HomeMy WebLinkAbout2001-09-05 Utilities Advisory Commission Summary Minutes UTILITIES ADVISORY COMMISSION MINUTES September 5, 2001
Roll Call ______________________________________________________________ 2
Oral Communications ___________________________________________________ 2
Approval of Minutes_____________________________________________________ 2
Agenda Review and Revisions _____________________________________________ 2
Reports From Commissioner Meetings/Trips _________________________________ 3
Director of Utilities Report _______________________________________________ 3
Unfinished Business ____________________________________________________ 6
Streamlining UAC Procedures _______________________________________________________ 6 Gas Quarterly Report Operations Charts _______________________________________________ 10
New Business _________________________________________________________ 12
Water Quarterly Report ____________________________________________________________ 12 Utility Financial Reporting to the UAC ________________________________________________ 18 S & P Rating Affirmed on Utility Revenue Bonds _______________________________________ 20 Demand Side Management _________________________________________________________ 21 Electric Supply Portfolio Deficit Plan: Year 2005-2010 __________________________________ 24 NCPA Commission Report _________________________________________________________ 42 TANC Report ___________________________________________________________________ 42
Adjournment__________________________________________________________ 42
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Roll Call
Chairman George Bechtel called the meeting to order at 7:30 p.m. Present also were Commissioners Richard Carlson, Rick Ferguson, Dick Rosenbaum, and Dexter Dawes.
Bechtel: Let the minutes show that all the commissioners are present. Our council
liaison, Bern Beecham, is going to be absent.
Oral Communications
Bechtel: And so our next item, oral communications. I don’t have any cards. Any members of the audience wish to speak as part of oral communications? There being none, we’ll move to approval of the minutes of the meeting held on August the 1st.
Approval of Minutes
Bechtel: Do I have a motion or comments?
Rosenbaum: Moved to approve. Ferguson: Second from Ferguson.
Bechtel: Moved by Dick Rosenbaum. Seconded by Mr. Ferguson. Opposed? And the minutes are approved.
Agenda Review and Revisions
Bechtel: The next item is agenda review and revisions. Tonight, we have, perhaps it’s the second time we’re using a slightly different format. The next item on the agenda
would be after discussing the reports of the commissioners. But other than the change in
the overall format, I’m not proposing any changes to the agenda tonight. In speaking with Randy Baldschun who will be sitting in for John Ulrich tonight, he has no recommended changes to the agenda. So unless some one of the commissioners has any comments, we’ll go with the agenda as published. I did notice that it was not on our
website today, so perhaps it will hit later on today. But I was a little disappointed that
tonight’s agenda was not on the website so hopefully the “webmeister” for the city will make sure we get the agenda posted on the website in a timely fashion. Any comments about the agenda from the commissioners?
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Reports From Commissioner Meetings/Trips
Bechtel: Being none, we’ll move to the next item, reports from commissioner meetings and trips. Our most recent meeting to which we were invited was an NCPA meeting in Murphy’s. Unfortunately none of our commissioners were able to attend that meeting,
but later on tonight we can have a report from Randy who will talk about what went on at
that meeting. We are planning another meeting of NCPA to be held in South Lake Tahoe later on this month and all the commissioners have been invited and hopefully many of you can attend. I personally plan to attend and so will get a chance to have the annual review by NCPA. We’ll have more to report on that in our October meeting.
Director of Utilities Report
Bechtel: Next item, item #6, Director of Utilities Report. Randy do you want to do it? The floor is yours. Baldschun: Thank you Chairman Bechtel. A few items just to bring you up to speed. Some of these items have been well publicized. But one of them bears mentioning
because of the importance of the events that have transpired since the last UAC meeting.
That is the FERC proceeding, with PG&E attempting to raise our Western rate to market prices. A significance was that the ALJ held oral arguments in which our attorneys presented their arguments. And we filed a brief with the FERC staff, which is unusual, where the FERC staff is working in conjunction with one of the parties of record as the
proceeding comes to a head. The ALJ has taken the briefs under consideration, is due to
render a decision Sept 21, and then it will go to the full FERC for final approval. We’re optimistic at this point, cautiously optimistic. Other events have transpired, and one that’s moving along fairly well, although I don’t
want to talk about it, is the COBUG. We are expecting to get the gas-fired generator on September the 10th and if it comes by the 10th, it will be installed and operated by September 30th by “Repliance”. Of course, the diesel will be returned. The total cost of this CIP is about $4.6 million. And again, this generator is going to be used to reduce the frequency of rolling blackouts for this year and next year. It remains to be seen if there
are going to be any, but in the event there are, we’re prepared to deal with them by having this 5-megawatt generator in Palo Alto to keep the reliability going to our customers. Girish handed me something here about the Interconnection Agreement. It says it expires
on March 31, 2002. NCPA and PG&E have been negotiating without success to extend the IA. August 30, PG&E unilaterally filed a replacement Interconnection Agreement with FERC. This Interconnection Agreement essentially offers NCPA members ISO transmission service. NCPA developed a reply intervention to FERC and NCPA staff
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will be in Washington DC next week to meet with the attorneys and work out strategies. And if you have some more questions, perhaps Girish can answer those.
The last item. On September 19th we’re going to have a study session with the city council on water issues, particularly as it has been well publicized. Mayor Eakins has taken a leadership role in the Bay Area to secure support for the rehabilitation of the regional water system. She met with Mayor Willie Brown and a number of other mayors
from some cities. So on September 19th from 6-7 p.m., we’re going to meet with the city
council and we’re going to present maybe a half hour presentation on the water issues that we’ll take into account: What we currently can provide in terms of our reliability in the event of an outage or in the event of an SFWD-Hetch Hetchy outage. How long can we provide water to the citizens of Palo Alto. Our plans to rehabilitate the system which
we’re all aware of. And then talk a little bit about working with BAWUA to convince the
powers that be in San Francisco that there’s an urgency to address this issue. That’s it for the Director’s report. If you have any questions, feel free to ask myself or Girish or staff.
Bechtel: Thank you Randy. Any questions from the Commissioners? Dexter? Dawes: I was a little confused when you were talking about the FERC situation and the September deadline, talking about our attorneys and our contribution. Is that actually
City of Palo Alto attorneys, or is this all being done through NCPA or Western. And I
was just a little unclear as to CPAU’s direct involvement in it. Baldschun: I’ll let Girish Balachandran respond to that.
Balachandran: NCPA is taking the primary role. One of the 5 attorneys, Wally Duncan,
is also representing certain other parties in this case, and the filing was made, basically, by all of them. They work together so all of the attorneys collaborated on this particular intervention. And Western’s attorneys are also pretty active. Western of course is the main party over here.
Dawes: Thank you, and one other point of clarification, the Interconnect Agreement and the September 28 decision: are they one and the same issue or are these separate issues, and if they are separate, bring me up to speed on a little more of the intricacies there.
Balachandran: The September 21 date that Randy mentioned has to do with the Western
contract and PG&E’s attempt to change the rates on that contract to market-based rates. The Interconnection Agreement is a different agreement by which the NCPA members have with PG&E for transmission and basically principles to interconnect our systems with PG&E’s system. PG&E cancelled that, issued notice of termination of that contract
several years ago and was effective March 31, 2002. There’s a certain time period after
which they actually have to make a filing to say here’s a replacement Interconnection Agreement. It doesn’t have to do with energy. The September 21 date had to do with
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one contract and the energy rate. The Interconnection Agreement has to do with transmission and interconnection issues.
Dawes: Availability of transmission, or pricing, or both? Balachandran: We will make the argument that it is both. PG&E -- in the replacement IA filing that they just made -- has basically said, take it from the ISO. There’s
transmission available in the state. You can essentially take it from the ISO. So they’ve
said it’s available and you can take at whatever price it’s available at the market. And the argument that we’d make is that there are certain rights we have to fixed price transmissions, and there are other benefits in the Interconnection Agreement which should have been included in any kind of extension. That’s what NCPA and PG&E have
been negotiating about for a few years, without any real success.
Dawes: Any clues as to where it will go? Balachandran: We hope, well we are going to litigate. We are going to go to FERC and
intervene and NCPA staff is going to go to Washington DC next week to meet with the
lawyers, both our lawyers and the City of Santa Clara’s lawyers. They have a similar Interconnection Agreement, so to join forces and strategy and we expect to be successful in this case too.
Dawes: Thanks.
Bechtel: Other questions? Dick Rosenbaum? Rosenbaum: I’m just following up on the Interconnection Agreement. Is this something
that would in any case go away at the end of 2004?
Balachandran: 2002. March 2002. Rosenbaum: I know. But and we are trying to either have it extended or get a
satisfactory replacement. But would it disappear any ways at the end of 2004?
Balachandran: No. It would not. There is no connection between that Interconnection Agreement and the Western agreement. They are on different time scales.
Rosenbaum: So we’re asking that we continue what we regard as a good deal with
PG&E -- essentially indefinitely? Balachandran: Right.
Rosenbaum: Thank you.
Bechtel: Other questions? Thank you very much Randy and Girish. Actually, one follow-up question: the water review by the council. I’m not familiar with the format.
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Can you fill me in as to what’s going to take place here? If you’ll talk about that later in the month?
Baldschun: The plan is for staff to make a presentation and let the council ask us questions and the public. I don’t think that there is, in terms of UAC rule, that I’d imagine that it’ll be similar to when we had the energy forums where you were encouraged to attend. But I don’t think you’ll be asked to make any presentations or
statements unless the council sees you and asks you.
Bechtel: This is just basically to allow you or the council to have dialog with you. Baldschun: Right, obviously it’s quite important that we elevate it to the Mayor of San
Francisco and now it’s probably important to elevate it the city council via study
sessions. Bechtel: Okay.
Commissioner: And what time of day was that on the 19th?
Baldschun: 7pm
Unfinished Business
Streamlining UAC Procedures
Bechtel: Okay, so moving on to unfinished business. The first item under unfinished business is streamlining UAC procedures and that is up for action. You have, we all
received in our packet, a summary of some of our earlier discussions that Rick Ferguson
and I had with staff brought to you last meeting and Rick has done a great job in summarizing in his note what is recommended in streamlining. Perhaps, basically updating the procedures that we have. There has been a fair amount of discussion, we had discussion earlier, I think 2 months now. Some of the, one of the actions that had
been recommended in that procedure will be discussed later by Randy under the utility
financial reporting to UAC under new business item #2. Some of the implementation will be discussed then. I guess really what I’d like to do now is to have Rick introduce the subject and then open it up for questions. Then hopefully we can review it and take some action on approving this particular procedure or some modification as you with.
Ferguson: Thank you, Mr. Chairman. This is pretty much as we’ve discussed it. There’s a more streamlined annual-meeting cycle, improvements in the regular meeting agenda and procedure reflecting some of our experience in the last couple of years, some requests to staff and to ourselves for a change in the way we prepare materials and
questions coming into the meetings, and a couple of clean-up items on how we handle our elections. But everything in here is not a surprise. I’d appreciate comment if I missed something here, or need to add something, and then I’d be glad to make a motion.
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Bechtel: Questions from the commissioners on the proposed UAC procedures? Mr.
Dawes?
Dawes: Mr. Chairman, you mentioned that there was a future item here on financial reporting which obviously is a new thing. I would propose that Mr. Ferguson modify or add to the annual meeting cycle item number one, an “(F)” which would specify that the
UAC would receive quarterly financial reports, November, February, May and August,
which would summarize the financial performance of each of the utilities and the performance and the status of the reserves for each of the utilities as proposed by staff. Bechtel: Okay. Any other discussion on that particular item?
Ferguson: I’d be happy to do it. Actually, when I saw the packet here -- Randy sent along a copy of the calendar as well -- it will dovetail. My preference, and I hope you’d agree, is to just have a straight up-and-down vote on this procedure, and then deal with the staff proposal as a separate item because it would dovetail in as an independent
action. It will also leave a little scheduling discretion to the staff. This particular
proposal locks them in on 6 or 8 items already. If they have a little more scheduling discretion, as long as they get at least 4 reports in the course of a year -- we could discuss this under the financial reporting items. My recommendation is to have 2 votes.
Bechtel: Well, perhaps Dexter’s proposal. I’m just going over the 5 items that are in our
proposed annual meeting cycle and I’m just wondering if our quarterly reviews would be included in any of those and I’m not sure I see that anywhere, so I guess I’m open to adding it, I’m open to leave it at the discretion of staff to putting it in. Any more comments on this particular addition to the annual meeting cycle from any of the other
commissioners? If you feel strongly about detailing the quarterly reviews or not? I don’t
hear or see any other strong indication one way or another. Dexter, if you want to propose it as a motion, then we can deal with it that way, otherwise we can move on with any other comments on that, so maybe we can just leave that as an item and collect from them. Any other comments from any other commissioners on any other items here?
Dick?
Rosenbaum: Item 1A under the Annual Meeting Cycle, the dates for the meetings in January and February, I thought were a little too indefinite. I wonder if we can do something with respect to that taking into account of why you brought that up.
Ferguson: Third Wednesdays, I think, are planning commission. We may end up in a perpetual scheduling conflict, so I just wanted to leave a window of wiggle room there so that in any given year, the staff can drop the UAC meeting into the available date.
Rosenbaum: Well something other than a Wednesday. The problem with me and I’m
sure others, I do schedule things, cultural events, far in advance. I try to take into account to the degree I can, my commitments. I don’t like to have an indefinite commitment.
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Ferguson: I certainly assume the staff would be able to pin down those dates for us far in advance. The hope is for this procedure to work for a couple of years running into the
future.
Bechtel: Now I’m trying to remember, Rick. We’re talking about not trying to schedule anything really close to the beginning of January. Was that the reason that we had moved to the middle of the month? I can’t remember the reason. So that is part of the reason for
the vagueness, partly to accommodate trying to eliminate a meeting right after the first of
January. Ferguson: There are a little portfolio reasons. One of which is that it’s vacation season. Getting a packet out on time for a first Wednesday meeting would be a stretch. The
second thing is, at least every other year, or every year is the council’s own kick off
meeting where the council organizes itself. Rather than us trying to get ahead of that and prepare, let’s follow it. We also wanted to be a week ahead of the California NCPA events as well. That third week, ideally, it would be the third Wednesday. You’re right, Commissioner Rosenbaum, it would be the perfect week. I’d be happy to suggest that
if...
Rosenbaum: But not the second Wednesday? Why wouldn’t the second work? Bechtel: Did you say something about the planning commission on the second?
Ferguson: No, the planning commission has been on third Wednesdays, the UAC is on the first Wednesday. Bechtel: Does anyone have a council, I mean or another meeting calendar? I agree that
if we could be a little more specific, for example like the second Wednesday as opposed
to the third, we might be at least able to pin it down. It makes sense to be more specific, unless we were even more vague like say perhaps in the December meeting, we can reschedule for the next month or so. Any other discussion?
Dawes: I’m just trying to follow up on that point. Is there any reason why we don’t want
to do the second Wednesday in January and second Wednesday in February? Would that not take care of the conflicts that we’re trying to avoid? Ferguson: The second Wednesday in January presents a problem if New Year’s is on a
Wednesday. We’re still short on time to get a package out.
Bechtel: At least, the second Wednesday is at least better than the first Wednesday so we’re making some progress here. Perhaps we, can we be more specific?
Ferguson: The best bet, if you want a specific Wednesday, is to say the third Wednesday
in January and the second Wednesday in February. I’d be happy to make that change. Dawes: Alright.
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Bechtel: So we have a proposal to change item 1A in the annual meeting cycle to the
third Wednesday in January and the second Wednesday in February. If those dates don’t
work, I’m sure we can as we go forward we can look at a possible change. We have 2 changes proposed for the annual meeting cycle: this last one and the first one from Mr. Dawes about adding the quarterly reports. Other additions from commissioners on our UAC procedures? Mr. Rosenbaum has one more.
Rosenbaum: I have a question on B. During the October and March meetings, the commissioners conducted semiannual review of performance against the strategic plan. Is this a new assignment for us? Is this something we’ve ever done before?
Ferguson: No, but we’ve actually discussed it, adopted it and the city council agreed
with our motion. There was a formal council action here to have a semiannual review against the strategic plan. Our interesting scheduling challenge was to decide to do that with the council, or get it done ahead of the council’s review. We laid out the schedule so we can get it done a month or so ahead.
Rosenbaum: Performance against the strategic plan strikes me as a little constraining. Is that really the intent given the broad general nature of the strategic plan? If we compare it to the comprehensive plan with land usages, typically the staff would never have a problem with coming up with justification for any recommendation because of the nature
of the comprehensive plan. I’m concerned that the same thing may happen with regard to
the strategic plan. I don’t know if that is something we can address tonight, but we might want to be aware during our discussion of those 2 meetings, we might not want to limit ourselves quite so stringently.
Bechtel: I have a feeling, Dick, that we really won’t feel too constrained. But one of the
things we haven’t done yet, is come up with performance measurements. So personally I’d like to see at least one cycle with this review just to make sure we have a chance to review the performance measurements. I’m not sure whether we’re going to see and I suspect that we’ll probably have to work in the next few meetings, to hopefully we’re
going to have something from staff, an update to the strategic plan and at that point
hopefully we’ll be able to at least talk about performance measurements and then at that time hopefully we can address also whether our review is going to make sense and what format it to have. Yes, Randy?
Baldschun: If I might add, our plan is to work with the UAC and get a consensus on
what makes sense to measure. And so we’ll have some performance measures we’ll be bringing to you, and some you may like and say that’s fine, and some you may kick out and then when we get the agreement on what we’re going to measure, we’ll be reporting those semiannually.
Bechtel: Thank you Randy. If there are no other questions, let’s see, we have 2 proposed changes, perhaps, I was hoping the Rick would make a motion to approve this and if he
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would incorporate or include those changes that are acceptable to him in his motion, then we can deal with this in one fell swoop.
Ferguson: Sure, I’d be happy to. I move that the UAC adopt the new procedures as proposed in the memo here with the following 2 changes. In paragraph 1A, the dates are replaced with the third Wednesday in January and the second Wednesday in February. And then we have a new item 1F, to incorporate the integrated quarterly financial reports
that the staff has proposed in its separate item on tonight’s agenda.
Bechtel: Do I have a second? Carlson: Second.
Bechtel: Seconded by Mr. Carlson. No other discussion? All in favor? Let the minutes show that it was approved unanimously. Thank you, Rick, for pulling this together. This is something you were interested in and looking to add, to jazz up our meetings and make sure we’re covering the right issues. This does a great job of addressing that.
Gas Quarterly Report Operations Charts
Bechtel: The next item under unfinished business is Gas Quarterly Reports Operations Charts. I gather from the minutes since I wasn’t here last meeting that this item was overlooked. I guess the appropriate action if there’s no introduction, are there any
comments on these charts? Baldschun: Roger Cwiak is here, Chief Engineer from Wastewater. If you have any questions on the charts, he’s prepared to respond.
Bechtel: Questions on the charts from the commissioners? Mr. Dawes? Dawes: Just wanted to run down on the extraordinary gas outage looks like #105 was out for 9 hours, an unplanned outage. This seems like a major problem. I was wondering if there were any lessons to be learned from it.
Bechtel: Roger is thinking whether he is going to come up and talk to us about it. Cwiak: I’m not completely familiar with this particular item so I would hate to speculate as to why it took 9 hours other than it must have been type of kind of problem in the field
while they were digging down to repair the pipe. I could get back with the information on this particular incident if you would care for us to report. Dawes: If there was, it doesn’t come to mind, there probably wasn’t anything extraordinary about it so I don’t want to put staff to that discomfiture to do that so.
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Cwiak: This may have been related to the number of customers who were put out of service at a length of time and as the system was restored, it took a long time to re-light,
There were a lot of customers who were put out of service on this incident. It may not
have been the time just to repair the pipeline, but also to restore service to re-light all the pilots that have gone out. Dawes: On that customer effective chart, it’s apparent that there’s a big spike at the same
time.
Bechtel: Thank you Roger. I have only one comment on these: it will be helpful to put the date on which these were prepared. I know you run a running count by incident, because I asked a question in my first year on here and found out that this is by incident
and not by date so it’s kind of hard to track, but if you could at least ask the person who
prepares these put the date that the chart was prepared or presented it would be helpful when you pull it. I’m not sure, I assume know it says fiscal year, but it doesn’t say the date as of a month ago or whenever whatever it is. If you can add that, it would be helpful to me. Any other questions on this item? Yes, Mr. Rosenbaum.
Rosenbaum: As long as we’re talking about gas, let me broaden the subject a little. Last month, we mentioned we’re going to have these extraordinarily high natural gas rates in this coming year and I wondered if staff had given any further thought about whether or how we’re going to notify our customers of what they have to face this winter.
Baldschun: I don’t know if you received your bill this month, Dick, but in the Utility Community Announcement (UCA) page there is 2 or 3 paragraphs that talks about the point you’re bringing up which is to make customers aware that the full brunt of the gas increases that we’ve passed in the past 12 months has not really hit them until this
upcoming winter comes. And our strategy is, we do have a communications plan. We
have 4 or 5 staff working on it. The first step is UCA, which is going out this month. There’s going to be a bill insert if we can find the space. There will be some newspaper advertising, but basically the message is, your gas rates, you’ve been shielded from the brunt of them so be prepared for this winter and there’s some conservation programs you
can take advantage of and we have some financial assistance programs that you can take
advantage of. But I do want to add that this is nothing new. We do this every winter. If you go back to the bill inserts for last year and the year before, this is kind of the standard reminder we tell our customers, to prepare for winter. And but this particular year is going to be the worse we’ve ever had in terms of the high bills so yes we are going to, it
is a priority for us to do that.
Rosenbaum: I guess one thought I had and I’m not sure the wisdom of it. We have the data for each customer, to send each customer a letter to say, this is what you paid in the winter months last year, and this is what you’re going to pay this year if you use the same
amount of gas as last year. This will really catch people’s attention. Now whether this is
a good idea from the standpoint of utilities or not, I don’t know. But there’s an idea for you.
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Bechtel: Sounds like “break the news gently but hit them on the head with it at the same time.” That’s going to be a tough one, but I’m sure that Randy and his marketing staff
will deal with it in an appropriate fashion, and break the news to us gently.
Baldschun: The other piece we have to explain too is why the gas rates aren’t going down in Palo Alto while they’ve gone down in surrounding cities. That’s one component I failed to mention. We need to communicate.
Bechtel: Other comments on the Gas Quarterly Report? Carlson: In this kind of situation, blunter is probably better, because we really need to get this message across early. The bigger the hammer, the better to get people to
conserve now when they have the time to take the actions, rather when it’s too late. So
I’d push this as hard as we can. I don’t think we can be too hard on this kind of issue. Bechtel: Hopefully more people like myself took advantage of the high efficiency furnace rebate we had. We have some great programs to save on gas, so hopefully people
will take advantage of everything they can from a conservation point of view even if the
city has to fork over a rebate of $500 or whatever the sum was. Other comments?
New Business
Water Quarterly Report
Bechtel: We’ll move under 7 items under new business. The first one of those is the Water Quarterly Report, which is an information item. Jane, I guess were you going to
brief us or take questions on the Water Quarterly Report? Ratchye: Girish is handing out the third attachment that was referred to in the quarterly issues update. I don’t know if any of you noticed it wasn’t attached. This is a document
that was put together by Assemblyman Lou Papan a very nice package of information
including a cover letter that’s pretty aggressive from him about moving towards regional governments and the regional system, followed by this study done at his request by UCLA that explored two types of regional government formats and that the system should move towards a regional governments. Followed by some things you’ve probably
already seen before including the state auditor’s report that Assemblyman Papan asked
for a couple of years ago that was very critical of the PUC’s management of the system and asked at that time over 2 years ago that they complete and adopt a long term CAP and Financial plan that we now know they still have not done. Commissioner Bechtel, you asked for a debriefing on the meeting with Mayor Brown. I sort of missed what you
were requesting.
Bechtel: I had not specifically asked for that before tonight but I will ask that. Mayor Eakins has done a great job at representing the city pushing forward I saw a various meetings, I’m sorry, various press stories on that. We’d all appreciate an insider’s look at
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the effectiveness of that, what we might perceive as some of the stumbling blocks we’re still going to have. I guess I’m not very bullish on what I see coming out of the City of
San Francisco and still, the conclusion had been that it’s going to be a political issue and
not much is going to happen, but that’s my own personal opinion. And maybe some of this comes from Art Jensen’s who has done a great job also pulling it all together. Your personal take on this? I’d personally like to hear from you.
Ratchye: Well it is a political issue and it’s a very long uphill battle we face with San
Francisco, but there isn’t that many alternatives. We have to go as far as we can towards requesting that and do a lot of homework around coming up with an alternative structure and a recommendation on principles on how to operate that system them regionally. We’re on an effective path by raising this up and using our political resources to get the
word out.
It’s fairly amazing that we got a meeting with Mayor Brown in San Francisco and that was done relatively quickly. He said he cleared his calendar with the elected officials and it happened fairly quickly. He heard what they had to say but he didn’t commit too much
in that meeting. There were a few follow-up items that we will be following up on. One
is to go to this task force, the mayor’s infrastructure task force who he Mayor Brown has tasked with taking the CIP plan and for another 90 days of public hearing and let them know that there are agencies beyond the borders of SF that are concerned. I went to this task force meeting a couple of weeks ago and it was clear to me. They were all San
Franciscans. They were very, very bogged down in just neighborhood politics. I’d say
an hour of the meeting was about where a certain sewage digester was going to be located because they were thinking it is located in the Bay View Hunter’s area -- and that is holding up the CIP for the regional system.
Their CIP has 4 main areas in it: it has the in-city water projects, it has the sewer system
of the City of San Francisco, it has the Hetch Hetchy power project, and finally it has the piece we’re interested in, the regional water that effects 1/3 of San Francisco and 2/3 of the rest of us. And to have all of that tied down together like that, I see tremendous political problem with going forward like that. There are many community groups out
there that are going to pick out one project. It is going to be very hard for them to get
some of these projects. I don’t know if they need them or not or whether they are cited appropriately or anything. The whole thing is going to be delayed because of that and so I would like to find a way to sever out the regional system and have them do whatever they need to do internally in the city to solve the problems of their water and sewer and
whatever power problems they have or CAP projects they have at Hetchy power and let
them follow their own timeline to do that. A case has to be made to that task force that we don’t really care what they do there but we do care about our part and we feel the need to reduce the risk that we see ourselves exposed to on the regional system. We tried to make that case to Mayor Brown, but I’m not sure we got any traction at that meeting
on that. But it has been raised and we’ll raise it again at the task force.
Baldschun: What is encouraging and new here is that we’re getting these Mayors in cities now talking. There’s going to be some educational process amidst Peninsula cities
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that depend so much on this regional water supply. If we get enough of these Mayors interested in these various cities, that will give us another political arm to try to persuade
the powers that be in San Francisco to move forward on this project. That’s some good
news. Sandy, to her credit, is very dedicated in working hard for Palo Alto on this issue. Bechtel: Good. Thank you both for being straightforward and particularly Jane being straightforward in assessing what’s happening in San Francisco. And Randy, your
comments on what Sandy is doing is great. We’re going to gain traction on this issue.
Other comments, questions for Jane on this Water Quarterly Report? Mr. Ferguson. Ferguson: First of all, thanks again for a sustained 2-year effort here. There are so many unresolved issues in the SF relationship, we knew we had to open a third front on the
legislative side. It’s still difficult, but at least we made some forward motion, so thanks
for the sustained effort. A question about the timing: I understand that there was a rational political judgment in a difficult political environment in San Francisco not to put this on the ballot this November. But isn’t it possible for them to schedule a special election shortly afterward? Do we lose a whole year or two to put this issue in front of
the voters in a way that it gets severed from their other hot utility topics in November?
Ratchye: A special election to have -- you mean before? What we wanted first of all, what we hoped is that they’d adopt this thing and take the first bond measure to the voters in March 2002 but that would require action on the part of Mayor Brown prior to the
November election when he’s going to have these 2 government issues on the ballot that
he doesn’t want to see passed. He’s afraid that if they adopted the plan, first of all if they adopted the plan before the first of November, that the headline would be “water and sewer rates in San Francisco would double, tomorrow vote to get rid of the PUC”. And he didn’t want to do that because he gets to appoint the members of the PUC now and he
doesn’t want it to be replaced by a body that would be elected by the voters directly.
There’s some timeline in order to get something on the ballot by March and he would have had to do something before November. Right now they’re thinking they can get it on the November 2002 ballot. And I don’t know if you’re asking about could it be between March and November.
Ferguson: Yes. How much time have we really lost here? Is it as much as a year or is it only 6 months? Ratchye: Well I’m not sure how much time will be lost. They do have money in San
Francisco. If you remember the measures A & B that the SF voters approved, I think it
was in ’97. Two bond measures that totaled around $300-305 million. They also sold some property, the Bernal Property, for about $425 million, so they have a lot of money sitting around. Their problem is they just can’t seem to pour concrete and spend it. They have enough money to begin, they’re not in need yet of these bonds. What they’re in
need of is a plan and so I’m not sure that this is a delay of construction. But it will be a
delay if they don’t adopt the plan and commit to the financing of it somehow of it. We’re also trying to take the message that even if you haven’t got the bonds or if you haven’t adopted the long-term financial plans, you can still go forward on some of these critical
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projects that everyone knows we need to start on now. We’re trying to get them to move on that too. I don’t think it’s more than a financial problem there. It’s just, this
magnitude of a program, I don’t think they’re capable of doing it.
Bechtel: That’s a very discouraging comment. Other questions? Mr. Dawes. Dawes: There was an article in the Palo Alto Weekly, I think it was today’s edition,
which sort of reported on this whole situation. The thrust of the article was that Palo Alto
was leading the charge to establish a regional governance program for the suburban people particularly for the assets outside San Francisco. Clearly that’s in our sights. But in reading this material and a general understanding of the situation was that effort was being sort of edged onto the table. As I read Mayor Eakins letter and Art Jensen’s speech
to the PUC, there were sort of veiled comments about if you don’t get on with it, there
were other ways of accomplishing this. There were not a shall I say any specifics along the line that the suburban people are going to push for a governance changes obviously with Papan’s thing which I knew about but haven’t seen. It’s going to rapidly be coming on the table. Is there any understanding of what that process is going to be? Papan’s
office talked about introducing legislation. Is legislation necessary? Are votes of the
people necessary? How does that process likely to unfold if anybody has any ideas? Ratchye: It can unfold in a number of different ways. It can be legislative and there wouldn’t have to be a vote. You can set up a different water district or some kind of
special district under the Metropolitan Water Act or something that could have
memberships by the different agencies whose governing bodies would agree to being a member of such an agency. In this packet, there’s the legislative analyst report that talks specifically about that. How it could be done legislatively. Now as to what ballot is doing there? I don’t think we’re doing enough there right now. For one, we need to have
a fairly good proposal prepared about what are the principles under any kind of
governance structure and there are several. How do we want it done if we could have our choice of how to do it? And we need to do that work. We need to put some resources to the effort.
Dawes: Is “we” BAWUA or Palo Alto?
Ratchye: It’s “we” BAWUA. It’s a joint action type of activity. Clearly it’s a regional system. We’re going to making a case for the best of the public interest, of the regional public interest, for the large public interest of the 2.4 million people that are served by
this system that it be managed by some regional entity that will and is accountable to
everyone, because now the PUC is only accountable for some small subset. Dawes: This is an informational item for us tonight. It sounds as though, if not tonight, then maybe fairly soon, that we should perhaps debate the issue in this forum and make a
recommendation to city council on how we would propose the city interact with
BAWUA, what positions we should take and so forth. Is this an idea the staff has taken? Any thought to it? Is that an appropriate way to go about this?
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Balachandran: Yes, we have given some thought to it and we will bring back more information to you in a way can provide your input to the council to structure your
strategies. There are a number of opportunities including the December legislative
agenda, that’s one area. We’ve also talked about having similar to the energy forum, having a water issues forum. For follow-up we have the council’s study session in September and maybe in the November time frame, we’ll have the water issues forum. That’s another place to get public input so we will be bringing this back to you.
Bechtel: Thanks. Yes, this is a great idea for us to look at this again. I can see all sorts of suggestions that can come out of our group for making sure we cover our bases in water. Any other questions for Jane on this particular topic? Or the general report itself? I have or Rick, did you have a …?
Ferguson: Did you want to open it up to the water system and O & M? Bechtel: I had a question myself but go ahead.
Ferguson: I would like to ask Roger again. But a general question Roger, not a specific
question about the charts. When you look at the little portfolio of water system leak repair charts here, is there anything about the pattern that seems out of line to you? Is this the typical pattern that you see year to year?
Cwiak: Which of the charts in particular were you?
Ferguson: We have 3 or 4 charts here, each of which offering a slightly different measure of leaks and water systems disruptions. I can ask questions about trends and so forth, but I just wanted to ask you about the gestalt of it. Is there anything that you’re
looking at out of line, or are we just looking at normal variations?
Cwiak: I don’t really see anything that’s out of line. Bechtel: Can I direct your attention to graph 19 call it unplanned water service
disruptions and to the reporting of who causes the water disruptions and I see something
called third party that really bothers me in terms of causing disruptions. Cwiak: We have contractors working in the city. We’re pursuing an infrastructure replacement program. During the last year, we’ve done some of the largest sewer work
that’s been done in the city probably in 50 or 60 years. We’ve put in pipes with open cut
trenching with trenches as wide as 15 feet and as deep as 16 feet and when you have services that you’re trying to maintain during construction with thin pipe service lines running across an excavation that may be up to 300 feet long and trying to maintain service to each customer with the water, gas and sewage service crossing all of these you
tend to have many interruptions. Most of them probably came over Lewis and Colorado
over the last year. Very difficult construction and lots of interruption to customers because we’re trying to improve the system. When we had the flood a few years ago, the customers in this area asked us could we do anything about the sewers that backed up on
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their properties during that time. And we told them that it would take 3 years to get to your neighborhood if we started right then, changing our design plans and worked on just
the sewers to get to your neighborhoods. We did that. We came through there this
summer and over the last year and we’re just now finishing those projects. The trend for the interruptions for those type of services should be in a downward trend now since we’ve completed these large pipeline construction projects.
Bechtel: Rick, did that help?
Ferguson: Yes. Just trying to get a read on what the staff thinks is a normal variation. Thanks.
Bechtel: Thanks Roger. I interpret the third party, to mean it could be city
commissioned projects not necessarily homeowner contractor work of some sort. Am I interpreting this right? Cwiak: It could be both but more of the incidents are caused by contractors working for
the city because of the difficulties of the construction I tried to describe there. These are
huge holes trying to maintain services and if we break a gas service or water service, it usually involves shutting down a block. On both of those utilities, we have valves at intersections and so we’re either shutting down whole blocks and that might happen several times in a day on the same block if there is construction.
Ferguson: What are the ways, how do we compare to our immediate neighbors -- Redwood City? Mountain View? Disruption rates? Leak rates? Failure rates? Are we about the same?
Cwiak: I really don’t know how they or what construction they have going on now. I
would think that strictly material failures for the same type of materials in the same utilities, they would probably be experiencing the some type of trend that Palo Alto is experiencing, just because they were built at the same time at the same type of soils so they’d experience the same type of stresses we’re experiencing in our system.
Dawes: Roger, I just wanted to get a sense from your group that the maintenance procedures for in this case the water system are appropriate and that we’re not getting behind the curve on deferred maintenance. There’s been some criticism amongst the citizenry about deferred maintenance on other parts of our infrastructure and sewers
specifically I guess and I just wanted to get on the record that staff is confident and
believes that the amount of money that is being put towards maintenance and infrastructure upgrades in water is appropriate and that we’re not behind on keeping our system in a good state of repair
Cwiak: I believe that we’re in a very good shape as far as keeping up with the
replacements in our system. And for the challenges for the Board of Utilities in the near future the work that we’re doing to replace the cast iron mains will reap a lot of benefits when we switch to the “chlorine” disinfectant. We’re eliminating miles of 4” cast iron
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mains that when we do our flushing program, there’s no real way to flush those lines individually because they didn’t have any fire hydrants. They were also breaking more
often than the larger diameter lines and some of the smaller diameter ACP lines-Asbestos
Concrete lines. Once we complete that, the system will be much better as far as of being able to operate it. The valves that have been replaced in the downtown area improve our ability to operate the system in the downtown area also.
Bechtel: No other questions? Thank you very much Roger.
Utility Financial Reporting to the UAC
Bechtel: Moving onto the next item- Utility Financial Reporting to the UAC. Information item. This is an excellent start on adding some more information to us
hopefully to others who read the reports. Randy do you want to talk about that? Baldschun: This is a response to a meetings you mentioned earlier that we had a couple of months ago and a discussions at the UAC meetings about reporting financial information. Basically we provide a number of different avenues to you to give you
financial information. Most important is during the budget process, when you consider rate increases. We looked at the 10-year financial forecast. What we wanted to provide you was, recognizing that we can’t do a 10 year financial forecast every month or even every quarter, because it involves quite a bit of staff to give us input on updating the numbers.
What we think is the bottom line is the Reserve projections. Reserve projections reflect the most updated information that we have internally on such things such as sales vs. projections, our purchase power cost vs. projections, wholesale sales revenues. Those are our main drivers. CIP is another one. What we’re suggesting is that instead of giving
you 12 quarter reports which is what we’ve been doing every month such as the one we went through on the water, we’d combine them into water, gas and electric. You would get a thicker report but it would be more comprehensive. The downside is it will take more time during that quarter to go through the report but the upside is that you’re going to get some graphs you’re not getting now, you’ll get some rate comparisons, you’re
going to get reserve projections, you’ll get updates on any BAO’s that we have taken to the council. This is all stuff you’re not getting now. It’s a better efficient use of our time. Frankly, Roger is here trying to answer questions about a graph. We can’t have a person 12 times
a year to come in to answer these kind of questions and be there for 2 hours just to answer one question, so hopefully by doing this on a quarterly basis, we’ll get the right people at that one meeting and they won’t have to attend 12 meetings so feedback I’ve gotten from the staff is positive and from you individually is positive. We can move forward with this.
Bechtel: Thanks a lot. Do we have questions on the proposed procedures? Mr. Dawes.
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Dawes: I just wanted to ensure I understood the projected reserve schedule. Seems
pretty straightforward. It’s all based on starting with the budgeted ending balance of the
reserve for the year and then applying changes. You show the change in operating margin actual bases through a particular month, then the BAOs and then the last 2 items I assume are the 2 main components of the operating margin mainly revenues and expenditures. Those estimates would be from the same month. In other words, it would
be actual and then there would be an estimate against the budget, but it would be broken
down into revenue side and a supply side, which is a very good way to flag any questions about it. That leads me to the assumption that it assumes the CIPs and the operating cost side are going to be on budget for the rest of the year. That’s the missing link there.
Baldschun: That’s the point is that yes, in recognizing that the CIPs and the operating
expenses are not going to be updates. But frankly those 2 pieces even though the CIP is large, it doesn’t typically change hugely. Dawes: In calendarizing, it’s really hard to understand. It’s an excellent schedule. I’ve
taken certainly a lot of interest in the issue of financial reporting and this is a big step
forward. I hope that as the items 1-4 on page 2 are moved forward -- in other words the accounting system is brought up to date and so forth -- I’m sure that NCPA will be providing estimates that get better and better, that we will have more complete information as we go down through the years. But it’s a great step in the right direction.
Baldschun: I do want to comment that the accounting system is accurate and the accounting system, we’ve actually gotten awards for our annual reports. The problem with our accounting system is that in any given month, the staff, it’s garbage in, garbage out. We have hundreds and hundreds of transactions that we do where we’re putting in
the wrong account # that goes into the accounting system and it’s created but it’s not
created that month. It may be corrected 2 or 3 months later when we recognize it. It’s the same problem with our CIS. There are meter reading errors that occur. If you look at a give month, you can see a tremendous swings in a month it’s obviously because there’s an error and it gets corrected but they don’t get corrected on a real time basis. It takes a
month or two for these things to flow through the system. I wanted to make that
distinction. I don’t want to give an impression that our accounting system is not accurate, but there are some human factors that do cause some frustration in the staff in getting the numbers.
Bechtel: Other questions? I have, I guess, the main question I have is, when are we
going to see our first report and when do we want to discuss it? I was looking back over our procedures and we just had a discussion of this item but we didn’t, there was no specificity about when we were going to discuss it. A proposal from staff?
Baldschun: I would propose that November be the first Utility Quarterly Report and so
that for October there would not be a report and come November we’ll have our first full scale Quarterly Report. And then the schedule would be November, February, May and August. The August report would report on the fiscal year results for the prior fiscal
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year. It would be a 12 month, you know the prior fiscal year ending which is important as well as the first quarter of the fiscal year to the extend we get the NCPA bills and other
things in a timely manner.
Bechtel: Sort of a fiscal year close-out in August. Baldschun: Correct.
Bechtel: And then lets say November and then quarterly thereafter. Okay. Comments about schedule from fellow commissioners? Sounds good. Thank you very much Randy. That completes discussion on item #2 under new business.
S & P Rating Affirmed on Utility Revenue Bonds
Bechtel: Item #3, the S & P Rating Affirmed on Utility Revenue Bonds. Our citizens should be very proud of our rating. Any discussion on that from those present? Randy do you want to talk a little about that or just take questions?
Baldschun: It’s important to at least acknowledge, because here we are in a very difficult year in the utilities business and there’s downgrading of municipal utility bonds, state bonds that rating agencies have come to us and said they want to do a full review of our bond rating for 1995 bonds. They cited some very strong strengths and reaffirmed the double A+ rating on ’95 issue. We take for granted sometimes the fact that we pass these
rate increases. But in the eyes of the bond rating agencies, that is so important that we can do that, because not every community can get a rate increase approved. And the fact that we had these 4 gas rate increases unanimously approved by the UAC, unanimously approved by finance and unanimously approved by the council. They were very impressed. And of course the reserve balances are another big plus factor for us.
Bechtel: Mr. Dawes. Dawes: I was actually kind of shocked that we didn’t get triple A on our utility bonds just like we have on our city bonds. I mean we got reserves equal to our annual cost in
this thing and I just don’t understand why we didn’t get that last little plus. Do you have any comments about that Randy? Baldschun: In this environment, I don’t think that they’re going to raise any bond ratings because of the uncertainty of the power industry. That’s a big concern. You know the
’95 issuance was on strong grounds. All the questions were on electric utility and the gas utility. And then this is a real difficult period the industry is going through and so I wouldn’t expect to see any upgrade. Dawes: I’m still annoyed.
Bechtel: Any other questions? Thanks very much for the report.
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Demand Side Management
Bechtel: Next item #4 is, just looking at the clock and thinking maybe we just move on forward here real quickly, or not necessarily quickly, but just move on. #4 Demand Side Management. Karl Knapp I guess is going to cover any questions he might have on that.
Questions from I guess on the presentation? What’s your proposal to handle this item?
Baldschun: I’d like to first recognize, Karl Knapp, who wrote the report. It’s an excellent report. And to Tom Auzenne and his staff in Marketing Services who made it happen for this past year our DSM program was just phenomenal and that report will give
you that picture but that’s a lot of work and a lot of people and they deserve all the credit.
That’s all I want to say. Bechtel: Karl, do you want to move ahead and talk to us about the major accomplishments that we see here.
Knapp: Yes, I had no planned presentation, but the key bullets are worth running through anyway. I wanted to acknowledge, not just Tom but all the people in marketing who pulled it together because this report wouldn’t exist in this state without them so. What happened with energy efficiency investments in the last fiscal year is actually reduced
electric load in Palo Alto by about 7 ½ megawatts. About 5.3 of those are from
commercial and 1 ½ from residential and another ½ megawatt just in city facilities. The, combined, DCAP and ACCEL which was put into practice in April achieved about 5.1 megawatts worth of reduction with a goal of hitting 5 megawatts. And all this realized well spending about $5.2 million in the DSM programs all together, $3.5 million of that
came from the electric reserve and $1.7 million from public benefits.
Bechtel: Could you, as you go through this, you might want to elaborate a little bit on the DCAP and ACCEL and some of the acronyms to make sure that you remind us of what we, we’ve seen these, but just you need to remind us every so often.
Knapp: Yeah, also for those who may not be familiar also originally there was the commercial advantage program and then when we really wanted to accelerate energy efficiency investments, DCAP was basically doubled all of those. It doubled the rebates and all the commercial investments. ACCEL was a shared savings program based on the
4 prices that were available at the time that we’re facing on the margin and so
commercial customers had a choice of saving between a double rebate on a prescriptive basis or half of what it saves in utilities whichever was higher. Together that made up the accelerated AEEP program which is yet another acronym for those 2 together The Accelerated Energy Efficiency Program. About expenses for DSM programs were 3.8
million for commercial and 1.6 or 1.4 million for residential customers. But on top of
that, city invested over ½ million dollars in city facility retrofits and there’s a total of matching grants from the CEC anticipated to be about $905,000 to go along with the ½ million dollars. And those together achieved this ½ megawatt load reduction saved about
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2 almost 3 million kilowatt hours a year. Now Palo Alto as a whole looking at historical data is reduced consumption by about 10% compared to last year, it’s even corrected for
the cooler temperatures this year. And this AEEP program although it was cost effective
given the price information we had in April, prices have stabilized since then and come more in line with utility rates so at this point looking forward, a shared savings program doesn’t make financial sense. Those are pretty much the highlights.
Bechtel: I was interested very much in the fact that I guess we’re now saying that buying
down is not the best policy. It’s interesting how life can change so quickly from a great look at this in about June of this year. Questions from commissioners on the report? Mr. Carlson first.
Carlson: Yes, I was very interested in some of these numbers and I was doing a quick
comparison of them to the proposed renewables program. And it looks like this really is by far the cheapest kind of green alternative. Conservation is just the cheapest thing you can do in terms of supplying power. And even at current rate, you’re still beating our current long-term contract rates. My question is, if that’s all true why don’t we keep
doing more of it or is there some limit on how much of this we can actually accomplish?
Baldschun: Next month we’re going to be coming to UAC with our public benefit plan for the next 2 years. Those are the kind of questions we need to ask ourselves. The megawatt issue versus renewable resource issue -- that’s something that you’re going to
be talking about tonight because you’re going to be looking at the 2004 resource plan and
we’re going to need to make decisions on whether or not we’re going to pursue renewable resources. Or alternatives -- you’re implying maybe it’s better to spend the money on DSM programs. Those are all things that we need to fish out here in the next few meetings. I don’t have the answers right now but we need to, the problem of course
is the projection of rates, market prices. One month, it’s this kind of resource and then
the next month, it says something different. That’s the difficulty. Carlson: Okay, thanks.
Bechtel: Mr. Ferguson.
Ferguson: Just one question. I noticed when you got down to the bottom line on each of these charts; you gave all the projects a five-year life, which made the cost and saving even more dramatic. Is 5 years a realistic number used for dividing all these things out?
Are they likely to last more than 5 years on the average?
Knapp: A large bulk of this came from projects that actually last longer than 5 years. like chiller replacements and ??-frequency drives on motors, some of the lighting projects are shorter depending on the lifetime of the light fixture. So 5 years is actually pretty short.
Ferguson: So your bottom line is even more conservative here.
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Napp: The key question is whether we made them make the same investment at least 5 years sooner is the other flip it’s not necessarily the life of the equipment but would they
have done this 5 years from now without the rebate or not?
Ferguson: Interesting things. Bechtel: Mr. Rosenbaum.
Rosenbaum: On page 10 of the report, the last sentence under cost effectiveness, future DSM programs given the current forecast for electricity market prices should focus on their public benefit nature. Give me some interpretation of that sentence.
Knapp: Basically it says you don’t make any money with DSM programs now. It’s a net
wash, pretty close, whereas the accelerated program was actually being done because we were actually saving money by doing it as opposed to focusing on it’s economic benefit. Rosenbaum: This past public benefit, I mean, with capital letters.
Knapp: That’s a specific program. Baldschun: The distinction is, the public benefit revenue we’re obligated to collect and obligated to spend. It doesn’t have to be a cost effective program. We have to spend it
on these 4 various areas, one of which is efficiency. And DSM actually was just added, I
guess, in the last year if I understand. But what we have to think about is what we did this year was we took some money out of the supply reserve and went with this accelerated energy efficiency program because it was a shared savings kind of program because of the high market prices. What we’re seeing now is that without these high
market prices, that kind of program is not cost justified and so the minimum amount you
can do or we’re obligated to do is public benefit program kinds of programs conservation programs. What we need to think about is do we want to go above and beyond what we’re obligated to do. Is it cost effective to society? You go through all these tests. The participant, the non-participant. So those are all policy issues we’re going to be talking
about with you and the council. There are other reasons to do DSM, other than cost
effectiveness in my view and but it gets, what I said earlier, the hardest part is what is the market price? If you justify it on a cost effective test and the market prices drop out, then where are you? We can’t be one month or one year having all these programs and then the next year taking them away and then bringing them back and taking them away. That
doesn’t work either so we have to be consistent.
Rosenbaum: I guess the public benefit program I thought was always supposed to have some economic rather than simply feel good justification so I was just surprised to see a statement of that sort.
Bechtel: Mr. Dawes.
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Dawes: I was trying to get a feel for the return on investment of the program in this past year. It seemed to me that you lay out the cost of rebate cost per first year kilowatt hour
saved which averages out to 14 cents and it seems that if you were going to try to do an
ROI that the revenue to us, we took money out of the reserve to invest in it, the revenue to us would be the difference between the marginal cost of power and the rates we were charging our customers. And clearly for part of this year, maybe for a good part of this year, the last kilowatt hours we were buying were higher than what we were charging our
customers and you know that varies from time of day and from month to month and so
forth so getting a handle on what we saved as a system by not buying that power is kind of tough not to get and having a feel for what the marginal cost was of power and what our rate charges were you might have at least a intuitive feel for what the ROI was. I can see that maybe we could have paid for this in one year and I was wondering, Randy, if
you or your staff had a feel for that payback period.
Baldschun: Well it will depend on the measure, and Tom Auzenne might want to respond to this as well, but some of the measures we did with the Accelerated Energy Efficiency Program, the payback was 3 years and some were 5 years. It depended: was it
a chiller, was it lighting? Some of them, say CFL, were the quickest of all. They paid
back within a year. Tom, do you want to comment on that? Auzenne: That speaks to the cost effectiveness from a customer’s point of view but I don’t really think it answers Mr. Dawes’ question. I haven’t (perhaps Karl has) taken a
look at what the real economic benefit would be to us. Because of time of day perhaps
variable pricing, it would be, it might be kind of difficult. Dawes: As I said, it isn’t exact; it’s just whether or not you guys had a feel for it. There’s no way you can compute it.
Auzenne: My intuitive sense is that it’s less than 1 year. Dawes: That’s my feeling in looking at these figures. 13.8 cents, I mean we were paying probably 15 cents more for power than we were charging for a good part of the year.
Auzenne: The highest parts, the highest payments were very high. Bechtel: Thanks. Other questions? I would just like to point out or at least ask a general question. If we had not done this at all, where would we have been in terms of either
rolling blackouts, rate increases or/and not only extrapolate from Palo Alto to the rest of
the state? There is a lot of feel good about this, Dick. We can feel good about our works. Thank you Karl and Tom and everybody who has participated in this. A good summary report of what we did on the demand side management side.
Electric Supply Portfolio Deficit Plan: Year 2005-2010
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Bechtel: Next agenda item, let’s see we have a, let’s see a fairly long presentation. Maybe we should take a, we have 3 more items here, I’m not sure how much I can judge
whether we should take a brief break and then cover this and when we come back. 5-10
minutes. Break Bechtel: Next item under new business is item #5, Electric Supply Portfolio Deficit Plan: Years 2005-2010. This is an information item and we will be getting a first chance to look at a staff plan and then again, I call your attention to our special meeting we are going to have on Tuesday, September 25th. A related is postal for Electric Resource Plan
so we’re going to get a chance to have and allot a discussion on what we’re planning to
do it covers the changes in our contract conditions on supply of energy from Western, PG&E and sources yet to be determined. With that, Randy, we have a presentation up on our screen and I guess Girish, you’re going to lead this.
Balachandran: I’m going to make the introductory presentation on this topic. And Shiva Swaminathan and Karl Knapp will complete the presentation. Basically what we’re going to go over today. I’ll talk about the objectives of the presentation and I’m going to go over the outline of some analysis we provided to you last February. Also talk about the principles we used for developing this recommendations. Discuss different kinds of
portfolios and deals we’re looking at. Also talk a little bit about the process that we’re going to use making this decision. Before going into this, I wanted to step back a little bit and talk about what we would expect at the end of today’s session. Maybe get some focus to what we’d like to have at the end of today’s meeting. Today’s meeting, the way we see it is the first of several meetings where we’re going to talk to you about the
electric portfolio. And it’s the first of two specific meeting- today’s meeting and the September 25th special UAC meeting. At special UAC meeting, we hope to come to you with a recommendation asking for approval to enter into a power purchase, a 3 year 25 megawatt power purchase. In today’s presentation, we hope to tee that up for you. We’re not asking for any recommendation today on that.
One of the objectives of today’s presentation is to tee that up and if you have addition questions for us, if you have addition analysis you’d like us to do, so that you’ll be ready to make a recommendation one way or the other on September 25th, we’d like to hear that
from you today so that we’ll have the time to do that. Another objective we have for
today is to talk to you about the objectives and the overall principles that we are using in determining our portfolio plan. Again, we are not asking you for a recommendation today, but on September 25th, we’ll ask you for a recommendation that night. If there’s any information you need from us today or between today and that meeting that would
help you make a recommendation we’d like that input also today so that it will give us a
roadmap of what to do between now and September 25th. Lastly, we’re also going to talk about overall strategy process and also about the renewable resource portfolio. Where it’s going to be information we provide today and we’ll provide you information on September 25th. We’re not going to ask you for any decisions on that area, but we
would like your input again on any information you would want from us.
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The 2 decisions we are trying to tee up for you for September 25th and that’s, first, purchase starting 2005 to start off our laddering approach and, second is approval of the
overall the principle objectives in determining our resource plan for the post 2005 period.
Those are the 2 decisions we want. Anyway, coming back to the presentation over here, in this light, we basically, in the presentation that Shiva is going to go over, he’s going to talk about, if you go to the second bullet, you’ll see a number of sub-bullets there, all those are titles of topics we’d like your feedback on. In the slide presentation, we have a
number of bullets which talk about our thoughts on these different issues and to the
extent we can get to them in today’s meeting, great, if not, we’ll have some more time at the next meeting to go over it. The idea here is to tell you our thinking on these different issues and get your feedback on it. Slide #4 basically goes over the recommendations we made to you earlier this year. The next slide talks about the primary objectives that
we’ve used in developing the portfolio and there are 5 of them and not all of them can be
met at one time, but this is what we had in mind in trying to vet any kind of proposal or recommendation we have in our portfolio plan. Low and stable rates, retail rates for customers, maintaining a supply cost advantage compared to the market cost, maintaining a cost advantage compared to PG&E, developing a renewable resource portfolio in
accordance with council guidelines, a strategic plan has strategy #7 talking about that,
and also developing local generation to meet customer and city reliability goals. These were the overall objectives that we had and we can continue to, we can come back to this at different points. This is something that we’d like we’d make a recommendation
to you next on September 25th for approval of these objectives.
Baldschun: Yeah, Girish, if I can just interrupt for a second. If for example, as an example of, coming back to this is to look at #5 on there which is local generation which has had lots of discussion. All the others we’ve talked about before but in terms of local
generation, we’ve never dealt with in a crisp comprehensive way.
Balachandran: That’s right and we have talked to you before about distributive generation, we’ve included that as an initiative in our strategic plan and this is taking it to another level. Over here, it’s still at a high enough 20, 30 thousand foot level where
we’re just talking about here’s something that we keep in mind when we’re making a
recommendation and our decisions. Some of these have different timelines, for example, objective 4, the Renewable Resource Portfolio. There isn’t, shall I say, we can take, that can go through on a parallel process in the sense of and you’ll see this once we get to that part of the presentation. There are a number of policy directions you can give us and it
can take on an independent path. And so we can still go ahead and perform and meet
several of the objectives of filling in the post 2004 hole without necessarily getting into the details of all these objectives at the same time. ??: Doesn’t the COBUG fall into item 5 as well?
Balachandran: It would. Yes. Here’s another high-level slide. It’s coming in at a little lower level little greater level of detail than the previous slide on objectives. Here are some of the strategies that we’re looking at: the first strategy is you can look at it in two
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parts, one is we are trying to, we’re diversifying the hydro risk that we have in our post 2004 portfolio which is essentially the CVP Hydro resource and the Calaveras Hydro
resource to diversify the hydro risk using 2 approaches, 1 is to look to other fuel sources
fossil fuel sources like gas and coal and maintain adequate rate stabilization reserves. The policies that have been approved by the city council right now for example looks at a supply rate stabilization reserve being able to withstand 2 dry hydro years so that’s essentially the way we’re mitigating that risk. Well we’re going to look at mitigating
hydro risk as one thing we’re looking at and that’s what strategy 1 is trying to do.
Strategy 2 is maintain a Flexible Resource Portfolio. And so looking at a portfolio, which has different resources basically, will give us flexibility and would meet the commodity product needs of customers. Third strategy is to use a layering or ladder approach that we’re all familiar with and we’ve been talking about in the electric
purchases with the SOC approval and also that we’ve been using the laddering approach
in our gas purchases. That’s another strategy that we have in mind in implement in achieving our objectives. Obtaining input from ratepayers and the UAC when we’re talking about the renewable resource energy efficiency and Local Generation Portfolios and preserving the Western contract value while maintaining relative independence from
some of the custom products that they’re offering. At this point, I’m going to turn the
presentation over to Shiva and he’s going to go over the majority of the presentation and at the end of the presentation, we’ll bring back to the focus to what we hope to get from you today and setting up some of the decisions for September 25th. After which we’ll have Karl Knapp talk about the Renewable Resource Portfolio and there are about 4 to 5
slides in that, so outline some of the policy questions related to that.
Swaminathan: We have here the existing Generation Portfolio essentially, which we own now and will continue to own for the next 20-30 years starting 2005. I guess lettering is a bit, essentially there are 3 major energy sources, one is the, the largest is the Western
contract which has the capacity of about 175 megawatts and energy of about 550 gigs
which is about 50% of our needs, 40-50% of our needs, but is highly variable depending on hydro conditions. The cost of the resource is about $20 per megawatt hour. The next is the Calaveras Hydro Plant, 54 megawatts capacity, we have outstanding debt of about 110 million dollars, but most, about 50% of that is covered with standard cost reserves.
Net cost would be about 32 megawatt, $52 per megawatt hour going forward and then we
have the Seattle City Light Exchange contract, a small portion and we have the COTP transmission line, so those are assets right now. We own and will continue to own after 2005. And of course we have to meet the city load which is about 220 megawatts and about 1200 gigs. If you see the balance, we have quite a bit of capacity to meet the 220
megawatt peak load, but we are largely energy short so we are about we have only about
50-55% energy whereas we have close to 100% capacity to meet the peak load. We are capacity, near capacity balance, but way short in energy. This is the portfolio we’ll start with going into 2005 and the plan is to build on this.
When we talk about building on that, we said what are the potential future portfolios
profiles we could try to develop? The first approach we thought would be short term commitments essentially for Calaveras we have a 30-year commitments, for Western we have a 20 year contract starting 2005, what for SCL the Seattle City Lights exchange
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contract expires in about 10 years. What level of commitment do we want to make for the additional resources commitments we need to make in the next 5 years starting in
2005? Essentially we said 3 broad categories: short term commitments which essentially
means we are on the market and that we are in the mercy of market price fluctuations, so a large cost volatility, then which essentially we are saying commitments of 5 year term or less and the second one, medium term commitment is commitment no greater than 10 years and the long term commitment is 20-30 years. And of course the fourth item, what
level of renewable portfolio commitment do we want to have? We meet 5% of city
energy needs, 10% how much would it cost and so on. These are the different types of portfolios we just took a look at. And then we looked at different deal types of different portfolios which could be used as building blocks to build
on to make to fill the energy hole. I’ll skip this slide for a moment. I’ll come back to it
later. I’m going to go to the next slide, 10. And this essentially looks at the short-term commitment. We already have made 2 major commitments for Calaveras resource for 30 years out and Western resource for 20 years out. What additional commitments do we want to make in the next 5 years, the next 4 years, to fill the 2005 energy hole? And this
we restricted ourselves to less than 5 year terms, so this is a 3 year purchase we make in
the next 2-3 years and another 5 year purchase and essentially expose all by these energy needs which is between the city load and the existing resources. This portion in the monthly annual market so we’ll take on market price exposure either annual or monthly for the short term, for the deficits so that’s one type. And this is what we call a medium
term commitment essentially commitments of up to 10 years for market base resources
but also make additional commitments the blue line you see here is some kind of a Local Generation and the brownish line is some kind of Renewable Resource Portfolio. ??: The Western green block assumes no integration.
Swaminathan: That’s correct. So we could build, essentially we make commitments of 10 years on these major portions and these 2 lines essentially renewables and local generations also need relatively long term commitments greater than 10 years but we will be prepared to make them if proven to meet our primary objectives. So that’s portfolio
type 3, 2 and then.
??: What are the renewables? What types of generation qualify under the renewables? Swaminathan: Solar PV, Solar thermal wind, geothermal, we also have a grouped
although it’s not strictly renewable, fuel cells into that mix, essentially relatively clean.
We’ll talk about that later and Karl will deal with that, present that later. And then this is the long-term commitment approach. Do more of it lock in supplies early, it’s essential to shaded area expands.
So these are 3 approaches we looked at. Now the building blocks are these different
colors and what types of building blocks we contemplate on these is presented on slide 9 so let me go back to slide 9. Essentially the deal type 1 is what Girish was just referring to, the small 25-megawatt Q4 purchase. Now if you look at the hydro profile, generation
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profile, we have large deficits during the fall and winter months so deal type 1 essentially tries to fill in part of the fall short fall and we think we want to do this type of deal sooner
than later and we’ll when we go to the presentation I’ll try to outline why we think so.
And then deal type 2, deal type 1 is essentially a fixed price contract similar to the one we entered for 3-year term. It’s fixed term, we think the price market price is relatively stable if not lower than sustainable. And deal type 2 is essentially a tolling contract where we will take on gas price risks but essentially locking in capacity for use whenever
we require it. And deal type 3 is some kind of a local generation. We are in the process
of evaluating different sites. It could be at a particular site where we think we can build up to 50-100 megawatts if possible and Palo Alto would essentially take, NCP is leading this effort on deal type 3 where they are looking at member sites where they can probably put in a clean, essentially a combined cycle but a small 100 megawatt unit. If you can
site it in Palo Alto, we’ll probably take part ownership of that, probably 10 megawatt
to15 megawatt a piece off the good generator and have some kind of contractual arrangement with the other owners to take on the output if there’s a system outdate of some kind. But we don’t want to commit more than 10-20 megawatts of such a local plant and I’ll be going to tell why that’s so. Deal type 4 is again another quarterly
purchase as I said the main deficits are during the fall and winter months. Deal type 5 is
the renewable portfolio, which Karl will be talking about in detail. Some, this is, we need extensive discussion and UAC council guidance on this. Renewables are at today’s market prices at above market resources so we need the council guidance on that and we’re also looking at and we’ll still need some purchases to be made in the spot market
within a year purchase, that’s deal type 6. Deal type 7 is we’re contemplating because we
have a large hydro risk associated with the CVP generation and Calaveras generation the hydro production variability we think we need to look at divesting part of the Calaveras resource to essentially reduce the hydro variability of portfolios exposed to so deal type 7 is explore the option of divesting part of the Calaveras resource. If you look at, right now
we have, we did lay off some of the Calaveras resource to Roseville. Right now we own
about, we have the output of about 38 megawatts, and we laid off 14, 16 megawatts to Roseville. That reverts back to us on January 2005 so we’ll have about 54 megawatts of Calaveras resource which is a hydro, essentially, “??” metered capacity. And also we have another 175 megawatts of Western contracts, which essentially again has a lot of
capacity associated with it, but limited energy.
So we are capacity long, energy short and that’s a difficult position to manage the hydro volatility so we’re also looking at potential options of divesting or at least laying off part of the Calaveras resource for the further 10-20 year period. So these are different
building blocks we think we can use to try to fill the hydro hole.
Rosenbaum: Shiva I have a short question. Swaminathan: Yes.
Bechtel: I just, if I can just interrupt Dick. Shiva can should we just ask questions as we go along, perhaps that may be the best way to do it.
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Swaminathan: Sure, yes, yes. I think that’s a, yes.
Bechtel: Go ahead Dick.
Rosenbaum: I was just wondering what a tolling contract is. Is that a standard term? Swaminathan: Yes, I’ll go into details in the presentation. Essentially, Western 2948A is
also a Tolling Contract. We essentially the price is determined by a formula. The input
to the formula is determined by market prices for natural gas called, in the Western contract it is determined by PG&E’s generation cost. It’s very similar in nature, it’s a formula essentially and power is delivered at a price determined by a formula. Using those building blocks, this is essentially the portfolio 2 you saw previously. The bottom
line is the hydro, the CVP, Western CVP generation. This is, on average hydro year, this
is how hydro production is rated. That’s when I said we have a and then of course, this is Palo Alto’s load by variation by month. So you see there’s a large hole, energy hole, in the fall and winter months and relatively small during the summer months. One of these e approaches, using those building blocks I showed you prior, we are trying to see how
we can meet this city’s energy needs. We have the Western energy and then we have the
Calaveras energy on average, all this is for an average hydro year and we think, and then, we could use a small fixed price purchase here to fill, so the idea here is to fill up this energy hole between the top of the blue line and the city load. The blue line is the Calaveras resource and we don’t have anything else.
To fill in this energy hole, we are recommending we go fill this portion first, relatively soon, in the next 2-3 months, if not sooner and we’ll tell you what our thought on that is. And then purchase, a essentially Tolling Contract, output to a plant with variable prices in essence and some kind of local generation in blue. And we don’t, if it’s a local
generation, we don’t expect it to operate 876, I mean around the clock throughout the
year. It’s a relatively “??” plant if it’s a small plant so the operation is not, it’s essentially an option to generate electricity when the prices are right, electric prices are right. For example, you see we, if we own a local generation, we don’t expect it to operate too much during the spring months in a normal hydro year when prices are relatively low.
And then, another block which we outlined earlier is a 25 megawatts Q1 and Q4
purchase. These 2 blocks to be purchased down the road. It could be again a fixed price contract or some kind of Tolling Contract. And then, the last piece is a hydro resource which is the piece that is not completely determined how we want to fill that need for a renewable piece, I’m sorry, this is a renewable piece on top. And it assumes a some part
of PV which is production is highest during the long daylight periods. And then leave
some of these white areas to be filled within a year, up to a year ahead. Again, all these blocks are a capacity option which we’ll take on. A Tolling Contract which essentially, we will lock the price of the Tolling Contract will be determined any time the city decides it will buy gas, so there will be a gas, essentially, Tolling Contract is a contract
which will specify heat rate for a thermal plant, say 7000 mmbtus or 8000 mmbtus
multiplied by a gas price which the city can go in and lock in the gas price at any time. It can lock in for the gas price for 5 years and until the supplier takes this gas and delivers power to us in all those 5 years. Or we can lock in 50% of the time and take up or, it’s
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essentially, it’s a capacity payment associated with it which has to be paid “take or pay?”. Plus, so capacity payment on dollars for kW month which is typically, in today’s month,
it’s about $5 per kW month plus 7,500 heat rate times gas prices at PG&E city gate, plus
$2 or $1.50 per megawatt hour variable cost. So it’s essentially a formula tied to gas prices. Bechtel: Shiva, can I ask a question about the net city load line? Did you assume any
ongoing conservation effort or is this just based on the recent data consumption?
Swaminathan: It’s actually 2005 projections and how right now we think we are saving somewhere between 10-12% energy load reduction from prior projections, but we think it will revert back to it’s original position over the next 3-4 years, but the savings, the long
term savings is about 2%, that’s the assumption. So the 10% reduction in load now is
most 2% is attributable to conservation program which Karl just outlined and we think that 2% will be, will continue indefinitely, but the 10% reduction which we see now will drop to half of that - 5% end of next summer, and then a % each and in year 2005, it’s pretty much the impact of the AEEP program and other continual energy efficiency
programs we’ll save about 2% from “??” projected I’d say a year ago. That’s the
assumption here. So this is the general portfolio, we think we want to table up over the next 2-3 years and in particular, we think we want to do this particular purchase right now and I’ll talk about
that a bit more. Now of course, the main problem and the other thing, this resource is the
hydro production, the green and the blue line, green line with the Western and blue line with Calaveras changes, this is a dry year scenario. The same access, the same graph, except you’ll see the energy hole is much greater, because of lower hydro production. The little bit of increase in some of these generation on a dry year, but essentially, these
remain the same. We’ll be making additional market purchases during this time. Now
again, there are ways, we are looking at where we buy capacity options by and exercise them when we know what the hydro condition is going to be so we can buy a 5 year option on a plant and exercise it monthly or annually when we know what the hydro conditions is going to be. This is the same thing as the previous one in a dry hydro year.
Similarly, in a wet hydro year, you’ll see there is we have surplus energy during the fall
or the spring and winter months. Now our strategy to mitigate a hydro production risk essentially is twofold. Mainly one, one is this just shows the level of hydro production variability, typical year, Western and CVP combines about 680 gigs but on dry hydro year it’s 380 and on a wet year, it’s 1000. And the average commodity cost is typically
about $35 million, can increase to $13 million in a dry year and drop by $9 million in a
wet year. How do we manage this risk? Our part right now is we could buy capacity options, we could buy weather derivatives but the part right now is we would want to manage it with the rates stabilization reserve. And the recently approved supply rate stabilization reserve did contemplate these changes. And the upping of the targets and
the maximum and minimum did take these into effect. And the reason why we think we
want to rely on the rate stabilizing reserve is essentially we think other mechanisms will be relatively more expensive. We’ve looked at whether derivatives are essentially and they’re found to be relatively more expensive. Also we can buy capacity options on
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plants, which also tends to be expensive. We also, this variability could also be reduced if you divest some of the Calaveras ownership.
So these are the strategies we are looking at right now. Given the portfolio type 2 and assuming that we commit about $5 million per year for Renewable Energy Efficiency Programs, here is just a quick projection of potential rates. “??” our 5 main objectives is low and stable cost competitive with market and also competitive with PG&E. The
commodity rates we think excluding, this is just market base and existing resources
excluding all other costs we’re thinking about 2.8 cents and would tend to increase given the load growth and load growth to be met by market-based resources. We don’t have, our low cost resources would not expand.
So that’s the general projection. Market commodity cost projections are in red. And then
the total bundled retail rates we think would go up from 8.3 to about 9 cents. Again this includes about $5 million of investment in renewable and energy efficient technology. The reason and similarly on the PG&E retail rates are going to be going up but they’re going, general frame would be to decline after the above market commitments made by
the governor eventually evaporates so the trend for PG&E is going to be on the way
down after the next 2 or 3 years. This is in 2005 again. We think right now we enjoy, we have a great rate well below PG&E especially after the PG&E rate increases too. But the trend would be narrowing down the road, so this is to illustrate to be conscience of whatever commitments we are making especially if it is not market-based resources.
There are quite a few topics we which we would like to discuss with you. Whether we
actually in invest in a power plant or just in another Tolling Contract, another 2948A Western type of a Tolling Contract. The attractiveness of a prepaid contracts, duration of commitments, how long we want to commit, and also in all this presentation I made so far, we assume that Western will provide us a bare CVP resource. No integration
contracts like we have right now. Now Western is prepared to do an integration contract
or individual customers or group of customers if they so choose. But our thought right now is we want to do it by ourselves and I’ll try to outline why we think we want to do it by ourselves. Generation options within the city: Market purchases -- do we buy some of the deficits right now versus later? Renewable portfolio standard which Karl will be
talking about and the portfolio plan and implementation process. The tolling contract, a
quick description, it tends to mimic the cost of a generation from an actual power plant and provides a mechanism of for pricing of energy, a formula for pricing energy. The advantage is that we don’t need long-term commitments. Tolling contracts are less risky. They have no associated cost over-runs or delays in operation of power plant and so on.
If we pay, if you prepay a contract, we could still leverage the city’s low cost of capital.
If we invest in a power plant, we can issue bonds low cost of capital ends and we can pass on the savings to ratepayers. Through a Tolling Contract too, we could essentially prepay the Tolling Contract. Essentially prepay for a piece of paper, a promise to deliver energy at this formula just like PG&E did in 2948A. We could still do that. The
disadvantages – performance and credit risks are higher. We don’t own real asset
essentially. It’s essentially a contract and does not provide any additional optionalities inherent to a physical plant like scheduling, efficiency upgrades and so on. So...
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Bechtel: Shiva, I guess I’m not real clear on the difference between a Tolling Contract as you described it and just a long-term market contract. Because both of them assume
someone delivering energy to us at a price. Explain to me the difference again in the
Tolling Contract. Swaminathan: The difference between tolling and…
Bechtel: And a market price contract. A Tolling Contract -- what you’re talking about
now is what we have now. It is a cost-based -- we pay cost plus some profit, or whatever. Swaminathan: Right. Right, but the cost is determined by a formula on the contract 2948A. It’s the average cost of PG&E thermal and nuclear plants. So tolling contract for
us would like cost = 7000 x gas price + fixed charge of $5 per kW month. This is, it’s a
mechanism to get a variable price contract so but we commit someone to deliver us capacity at $5 per kW month for the next 10 years, just like we have option on a plant. What would the investment we make in a physical asset is essentially, the availability of that asset to generate electricity when we need given a few other price. A tolling contract
essentially commits us to pay this dollar amount every month irrespective of whether we
use it or not just like in a power plant. Once we commit to build it, it’s there. It may not be economical to operate, we still would have committed to it. So this term we pay whether we take it or not, plus we have operating cost component which is variable.
Bechtel: But if I were Enron for example willing to sell power to Palo Alto, I might have
my accounting dept calculate our formula so that the marketing guys can tell me how to price things at long term. So the question is, how is that different? Swaminathan: Exactly, it’s not different. You’re right.
Bechtel: On the other hand, Enron might use an irrational pricing constant and just say arbitrarily pick out of the air a number for the next 20 years. Swaminathan: You’re right, you’re right. This one on the date of execution, a Tolling
Contract expected value is identical to a market price projections. Only thing is it
converges from then on. Because we take on, with changing gas prices, the gas prices go up and we don’t fix, if we have fixed the gas prices, again, the purpose of this is to take on positions to reflect actual market prices. This is the only mechanism we have to try to take some amount of variable price risk within our own control. We decide. The other
mechanism is, and also guard us against a capacity shortage. Because this piece was
about $16 or Calpine saw a capacity call to the state we were told at about $20 per kW month for the next 5 years or so. In the event of a capacity shortage, this component is going to go up. This essentially gives us mechanism to lock in capacity and take on some level of fuel cost exposure.
Bechtel: The alternative might be for the for us not to see this formula and the contract we sign as some variable element built into it where we every year renegotiate a price, a market price so I understand the difference now that you’re talking about between this
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and investment in a power plant. But somehow this is somewhere between investing in an power plant and buying at market over some, with a fixed price over some period of
time with no variable element in it.
Swaminathan: Right. Correct. This is similar to some kind of variable cost market purchase but it a tolling contract guards us against capacity shortages in the market, because we determine the capacity price ahead of time. And it exposes us or we take on
fuel cost risks. So, given the general variable outlook to tolling type of arrangements, is
it-- One of the advantages the city has is relatively low cost of capital. How do we not build a plant and still take advantage of low cost of capital? The Tolling Contract is pay as you go scheme, though you make a commitment to pay the capacity charge for the duration of the contract, but you pay as you go. So we say we are in the process of
examining essentially pay cash up front for the term of the Tolling Contract in return for
a discount on the price, essentially arbitrage on our low cost of capital. Now there are a number of hurdles we have to jump through essentially the IRS hurdles. We’re in the process of just evaluating that. I’ll just skip this presentation. Just information item. But our thought right now is the IRS hurdles are relatively stringent and what we don’t want
to do is and there are a number of risks associated with prepaying. Default of counter
party is if they’ve received a lot of money up front so the we are in the process of evaluating the relative merits and some level of USC guidance we may seek down the road. For example, the last one. The sole purpose of prepay is cost savings in the long run, a price break on the long run. What level of price break would justify us giving them
a bundle of cash up front. Of course, along with prepay, we would have some sort of
performance guarantees from banks and so on that counter party does honor the tolling contract or prepaid contract. But it becomes pretty complex, the IRS rules to be overcome and we’re in the process of evaluating that.
Bechtel: Are there any examples of where we have prepaid any contracts currently for
anything that the city has bought? I can only imagine if you did it on computers or you know some kind of small discount on some hardware, but there’s no other example we have that where this has been used.
Swaminathan: Girish, not in the past on the energy side, no.
Balachandran: Not in a major way. There may have, yeah, I can’t really see that. We may have done some prepays or to Western for some O & M kind of funding, but nothing of the nature that we’re talking about over here.
Dawes: Didn’t we advance to Western to cover the in effect the lag in the congressional? Balachandran: We signed the agreement to allow for that. We actually haven’t sent any money for that particular agreement. We’ve done some of the O & M funding, we’ve
provided some funding prior to work being done. But again over there, there was no
benefit of the kind we are looking at over here.
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Swaminathan: The other aspect we are looking at is a term commitment when making purchase decisions. Unlike before there is a relatively vibrant market, definitely for the
products of up to 5 years. The bid asked for it kind of widens as an outer years, but there
is a ready market. We don’t have to build or make long-term commitments to secure supplies. So we put purchase commitments (here??) as important for sole purposes of securing low and stable prices. And the 5 portfolio-planning objectives are not congruent at all times. So essentially investment in new plants requires a technology and term
commitment of 30 years. And essentially are recommending that though given the
market availability of power and the term commitment required for new plants are long, that we go for a kind of a 10 year term and no longer than 20 years in locking in future supplies. Again, when I talk about 10 year commitments. I’m not talking about 10 year fixed price commitments, it’s commitment for capacity of up to 10 years, so a Tolling
Contract for 10 years and we’ll renew it or renegotiate it down the road.
So that’s our general part, we don’t want to go beyond 10 years except for renewable resources or local generation. And we would like your guidance on that. This slide is talking about why we want to recommend a go-alone strategy with Western. Essentially
Western right now, the postal for our marketing plan essentially contemplates customers
receiving only the base resource, the naked hydro product and that is given. But Western now is in the process of beginning to say okay; some customers want some kind of a bundled product. They will go ahead and make a market purchase and bundle it up like the present integration contract and provide it to customers. The big Western customers,
SMUDs and the Reddings and the Palo Alto’s think that we are better off on our own
doing our own deals for a variety of reasons. And essentially 3 main reasons: we lose control and we’ll be at, and the decisions at Western are made for a group of customers, not for Palo Alto so again, Western won’t be prepared to provide Palo Alto with a product but if Palo Alto joins a group, for that group, they are prepared to do an
integration type of arrangement. We lose control, that’s one of the key areas. And also
there is considerable political risk associated with planning authority. The moment Western goes and integrates with another supplier, they’ll have to get, though we’ll be paying Western, the Federal Government also needs to authorize Western’s expenditure so they could, for example, lock into a contract with a supplier which could increase
Western’s cost by say $100 million and though we will be paying that $100 million,
Federal Government has to authorize that and there are a lot of, as we have periodically encountered, there are other risks associated with that. And also the suppliers we talked to are very wary of dealing with Western primarily because of this Federal Funding authority. In all of Western’s contract, there is a clause which says obligations will be
met only if funding is available. Suppliers are reluctant to do deals and we think there’s a
large risk premium associated with integration agreement with Western and hence more costs. Our thought at this point, though we are tomorrow we’ll be in one of Western’s meetings on coming up with these custom products, our thought right now is we want to do it ourselves. This is a slide on generation options within the city. The main advantage
is supply reliable to the city. Essentially the COBUG type of a advantage as well as if
it’s a bigger plant there’s a possibility of knocking off about 20 or 30% of our “??” and entire the rest of the city being able to function if it’s a bigger plant. We avoid congestion charges essentially across the Peninsula. Our thought right now is congestion
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charges could be anywhere between 50 cents to $5 per megawatt hour as transmission systems gets upgraded it’s likely to drop for example if there’s some supplier who will
prepare provide us energy delivered at city gate as opposed to the greater NP15 area, we
are prepared to pay more, because we think the congestion prices would be at least 50 cents. Where Palo Alto does not have any ideal sites for large base load plants, but the distributive generation team, Karl and his team, essentially have identified a site close to the waste water treatment plant and NCPA has commissioned a consultant to study to do
a essentially fatal-flaws study to look at that site. To site a 5200 megawatt plant. If it...
Bechtel: Shiva, who’s who did you say commissioned this study? And who is carrying it out?
Swaminathan: NCPA is putting out an RFP to have a consultant and a essentially an
architectural engineering firm, PB Power, to study different member sites and we had wanted them to study our site. It’s at preliminary stages and we are looking at 50-100 megawatt size. We’re working with other city departments to get their input and if it’s feasible, and again, if it’s a 50-100 megawatt plant, we will not be taking ownership or
output for the entire plant. Our part is not more than 20 megawatts, probably 10-20
megawatts. With an option to essentially take on the entire output in at times of emergencies. We’re also looking at 1-2 megawatt distribution sites, DG - distributive generation sites, at customer facilities. And the distributive generation plants essentially are relatively high heat rates and high operating costs, so we don’t want, we don’t
necessarily want to commit to too much of those. This slide brings us to what we think is
our immediate need. We want reason to act relatively soon to lock in a portion of our energy hole. Market prices are low. You could lock in a 5-year around the clock electric contract starting year 2005 for about 4 cents right now. A Q1, Q4 contracts which is essentially at times, when we need it the most, is about 3.5 cents. And we also heard in
the industry vibe that some of the generators who had previously committed to develop
plants and California are withdrawing their efforts because of these low prices. So we think we will see a blip up in the prices sometime soon. The high cost to bill at prevailing natural gas prices have been confirmed by when generators are purchased to
take ownership of some plants. We did submit some preliminary bids into some of the
base load plants and the feedback we got was the prices which we were quoting them or indicating to them were well below levels which were justified in building plants. And NCPA’s own evaluation also has confirmed that. I have a slide here essentially talking about Spark Spreads. Essentially what this means is that contract price and market price
is lower than the cost to build generation. This is essentially talking about, this green line
here which is not in your slide actually, is a very efficient plant, a 7000 heat rate plant at the prevailing gas prices, the contribution to margin after fuel cost is $10 per megawatt hour. $10 per megawatt hours is what we have to meet fixed price and O & M cost. We think that’s the most efficient 7000-megawatt plant. Everyone else is losing money. A
10,000 megawatt, 10,000 heat rate unit is losing money at today’s, it is long term, 2002-
2012, with a 10,000 unit, you’d rather shut it down at prevailing gas prices and buy a contract rather than actual build one, a 10,000 heat rate unit. Typically, the Tolling Contracts we are looking at is about 7,500 heat rate. The local generation, the
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distributive generation plants are about 9,000-10,000 heat rate. So this is an indication, the Sparks Spread says don’t build at prevailing gas prices, so either gas prices have to
come down further or electric prices have to go up. One of those has to happen for this
level to remain. Essentially, the market thought is the price pendulum has swung too far in the direction of low prices and our recommendation right now, which we will seek explicit approvals on September 25th, is to buy a 25 megawatt Fixed Price Contract for 3 year term starting in 2005 essentially for Q4 for 3 months part of the energy hole.
Essentially 10% of the post 04 energy hole. This strategy is make a small purchase now,
it’s consistent with the laddering approach to fill the energy hole. I want to skip for the moment; Karl will come and take the renewable resource presentation. I want to go to slide #32 and briefly touch upon some of the next step issues. You have
just seen this presentation so I would like you to ask questions now and at the next
meeting and couple of more meetings where we’ll seek your guidance. We want more questions. We would like to flesh this conceptual plan out more thoroughly. And on September 25th, as Girish was outlining, we want essentially 2 approvals from UAC.
That’s the 5 objectives and the strategies that we think we need to pursue to meet those
objectives at the they are what you think they should be and also approve this small purchase now, starting, for term starting 2005. If you do get that, we do plan to go to council in October and the subsequent deal types will come back to UAC for further discussions. And also on the renewable portfolio standards. We have right now under
the larger plan of Electric Portfolio, we’ve allocated about 5% room for renewable
commitments. We can easily fill that up with other resources. 5-10% room has been left for renewable and local kind of generation. Those issues have been fleshed out with council and UAC guidance. They are essentially above market cost resources and we need to will get our priorities firmly embedded before we make those commitments. But
with regard to the other deals, we would like to come back to you and talk more about it,
but for September 25th, we would like you to approve the first two. Now I’m going to turn it over to Karl. Bechtel: Thank you Shiva. Karl, before you start, let me get a sense of the commission.
It’s the hour is, we’re approaching10:30, we can only absorb so much. This is a lot more
information that I certainly knew that we were going to be discussing tonight. I knew what the issue was. The sense of the kind of discussion you would like to have more tonight.
Carlson: I suggest discussion of what we’ve already heard right now then into the
meeting. But to give them some response, because you know this is really important stuff. This is the heart and soul of the utilities operations for 20 years that we’ll be deciding in a few months.
Bechtel: Other comments? Dick?
Rosenbaum: Yeah, I too feel it’s a lot of information and I guess personally, I would be comfortable authorizing this purchase that you talk about. The price seems right at the
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moment and time may be of the essence, but with regard to the rest of the plan, is there really any urgency, because I would feel that I am going to be hard pressed based on what
I’ve heard tonight given a variety of questions to make a recommendation on September
25th for the rest of us. Balachandran: Commissioner, we are not asking for anything from you today. The whole point of today is just to tee up the issue for a recommendation on September 25th.
We apologize for not having this information in your packet prior, but this is a work in
progress and requires collaboration with a number of people in coordination. So our strategy was to just tee up the issue, provide the educate you on our thinking and we’ll ask for recommendation only on September 25th.
Rosenbaum: Right, I recognize that and I realize that you’re not asking for us to do
anything tonight. What I’m saying is on September 25th I will be prepared to speak to the issue of this 25 megawatt purchase that you’re interested in. But I doubt that I would be prepared to speak to the broader issues in any final sense.
Baldschun: Our plan is not to ask the UAC to adopt any of these strategies at this
September 25th meeting. We want to, this is our thinking and we need to have these discussions with you but we’re certainly not going to ask for adoption of any strategy. I don’t think we’re prepared ourselves to say that this is what we’re going to do over the next 5 or 10 years. But we do have this opportunity for the 25 megawatt, prices seems to
be right, the 5 objectives -- there’s adequate time to review the objectives and make your
comments to us. And those are the 2 things that we’ll be coming back to you in September and then we’ll continue with this resource plan in subsequent meetings to get more into some of the details of the various kinds of strategies and the pros and the cons of these various kinds of contracts but it is too much to absorb tonight and by the 25th, the
whole think but we wanted to give you the whole picture in this meeting. You’ll have a
couple of weeks to read some more, and I would suggest that if you have questions about our new streamlined procedures, you can email Girish directly and he can prepare responses for the next commission meeting if that meets your needs.
Bechtel: Other comments? Mr. Ferguson?
Ferguson: I agree with the email proposal. And the same thing maybe, I don’t know if we’re going to spend time on renewables tonight, the same thing is true. This is an eminently readable set of bullets and we have, as you say, a lot of background material
we’ve already gone over. So it’s probably okay to put a little more burden on us to bone
up for the meeting on the 25th. One question that jumps out at me: if we think prices are pretty good right now, why limit it to 25 megawatts? You know, why not 25 megawatts and then plan 30 days later on picking up another 15 or 20? I’m just wondering what the confidence level is and how the probability curve shapes up there in that decision? Or is
it just gut level?
Balachandran: Well...
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Bechtel: Are you starting to get the feedback you wanted?
Balachandran: Yes, we want to start off the laddering approach, so it’s a start and then
there’s a certain amount of judgement involved as to how much is too much and comments like what you just mentioned right now. We’ll take it in and see if it gels in with the overall objectives as we’ve laid it out and if it makes sense to maybe come up with another recommendation for additional purchases, we’ll bring it back to you. But at
this point, just the recommendation. We’ll let it stay the way it is right now.
Bechtel: Mr. Dawes. Dawes: I realize this is 2004 and beyond in the hopefully in the unlikely event that the
FERC decision in September goes against us. Seems to me that much of what we have
said here is going to apply to, you know, 2002, 3 and 4. And I assume that the policy issues that we will focus in on apply to the later date could also apply to the earlier period too if we have, you know, some bad breaks for ourselves.
Balachandran: Yeah. Right.
Bechtel: Let me just pose this for agenda for the 25th or at least in the order of the order of events. I agree with Dick Rosenbaum that the 25-megawatt purchase is probably not so controversial. It makes sense, perhaps there should be some discussion of that.
Maybe the issues really relate to the rest of the portfolio and so maybe my own personal
feeling is that looking at the rest of the strategies, we really need to digest the strategies that you propose for meeting the objectives and so in the context of one of those strategies is renewables, perhaps we could take it and with apologies to Karl, that we could address his part of it on renewables as part of discussion of strategies. Particularly,
the other one is local generation. Perhaps our discussion on the next time can focus
around maybe some of the other alternatives to straight market purchase which we’ve talked about and that could be some meaningful discussion so I’m suggesting basically we look at the contract first, talk about it and then in the remainder of the meeting, we look at your proposal for the strategies including the looking at renewables and what Karl
has here. Fellow commissioners?
Ferguson: Sounds good to me. Bechtel: Okay. With comments. Girish, go ahead.
Balachandran: I just wanted to confirm the feedback that we are going to receive from you so that we’ll have enough time to prepare for that meeting. We have this, we have quite a bit of material in this presentation and, you know, the more time you give us, the more, be better prepared for you and we’ll incorporate the question that you had
commissioner Ferguson, so we’ll be open and waiting for your emails.
Dawes: One clarifying point – this will be the only topic that we’ll address at our special meeting?
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Bechtel: That’s correct. Yeah.
Ferguson: And clarify for me again, we’re having a special meeting on the 25th because you certainly want to get in position to make the 25 megawatt buy quickly. Balachandran: Correct.
Ferguson: Before our FERC decision in October. Is there anything else that’s driving the schedule here? Is it just that purchase date timing? The rest of it is context? Balachandran: Well that’s just the start. 04 isn’t really too far away if you look at the
array of deals that we are looking at entering into. These are complicated deals that
require negotiation, credit checks, RFDs, all kinds of things. The limited staff and with our strategy to laddering, a laddering strategy, before we know it, it’s 2004. Ferguson: But I mean, slipping the rest of this discussion to the October meeting when
we’re going to be talking about overall utility performance against the plan, we’re not,
we’re not critical if we... Baldschun: This special meeting was really called for this 25-megawatt contract.
Ferguson: Okay.
Baldschun: These are all important issues, but we could have waited for the October meeting, but again we want to get into the council agenda and so that’s why we’re going with the special meeting for this particular contract. Let’s just focus on that on the 25th.
Bechtel: Well, personally, I’m quite interested in us having a plan on the use of renewables. The other is the issue of local generation and so those issues alone are not worth maybe a single meeting, but at least on the 25th, I would anticipate either we include them in the strategies, or we don’t, or some modification of those. That’s what I
assume would be the outcome. But maybe we won’t get much beyond that in terms of
having all the discussion that we’ll need to fill this hole that we see coming up. Was there anything else on this, Shiva, before you leave the floor? Did you want to wrap up with anything other?
Swaminathan: Essentially, we would appreciate, given that we gave you the presentation
only today. Emails, I would appreciate. I would appreciate emails from the commissioners regarding any additional issues they want discussed or fleshed out or comments of the strategies formulated so far. What Girish was saying, on September 25th, we don’t necessarily want approval for all concepts but we want to start negotiating
on other deals to, so we would probably want to buy in the next 2 to 3 months so that we
could flesh out whether we are going to do Tolling Contracts, how to implement Tolling Contracts, whether we want to build local generation and so on and so forth. So emails
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from the commissioners before the 25th meeting. Some input as to what additional topics they would like discussed, would be welcome.
Bechtel: One thing I did not see and we have seen in the past is the anticipated, I guess some of the alternatives presented in a way we can judge, prioritize it. I guess basically what I’m looking for is help personally in prioritizing some of the options. Whatever you can do to shed some light on that. Certainly one of the prioritization schemes is cost to
the taxpayers or to the ratepayers. What is it going to cost us for the options? Two, the
environmental impacts of these and so on. We need to consider some way to start going through these, the options we have in some organized fashion so that we can, you now, in one meeting at least have a draft plan that goes forward for the next year and so on. That personally is what I would like to see you think about in the next 2 or 3 weeks. Other
comments? Dick?
Rosenbaum: Yeah, I would think it might be necessary to have several more special meetings just to discuss this. As Dick Carlson said, ”This is important stuff”. This is the program for the city for the next 20 or30 years. Given what’s happened in both
electricity and gas, we’ve all learned a lot of humility and before we make
recommendations to the council, we want to feel pretty confident that we have a good understanding. The uncertainty in the future is such that we’re not going to make the wisest decision regardless which one it is, but we really want to feel confident we’re giving the council the best advice we can.
Bechtel: Other comments? Mr. Carlson. Carlson: I’m just curious about this procedure here. Do we email to Girish or John or all concerned or Randy or what’s the list? Because that is an efficient way to do it, I do have
a bunch of comments, but I’d be delighted to do it via email.
Baldschun: Given the next 20 days, with John and I here and there, Girish will be here and he can be responsible for keeping the rest of us in the loop so if you can just email Girish, you’re covered.
Bechtel: Dick, if we do it, we would copy each other on it. To Girish as the fundamental person collecting them and then copying the rest of us. Baldschun: I might add that Girish has a Blackberry, and you could email him any hour
of the day, any day of the week and he will get it. In fact, I think he sleeps with it.
??: Does it have an alarm? So we can wake him up. Bechtel: What does he have?
Baldschun: He has a wireless device called a Blackberry which is a fancy pager. Ferguson: The one with the big screen, too.
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Bechtel: All right. So apologies again to Karl. We will see you again on the 25th.
NCPA Commission Report
Bechtel: Returning to the agenda, we have really two more agenda items -- NCPA Commission Report and I guess was there anything significant that came out of that Randy?
Baldschun: John and Bern and myself were at the NCPA meeting. The first day was a conference call dealing with the PG&E bankruptcy which I won’t discuss. The second, and then the afternoon we went to Spicer Meadow and got a tour of the powerhouse and the reservoir’s down quite a bit. We learned quite a bit about the hydro system. I wasn’t
aware that, for example, Spicer only got 3 turbines, 2 ½ megawatt, another 2 ½ megawatt and ½ megawatt. The power’s generated way down the hill. But it’s a beautiful reservoir. And then the next day was the commission meeting and the commission meeting was basically a bunch of Utilities Directors saying “Aye” to this report or that report. It was kind of dull to be honest with you. The one thing that came out, I thought
was interesting, was NCPA prepared a chart that showed the NCPA transactions for all the member cities over the past year and on a month to month basis showing how much the, how many, what the total resources were that they bought and what the total resources were that they sold and 11 of the 12 months, they ended up buying more than they sold. So this myth that there’s a bunch of utilities in northern California gouging the
public, it was very clearly shown by the chart that that’s not the case because they’re more net buyers, not net sellers. Now there are various member cities will vary each month so I’m not saying we don’t sell more than one month but as a member of the NCPA pool, all the members who sell to one another including Palo Alto, 11 of 12 months, we sold to each other. I thought that was good.
Bechtel: Thank you.
TANC Report
Bechtel: And then lastly, TANC Report. Any, I guess there has been progress or action
on Path 15 and other issues. Anything else? Swaminathan: Don’t have anything else to report at this time commissioner.
Adjournment
Bechtel: Thank you. Our next regularly scheduled meeting is Wednesday, October 3rd. Special meeting and I guess for that meeting, I see there are a couple of items -- Time of
Use (for Action), Public Benefit Program. That was the key when it was mentioned
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earlier. That’s for a special meeting. I’m ready for a motion to adjourn. (Dawes/Carlson) All approved. Adjourned.