of 1996, signed into law. At that point, the market opened in 1998. What was provided again by the Commission’s policy decision, as modified by AB 1890 was a transition period for the utilities to have the opportunity to recover the costs associated with the power plants that we had built prior to the rules having changed. So it gave us a chance to accelerate the depreciation of those plants and again, really transition from a regulated cost of service obligation to serve model by the utilities, to one where customers would be able to buy power from whomever they chose. We were really stepping backwards out of that business. As I mentioned, AB 1890 changed some things but, quite a few things that were part of the market structure were in the Commission’s policy decision. The strong encouragement for us to divest our power plants was from the policy decision. The requirement that we sell all of whatever power we continued to generate and buy all of the power that we needed from the spot market was from the Commission’s policy decision. What AB 1890 did is shorten the transition period essentially and provided some other changes, provided the statutory authority for setting up the power exchange in the ISO. So that set in motion again the work toward restructuring the market place that was then ultimately put into place in January of 1998 and ultimately then delayed until March 1998. So, from that point forward, our role was to again step backwards out of the generation business and to be essentially a provider of last resort for our customers by buying power out of this spot market. I can at that point fast-forward to what happened during the crisis, which was that the wholesale prices in the spot market went way out of control. We did over the course of the years request on numerous occasions the opportunity to procure power through longer-term contracts so that we could hedge the risk that is associated with buying all of your power out of the short-term spot market. We weren’t really granted that authority until August of 2000, and even then and up until today, we still haven’t gotten any standards of reasonableness around our ability to buy power on a bilateral basis to hedge the price risk that was associated with the spot market. Nonetheless, we did in fact lock into a number of contracts in the fall of 2000, but as I mentioned even to this point today, the Commission hasn’t implemented rules around how those types of procurement decisions would be judged. There is a proceeding that is ongoing before the Public Utilities Commission today to look at procurement rules now for utility procurement. I am happy to answer other questions. I think everybody knows then what happened as a consequence of those high prices. We were locked into frozen retail rates, were not provided the opportunity to pass the costs along associated with the wholesale power market, and incurred a fairly significant nine-billion dollar under recovery of costs, which led us to then pursue bankruptcy as a means by which we could try to resolve this problem. So I do not know if that provides the context that you were looking for or if there’s more.

Chair Gonzalez stated yes, and I thank you for that. To what extent is the effort to get out from under direct access almost like going back to the let’s say the opportunity that deregulation provided, but with the very clear message to municipalities and anybody else that is interested, that they should be in the business of trying to arrange long-term contracts?

David Rubin stated when you refer to direct access, do you mean the aggregation proposal that we discussed earlier?

Chair Gonzalez stated, yes.

David Rubin stated we recognize that San Francisco and other cities within our area in fact would like to at least explore the possibility of taking on the obligation of buying power. From our perspective, we welcome that opportunity to the extent that cities want to take that obligation and risk on. We feel that the rules should be put in place in order to allow cities to make that choice. Our company’s position has really been continuing to be supportive of customer choice in this area.

Chair Gonzalez stated let me ask you in a different way--maybe that didn’t make sense. Presumably, when the market opened up, and you no longer had anybody that was responsible for let’s say long-term planning, right, the whole business of building new generation and trying to make investments with the thought of what the demand would be sometime in the future. I mean I suppose that there is risk involved in that. To the extent that deregulation takes you out of that process when the market opened up, what prohibitions were there in place that would not allow a municipality or anybody else that was interested from aggregation at that moment?

David Rubin stated cities could aggregate according to the way that the direct access rules were put into place. What is different about the proposal that is in the Migden legislation, is that the manner is which cities could aggregate prior to that new proposal is that they would need to go door to door. They could aggregate customers within their area, but they could do so by positive election in. The proposals that are part of AB 117 would really reverse that in a way, so that essentially the City would become the default provider of power unless a customer chose not to be part. So, the direct access rules that were put into place back in 1998 would have allowed a City to aggregate, and some cities did go forward with proposals. I believe San Francisco was one of them and Palm Springs was another. But the issue was you needed to then get customers to affirmatively sign up, which is a costly and time-consuming process. The proposal in the form of AB 117 would reduce those transaction costs very significantly. Does that get to your question?

Chair Gonzalez stated, yes it does. I am just sitting here reflecting. I think when the pitfalls of deregulation happened and everybody looked around and tried to figure out, how did we get here, what should we do in response to that? There emerged a lot of different definitions of what public power was, and how that could be implemented and what benefits a city would get with public power. I think in a lot of ways the current discussion around aggregation and the ability of the City to engage in that and because a municipality would be taking their future into their own hands, that somehow this is giving power to the people, and this is public power. To me, it just seems we are imposing a concept that meant something very different let’s say, even a decade ago and pushing it to fit into our repair of deregulation. While that may be good because we need a repair for this particular thing, I’m not sure that it seems to me to a certain extent a distraction from the greater issue out there which is, we’ve heard from representatives in different municipalities that obviously have different systems where they have greater ownership. Ultimately, that’s the bottom line, and I appreciate the remarks you are making. I appreciate that you have come here. When I hear that you are investing quite a bit of money yearly in distribution, transmission, and you’ve got plans for generation now even post deregulation as part of the repair. I mean I think that’s all good, but it seems to me, and I am saying this more for my colleagues than for you. I don’t want to be totally distracted from those other issues because even with this kind of repair we end up in a situation where you are still paying somebody else to do something that, depending on what the investment is and the cost of maintaining transmission lines or what have you, that’s where it would seem to me would be the largest place for savings in the process. We know that because that is where industry is able to make a profit and continue what it is that it does. I don’t know if I am making sense. You don’t have to respond to that, Mr. Rubin. Let me ask you this seriously. Just to lay out a point. Presumably a City could get engaged in an aggregation and save money at it because we are not going to be at the whim of the spot market and we’re going to get to take our destiny in our own hands I suppose. That appears to be the public power model that is out on the table right now in the public discourse. Am I missing something?

David Rubin stated I think that is part of what is on the table. There is quite a bit of discourse as you are well aware on public power issues, and I don’t think anybody is necessarily, at least from my perspective, thinking that this is somehow taking center stage. It is an option that is available or at least will be available if the bill passes.

Chair Gonzalez stated well, I am thinking of the way the press responded to some of the initial overtures in couching this as public power and we’re moving forward and the city is going to play a larger role and wow, PG&E is actually supportive of this larger role. It just seems to me that that larger role that we are all talking about is really a repair to this disaster that happened. While there may be public participation in the repair and public control and decision making related to that, it is a very different discussion than what the public power discussions were prior to that, which were really about explain to us why the City has Hetch Hetchy, and has the ability to create generation and invest in that, and try to meet our own demands? What are the pitfalls of doing that? Why is there an argument that PG&E does that better than we can do it? When we hear from municipalities, certainly they are different, they have different needs; they have different problems what have you. Nevertheless, certain models have managed to work for those municipalities, and I think that is what ultimately I see as more of a discussion of what public power is. You would agree with me that that was the way the discourse was centered in the past?

David Rubin stated correct in the past the discourse at least prior to deregulation of the power market, was always focused on either an investor owned utility or a publicly owned utility for everything.

Donald Maynor, Esquire stated I had some questions concerning PG&E’s current ability to engage in procurement. You indicated there were some limitations that you are going through in a proceeding at the PUC. Obviously with the end of direct access and PG&E’s financial problems, do you have current limitations on your engaging in procurement now, and what is going on at the PUC with that process? What are you asking for at the PUC in terms of allowing you to be in the procurement business in a functional way?

David Rubin stated I have a slide that partly speaks to that but I am happy to just go ahead and answer the question now.

Donald Maynor, Esquire stated if you want to answer that now, that’s fine. I had another question on the investment and distribution system, the $50,000,000. How much of that or any of it is related to under-grounding of utilities?

Kevin Dasso stated that about 8,000,000 million of that is related to underground utilities.

Donald Maynor, Esquire stated you can answer the other question later if you would like.

David Rubin stated you know it’s not much further behind. If you don’t mind, we’ll move right through and I’ll get to in probably five minutes or less.

Vice-Chair McGoldrick asked, that $8,000,000 for under grounding, has that been put in abeyance? Have you suspended your under grounding operation?

Kevin Dasso stated no, actually that’s moving forward.

Vice-Chair McGoldrick stated and you are moving forward at the same rate that you were moving forward prior to the energy crisis, well your bankruptcy of course above all?

Kevin Dasso stated I would say actually immediately prior to the bankruptcy filing, we are actually moving at a faster rate than we were at that time.

Vice-Chair McGoldrick stated and you are only speaking about San Francisco?

Kevin Dasso stated that is correct.

David Rubin stated that the next slide addresses the energy efficiency programs that we offer and the extent to which the City is taking advantage of those programs. What I have identified on this slide is the fact that in fact San Franciscans are taking advantage of our programs in a way that actually exceeds in these various program categories the amount of funds that the citizens within San Francisco were contributing to the funding. Roughly speaking, about six percent of the total public purpose-program funds are provided by citizens of San Francisco. That is on a system service-territory wide basis. Through those funds, we provide a number of different types of energy efficiency programs, which involve for example, rebates for different types of investments in energy efficiency, different types of energy efficiency management services, for example audits and information. Then last year in particular we really upped the money that was available for more efficient refrigerators pursuant to SBX5, which was a piece of legislation passed last year. Even though San Franciscans generate again about six percent of the total funds for these programs, they benefit to the tune of about seven to eight percent, depending on the category. If you just simply look at the amount that San Franciscans pay in to the amount that San Franciscans pay out, they actually get more out than in. Now that’s not to say there is still additional room for customers to avail themselves of our programs even more fully. In that regard, we are working with the City, and I believe the Department of Environment and others on the monies that San Francisco received that were dispersed by the Public Utilities Commission pursuant to the same bill that we discussed earlier, AB 970. Where I believe the City got funding in the range of about eight to ten million dollars. The monies are going to be used for various types of lighting strategies for small businesses. We are working very closely with the City and looking for ways to implement that program.

Commissioner Schmeltzer asked, do you have a sense of what the participation rate is in San Francisco compared to other parts of your service area?

David Rubin stated generally speaking, San Franciscans contribute about six percent from the total monies and across these program categories, benefit to the tune of about seven to eight percent depending on the category.

Commissioner Schmeltzer asked, when you say six percent, is that six percent of the total funds or six percent of the eligible customers?

David Rubin stated it is six percent of the total public purpose program funds that emanate from San Francisco. About seven to eight percent actually flow back to San Francisco across our service territory.

Donald Maynor, Esquire asked, is there an outreach program, again I called it the audit, but again we were getting this testimony last time? It just sounded like they were all suggesting that for these programs, to maximize their efficiency, you need to actually actively go out and investigate what the potential is. More than simply having the programs available or on the Internet, there needs to be more of an active program to fully take advantage of it.

David Rubin stated and maybe I misunderstood but the last time you used that same term. With regard to energy efficiency, we do engage in active outreach throughout our service territory in the form of different types of information and campaigns that are provided, as well as soliciting input from customers on what types of programs they would like to see.

Donald Maynor, Esquire asked, what about going out and visiting facilities? That’s why you use an energy audit where they to go in and look at a building because the owner may not even recognize what they are capable of doing to achieve energy efficiency. In this facility, you could say, if you did the following things you could save the following amounts of monies. Is that kind of a program useful? Is that something that you do now? Or is it always initiated by the customer?

David Rubin stated the energy management services category really includes things like audits of different types of facilities. We actually both initiate those types of suggestions for customers. When we get calls from customers at our call centers, depending on the issue, we usually suggest that there are ways that they can save energy, and look for those types of opportunities. So it takes place at a number of different levels for a number of different types of customers. Generally, there is a very proactive outreach opportunity because quite often, and I can certainly speak for myself, customers aren’t always fully aware of what types of opportunities may be available for them to save energy and in some cases through just simply a change in practice. In some cases, by putting in some relatively low-cost types of items in their homes or their offices in order to save electricity and natural gas as well.

Donald Maynor, Esquire asked, does PG&E have any suggestions to local governments in terms of using their police power in adopting local ordinances, building codes to improve in energy efficiency? We have heard some discussion about that as well.

David Rubin stated it is my understanding that we do in fact work with other agencies, for example, the California Energy Commission, that has, and I am no sure whether you had somebody from the CEC at your last hearing or not. But at least based on my past knowledge, the CEC has been involved in helping cities, for example, put various types of local building codes into place that would make sure that buildings that are either built new or remodeled actually have energy efficiency devices. In fact when I worked for the City, again this goes back to the mid-1980’s with the Bureau of Energy Conservation, that was one of the jobs that I had. PG&E has been a participant in those types of activities.

Donald Maynor, Esquire stated one of the comments that was made was that it is necessary to get information from the utilities to find out what the effects may be. Particularly, when the prices were exceptionally high, what was working, what wasn’t working? Which sectors were actually conserving energy? That sort of thing. For PG&E, a lot of this information is confidential because it is customer related, but it is essential for purposes of knowing what is effective. Have you had discussions with the Energy Commission in terms of doing studies to get a better sense? For example, in San Francisco what worked, which sectors were actively involved in conservation? What programs were most effective? How detailed does your analysis go in the energy efficiency area?

David Rubin stated that is a good question. I don’t have an answer for you. I am happy to get an answer for you. I know that there have been efforts looking back at how successful the overall statewide response to the energy crisis last year was, and I believe that has been led by the California Energy Commission. The numbers are impressive. In a later slide, I was going to make the point that in terms of what we are doing to try to make sure, for example this summer, is equally as successful as the last one. Clearly, conservation by customers was the big winner last year. We’re hoping that that type of conservation ethic stays with us all, this coming year in particular. Other questions on this slide? Move to the next one.

David Rubin stated which gets back to the question regarding the power procurement issue. Just in terms of whether we are still in the generation business or the power purchase business, the portfolio of power that is currently provided to customers, generally speaking across the service territory, includes approximately 40 percent of the total needs that are met by the generation assets that we still own in nuclear and hydro. Approximately 25 percent from contracts that we have with qualifying facilities, the ones that I mentioned earlier. And the remaining amounts come from the Department of Water Resources, which was put into the power procurement business through ABX1 from January of last year. Now, pending events will resume power procurement. I am not supposed to discuss obviously our bankruptcy. But, at least in so far as answering this question is concerned, we need to be able to be financially able to buy power. That was the issue that really brought the state to the power procurement table in the first place was that we were no longer creditworthy and could not continue to buy power because of the financial pressures from the power crisis. There is a Commission proceeding at this point that is looking at the rules under which that future power procurement will be carried out. So, assuming various hypotheticals around our restoration to creditworthy status, and the Commission’s following through, with what I will argue which should have been done quite a while ago, which is to put in place standards around the means by which these various investment or procurement decisions will be judged, so that we are not making decisions and then finding the rules around the judgement terms at a later point. We’re assuming that we will be stepping back into that role.

Donald Maynor, Esquire stated what would the alternative be? If you are not given procurement authority and you can see here there’s a need to purchase power in the future, what are the options that the PUC is considering in its procurement proceeding other than to turn back that procurement responsibility to PG&E?

David Rubin stated I am not intimately familiar with the details of the proceeding. I know that it is ongoing in what it is designed to do. In terms of what the options are to the extent that we are not able to step back, we need to be mindful of the fact that at least in so far as today’s supply and demand situation is concerned, as you see before you on this slide, we really almost have a full portfolio in terms of what we still generate, what we buy from qualifying facilities, and then what the state has stepped in to buy through its contracting. Now as you all know from the press, the state is looking at renegotiating some of the contracts that it has with suppliers, that to the extent that there is in fact renegotiations may well change the overall supply and demand balance. The state really has up until the end of this year to continue to make procurement decisions. It would still continue to hold whatever contract its’ executed after the end of this year. But you can certainly speculate that if the two pieces don’t come together, meaning we’re not in the position to step back and buy power and the state’s authority to do that runs out, either the legislature would need to go back and extend the state’s authority or something would need to happen for at least the margin of power that would still need to be purchased. Given the fact that again the state did buy a fair amount of power through its contracting. As you may well recall from some press reports was in a position of having to sell surplus power during certain hours last year.

Commissioner Fellman stated Mr. Maynor, I suggest we ask Barbara Hale from the CPUC that same question. In fact, PG&E tried to move the process forward by filing testimony in advance of a Commission order requesting it because the authority for procurement does run out at the end of the year. I have a question. I know you are not supposed to discuss the bankruptcy. You are telling us that you still have your hydro and nuclear facility as 40 percent of your power. However, in the bankruptcy proceeding you are proposing to divest those resources and place them under your PG&E corps federally regulated subsidiaries. Is that correct?

David Rubin stated with all due respect, I can certainly provide the answer. I have just been advised by counsel not to address the bankruptcy specifically. We are happy to provide a response back in writing.

Donald Maynor, Esquire stated that was our agreement with legal counsel to stay away from issues relating to the bankruptcy.

Commissioner Fellman stated the one thing that I think we need to look at in terms of our Commission is going forward. When we’re weighing the risk of having potential City and County aggregation versus PG&E procurement, that I think it’s a matter of public record that PG&E is proposing or has proposed to transfer at these remaining assets within its state-regulated utility to the federally-regulated affiliate in the corporation.

Donald Maynor, Esquire stated I am not suggesting that we shouldn’t get answers to those questions, but the agreement was that these gentlemen wouldn’t provide the answers. My suggestion would be if we have questions like that, you can provide them to me, and then we’ll submit those questions to legal counsel and PG&E will provide answers to those questions.

Commissioner Schmeltzer stated and I guess we can provide them to you in writing. But just so the folks here can hear what the question in some form will be and we understand that you can’t respond.

David Rubin stated I appreciate that and don’t mean to be an obstacle to getting an answer to you. I just had it prearranged, but we will provide you with a very speedy response.

Commissioner Fellman stated I was just probing how far that could go with respect to what was already in the public record.

David Rubin stated I appreciate that. I’m just not on real solid ground myself to know how far we can venture down that path.

Commissioner Fellman stated Mr. Fallin’s letter was vague at best in terms of what it entailed.

Commissioner Schmeltzer stated but adding to what Commissioner Fellman just asked, the question is if PG&E regulated by the state-regulated entity then would have no substantial generation assets. If this is accurate that it’s been proposed that the Diablo and the hydro facilities would be transferred to the non-state regulated corporate entity, then as far as the City trying to aggregate to obtain power versus PG&E providing that power could essentially be in the same position. That would be the question to ask.

David Rubin stated I think I can answer that and stay clear of whatever I need to stay clear of. The plan of reorganization that we filed does propose a 12-year contract between this newly created entity that would own the Diablo and Hydro assets and PG&E. So PG&E the remaining retail gas and electric distribution business would buy the power output from the nuclear and hydro facilities and provide that to customers. Insofar as aggregation is concerned getting back to your question, the difference between our current bundled utility ownership of those assets today versus the proposal in the plan of reorganization wouldn’t have any consequences.

Commissioner Fellman asked do you know if that contract had a specific price?

David Rubin stated yes, it is.

Commissioner Fellman asked is that price public?

David Rubin stated yes, it is.

Commissioner Schmeltzer asked and you can tell us that price or the written responses can tell us?

David Rubin stated I think this is safe. It starts at 4 1/2 cents in 2003. It averages 5.1 center per kilowatt-hour over the twelve-year life.

Commissioner Schmeltzer asked and that’s for both Hydro and Diablo?

David Rubin stated it is for the collective grouping of assets.

Commissioner Fellman stated we can get that clarified. I think that’s for all of the PG&E, whatever it would be Genco assets.

David Rubin stated that’s correct.

Commissioner Fellman stated there may be something other than just Diablo and the other hydro facilities.

David Rubin stated its Diablo and Hydro. The hydro includes the assets we own plus certain contracts that we have with certain irrigation districts under the so-called partnership contracts.

Donald Maynor, Esquire stated you had mentioned in 1998 there was a CPUC decision to accelerate depreciation in what I used to call stranded investments. They came up with another name. Is that finished? Is this stranded investment charge gone now?

David Rubin stated the stranded investment charge, as it was set up as part of the Commission’s policy decision and then subsequently AB 1890, would allow for the opportunity to recover PG&E’s past investments in power facilities as well as the ongoing costs associated with the qualifying facility contracts. Now that latter part in particular was an ongoing charge that I believe the last contract we have with qualifying facilities runs out in 2025. It was meant to tail off over time as more and more of those contracts expired. In terms of whether it is all finished, that might be an appropriate question as well for the PUC. At this point, it’s not entirely clear exactly how all of the various accounting things that were put into place and then subsequently modified about a year ago by the Commission will all have played out.

Donald Maynor, Esquire stated and you generally view that as one of those non by-passable charges if the City were to be involved in aggregation?

David Rubin stated that is correct. Any other questions on this slide or should we move on to the next one?

Commissioner Fellman stated I have a related question. I didn’t see it anywhere in your presentation so I could hold it until the end or can ask it now. It relates to the issues of procurement by the City in the event it elects to do aggregation.

David Rubin stated I am happy to entertain that now.

Commissioner Fellman stated right now the City and County of San Francisco delivers Hetch Hetchy power through the PG&E system to the City and County of San Francisco. Is that correct?

David Rubin stated to the City and County loads.

Commissioner Fellman asked where does that come into the PG&E system?

David Rubin stated I believe the Newark substation, is that correct?

Kevin Dasso stated I don’t know.

David Rubin stated I think it is delivered by Hetch Hetchy transmission facilities to Newark.

Kevin Dasso stated that Newark is located in the East Bay very near the Dumbarton Bridge.

Commissioner Fellman asked if we were to develop in-City generation that would be, and this is something that has been discussed in the Energy Plan and has been discussed through the implementation of our propositions as well. If we were to have in-City generation that would go beyond on-site customer type generation, how would that get to our customers if we were an aggregator? How would that get to the citizens? Would it have to go back through Hayward or would we have a new interconnection with PG&E?

Kevin Dasso stated well electrically, it would be interconnected wherever the nearest point of interconnection would be depending on the size of the generation. It could be interconnected in the distribution system, essentially right outside of the site. If it is a larger size generation it needs interconnect with the transmission system, it would be to the nearest point of interconnection with the transmission system. In fact, last week we met with members of the San Francisco PUC talking about the Energy Plan. One of the projects that was contemplated was an interconnection at PG&E’s Mission Substation, which is at the corner of 8th and Mission for a 50 megawatt generation project linked to the company that provides steam service here in San Francisco. We are currently talking with them about how and where we would go about interconnecting that facility. The size of that project would require a transmission interconnection. We are not certain whether that project and it really is a function of how the City and its developer wants to pursue it, is to whether that is a merchant project that will be interconnected under normal merchant FERC-regulated tariffs, or whether that would be a facility that would be under contract with the City and County of San Francisco and would be subject to the City and County of San Francisco’s interconnection agreement with PG&E. Those are things that we discussed briefly and those are things that the City would have to take a look at and advise us as to how they prefer to pursue that. Electrically, it would be to the nearest point of interconnection with PG&E’s system. For a merchant project, we are obligated under FERC regulation to interconnect those projects to our transmission system and provide them transmission service.

Commissioner Fellman asked if it wasn’t’ a merchant project, would you still have obligation to interconnect?

Kevin Dasso stated I believe we would. It’s just the question of which agreements it would be applicable to. Would it be under the interconnection agreement that PG&E already has with the City and County of San Francisco? Would it be an amendment to that or is it already envisioned under that agreement? Or would it be a separate general tariff service interconnection? Those are both possibilities. It would really depend on whether the City was--as he understands it today the interconnection agreement covers serving City and County load. To the extent that a generator was being interconnected to provide service for City and County load, then it could logically be interconnected under that interconnection agreement if it were providing service for an aggregation. I am not sure how that works. But you certainly would not have to build facilities back to Newark Substation to interconnect.

Commissioner Fellman asked what about the costing provisions? Would it make a difference whether it was at the Mission Station or it was under the interconnect agreement with the delivery at Newark?

Kevin Dasso stated I don’t know.

Donald Maynor, Esquire stated we are allowed to ask unusual questions. One of the questions that was raised at one of our meetings was why couldn’t you put a transmission line in the Bay? Has PG&E ever considered doing that and avoiding all of the costs of right of way and other kinds of problems?

Kevin Dasso stated I mentioned earlier the stakeholder group that met to look at the long term transmission system upgrades or supply to San Francisco that the ISO ran about two years ago, they did consider a new 230,000 volt line from the East Bay. They looked at various options associated with that. The general conclusion, although detailed engineering and land acquisition procurement siting were heading up and done, the general conclusion was that the cost would be substantially higher than the Jefferson Martin project and would very well likely take a substantially longer time to do that. Essentially, the nearest source for the type of capacity would be necessary is over in the city of Moraga. So you would have to construct facilities all the way from Moraga to the edge of the Bay and then across the Bay to PG&E’s Potrero Substation. It is a substantial undertaking. I think we counted about 35 separate federal, state and local agencies that would have to be involved in the permitting.

Donald Maynor, Esquire stated I was thinking of going from Newark to San Francisco and you mentioned going across the Dumbarton Bridge. Perhaps that is where the thought came in.

Kevin Dasso stated actually, currently PG&E has substantial overhead facilities that cross the Bay today and those could be upgraded at a much lower cost than any kind of a new Bay cable crossing or one that was considered by that study group. However, those terminate at a substation in San Mateo.

Donald Maynor, Esquire stated so you would still have the bottleneck problem of bringing it in as opposed to going from say directly from Newark to San Francisco avoiding the bottleneck.

Kevin Dasso stated you would have to get it from Newark all the way to San Francisco. The study group looked at a new line from the San Mateo Substation, which is where those existing lines feed to from there into the City. The general conclusion was that rather than continue to add to that Substation’s capacity, a better plan would be to devise a completely separate route and hence, the Jefferson Martin project. Essentially, to get from Newark into San Francisco, you would have to go to the San Mateo Substation. A better route would be to come the other direction.

Donald Maynor, Esquire asked where are those studies?

Kevin Dasso stated they I believe they are on the ISO web site. I think they’re still public. I am not sure if those were studies that were removed recently or not. They are generally available. I know there are a number of entities here in the City that participated in that study and have those documents.

David Rubin asked shall we move on to the next slide? These next two slides get to some questions around rates. The first one, what’s the latest on transmission rates? And then more generally, are there any new rate design proposals that may impact San Francisco electric customers? In order to really respond to the question, it is useful to maybe just remind everybody that our electric rates are made up of three basic categories of costs including delivery which includes distribution and transmission; generation; and then public purpose program, which includes energy efficiency, low-income, renewables, etc. The delivery rates represent today about 25 to 30 percent of the total electric rate. Most of the rate is now generation based on, as we’ll discuss in the next slide, the recent surcharges that were introduced. In terms of any new rate design proposals, I will discuss base line changes in a moment because there was a Commission decision that was just issued that will impact rates paid by San Francisco customers. For delivery charges, as Kevin had described earlier, we continue to invest in our system to replace, augment our facilities, address reliability concerns, and connect new load. Those types of activities on an ongoing basis, normal course of business investments in transmission and distribution, generally have cost implications. We have the opportunity to approach the various regulatory agencies that have oversight of those costs, both the PUC and the FERC, respectively, for distribution and transmission to request the authority to change our rates in those areas. In fact we had been ordered by the PUC recently to file for a 2003 general rate case. In fact, we will be beginning that process next week. On the generation side, it really doesn’t appear like those charges are going to go up and in fact, we are all hoping that there will be room in the not too distant future to start to bring those charges down. In the next slide, I will describe those charges in a little bit more detail. But it would all depend on a variety of factors, most notably the costs associated with the DWR procurement that was begun last year.

Commissioner Fellman stated that was my question. When you say generation, does that where your procurement contracts also fit in?

David Rubin stated the contracts that we have with qualifying facilities?

Commissioner Fellman stated no you said you had your DWR contracts that are used to procure power now, correct?

David Rubin stated correct.

Commissioner Fellman asked if that is in your generation category?

David Rubin stated that was all under generation.

Commissioner Fellman stated and you said PG&E signed some procurement contracts that had not yet been approved.

David Rubin stated we had signed some contracts back in again it was I believe October of 2000. I don’t know the size of those contracts. I believe they have all now been terminated.

Commissioner Fellman asked those are terminated?

David Rubin stated that was my understanding, correct.

Commissioner Fellman asked and you put your qualifying facility contracts under generation also?

David Rubin stated correct.

Commissioner Schmeltzer asked and then also of course the Diablo and the Hydro falls under there as well?

David Rubin stated our utility generation is also part of the generation category. That is correct.

Commissioner Fellman asked and with respect to utility generation, have those costs been fixed by the California Public Utilities Commission now?

David Rubin stated the Public Utilities Commission did issue a decision, I believe about four weeks ago if I am not mistaken, to set the price for utility _____(unclear) generation.

Commissioner Fellman asked and do you know what those prices are for the Diablo and the Hydro?

David Rubin stated not precisely, no. I believe they are somewhere within the 2 ½ to 3 cents per kilowatt range.

Commissioner Fellman stated I am just trying to get a sense of comparisons because what you have told us today indicates that the only place, where if we had aggregation we could be competitive, would be on the procurement side. So I was just trying to get some sense of what your procurement portfolio costs look like now. Are you planning on sharing that? I saw you had the rates. Can you tell us what the average costs are for the CDWR contracts?

David Rubin stated the Commission just recently issued a decision for the CDWR contracts or procurement, not just contracts but partly what they paid already, which I believe for PG&E is about 9 ½ cents per kilowatt hour. Now, that is for 2001-2002 only. As I understand, does not include the amounts associated with the bonds that the state is expected to be issuing in order to recover the costs associated with the approximately six billion dollars that were spent out of the general budget plus the four billion dollars that were issued as part of a bridge loan last year. My understanding is that the state is about to embark on an approximately ten billion-dollar bond effort to repay those costs, which would then need to be recovered.

Commissioner Fellman asked what about the average cost of your QF contracts?

David Rubin stated those are approximately 7.9 cents a kilowatt-hour and I believe that’s probably for the whole volume. I know that the Commission issued a decision in June of last year setting that price for about 75 percent of our QF contracts. We were able to renegotiate them. Now the Commission decision set the price at 5.4 cents for the energy, but those contracts also have a capacity component of about 2 ½ cents so the all end price is about 7.9.

Commissioner Fellman asked that has a five-year window?

David Rubin stated correct.

Commissioner Fellman asked and you said your October of 2000 contracts have been terminated, so are there any recovery costs associated with those?

David Rubin stated I am just not aware that there are. I don’t believe there are, but I don’t know for a fact. Baseline. The Commission recently issued a decision, I think it was with the last couple of days, that moved the baseline amounts upwards. Now the baseline amounts are essentially a basic level of usage that are typically set somewhere around 60 to 70 percent of the average usage by climate zone. I believe we have thirteen climate zones in our service territory. San Francisco’s climate zone includes San Francisco and as I understand, some of the East Bay cities as well. By virtue of that baseline amount moving up, and as I will discuss on the next slide also by virtue of the legislative act last year, which is again ABX1 that established that none of the rate increases that were introduced in March of last year, the 3 cents a kilowatt hour would be applied to customer usage up to 130 percent of baseline. By this recent Commission decision, you now have a greater amount of usage in San Francisco. In fact, I think it went up by ten percent. You have a greater amount of usage and consequently, a greater number of customers that will now not see that 3 cents surcharge that was put into place in March of last year. Now roughly speaking as I understand it, approximately 55 percent of the residential customers in San Francisco didn’t see an impact from the 3 cents surcharge when it was introduced last year because their usage basically fell underneath 130 percent of baseline. And based on our estimates and the Commission’s recent decision that will now increase to about 70 percent. So in a going forward basis, about 70 percent of the residential customers in San Francisco will not pay or contribute toward the 3 cents surcharge that was put into place June of last year. So it actually is a rate design change that has benefited now a greater number of customers in San Francisco. Any questions?

Commissioner Fellman stated she had another question just on the allocations of your rates. You said 25 percent went to delivery. How much goes to generation?

David Rubin stated approximately 70 percent. Again, these are in rounded numbers.

Commissioner Fellman asked that leaves 5 percent for the public purpose?

David Rubin stated that was correct.

Commissioner Fellman asked and how much is the public purpose program per kilowatt-hour, do you estimate?

David Rubin stated it is about 4/10 of a cent per kilowatt-hour, I believe.

Commissioner Fellman stated I could do the calculation on my bill, I’m sure.

David Rubin stated it is very easy. Moving on to the next slide. The question really relates again to rates and what happened last year about the various add-ons and surcharges. Quite simply, the Commission approved two rate increases last year-one was a penny a kilowatt hour in January, and the other was 3 cents a kilowatt hour in March that actually that was put into rates in June. So these are part of what I call generation on the previous slide. As I mentioned before on the second increase in particular, customer’s usage below 130 percent of baseline and care customers, which are low-income customers are exempted from those increases. In terms of what PG&E is doing to avoid power shortages and high prices going forward, as I mentioned we’re both helping customers continue to conserve in a variety of ways, and then helping customers as well as power producers interconnect their projects to our system. So in terms of approaching it from both a supply and demand perspective ensuring that we have a very solid balance between supply and demand. We’re obviously not alone in this regard. There are a whole range of state and other entities that are busy trying to promote or induce additional generation to come online and or looking for different types of market demands to make sure the fixes become robust enough to ensure that we don’t step back into the dysfunctional market situation that occurred in 2000.

Vice-Chair McGoldrick asked what would it take to put into place a time of use system of rates? Do you have that elsewhere in the state, and are you able to indicate what level of adjustment usage that that effects?

David Rubin stated all of our larger customers above 500 kilowatts are mandatorily on time of use rates. Now below that level, it’s mixed. Commercial customers depending on their usage profiles and their size may or may not be on time of use rates. There was a process set up by the Commission in response to legislation that would have lowered the size threshold for customers to be on time of use rates. We’ve made filings before the Public Utilities Commission. It hasn’t been acted on yet. The presumption is that at some point more and more customers might be required to be on time of use rates, and then below again a particular size threshold customers can voluntarily be on time of use rates. Residential customers for that matter can and are on various time of use rates. One of the issues though is that with the power market sort of still trying to fix itself or be fixed, the connection between the prices and the power market and the time of use base rates that customers see is somewhat less direct than it otherwise might have been. In other words you really need to have it working all of the way through, have a robust wholesale power market that provides the appropriate time base pricing signals to really then have those connect directly with the price signals that retail customers are seeing. Otherwise, it’s really done by an allocation process, which are based on various types of allocation assumptions that may or may not fully match what’s happening in the real time market at any point in time. I don’t know if that was directly responding to your request or not. There again is at this point today a fairly significant penetration that customers on real time rates, and we frankly expect that will continue as we move forward. Part of what’s required though is in many cases changing out meters so that the customers would have the adequate metering capability to be able to have their usage recorded according to either time buckets or hour by hour.

Vice-Chair McGoldrick asked when you say that customers can voluntarily be on these rates, how would that work?

David Rubin stated we have again for each and every customer class, rate schedules that have time of use rate components. If you wanted to choose to do so for your home, you contact the PG&E representative and they can move you from what you’re on now which is presumably not a time of use rate to a time of use rate schedule. Depending on your usage characteristics, that may or may not benefit you or how you change your usage characteristics relative to the time differentiated prices that you would see.

Vice-Chair McGoldrick asked have you promoted that very widely as an energy management progam?

David Rubin stated yes, we have. It’s been a long-standing program where we in fact send out bill inserts, on a I don’t know if it’s a quarterly basis or not, but on a regular enough basis to encourage customers to look at switching their tariffs to a time of use tariff.

Vice-Chair McGoldrick asked that would involve people actually calling PG&E and requesting a meter change?

David Rubin stated that’s correct. We again send out informational notices in our bills with our bills to let people know that they may in fact be better off under a time of use rate either based on their existing usage characteristics or based on how they might change their usage characteristics in response to the different prices in the time of use bins.

Vice-Chair McGoldrick asked how many households in San Francisco utilize that?

David Rubin stated I can get back to you on that. I don’t know exactly. I believe service territory wide we have close to a quarter million residential customers on time of use rates. I have to confirm that number. I am not sure what the answer is for San Francisco. There was at one point in time, and the reason I am going to give you a sort of I don’t know for sure answer is that prior to 1996, I believe, it was recovery through a special meter charge on the rate schedule. Then there was a Commission decision right around the time that the market was being restructured that then had the customer pay up front for the meter, and they wouldn’t pay the ongoing meter charge. I just don’t remember. I seem to have some vague recollection of that decision having been overturned, but I simply can’t recall. So, in any event it would either be paid as an ongoing component on the rate schedule or up front by the customer.

Commissioner Fellman stated that is something we might want to ask Barbara as well if you are interested in it, Commissioner McGoldrick.

Vice-Chair McGoldrick stated this is the first I’ve ever heard of it, and I’ve lived in San Francisco for almost twenty-seven years.

Commissioner Fellman asked do you pay your PG&E bill or does someone else?

Vice-Chair McGoldrick stated of course.

Commissioner Fellman asked do you open it?

Vice-Chair McGoldrick stated of course. So I have to confess I never knew this existed, and I have never heard anyone discuss this in the city of San Francisco. That’s why I am curious to know. You say you have in your territory, could you tell me what that territory is--250,000 people approximately on this time of use rate?

David Rubin stated that’s residential customers. We have about four and a half million electric customers, so about a quarter of a million residential are on time of use all commercial and industrial.

Vice-Chair McGoldrick asked out of how many customers?

David Rubin stated four and a half million.

Vice-Chair McGoldrick asked out of four and a half million about 250,000? I would just be curious to know about San Francisco because again, I have never in twenty-seven almost years ever heard of it.

David Rubin stated you just have to take a closer look at the wonderful material that we send as part of our billing envelope.

Vice-Chair McGoldrick stated I am a little surprised, but very pleasantly surprised and hope that we can promote this for one thing.

David Rubin stated I will get back to you on the number of accounts that we do have.

Donald Maynor, Esquire asked how long have you had the mandatory program for the larger customers? Is that relatively new? Is it a mandatory program?

David Rubin stated I think that goes back to 1990 if I’m not mistaken. I can confirm that but it’s been quite some time.

Donald Maynor, Esquire stated the reason that I ask is because Edison was telling the cities down south that as a result of going on time of use rates, that cities could see a substantial increase in their electric bills for whatever reasons because the nature of their load, may be the streetlights or whatever. I don’t know to what extent San Francisco’s municipal load is provided through the Hetch Hetchy or is subject to time of use rates. Do you have any sense on that?

David Rubin stated I don’t know but I can certainly check and find out for you. It is true that certain types of customers depending on their load characteristic; if they were to voluntarily self select onto time of use rates may pay more. What you’ve typically seen over time is what I’ll call a self-selection process, which is typically that customers that do benefit by going on to time of use rates. If you are not within the category of customers that have to, right, which are the larger ones. The ones that tend to go onto time of use rates typically have usage characteristics that are favorable for that type of rate schedule, which means people who are not home from noon to six which is when the higher prices are, or people that tend to use more of their power off peak. It’s not to say that you don’t find still customers who move onto the time of use schedule and then actually modify their usage to then respond to the pricing signals. That happens as well. The point that you are getting at is a good one because that’s been part of the debate of moving the size threshold down to smaller customers and forcing them onto time of use. If they have a commercial business that just simply doesn’t allow them to shift much usage into the off-peak, they may end up paying a higher price.

David Rubin stated next slide, I believe this is the last one in terms of the prepared material, which raises the question regarding what PG&E is doing in order to encourage economic development in San Francisco. The answer is we actively support economic development not only in San Francisco, but throughout the service territory. There are a number of specific initiatives that we have supported in the City including as is mentioned here employment training, such as for example, the San Francisco Conservation Corps job training program; various types of small business incubation efforts, and an example would be the San Francisco Renaissance Center, the Women’s Tech Incubator; and other types of social service programs. We’ve also provided grants to over approximately sixty local organizations over the course of the last three years. The total grants for these organizations amount to about half a million dollars. I think about $580,000. Then I will note the supplier diversity program, where we have won awards for our supplier diversity results greater than 26 percent of our expenditures on contracts and various types of services and supplies had been with minority or women-owned businesses.

Donald Maynor, Esquire stated municipal utilities will often times create special rates to induce businesses to come into their communities. Does PG&E have the ability to do that, or is that something unique to municipal utilities?

David Rubin stated no; it’s not unique to municipal utilities. We do have on the books today an economic development rate option that would be applicable within enterprise zones throughout our service territory as well as reuse military bases. We’ve made a proposal before the Public Utilities Commission to offer the rate that has broader geographic reach, i.e., throughout our service territory as opposed to just within enterprise zones. We made that proposal back in 1999. It hasn’t been acted on. We are hoping it will be acted on sometime soon.

Donald Maynor, Esquire asked do you know whether San Francisco has enterprise zones in the City and County area?

David Rubin stated I will check. I do not believe there is an active enterprise zone in San Francisco. Although as I say that, I will also need to check whether the Hunter’s Point base fits within the military base we use at Mieran. We are happy again to entertain further questions.

Donald Maynor, Esquire stated I was kind of curious about the fifty million dollars that you are spending on distribution. I know I’m not allowed to get into the bankruptcy side. Where does that money come from? Is that money that’s available through your normal PUC rate process, so it’s there, available and being spent on distribution?

David Rubin stated yes, correct.

Donald Maynor, Esquire stated we heard a lot of testimony. I can recall talking to people talking about the distribution system in San Francisco itself as being very old and archaic in some respects. What is your general sense of the distribution system here?

Kevin Dasso stated with respect to age?

Donald Maynor, Esquire stated with respect to age, reliability? You indicated that in terms of outages it was in the upper third. That sounds good. But maybe when something gets old, you’ll start encountering more problems like a car. At some point my clunker is really going to start acting up on me. Is the age and condition of the system in San Francisco one that you would anticipate having more problems because of its age or its configuration over time, or is it in relatively good shape and getting better each day?

Kevin Dasso stated I would have to say generally, it’s in relatively good shape. There are many parts of the system that are older. However, some of the technologies that were used in the earlier days of when the system was constructed or actually very robust, and if maintained properly and inspected and checked that they can perform adequately for quite a lot longer. With respect to the specifically, the frequency of outages, our system here in San Francisco has actually been improving. We’re seeing some improvements. The fifty million dollars that I have mentioned is going into upgrading and replacing cable pulls, transformers and other equipment. So that as it reaches near the end of its effective life, that we are replacing it at that time. We’ve done a substantial increase in those types of investments over the last couple of years. Our aim is to keep pace with any deterioration that may be occurring with regard to age.

Donald Maynor, Esquire stated when deregulation came about there was a lot of cost cutting in utilities. Did you see a reduction in your budgets for maintenance of the distribution facilities?

Kevin Dasso stated with respect to the deregulation in California the `95-`96 time period, actually our capital expenditures went up during those time periods.

Donald Maynor, Esquire asked what about the maintenance?

Kevin Dasso stated the same thing, the vegetation management, maintenance activities, inspections, capital investments, those have been actually increasing dramatically over the last couple of years. Overall, we’re looking at a capital budget this year for the utility of about $1.5 billion dollars, so it is substantial. It is not going the other direction. Actually, it seems to be staying at those higher levels.

Donald Maynor, Esquire asked, do you anticipate power shortages? Medium, low, high risk of power shortages in the next one to five years? What are the potential problem areas?

Kevin Dasso stated the ISO just recently came out with their assessment of the summer of 2002, indicating that they do not expect to have to implement any type of rotating block outages on a expected basis. There is always the possibility that a plant or a local condition could have an impact on that. However, the energy outlook is guardedly optimistic. That is probably the best term. They are still encouraging and everyone is encouraging continuing the conservation efforts that took place last summer to the extent that even if it’s not to the same levels as we had last summer, that improvements over prior years would further help the supply picture. I think they are assuming that some of the load will come back this summer, but even with that assumption, the energy outlook is pretty good. Hydro is good in Northern California. Hydro in the Northwest is coming back. It’s not back to normal yet. However, it is being restored. Those are all good things. There have been additional generators built here in California that further address those issues.

Commissioner Schmeltzer asked, going back to your slide about half way through with the discussed distribution transmission in Hunter’s Point. On the transmission portion, what do you anticipate happening or what problems do you foresee if that Jefferson Martin line doesn’t meet your proposed schedule.

Kevin Dasso stated I think the biggest question there is the ability to reduce our reliance on Hunter’s Point Power Plant and having Hunter’s Point comply with a ratching down of air quality emission requirements. There is a change that occurs in 2005 that further reduces the noxious output from plants in the Bay Area. That is one of the issues that tend to drive the timing of that project. Again, as I mentioned, we’re committed to shutting that plant down. We want to have that project in place so we don’t run into that situation. It would require substantial investments in Hunter’s Point, and that would be going in just the opposite direction of what our stated commitment to do that is. That’s all the more reason why we want to work with the Public Utilities Commission to be sure that we can stay on schedule with that project. If I could just add one more thing--It really depends on the load growth in San Francisco. We have a number of load growth scenarios that we have looked at and the extent to which we have issues that are driven by that project really depend on how the load grows. If it stays at current levels, we would not anticipate a problem for quite some time even without that project. However, we are assuming that load will grow and that development will occur and that there will be a need to expand the system. That really drives the timing of that project quite substantially.

Commissioner Schmeltzer asked and if I understand correctly the project is for a new line or extended line between the Jefferson Substation and the Martin Substation?

Kevin Dasso stated correct.

Commissioner Schmeltzer asked does that require additional construction at each of those substations to enlarge the stations themselves or it just the line that would run in between?

Kevin Dasso stated actually the footprint of those substations is not going to change; however, there will have to be substantial construction that will have to occur within those substations. The vast majority of the construction will be along the 27-mile length of the project.

Commissioner Fellman asked where is the Jefferson Substation located?

Kevin Dasso stated it is very close to the intersection of Highway 84 and Highway 280 near Woodside. It’s a couple of miles north of there.

Commissioner Fellman asked and Martin is?

Kevin Dasso stated the Martin Substation is very near the Cow Palace.

Commissioner Fellman asked I had a question that you just triggered with your comment about how much load growth there will be in San Francisco. If there’s a new customer that brings in new load like a new office building, a new industrial facility, a new residential development, and suppose those customers would become part of the City and County’s aggregation plan, would those customers be subject to your exit fee or your non by-passable charges?

David Rubin stated all customers within our service territory, and this is the same issue actually if I can take a step back, came up in the context of the restructuring decisions that were put in place in 1995 and 1996. The same general discussion around should new customers be distinguished from old customers with respect to the costs of, say in that case, power plants that we had built or contracts that we had entered into? Where the Commission and legislature came out is that they would make no such distinction one way or the other. In other words, they wouldn’t have a sort of benefit for a new customer that a legacy customer would have to continue to pay. Although this question hasn’t directly been brought into sharp focus as part of the Commission’s proceeding on the direct access non by-passable charge issue, my presumption is that they will probably end up treating it in the same way, which is that all customers within the service territory. Arguably the procurement decisions made by the Department of Water Resources to lock into contracts that in some cases were ten or twenty years long were predicated on a certain expectation of load growth as well. So the cost associated with those procurement decisions would presumably be paid for by all customers both existing as well as new.

Commissioner Fellman asked and what if there were customers that were interconnected through a City-owned facilities that were then connected to PG&E so the customer itself never saw a PG&E bill, do you see those customers being subject to exit fees?

David Rubin asked can you explain the scenario again?

Commissioner Fellman asked, if there were a customer, say there were a new office building or new industrial facility that wanted to be served by the City alone, and the City built an interconnection with PG&E so there would never be a direct nexus between the customer and PG&E, the City would serve as the intermediary. For example, if there were an office building and the City took the power, and then we would have the right to sell it then to that office building.

David Rubin stated that I don’t know how that type of situation will be treated by the Public Utilities Commission as part of the proceeding that I mentioned earlier. The way that it was treated again analogously looking at AB 1890 was that that customer would still end up paying the non by-passable charge.

Commissioner Fellman stated thank you.

Donald Maynor, Esquire stated when you look at the nuclear power plant Diablo, are the decommissioning costs included in the rates that you are currently charging? What is the estimated life for the nuclear power plant by the way?

David Rubin stated I can answer the first question which is that the nuclear decommissioning costs are included in the rates. There is a separate rate component for nuclear decommissioning. In terms of the remaining life, is that something you have an answer for?

Kevin Dasso stated I don’t know.

Donald Maynor, Esquire stated so when that plant is decommissioned there should be no costs that are assigned to future customers for paying that project? It’s built into the life of the project?

David Rubin stated yes again, there is a rate component called nuclear decommissioning that is a non by-passable charge similar to others that all customers contribute toward. I know that that has a remaining life of I believe another fifteen years-the charge itself. So maybe that lines up with the physical life of the plan.

Donald Maynor, Esquire stated now may be a good time to entertain our questions from the public. We only have one question. If there are members of the public who would like to ask a question, we ask that you pick up a questionnaire from the kiosk, place it on the speaker platform, and we will pick it up and ask the question. This is a question from Charles Kalish and it is a detailed question. What is PG&E’s target goal and date for providing these following items? This would be a percentage of electricity supplied by renewables, percentage of electricity supplied by conservation and by energy efficiency. If you have the plan of that nature, if you could give us the details of that plan? Do you have a sense of what the question is about?

David Rubin asked if I understand, if you are asking if we have a specific plan?

Donald Maynor, Esquire asked do you have a plan with a date and the amounts of energy electricity that would be achieved by renewables by conservation and energy efficiency? That would be the target dates as well as the amounts.

David Rubin stated subject to check. I am not aware that we have a specific plan with specific goals and specific dates associated with those goals. We do again, as I have indicated earlier, offer financial incentives and manage a range of programs that are directed toward each one of those different categories. I just don’t know that there’s a specific objective in terms of the amount of load that will be represented by each one of those different forms of either conservation or in the case of renewables production. There is, as you may be aware of a draft bill now that is sponsored by Senator Sher, I believe it’s SB 532. Mr. Dasso you may know more details than I do, but it does call for a renewable portfolio standard that was in a target for power procurement coming from renewables. I believe the target is 20 percent. I am not sure if the date is 2011 or 2012. It’s sometime out in the future. If that bill were to come to pass, that would impact.

Commissioner Schmeltzer asked does PG&E have a position on that bill?

David Rubin stated I believe our position is that we are concerned that the bill only applies to investor-owned utilities. Beyond that, I am not sure whether we have taken a neutral or a support position. We do know that a large part of our procurement portfolio today, including the qualifying facility contracts do have power coming from various types of renewable resources. I think that we are at the ten or eleven percent level, if I am not mistaken.

Donald Maynor, Esquire stated you mentioned a number of programs that you have conservation energy efficiency, are these programs essentially system-wide programs or to what extent can a community work with PG&E to attempt to tailor those programs for the particular community?

David Rubin stated the answer is yes to both. The programs are both system wide but we also work very closely with communities in our area to help implement the programs, tailor them to the specific needs. I know we had a specific program with, I believe the City of San Jose, over the course of the last couple of years. There has also been now a growing opportunity for cities to avail themselves of some part of the total monies that are made available. That is the process where the Public Utilities Commission reviews specific proposals. I believe they just recently issued a decision allocating the monies for the program year 2002, and I know there were a number of cities and or private entities that received monies under that program.

Donald Maynor, Esquire stated we have another question from Robin David, and I assume this relates to the Jefferson Martin line. The question is with respect to this line. Are you going to run it through the existing right of way used for the old transmission lines, and if not, what political, land use, and environmental problems do you anticipate?

Kevin Dasso stated the environmental work associated with the siting of that project hasn’t been completed. However, what we are currently leaning towards is that we would reconstruct an existing transmission line that runs along 280 from current operation at 60 KV to 200 KV for at least half of the project. We would be attempting to use existing overhead facilities for half of the project. The other half of the project would be run underground, and I believe we studied actually six routes. We are looking at three that we think are very feasible that are largely in the franchised areas or existing city streets and would not require any substantial new land acquisition in order to accommodate that. One of the routes includes a portion along the CALTRANS right of way and also the BART right of way. Those are things that we would have to negotiate with those agencies. But by and large, it would be located in the franchised areas. There is another route that we are considering, an all underground route all of the way from Jefferson to Martin. We are currently proposing or evaluating that that would be located in the franchised area and would not require any additional rights of way to be acquired. In terms of the issues that we have, it’s typically people who have businesses or live along the streets would prefer not to be disrupted with regard to the construction especially with those projects and will tend to lobby to have it on another street or another area. Those are the types of issues that the Public Utilities Commission deals with as they go through that siting process which is required under CEQA. Those are all considerations. Those are the types of issues that we anticipate.

Donald Maynor, Esquire asked if there are any other questions from the public? Or did you want to ask any follow-up questions Mr. Kalish or Mr. David? Any more transmission questions?

A presentation was made by both speakers and is available at the Clerk of the Board’s Office, in Room 244, City Hall.

Vice-Chair McGoldrick stated I see no other questions. This should end our morning session. We would go on a break and we would be back with the afternoon session beginning at 1:30 p.m. Thank you very much for coming here, Mr. Rubin and Mr. Dasso.

The morning session adjourned at 11:54 a.m.

Afternoon Session: 1:30 - 2:00 p.m. Representatives of California Public Utilities Commission and The Utilities Reform Network (T.U.R.N.).

The afternoon session convened at 1:40 p.m.

Commissioner Ammiano called the meeting to order.

Members Present: Commissioner Ammiano, Commissioner Hall, and Commissioner Schmeltzer. Commissioner Fellman was noted present at 2:04 p.m.

Members Absent: Chair Gonzalez and Vice-Chair McGoldrick.

Donald Maynor, Esquire stated this afternoon we are hoping to hear from T.U.R.N. as well as a representative from the California Public Utilities Commission (CPUC). One of the difficulties we had in planning today’s meeting was we had a late commitment from PG&E, and so we had to get a belated request over to the CPUC. I’m not sure T.U.R.N. will be present. If Mike Florio appears, he will he here. If not, Barbara Hale here is from the California PUC. She has been with the PUC for a long time. I don’t have her bio, so I will ask that she relate her credentials to you right now.


Barbara Hale, Director of Strategic Planning, California Public Utilities Commission stated I apologize Mr. Maynor, you had asked me for a bio and I neglected to follow through on that. I’ve been with the Public Utilities Commission now for about fourteen years. I have had a number of roles there. At present, I am Director of Strategic Planning for the Commission and responsible for helping the Commission look out into the future and understand what coming regulatory and market issues they may need to be grappling with. When I was asked to represent the Commission today, I was handed a list of questions from the Committee that I liked to address in the context of some prepared remarks and I am certainly open to a free range of questions and discussion. I think we could both benefit from that. As a regulator I come to you to offer the perspective of the regulator and the perspective of the regulator from the unique context of what California has experienced in the electric market since late in the year 2000. Let me take a moment to describe what it means to be speaking from the perspective of the regulator. The California PUC doesn’t just regulate privately owned electric and gas companies like Pacific Gas and Electric Company. We also regulate privately owned telecommunications, water, sewer, rail, transit, and passenger transportation companies. The California PUC is responsible for assuring California utility customers have safe reliable utility service at reasonable rates protecting utility customers from fraud and promoting the health of California’s economy. The California PUC is generally responsible for industries whose services are considered essential and whose revenues from California exceed sixty billion dollars annually. Some of the questions that are posed to me from the Committee have to do with the Commission’s objectives. I will address them more specifically for this coming year. In general, the Commission’s fundamental objective is to assure fair and reasonable utility rates, reliable high quality essential services. California’s PUC actions are driven by the belief that the provision of reliable and reasonably priced utility services are essential to the health of the economy, the health and well being of the population, and the high quality of life for all Californians. The key challenge for all the essential services that the California PUC regulates is to promote and encourage infrastructure expansion and improvement while assuring environmentally sensitive development and compliance with environmental and safety laws.

Now I would like to talk a little bit about the electricity market in general, and then I will get more into the specifics of the questions. Beginning in the spring of 2000, California has been beset by a runaway wholesale market on which California utilities had become overly dependent. The dependence was the result largely of policies that encouraged utility divestiture of their generating resource base. That resource base was substituted with purchases in spot and real time markets from marketers and merchant generators. At the end of 2000, the Federal Energy Regulatory Commission eliminated wholesale price controls without any effective substitute for preventing the exercise of seller market power. I’ve provided each of you with a comparison of the wholesale to retail energy crisis in the year 2000 and 2001. As you can see as that’s charted over time how we saw in California prices that were really out of control until FERC stepped in. Within a matter of days, utilities were completely stripped of their cash and credit. The State of California through the California Department of Water Resources had become the buyer of last resort to prevent wide spread blackouts caused by generators withholding supplies, and the California PUC had to raise rates to unprecedented levels. Calendar year 2001 was spent returning stability to commercial relationships in the electricity business through the re-imposition of FERC price controls, rapid development of state purchasing capability, rate increases, wide spread deployment of conservation and efficiency measures by consumers, and settlements of some outstanding disputes over the responsibility of the state for recovery of unreasonable wholesale costs from ratepayers by utilities.

Now the Committee had asked me, what are the primary goals that the PUC will be addressing that may impact San Francisco in that historical context? I see calendar 2002 spent rehabilitating the electric utilities’ financial conditions so they may resume their obligation to serve their customers in accordance with their constitutional and statutory responsibilities. Creditworthiness is a word you will be hearing about a lot in 2002 from the PUC. I imagine you heard a lot about it this morning from Pacific Gas and Electric Company. For PG&E the Commission’s vehicle for establishing creditworthiness is the bankruptcy proceeding. On Monday, according to the schedule established by the bankruptcy judge, the PUC will file its alternative reorganization plan. 2002 will also be spent putting in place comprehensive measures for assuring that electric service will remain reliable and reasonably priced through the development of integrated resource planning procedures for timely, effective, and environmentally appropriate infrastructure development and demand site program deployment for each of the utilities and the state as a whole. 2002 will be spent working to stabilize wholesale electricity prices.

You also asked the PUC what role the legislature should play. The California legislature may need to clarify the deregulation statute further, but largely I see the going forward work as traditional work of the regulator. Rate making that enables utilities to serve that protects consumers with special attention paid to low income customers, and that funds appropriate infrastructure development.

You queried me as to whether PG&E is going to be in the generation business or the power purchase business.

Commissioner Schmeltzer stated that last question about what role should the legislature play. Are you saying that you see them taking on some of the issues that were generally held by the regulator.

Barbara Hale stated no, let me clarify. I was trying to say that the deregulation statute may need to be, and by that I am referring to AB 1890, may need to be further clarified as we go forward this year with the transition from DWR back to the utilities of the responsibility for procurement. Recall that in January of 2002, DWR was given the authority on an emergency basis to take up this responsibility. That was a revision to the statutory construct that is hard to jive with 1890. Because of that as we transition out, there may need to be some clarifying statutory effort. I don’t see a role for the legislature in doing what I was describing just then as traditional regulatory work, rate making, consumer protection, those things. I am happy to take questions as I go through each of the questions that are on your list. I don’t mean to just be pushing forward. Please speak up if you have questions as I go.

You’ve also asked whether PG&E is going to be in the generation business or power purchase business on a going forward basis. In my view, PG&E Corporation is decidedly in the generation business. The open question framed by PG&E’s bankruptcy reorganization plan is whether its generation business will be regulated by the PUC, not whether they are going to be pursuing a generation business. As I see it, it comes down to whether the state should allow PG&E to earn unrestrained profits on the investments made by ratepayers like us in its generation infrastructure. The PUC position is that the state should continue to regulate PG&E’s generation business to protect consumers from unreasonable rates and untold (unclear) profits. You had posed some questions about direct access’s future. The future of direct access is driven largely by the legislative directives the PUC has been given. Electric service providers serve between ten and fifteen percent of the utilities’ load in California, primarily that of large industrial customers through the direct access program. The program was suspended by legislative directive in February of 2001, and now the PUC is focusing on the rate making consequence of the shift of load from utilities and DWR to energy service providers. That shift effectively leads a power purchase surplus that must be paid for by all customers. At this point in time, the PUC is not considering reopening enrollment in the direct access program, but rather addressing the rate making concerns that existing levels of enrollment in direct access have created.

Commissioner Schmeltzer asked I’m not sure if it appears farther down here, but, Migden’s aggregation bill that is pending in Sacramento right now, how does the PUC see that bill? Should it go forward, being implemented effecting the direct access program or San Francisco or other customers in the future?

Barbara Hale stated the Commission has not taken a formal position on the Migden bill. Some of the concerns the Commission has about the direct access program and the shift in load that it creates would be similar to the shift in load concerns that a community aggregation program may create. I think there are parallels there that may be instructive on what sort of position the Commission may take on that legislation.

Donald Maynor, Esquire stated our protocol is there’s a questionnaire on the kiosk and if you can fill it out, we will ask your question at the end of the presentation. I had a question Barbara, about your comment about the PUC stabilizing the wholesale market. I wondered if you could explain what comprises the wholesale market and what can the PUC do to stabilize that market?

Barbara Hale stated at present, the wholesale electric market is regulated solely by FERC, the Federal Energy Regulatory Commission. The independent system operator in California has tariffs that are approved by FERC, and most wholesale electric transactions in California go across the independent system operators run grid. That’s true certainly for the investor-owned utilities that the California PUC regulates. When I talked about the PUC taking some time and dedicating some effort this year to stabilizing the wholesale price of electricity, that’s largely through its participation in FERC forums.

What aspects of electric service are likely subject to PUC regulation in the future? In the aftermath of deregulation, I see the PUC returning more to its regulatory roots. The PUC will continue to oversee infrastructure additions. At this point, largely transmission and distribution system additions, energy efficiency investments and scrutinizing utilities costs of service. During 2002 and 2003, the PUC will perform general rate case reviews of all the investor-owned energy utilities including Pacific Gas and Electric Company. These reviews will be comprehensive and will establish the relationship between delivery rates and delivery service as well as establishing standards for the quality for delivery service for the major California utilities.

You were also asking about steps that the PUC would be taking to address outages. Given that PG&E was represented this morning in part by Kevin Dasso, I imagine you heard quite a bit about the transmission upgrades that they are slated to perform. Those will largely address the outage concerns for the San Francisco peninsula. We see substation upgrades up and down the peninsula as well as major transmission line upgrades. I imagine Mr. Dasso talked a little bit about the Jefferson Martin upgrade.

Donald Maynor, Esquire stated yes, he did. I think he explained, correct me if I am wrong, that he didn’t need the permission from the FERC. It was more of a permission from the ISO and there was an approval from the PUC that was necessary.

Barbara Hale stated I’m sorry Mr. Maynor, did you say that he said that there was no approval?

Donald Maynor, Esquire stated that the only approvals that would be required would be by the ISO and the PUC. I forgot what he said the timing would be at the PUC process, but I got the impression that it would be within the year.

Commissioner Schmeltzer stated that he said that they were on the ISO calendar for April 25th, and that they expected to file their environmental assessment with the PUC in the fall.

Barbara Hale stated that is consistent with representations that Mr. Dasso and other PG&E representatives had made to me and to the Commission. PG&E has gone through an extensive series of studies that have included Public Utilities Commission staff and looking at what the alternatives are for addressing the transmission upgrade need. The Jefferson Martin transmission line is one of several that were under consideration, and we understand that the ISO will be acting on the 25th on that. Perhaps Mr. Florio would be ready to talk a little bit about that. We’re anxious to have Pacific Gas and Electric Company come in with their application for PUC approval. They have not done so yet and have represented that that should come in the fall. You had also asked what the date of service was for that. They have indicated to us, assuming all approvals go smoothly, that that upgrade would be in service in June 2005.

Donald Maynor, Esquire stated I should introduce Mike Florio of The Utility Reform Network (T.U.R.N). I appreciate you coming by, Mike, on short notice.

Mr. Florio stated my apologies for being late. We had a little confusion on our end, but hopefully I can make up for that.

Donald Maynor, Esquire stated no problem. What I wanted to encourage you to do is if you had questions or comments that you would like to share on some of these topics, go ahead and chime in because I think it would enhance the discussion.

Mr. Florio stated I would just say on the Jefferson Martin, I have also been told that’s going to be on our ISO agenda. At this point, I don’t see any reason why that wouldn’t be approved. Then it’s a question of siting which is always difficult for transmission, but I don’t think there’s a whole lot of controversy about the need for it at this point.

Barbara Hale stated yes, we do expect that it will be a contentious siting proceeding at the PUC. We have found that almost every transmission line that comes before the PUC of late is rather hotly contested by local residents, and I don’t expect this to be an exception to that.

Donald Maynor, Esquire stated that one of the things that came out this morning was the discussion about the transmission rates and I guess the ISO has a proposal at the FERC at this time. One of the questions that we were asking about was how would this impact San Francisco? Would they be included in a zone for purposes of congestion rates? The reason why that could be important is if they got into the aggregation business, and they were deemed to be in one of those zones, they may have to pay a much higher transmission rate. Of course, as long as I have been around I have always heard the notion, on the retail side, of arguments being made of having zonal rates on the retail side. Is that something that might come back again? Or what is the PUC and T.U.R.N.’s position on the retail side.

Barbara Hale stated on retail electric rates being adjusted by zone?

Donald Maynor, Esquire stated yes.

Barbara Hale stated at this point, the Public Utilities Commission has relatively flat rates for residential customers and then tiered rates for other customers. That’s the traditional approach. In the face of the energy crisis, we tiered rates for all customers with and protected lower consuming residential customers from any rate increases whatsoever. There have been a lot of work of late looking at further time differentiated rates for all customers. But not much looking into zonally different or geographically based rate differences. The exception to that is in the way the Public Utilities Commission calculates rates and the baseline allowance that you have, the allowance that you have for your household expected to be consumed at the lowest possible rate is a zonally-differentiated amount of energy. So that’s the only geographical or zonal difference that is currently in the rate structure for retail customers.

Donald Maynor, Esquire stated in my question was really what happens if the FERC comes out with dramatically different rates depending what zone you are in? Is the PUC or T.U.R.N. philosophically opposed to creating or differentiating or allocating those costs based on those zones?

Commissioner Schmeltzer asked may I ask a clarifying question? My understanding from this morning is that the zonal ISO rates that were being discussed had to do with transmission only and not generation, is that right?

Donald Maynor, Esquire stated right.

Commissioner Schmeltzer stated I think that you were just describing generation rates, or am I mixed up?

Barbara Hale stated I was describing retail rates because that’s what Mr. Maynor was asking me about.

Commissioner Schmeltzer stated retail rates, okay.

Donald Maynor, Esquire stated here is the question and this is very significant actually. Because of this proceeding that is going on at the FERC possibly creating special transmission rates depending upon what area you live in, so if you live in a congested area, you would pay much higher rates. Likely, San Francisco is located in one of those congested areas. Today, when you pay your PG&E rate, part of that rate includes transmission costs, but is based on a system-wide basis. If San Francisco wanted to get into the aggregation business and they had to pay their own transmission rates to bring import power in, they may find themselves paying a much higher transmission rate because of this FERC proceeding because they live in a congestion area. My question was, in the past, there has always been a discussion whether you should have different kinds of zonal rates depending on where you live at the retail level. I was wondering if there was a philosophical opposition to this idea of maybe allocating those costs that would come from the FERC based on these zones and reflect them in the retail rates depending on where you live. I don’t know if that makes sense.

Michael Florio, stated actually, from my work at the ISO, I am fairly familiar with what is going on. I think it’s fair to say that it’s extremely likely that there will be some kind of locational pricing at the wholesale level. While those are transmission congestion costs, they end up being reflected in energy prices, so energy will very likely be more expensive in congested areas than in not congested areas. What the PUC does with that at the retail level is an open question, and I think many of us expect that the PUC will not simply flow those prices through a retail but will retain some sort of averaging. I may be presumptuous here, but it does have an impact for a municipal utility such as Palo Alto, or if San Francisco were to form a municipal or a community aggregation, it would be subject to those prices. That’s not as bad as news as it sounds initially for a couple of reasons. First, any implementation of what’s called locational marginal pricing or zonal pricing would have accompanying it a system of what are called firm transmission rights that would allow the holder of those rights to avoid the congestion charges. One of the issues that is currently before the ISO, and we will need to make a proposal to FERC on that, is how to divvy up these firm transmission rights. One of the proposals is for the local load serving entity to be allocated a proportionate share of those rights. San Francisco has been well represented in these discussions,, and my sense is it may be swimming upstream to try and say we don’t want any kind of zonal pricing at all. I think a more productive approach for the City would be to advocate vigorously that it be allocated firm transmission rights that would be a protection or a hedge against transmission congestion charges. That’s something that is probably going to be decided in the next couple of months. I think it has great import really for consumers throughout the Bay Area. The other side of the coin in terms of congestion costs is in the Bay Area we have a more moderate climate and our usage tends to be less on peak and therefore less expensive than in the valley. On the one hand we have a congestion problem that hurts us, but on the other hand we have a favorable climate than a flatter usage pattern that helps us. How those two balance out is really something that hasn’t been analyzed fully, but it’s not an unmitigated bad thing for the Bay Area because we do have some natural advantages as well as disadvantages.

Barbara Hale stated I would just add that the PUC in its interactions with the ISO on this issue has been supportive of zonal pricing at the wholesale level. When you were posing your question to me, I was trying to focus on the retail aspect. The Commission has always set or traditionally set retail rates based on marginal costs but does not just pass through the full marginal cost. Yes, I would agree with Mr. Florio, you are not being presumptuous I don’t think, or at least I will join you in the not being presumptuous that I would expect the Commission would not pass it through wholesale.

I was going to conclude by talking about some of the proceedings that I thought the City of San Francisco and the LAFCo folks would be interested in my highlighting because of the impacts in San Francisco. Clearly, the bankruptcy proceeding is a big one. But for purposes of participation before the Public Utilities Commission, I would strongly encourage the City to focus its attention on the general rate case filing that PG&E will be making. That’s where the real rubber hits the road at the PUC is reviewing the prospective expectation of the utility and how much its going to be spending and how its going to be spending it. The proceeding where we will be looking at setting the direct access exit fees is also a proceeding I would imagine the City would be interested in. That’s where we will assign costs among customers based on whether they are keeping their load with the regulated utility or have exited the utility’s fold and are taking advantage of the direct access program. Any time that the Commission is looking at setting rates and shifting the allocation of costs among customers classes I think would be a time for consumers to be actively engaged which is why I mentioned that proceeding.

Commissioner Schmeltzer stated Ms. Hale, speaking of direct access and in light of the Commission’s recent decision of allowing some of the direct access contracts to stand and how that shifted the burden. Can you talk a little bit about the impact of that decision and how that might be comparable to the aggregation bill.

Barbara Hale stated that what the Commission had before it basically was a question of, in light of the legislative direction to suspend direct access, at what date should that become effective and what should the impact be? What does the Commission imagine the impact to be going forward? The Commission set, and this was not just an inconsequential choice between dates, but I am going to describe it as that. First there was the date in July I believe it was, where if the Commission chose to suspend the program as of that date, there was only about three percent of load signed up with the direct access contract at that point. The alternative date under consideration by the Commission was a date in September. By that point in time after going through this crazy summer, we now had ten to fifteen percent of load signed up with an energy service provider under contract for a direct access service and not for service by the investor owned utility. What that means is the power that was contracted for the power purchase commitments that were made to cover the full load of DWR and the investor-owned utilities, while the contract commitments remained the same, the load it was to serve shrunk. The effect of that absent an exit fee calculation, absent an obligation on the part of the departing customer to pay, what that would mean is that all remaining customers, that remaining eighty-five to ninety percent would have to pick up the full cost of the power purchase commitments. That same question comes up in the context of community aggregation. If a group of customers in the case of the direct access program primarily large industrial and community customers in the community aggregation program, just about anyone is going to create a shrinkage in the load to be served, while the outstanding commitments for power purchases that were made to serve that load and the remaining load still remain. So there’s a chunk of dollars that are left to be paid without customers to pay them. That is the analogy I was trying to draw earlier.

Commissioner Schmeltzer stated and I understood that and I guess I wanted to ask the second half of that which is, since those customers were allowed out of the pie, what’s the second half of the analogy for aggregation or is that the open question at this point?

Barbara Hale stated are you talking about the actual dollar amounts? I apologize I’m not getting your point.

Commissioner Schmeltzer stated well, the customers were allowed to retain those contracts and sleeve the state without those additional customers. While I understand what the concerns are for aggregation and I understand that PUC hasn’t taken a position on the aggregation bill. I am just wondering what the lesson is then to be drawn from?

Barbara Hale asked from the direct access experience?

Commissioner Schmeltzer stated yes.

Barbara Hale stated for me the lesson is largely a lesson in timing and understanding what it is. When you signed up as a direct access customer, there was no program for paying an exit fee. It’s only an after the fact program for paying an exit fee. Because of that, I expect it will be hotly contested and litigated. Whether the Commission has the authority to impose it and whether any direct access customer would have to pay it. A lesson learned for community aggregation would be to understand the rules of the game in advance and understand whether there will be something comparable to an exit fee in any community aggregation program. I think it would be unfortunate for community aggregation to go forward without having a clear understanding of what other obligations you may be taking with you as you leave.

Mike Florio stated for our part, we oppose the Commission’s decision to use the later suspension date for direct access, and we will also be vigorously advocating a hold harmless principle that when somebody leaves the pool of the DWR contracts, they should be obligated for their proportionate share of the costs so that nobody that stays with bundled service is worse off. That is a position we’ll be advocating at the PUC and at the legislature. I think that concept is already reflected in the community aggregation bill. I am not sure what the latest language is. I think even last year when it was vetoed it had some language to that effect. We are supporting AB 117 on that basis.

Commissioner Fellman stated this is something we heard from PG&E this morning so it’s an area where you are in agreement with PG&E.

Mike Floria stated accidents happen.

Commissioner Fellman stated I wanted to ask you and then if Mr. Florio wants to comment just on this concept of new load. What about new customers that are coming onto the system. Do you see them having the same liability for the exit fees?

Barbara Hale stated the Commission has not addressed that issue head on and I expect it will have to in the context of the exit fees calculation.

Mike Florio stated typically rate making has not made distinctions between new and old customers. The analogy here is the competitive transition charge that was assessed under deregulation and I think there was an assumption that customers come and customers go and everybody pays the rate, and the rate includes a component for historical costs as well as going forward costs. That’s what I would expect to see come out of this. Now, there’s always an exceptional case perhaps. I would be surprised to see a different set of rates for old and new customers. That would be somewhat atypical from what I am used to seeing in utility rates.

Barbara Hale stated I would agree, but I guess I took your question perhaps too narrowly. I thought I heard you say new load, not necessarily a new customer?

Commissioner Fellman stated that’s correct.

Barbara Hale asked so that could be the same customer who has a direct access contract, but whose load increases?

Commissioner Fellman stated that is correct. Or it could be a new building that elects not to be a utility customer and would become a customer of the City and County of San Francisco aggregated service provider.

Barbara Hale stated and I think I was answering it thinking of it in terms of what if you already are a direct access customer and you’re a commercial customer and you increase your business, you only have a certain number of megawatts under contract with direct access. Does that mean you can add your new load onto that direct access contract, which would have exit fee implications, or are you for purposes of that additional load still a bundled utility customer? I think the Commission has not confronted that issue yet.

Donald Maynor, Esquire asked what is the status of that exit fee proceeding? Is it just started or near the end?

Barbara Hale stated I think actually there is a workshop today on it. Workshops are under way and the Commission intends to address it expeditiously. We’ve heard proposals from the California Large Energy Consumers Association and others who have been making an effort to try to reach closure on this. They have every incentive to as we go forward.

Donald Maynor, Esquire stated we had a conversation with PG&E about what we used to call "stranded investment" and they pointed out in 1998, they were allowed to accelerate the depreciation of these so called uneconomic assets. Is that gone now? Is that complete? Or is that something that is now left over for these exit fees? Is that one of those issues that is going to show up there?

Barbara Hale stated yes.

Mike Florio stated and there are also some of the contracts with QF’s had above market costs that are continuing on, and even in AB 1890 there was a provision for recovery of those after March 31, 2002. That will probably be an aspect of this proceeding as well.

Donald Maynor, Esquire stated this is a very important proceeding. It sounds like if San Francisco is interested in getting into this business and it may even relate to the state bill, because it is possible that they would tie in those non by-passable charges to what comes out of the PUC. Is that a possibility?

Barbara Hale stated yes, and that is why I have it on my list of recommended proceedings for the City to be engaged in. I think I have gone through the questions you had posed to me on paper. I’m happy to continue to answer questions.

Commissioner Schmeltzer stated there were a number of things that came up this morning in PG&E’s presentation that I think some of us had questions on. I don’t know if you’ll be prepared or know the answers, but you may. PG&E this morning discussed the costs of their utility-regulated generation and what the cost currently is, and they described that as if I remember what they said correctly as 2 ½ to 3 cents per kilowatt hour for the Hydro and the Diablo.

Barbara Hale stated I would have answered that question in about that same range.

Mike Florio stated I wouldn’t have expected them to.

Barbara Hale stated, yes it’s a little bit surprising.

Mike Florio stated it tends to be a hotly disputed issue.

Commissioner Schmeltzer stated they also discussed their proposal to transfer their Hydro and Diablo out of the California state regulated utility in the bankruptcy proceeding and said that generation would stay under contract for twelve years at a rate of 4 ½ cents.

Barbara Hale stated I understand that to be part of their reorganization plan. Yes, that they have in putting together the reorganization plan, Pacific Gas and Electric Company has committed to what they represent as cost of service fees for the generation currently regulated by the Public Utilities Commission and under their reorganization plan, would be spun off to an affiliate. While they make that commitment, there is nothing that in the reorganization plan that would prohibit them from selling the assets on the open market. Of course the PUC’s underlying concern with the reorganization plan is that it removes from regulation, from consumer protection assets that ratepayers like us funded.

Mike Florio stated the only thing I reacted to there is the 4 ½ cent number because I think that over the life of the contract it’s more like 5.2 cents on average. We’ve been as a rule of thumb saying that it would roughly double what we’re currently paying for that generation just by changing the ownership of the assets. Obviously, that is something of great concern to us.

Commissioner Fellman stated with respect to the bankruptcy and what you have just described, Ms. Hale, I understand that the PUC has put in its own reorganization plan.

Barbara Hale stated the PUC will be filings its alternative reorganization plan on Monday.

Commissioner Fellman stated from the perspective of what we are looking at for the City and County of San Francisco, would it be your opinion that the transfer of these assets from the state-regulated entity to the corporate federally-rated entity, would that create greater risk of the power that’s being procured as a result of the contracts that are going to be entered into? In other words we are looking at transfer of the assets. We have to see if PG&E is going to be able to provide reliable reasonable power to San Francisco and evaluate whether or not we want to enter into citizen aggregation of some form should that become possible. We are looking at the risk of the delivery of PG&E’s power. Do you feel that creates a greater risk once the transfer occurs?

Barbara Hale stated I think PG&E’s, Pacific Gas and Electric Company’s plan for reorganization-it’s tuff to follow all of the corporate entities when we all refer to them all as PG&E when they are very distinguishable. Pacific Gas and Electric Company’s reorganization plan would face a tremendous amount of litigation which creates some risk, some uncertainty out there in the market place for the ability of it to really consummate its deal. Were the court to approve PG&E’s reorganization plan, I see a tremendous amount of litigation. The PUC’s alternative plan is a plan that is designed to avoid that litigation risk and to ensure that not only the utility reestablishes its creditworthiness, but also is able to continue to provide reliable electric service to Californians. In that choice that you have posed, I would say that the less risky world for San Francisco is what you are going to see on Monday’s PUC plan. Now, were the PG&E’s plan approved by the bankruptcy judge, I think then the primary risk is that of litigation of that plan and whether it could actually be consummated.

Mike Florio stated just an additional point, the chief Hydro power is one of the few advantages now of buying power from PG&E that you get that low cost power as part of the bundle. If they are allowed to mark that up to market value, I think virtually any advantage of remaining a PG&E procurement customer goes away, and everything is at market prices or higher. It’s an irony in a sense that if they succeed in what they are trying to do I think it would eliminate perhaps the one remaining reason why someone would want to consider being a PG&E procurement customer because you’d lose that cost advantage of the cheap power.

Donald Maynor, Esquire asked what is the situation with Diablo? Are there decommissioning costs associated with the nuclear plant that would be included in exit fees? Is that a topic that even comes up? PG&E indicated that they thought that there is a fifteen year time period for decommissioning costs. I wasn’t clear whether that reflected the actual life for Diablo Canyon or not. I was just curious as to how the nuclear plant fit into the equation of what we’ve been talking about.

Mike Florio stated there is some controversy over where they have already collected enough decommissioning costs. Some people feel that they have. Others feel that more will be required. I think that will be a litigated issue at some point in the future at the Commission. There is currently a non by-passable rate component for nuclear decommissioning that everyone has to pay. If there’s a finding that its sufficiently funded, it’s possible that might go away. There’s also an issue in the bankruptcy about control over the decommissioning fund because PG&E is proposing to transfer that fund to the affiliate along with the asset. I believe they are now saying they would take away the PUC’s remaining jurisdiction over that fund. There was some ambiguity about that at first. I think they are trying to take the fund to federal jurisdiction as well, which may potentially leave the state out of the picture entirely on that.

Donald Maynor, Esquire stated it sounds like you are very much at the whim of what happens in the bankruptcy proceeding before you can decide what kind of regulatory rules you will come up with for procurement and things like that with PG&E.

Barbara Hale stated Ii would say that at the PUC we are not waiting for resolution on the bankruptcy proceeding. The regulatory responsibilities and authority of the Commission has today, it’s acting on. You mentioned procurement rules in particular. The PUC the assigned Commissioner just recently issued the scoping ruling on how it is going to go forward in making the transition from DWR back to the investor-owned utilities in procuring to meet the full customer load for each of the utilities in 2003. We are going forward with that and not waiting for a resolution in the bankruptcy proceeding.

Mike Florio stated although at some point, we could get into a situation where the PUC has procurement rules for regulated entities, but if PG&E is still in bankruptcy there may be a disconnect there that they are not creditworthy or able to actually take on the procurement. That is one of the items on my list of things the legislature has to deal with this year is the current authority of the Department of Water Resources to be the procurer of the electricity for ratepayers of the investor-owned utilities expires the end of this year. I think it’s becoming increasingly clear that PG&E is not going to be out of bankruptcy by the end of the year, which raises the question is DWR’s authority going to be extended? Is another state agency going to be given that responsibility, or are we just going to collapse into chaos, which is always the default option on these things. The legislature so far this year, I think it’s fair to say displayed issue fatigue on energy and has tended to stay away from dealing with it. This is one of those issues, as well as potentially the exit fee issue, that they may have to deal with whether they want to or not.

Donald Maynor, Esquire asked Mike, did you have some prepared comments that you would like to share at this time?

Mike Florio stated a few, but I would mostly just like to respond to your questions,

Commissioner Ammiano stated we are supposed to wind up at about 3:00 p.m. If people wanted to stay a bit longer and there is a quorum, I think it’s fine. I have to leave at 3:00 p.m. for another meeting, and of course we want to get in any questions from the public too.

Mike Florio stated okay, I will be very brief. The ratepayers of California including San Francisco have essentially been through a blitzkrieg over these last two years. All the promises that were made about what deregulation would bring supposedly twenty-percent rate reductions and abundant choices, etc. etc. have pretty much all proven to be false. Rates are at their highest level ever and show previous little prospect of coming down soon. I think the only silver lining in this from a ratepayer’s standpoint is it does create an opportunity for innovative local programs like community aggregation, or the solar development that the City is already moving forward with, local energy efficiency initiatives, things like that, that may provide a long-term way out of this mess. Obviously, if you go in that direction, it’s the City taking on a set of responsibilities that traditionally have been handled elsewhere. Given how well they have or haven’t been handled, I think there is certainly a lot to be said for the City taking a hard look at these alternative ways of providing electric service to their residents and businesses. The system that we have has not worked out very well for most consumers. With that, I would just offer to respond to questions. I know our time is limited, so whatever you would like to hear more about, I will offer my two cents worth.

Commissioner Fellman stated I have a really important question, and I think you are the best person to answer it. That is the whole issue of community aggregation that T.U.R.N. sponsored throughout the deregulation, lessons learned, advice, observations, twenty-five words or less.

Mike Florio stated community aggregation as we had conceived of it was not really permitted under AB 1890 because it required this customer by customer sign-up that is very costly and really did not work out anywhere. So, Assemblywoman Migden’s bill is really our first opportunity to try community aggregation. I think we certainly pushed pretty hard for it the first time around, but didn’t have much support. I think in large part because the local agencies were just not, there wasn’t a demand for it. It was an idea without a constituency. Now, I think the constituency is there in abundance.

Commissioner Ammiano stated we introduced it here previously and there was a lot of resistance and actually a lot of lobbying by PG&E to try and kill it. We did what we did and we did get it through. We then took our journey to Sacramento. Some of it was the lobbying but also some of it was people really not understanding what it really was. I had to be taught what the concept was. Then if you saw it in the bigger constellation, you thought this could be something very, very good. I think it was a sock initially and they thought no one would take advantage of it.

Commissioner Schmeltzer stated there was a discussion of PG&E’s rates this morning, where they broke out the portions of their rates and what was made up. I wanted to go over what they said. They sort of told us what they thought were non by-passable rates. But some of it was a little unclear, so I am looking for some feedback. They said that delivery of electricity was about 25 percent of their rates. They said generation was about 70 percent and the generation was made up of QF’s at 7.9 cents per kilowatt-hour, the DWR contracts at about 9.2 cents for 01 and 02 and the utility generation, Diablo and the Hydro, which we discussed earlier. They also said that the contracts they entered into in October of 2000 have been cancelled and there are no costs associated with that. I was wondering if there are any other pieces that were missing, and if the City were to aggregate rather than purchasing from PG&E, what pieces of that you would see as the City’s remaining obligation? Then they said the final five-percent was the public purpose-programs, the public goods charge.

Barbara Fellman stated that was the one thing I was going to mention as missing.

Commissioner Schmeltzer stated and that was .04 cents per kilowatt-hour.

Barbara Hale stated I don’t think I disagree with the general breakdown in these broad terms. But, I don’t think I can really speak to what pieces, as you are saying, what pieces a community aggregator would have to pick up. Philosophically, my perspective on this is that you need to pick up your share, not your share of a piece, but your share. For me it’s not an issue of yes or no to delivery or yes or no to generation, it’s yes to all of them, and the question is how much of each. Otherwise, you would be leaving behind costs that were incurred on your behalf for others to pay.

Commissioner Schmeltzer stated I think my question was really focused on the generation piece and the DWR contracts I think I generally understood to be something that everybody is going to carry a piece of it in some way. It was not clear whether the QF’s were, maybe you can help me with the terminology that was used with the QF’s and the stranded costs this morning.

Donald Maynor, Esquire stated I was just thinking about my next question. I wasn’t following.

Commissioner Fellman stated what they talked about with the QF’s is what Mike said, the continuation costs of the stranded assets from the initial AB 1890 allocations.

Commissioner Schmeltzer stated it was not clear whether that was still out there or not.

Mike Florio stated I think there is still a question about that. I also thought the 7.9 seemed a little bit high to me currently.

Commissioner Fellman stated he took that from the 5.37 plus the capacity cost for a five-year block.

Mike Florio said okay, because the gas-fire QF’s I think are probably less than that now. I think there is some degree of an open question on how QF’s and renewable QF’s in particular might be treated. I think there is also a question of whether you look at QF’s alone, or if you bundle together QF’s with the cheaper utility-owned generation, and look at whether they are any excess costs once you average them together. That I think has really not been resolved yet. The legislation may address it. The Commission proceeding will probably have to address it in some fashion. I think on a going forward basis, there will probably be some kind of provision. The mechanics of this has not been worked out. If there is an opportunity for people to leave and that opportunity is not taken, and the utility goes out and signs some new long-term contracts; we call these the coming and going rules that there may need to be an open season or something that you can leave. If you don’t leave at that time you’re committed to some period of time to some costs. That still remains to be worked out.

Barbara Hale stated there may be some parallels that may be drawn between electric and gas. There have been options for gas customers to take advantage of aggregation programs historically. They haven’t been programs that have been utilized a lot, but there may be some models there that the Commission would rely on and the City may want to look into.

Commissioner Fellman stated I had to be out for a bit. Did you discuss the Jefferson Martin transmission line at all?

Barbara Hale stated briefly, yes.

Mike Florio stated that is coming up soon at the ISO, and I think we agreed that the need is pretty clear that the question is going to be siting because nobody wants a transmission line in their neighborhood, but everybody likes to have the benefit of it. So you have a tension there that the PUC has the unenviable task of sorting out.

Commissioner Fellman stated did you ask about alternatives?

Barbara Hale stated I had offered that. Before PG&E settled upon the Jefferson Martin option as the option they will present in the fall before the PUC, there was a working group that involved the ISO, the City, the PUC, where a number of options were evaluated. I am happy to talk about that further if it’s helpful. In the context of what they actually filed before the Public Utilities Commission, they will be required as is required under CEQA, they will be required to file alternatives to the particular route they prefer.

Mike Florio stated generally, I have heard positive feedback about this process that was carried out to select Jefferson Martin, and you know if there are folks that feel that wasn’t a good process I would like to hear about that. Because generally, it seems as if people were satisfied that good information was provided and public input was taken heavily into consideration. Before the ISO votes on this, hopefully anybody that has concerns will let me know on that.

Donald Maynor, Esquire stated Mike, you said something interesting to me that brought back a lot of the things we used to talk about in the old days. That was the importance of having a competitive alternative to PG&E. Out of this chaos, maybe there’s some opportunities for communities to come up with some creative new ideas. I think it is beneficial that those things happen because communities oftentimes, that was the case in Palo Alto, where they would come up with some unique conservation programs. Then, PG&E could see the benefits of those programs. There are some advantages of doing that. I think it would be useful if T.U.R.N. and the PUC could recognize the benefits of seeing that it is necessary for communities to have more flexibility to do some of these things and engage in these activities. To the extent that the PUC can avoid creating impediments through exit fees. I understand some of that has to happen. There should be some discussion on that and maybe the burden is on the City to bring these issues out. There are real benefits in your role as a regulator to have some competition out there in terms of, here, are some alternative programs. We have heard a lot of testimony from SMUD and others, and it is very enticing to hear what some of these other municipal utilities are doing and are able to do. At the same time, we would hear testimony from some of the folks from distributed generation, energy efficiency. They say you know, there may be a lot of potential here in San Francisco, but no one’s ever done an audit and really identify what the possibilities are.

Barbara Hale stated you know Don, the City has taken advantage of an energy efficiency program that the Public Utilities Commission offered. That was to fund to the tune of about eight million a small commercial lighting pilot program here in San Francisco.

Donald Maynor, Esquire stated we heard about that this morning.

Barbara Hale stated I think that sort of model taking advantage of that creates the competition, if you will, that you are talking about where you get to determine your own energy destiny without taking on the full risk of providing for your full load yourselves. There are other examples. For example, in San Diego County there is a regional energy office that has tried to work with various local government entities to duplicate good programs throughout the county. So there are some partnering opportunities there, there’s public goods charge funds available that are administered through the PUC that you folks should be taking advantage of and did this last program year.

Donald Maynor stated we have heard testimony to that effect. I was thinking more in terms in the procurement area where there are so many question marks. If the opportunity, particularly if things don’t evolve--Mike was talking about well, if that doesn’t happen or if this doesn’t happen, chaos could rule again. It would be useful to have as an alternative a realistic and effective option such as aggregation that doesn’t have arbitrary impediments because I think that may be something that even you would want to see happen as well as a regulator. It’s just a comment. As we are getting near the end of these public hearings, we start to get a feel for what the options are for municipalities today, particularly with all these open questions. That was just a thought that I wanted to share. Now would be a good time to have any questions from the audience.

3. Public Comment

Denis Mosgofian, San Francisco Labor Task Force for Public Power stated I am a life-long resident native of San Francisco. I’m formerly president of one of the newspaper presses local in San Francisco. I raised by kids here. Those are by way of credentials. I was active in the public power campaign last year and am on the Labor Task Force for public power. I had a question specifically the question that I wrote out for the CPUC representative, Barbara Hale. Given the recent vote by the CPUC, 3-2 to let stand existing direct access contracts, if I understand it correctly, that shifted the burden to those who remained, and yet the contracts were allowed to stand. Notwithstanding the discussion subsequently of an exit fee, is it not the case that your position as you described it generally that CPUC’s concern about shifting the burden, isn’t it the case then that that amounts to opposition to aggregation because that would continue to shift the burden away from DWR contracts. Doesn’t that constitute a way of fixing the larger share of the burden on residents, small businesses and local users that are not the big users that took off on direct access?

Barbara Hale stated yes, the effect of the shift is that the remaining customers, who are small business, commercial and residential customers largely, the direct access program has taken advantage of by large commercial and industrial customers. That does leave the burden on those who are traditionally least able to pay.

Denis Mosgofian stated so it leaves the question when you opened you opened at the CPUC’s charge is fair and reasonable rates, and yet there is nothing fair and reasonable when big users get to opt out and then restrictions are imposed leaving the rest of us holding the bigger portion of contracts that were ill-advisably entered into for longer periods of time at higher rates than they should have been entered into by the Davis administration. I’m not Republican or Democrat. I am not involved in that. I’m just saying that is where you look at it. I will get to the point on LAFCo. I like your comment. I do not see an alternative with the CPUC’s approach. That represents the larger number of us.

Barbara Hale stated I think what you have just described is largely why the vote for that item was a split vote. It’s not an easy issue to resolve. When you have these shifting of responsibilities and costs as you describe them accurately, it’s a controversial and difficult decision for the Commission to make. The real devil will be in the details in how the exit fee is calculated and assessed.

Denis Mosgofian stated let me go back to something you said. I think it was you. I thought it was you that said that the real risk of the PG&E’s Plan of Reorganization is in the risk that would arise from litigation.

Barbara Hale stated I was saying that there is a lot of risk associated with that plan because it will be litigated if it is approved by the court.

Denis Mosgofian stated would it not be the case then that there would be equally a risk with such a hot button or a controversial subject such as exit fees and a sort of an after the fact program that would end up in litigation and benefit very few of us?

Barbara Hale stated yes, I believe I pointed out that I expected whether the Commission had authority to assess an exit fee would be a litigated issue.

Denis Mosgofian stated let me go to my comment to the LAFCo. I’m a strong advocate for public power, and I believe that the Carol Migden’s bill for aggregation and what Mike Florio described as T.U.R.N.’s position in previously advocating for it provides a basis for San Francisco to begin to get into the ability to have local control as Ed Smeloff likes to talk about it in the Electricity Plan that he’s shopping around San Francisco. I think that there’s a risk here, and I think that’s why LAFCo if I understand your charge correctly you are in the business of trying to crunch the numbers and figure out what the feasibility is of more local control and even public power in San Francisco. If I understand it correctly, then I will proceed. Is that approximately right?

Donald Maynor, Esquire stated I’m not sure that’s quite accurate. It’s an investigation of the alternatives and the options. One, if it makes sense to go to the next level and actually crunching up numbers would be one of the steps down the road. I think the initial phase we are going through right now is gathering information, finding out what the issues are, what the risks are, and then to put together a report that would provide an information base which LAFCo can make recommendations on and the City would have a basis for making decisions. The one thing by the way, this is atypical for a person to come up and engage in the conversation. We typically just have the questions written out. One of the issues that we are going to talk to the Commission about next week is to have a public hearing to allow members of the public like yourself to come in and make statements and ask questions and that sort of thing. So, we’re at 3:00 right now and I didn’t want to preclude you from asking questions, but our format in the past has been to submit the written questions. Even if you want to submit them afterwards, we are happy to get the answers for you.

Denis Mosgofian stated I understand the process, but the problem with that sometimes is that is difficult to put exactly in writing in a concise enough way to make it easy, a question that really is part of a bigger picture or context in which a remark might be made. My remarks couldn’t have just been summarized by one simple question. I think given that your mandate is to look at options and look at the issues, I think LAFCo needs to look at a very large picture here because the way it is being set up in San Francisco now, the way it has been unless it is recommended that we really look at the option of having both local control and public ownership from generation forward, we will ultimately end up with the manipulations of the market, the rather weak positions that end up coming from the CPUC in terms of representing ordinary folks and small businesses, the bulk of the people, and we will end up being manipulated by the Mierans or PG&E like they’re doing now with through their bankruptcy process. So, I am likening it back to what was done in the 1930’s when we were at the depths of depression and very difficult times in this country for a variety of reasons. The government chose to commit itself to really build infrastructure that has served the country in many areas including the area of electricity generation and distribution for the last sixty-five or so years. I would suggest that LAFCo needs to be thinking in terms of that magnitude of a contribution. I will in fact participate in the future.

Donald Maynor, Esquire stated I think you made a strong argument in favor of having a public hearing. We’ll bring that up on the 19th and see what the Commission decides to do on that.

Denis Mosgofian asked is the 19th hearing here at the same time?

Donald Maynor, Esquire stated 2:00 p.m. Any other questions for our panelists?

Commissioner Fellman stated I have no further questions. I do appreciate the last gentleman’s comments, and we are taking that issue under consideration because that is something that is on the agenda here for LAFCo so it will be considered.

Public Comment closed.

4. Adjournment

Donald Maynor, Esquire stated I want to thank you both for coming here on short notice. It is very much appreciated. You gave good balance to the whole day.

The public hearing of the San Francisco Local Agency Formation Commission adjourned at 3:05 p.m.

Last updated: 8/18/2009 1:54:50 PM