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HomeMy WebLinkAbout2006-09-06 Utilities Advisory Commission Summary MinutesApproved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 1 of 37 DRAFT UTILITIES ADVISORY COMMISSION MINUTES OF SEPTEMBER 6, 2006 CALL TO ORDER The September 6, 2006 Utilities Advisory Commission meeting was called to order at 7:00pm. Melton present, Dexter Dawes present, Dick Rosenbaum present. George Bechtel, Marilyn Keller and Bern Beecham liaison absent. Melton: Next order of business is Oral Communications and I have one chip from Jeff Hoel who would like to address the Commission. ORAL COMMUNICATIONS Jeff Hoel: Hi On September 18th City Council is going to be considering an RFP for a city-wide telecom system and the most recent draft differs from the draft before. In the previous draft, it outlined a process by which various bodies including the Utilities Advisory Commission would get to consider bids. If we should support the consideration of the bids, it could become a public process and the most recent draft omits this. It is not clear what the process of reviewing the bids will be, and if any of you Commissioners would like to write to the City Council as private citizens and ask them to let the UAC take a crack at it, I would appreciate it. I think since it is not on the agenda you can’t do anything official before September 18th. Thanks very much. Melton thanked Jeff Hoel. APPROVAL OF THE MINUTES Melton - Are there any other comments that the public would like to address? Seeing none lets move on to the approval of minutes of August 2nd meeting and I ask for a motion. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 2 of 37 Rosenbaum – A correction, I think. Didn’t we have our election for Chair and Vice Chair last meeting? I didn’t see it mentioned in the minutes. Melton – Asked Jennie Castelino. She responded that it was a special meeting. We did not include those the minutes in this packet. However, she has them recorded on file and could send them tomorrow via email. Melton – That is correct. We did have a special meeting for the election but those minutes do need to be approved as well, so could you prepare the minutes of the special meeting and have them in the next month’s packet for approval? Jennie agreed. Melton – Thank you Rosenbaum – I would move approval of the minutes of August 2nd. Melton – I will second Dawes – I have to abstain because I wasn’t here. Yeats – We will have to wait and approve those at the next meeting due to lack of an attending quorum. Melton – when we have three more Commissioners who attend that meeting. Melton – So we will defer the approval of the August 2nd minutes and reconsider them at next month’s meeting and we will bring both sets of the minutes back at that meeting. Rosenbaum – Actually all three I guess. August 2nd regular meeting, the special meeting and minutes of the September 6th meeting. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 3 of 37 Yeats – okay. AGENDA REVIEW Melton – Agenda review: Agenda for this evening is the Quarterly Report and the Quarterly Risk Management Report. Are there any additions, changes, deletions? Yeats – I would just like to call your attention to Item #5 on your agenda. We have added a regular item to the agenda as you may recall from your AB 1234 training. REPORT FROM COMMISSION MEETINGS/EVENTS Yeats - When you go to an event or training or a meeting that is paid for by the city, now under AB 1234 you have to come back and disclose that you attended the meeting and all that stuff that you learned at the training session. So we put a regular agenda item on there so that within the agenda if there is anyone that needs to report, you can do it under that item. Melton – Thank you. That’s fine. Moving on then to item #5 – Reports from Commissioners Meeting and Events – I know that Commissioner Bechtel went to Murphy’s but since he is not here he can’t report on that and I haven’t been to anything in the past month. Dawes wanted to know if any other commissioner went to that meeting. Melton responded that there is no other commissioner that went to that Murphy’s meeting. If any one on staff who went to Murphy’s would like to comment on that meeting, we would appreciate hearing it. Balachandran – I was at the meeting. Commissioner Bechtel and the Council Members Beecham and Mossar were at the meeting. We toured the Calaveras facility and then went to New Spicer Reservoir to make sure that all the water we received early in the year was still there and it is all Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 4 of 37 okay. (Laughter). This was Council Member Mossar’s first visit to the facilities. It was a great tour. The staff there talked to us about changes they made in the last three years at the suggestion of one of our staff member Shiva Swaminathan about three years ago at a similar tour. They initiated changing some of the hardware in the hydro facility to allow NCPA to participate in the ancillary service market so they recognized him. It was a great tour and they do this every year and in the coming months they are going to have an additional tour also. I think it was well liked by all the participants. Dawes – What were some of the main issues at the strategy session and the NCPA? Was there anything interesting? Balachandran – It was a commission meeting. So really it wasn’t a strategy session. The strategy session of NCPA take place in January and February at the Utility Director level. What is going on we report in the quarterly report but nothing major on NCPA. Melton – thank you. The next item is the Director of Utilities Report. UTILITIES DIRECTOR REPORT Yeats – Rather than just having an oral report; we have now started putting it into a written format. Items #1, 2 and 3 of this report are brief synopsis of some legislative issues that we have been working on and kind of details our actions on those, and then I would like to call your attention to Item #4 which is the NCPA legislative staff tour that will take place from October 4th to the 6th and NCPA staff will actually be in Palo Alto on October 5th and Council member Beecham will address the group and if any Commissioner would like to attend, we would like to make you aware of this event. Whoever would like to attend some point in time just let us know? If you would like, Girish can go through in detail any of these legislative items here if you have particular questions on them – there was a flurry of activity right at the end of the month as you are probably aware of and so there were significant actions that took place. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 5 of 37 Rosenbaum – I have a question on SB 107 on the background. Maybe you can help. It is one thing for Palo Alto to have 20% of its supply be renewable. We can accomplish that with a reasonable amount of wind and the landfill gas. But PG&E and Edison – how in the world they are supposed to get 20% of what they produce. What is the intent there? Balachandran – The legislature had adopted a certain goal of 20% by 2017. Subsequent to that the governor stated certain policy goals of advancing the date. So this is basically changing that state policy goal and incorporating it into legislation. Exactly right, IOU’s found it very difficult to actually increase their renewable procurement – I think just about two months or three months ago the CEC had a workshop where there was some very intense discussion but why they weren’t able to increase it. In terms of the resources that they plan to purchase, it is going to be very similar to the ones we are. Landfill is not going to be a big part of their portfolio. There is just a limited amount of landfill gas in California. CEC has identified that. Wind is going to be a big deal. There is wind in the Techapis, a tremendous amount of wind over there which they need to get to their load, and what is happening is that there is a transmission component which needs to be put in place before they can actually get those resources to load. Another relatively controversial proceeding is how that transmission is going to be paid for. The current estimate for the cost of the transmission if about four billion dollars and the California ISO has taken it upon itself to suggest a new transmission rate in addition to high voltage and low voltage and another category which will be renewable transmission. The municipal community has got involved in that in the sense that it is all being built for the IOUs to essentially to meet all these goals by 20% of 2010, and that is what is pushing these projects forward. One of the concerns that the municipal community has is if we pay for it do we actually get access to the markets on the other side? It is just being pushed right now by the ISO. ISO have made some comments on those proposals. We are going to be competing with them for the similar kind of resources such as the NCPA Green Power Pool that council approved. In Palo Alto we are going up to 33% and we are going to compete for the same wind resources up in the Northwest and the Techapis. I think this is more than you are asking for. Rosenbaum – You think that is all out there. I would think that the IOU’s together in California probably produce thirty-thousand megawatts of energy. 20% is six-thousand megawatts. I was Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 6 of 37 not aware that there is anywhere nears the potential for six-thousand megawatts of wind power in California. Balachandran – I don’t believe – it does not exist right now. There are a lot of developments happening in the Northwest. PG&E has just sent a proposal to the CPUC for transmission line that goes right up into British Columbia and bring it right down the southern terminus point would actually be down here in the South Bay and that is to bring wind power in Southern California. Edison has proposed that Techapis. There is a line called the Frontier Line which goes into Nevada and Wyoming. Those lines are not going to be built by 2010. These are somewhere between 5 to 10 year time horizon before they can build this. The likelihood of them actually meeting the 20% goal by 2010, I am not sure it is very high. Rosenbaum – thank you. Melton – I would like to learn a little more about SB 1368 which you referred to as the bad news of the bills to the point that NCPA is requesting the governor to veto it. Explain in a little more detail what it is about that bill that is so honest. Balachandran – the key point from a municipal prospective. Let me step back. Overall in terms of greenhouse gas legislation, CMUA has basically taken a policy position of supporting those bills. The problem with this bill is if we enter into a contract of greater than 5 years in length, it basically has to be approved by the CEC. It puts the CEC essentially as another decision-maker between staff and the City Council. The League of Cities has also opposed this legislation in terms of state over sight of local contracts. Not a policy goal that they are trying to achieve – there is no opposition to that. It is the opposition in getting in the way of local oversight and local approval of contracts. So it is on that basis that NCPA and CMUA are opposing the bill. Melton – Carl are you going to have any comments tonight regarding the Bighorn decision that We talked about. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 7 of 37 Yeats – No I really wasn’t but I have arranged for it at the next meeting Gary Baum, the City Attorney or Grant Kolling will be here to discuss it at length and we are working on putting a package of information together for that evening. Melton – So we will just put it all off till next month. Yeats – Anytime there is a decision like this, there is about as many as attorneys as we can find that have varying opinions of it and we are really trying to find out what is going to be the line. I talked to Gary today and it is actually one of the items that they are talking about at the League of California Cities conference in the attorney’s section of the conference and so he is hoping to bring back that information. UNFINISHED BUSINESS None. NEW BUSINESS Utilities Quarterly Report – whoever wants to lead this can go on: Girish – We are going to have a three part presentation here: Attachment A, B, and C. Attachment A – Jane is going to make a short presentation. This is a preface to the kinds of questions you ask. We just extracted a few pieces of information from the report to highlight and Jane will start with the Water Report, I will do the Gas and Electric which is attachment B and C. Tom Auzenne is going to do the Financial Report attachment D. Ratchye – Good evening. You can obviously ask questions about anything in the report. Some of the highlights in there are that the Department of Water Resources (DWR) issued its report about the climate change, its effect on state water resources. We have heard these things before that the amount of water stored in snow pack is going to be decreasing. The expectation is that the run-off will occur in a different pattern, it will come earlier. DWR evaluated different scenarios and some of them included a sea-level rise. If that occurred then it would certainly affect the delta water quality for the people who take water directly out of the delta. They think that will increase the Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 8 of 37 salinity of the water in the delta. So there are significant impacts. It is an interesting report. It shows what might happen in the State Water Project, Central Valley Project. Delta levees are addressed as well. It impacts our San Francisco regional water supply in that the snow pack and the need for storage is probably increasing. One of the pieces of legislation that BAWSCA sponsored was to require San Francisco to go to the state whenever it made a change in their capital program and for the Department of Water Resources and the California State Seismic Commission to make a determination of whether those changes impact human health and safety. Both of those reports were completed after San Francisco adopted its plan last November and gave the report to the State and the comments generally received from the State were that the new adopted water system improvement program (WSIP) is an improvement over their earlier capital plan. One of the things they noted was that one of the level of service goals which is critical is that they will return water to 70% of the turnouts within thirty days after a large event such as an earthquake. What that means is that there could be up to 30% of the turnouts without any water up to 30 days after an event. They wanted everyone including the legislature to know about that, to make sure everyone is able to handle such emergency. San Francisco doesn’t know which turnouts would be without service. The state questioned the ability of the BAWSCA agencies to be in shape, seismically to accept water after an emergency. We are expecting to get questions from the California State Seismic Commission, or the Legislature about the readiness and seismic vulnerability of our own distribution system. We have not received any questions yet but BAWSCA is expecting it. BVAWSCA is coordinating a response by all the agencies on where we are, when is the last seismic vulnerability study we have done, what emergency preparations have we made. About their WSIP – San Francisco’s quarterly reports on the WSIP have been great tools for us to see the progress of the program. Of course, it is very early in the project, but they are on schedule. The only thing that is off schedule is the environmental review phase because some of the projects that they expected to be able to get a negative declaration through CEQA will be required to do full environmental reports. The schedule for the program EIR for the whole WSIP is now pretty much set by San Francisco. They are now reviewing their administrative draft of the PEIR right now. They are expecting to release a public draft PEIR sometime in November and give us two months for review. BAWS (Bay Area Water Stewards) is an umbrella organization of probably 30 environmental organizations Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 9 of 37 that is scrutinizing the PEIR and they are looking at all the BAWSCA agencies choices that they stated in the urban water management plans for example and also in the statement of future purchases from the regional system, how much water they expect to purchase in 2030. BAWS is questioning whether the BAWSCA agencies are doing enough efficiency programs. We may see questions coming up from there and they are certainly going to address that in their comments on their PEIR. At the end of this month there is going to be sustainable water symposium – a two day workshop where BAWS will examine information and all the assumptions that went into the long term demand projections, the selection of the different conservation programs. They will certainly be questioning us, questioning assumptions, questioning why certain agencies aren’t using enough. They are also going to have information about per capita water use of all agencies and Palo Alto has one of the highest residential per capita uses so we are looking to respond to a question which is likely to be posed there. Third item is that BAWSCA has asked San Francisco to present the full total cost of improving its system because they have shifted some things off the ten-year horizon of the WSIP and they have not allowed for inflation for some of their projects and so BAWSCA is saying we need to see it all in one place and so instead of $4.3 billion it looks more like $5.3 billion. The emergency supply project here locally is nearing the review process – the public review of the public draft EIR will start probably this month and they are expecting certification of the CIR at the end of the year. The recycled water market survey - you have heard about this many times and probably expected to see that. Melton – Before you get to the draft EIR is that out yet? When do you expect it? Ratchye – It should be out later this month. Melton – And we will each receive a copy I hope. (Jane made a note to herself) Ratchye – I would think so. The Recycled Water Market Survey – we heard a little about this before and there was a major error discovered in the final review. After that error was incorporated the potential for recycled water was much lower than we thought. It is only 840 acre feet a year which is only about six percent of the demand but the cost did not fall much because we still need to build those pipes and so the cost went up much higher than originally thought. I do not want to Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 10 of 37 talk much about this tonight – this is coming back to you in October, and you will get the report and so we can talk about it then and what my recommendation is on the next step to this project. Balachandran – If there are any questions on the water report, can probably ask them now. Melton – I just want to comment that when I read that item on recycled water that I seem to recall that one of you two gentlemen said “I don’t believe that number” and it turned out for good reasons. Anyone have a question on any part of the water report? Melton – Thank you. Dawes – 20% water rate increase in SFPUC water for next year was just sort of thrown in there. I couldn’t locate my long range plan to see what our expected increase was or how it compares to our current projections. What is the relationship of that number what we have been using? Ratchye – I know the long term projections are in there. I am not sure what was used to budget for this year for the wholesale water cost. Lucie would have to answer that question. It was a much higher increase and found out about much later than we normally do and it was really because as your can see our usage went down. The whole region’s water consumption fell quite a bit and the suburban revenue requirement that San Francisco expects to get from the BAWSCA agencies is mostly fixed cost. So the cost per unit had to increase quite a bit. Dawes – We put our rate program together in May, June and it sounds like this came afterwards and I couldn’t remember what the assumption was on setting rates for the SFPUC water. Hirmina - Actually this increase we heard about it after the fact we put this together. Dawes – What did we have in our plan for the SFPUC number? Hirmina – I do not recall right now in my head. I can check it. Dawes – Are our rates now too low Lucie? Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 11 of 37 Hirmina – I think they will be low. We have heard about this rate increase from San Francisco that will happen. So we are going to adjust to look at it in mid-year and see where we are at. Dawes – So we may have a mid-year revision if this begins to bind too much. Hirmina – Yes, because our water consumption has been going down. Melton – okay Jane. Thank you very much. Balachandran – Moving on to the next attachment B – Gas side. We have a few slides here and again if there are any questions in the part of the report, we have staff here to answer them. Essentially, prices haven’t change very much in terms of this year’s average versus last year’s – it is still about 35% greater than 2004. Essentially pretty high prices. This slide shows our hedging strategy basically what our target is and how much we have hedged take away from this. This slide shows the comparison between market prices in the next 36 months versus our weighted average cost of gas which is an average of our fixed price pool purchases, and the market prices for the portion of our load hasn’t been purchased yet. For the coming physical year we expect about 20% less than market and the fiscal year following currently about 10% less than market. Dawes – Enlighten me why the fixed price pool purchase that is the big customers differs so much from the WACOG I would think there wouldn’t be a difference. Balachandran – The large customers were on the G3 rate on the fixed term rate – they are not here. This is showing the price for the entire pool and it is the portion of the pool that has been locked up already. So if you look at this slide for example – if you look at the first 12 months of this chart – this is our load and we fixed the price after this red line. It is all this which is exposed to market. When you look here the WACOG is the average of all the deals we have already done at a fixed price averaged with the portion that is not been fixed which we are pricing at this forward market price. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 12 of 37 Dawes – But you fixed 100% haven’t you through at least through December – I do not know why there should be such a difference. Seeing them being together and then diverging as we haven’t yet bought gases we go out. I cannot understand why the expected WACOG and fixed price pool purchases are identical for a longer period of time. Dailey – Because we have not fixed 100%. If you go back to that slide the red line is what we fixed and the top of the grey areas are expected. We have about 20% exposed. Balachandran – You can see that in the report. Dawes – We have 18% yet to go and the difference between the red line and the top of the grey is only 18% that visually didn’t seem to work for me. Balachandran – If you look at the report. The report has additional chart which shows this in percentage terms figure 4. Dawes – I got it. Just my mental calculus of integration under the curve, between the curves is little off I guess. Balachandran – That is all we have in this presentation and we are open to any questions on Gas. Melton – Let us go ahead. Balachandran – We are moving on to Electric. Little bit about the regulatory on certainty still continues. This talks about the MRTU – which is the market redesign as the California’s new design for the energy markets here. On several fronts right from California ISO and the CPUC the local resource adequacy issue is being dealt with, and all these forums and we are dealing with it at NCPA also on how to address this local capacity issue. City Council adopted the system resource adequacy principles and we have resource adequate from system perspective, from local perspective, we are not resource adequate so there is a potential for additional cost. This has been identified for a while but it has not been resolved yet. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 13 of 37 Dawes – I thought a long time about this and I am trying to understand – what I wanted to ask is for you to describe exactly how we would address what I would call a hypothetical resource adequacy which I would say is 15% of our expected load which I would say is one gig. Balachandran – It is 200 megawatts. Dawes – Annually it is one. Balachandran – It is energy versus capacity. This all has to do with capacity. So 15% of 200 megawatts so it is 30 basically. Do we have to contract for that actually? And make a contract with somebody that would deliver that amount of energy in order to satisfy this and if we do as reported by Carl – it is a part of our risk and so on..and we don’t use it - let’s say we come right on target with all our other suppliers we just then have to dump that off in the market? Is that the way that works so if everything goes according to plan we always be in that seller. Balachandran – These are two different concepts. Dawes – That is why you have to explain. Balachandran – This capacity and this energy – your question in terms of buying more than what we need and selling into the market that has to do with energy. This is reliability. The driver behind this is maintaining enough capacity such that if any one transmission line goes down or any generator goes down in the system as a whole there is enough access capacity to keep the lights on. Dawes – Okay what does that mean to us? Let us focus on these 30 megawatts now. I guess we do not have to contract to buy that. If that is what you have to say what do we have to do? Balachandran – Say a load is 200 megawatts and say we only had capacity resources of 150 Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 14 of 37 Dawes – when you say ‘we only’ or do we have them under contract? Balachandran – Either way. Under contract you got another point and the resource adequacy principles addresses this. The kind of contract you have to have to show that resource is adequate, it has to be a particular kind of contract. In the sense some of the contracts that are entered into the market had these terms called liquidated damages which says if a supplier doesn’t supply power they will basically pay you whatever damages you suffer. According to the ISO the PUC has not allowed these kinds of contracts – liquidated damage contracts to come to resource adequacy. The reason is resource adequacy is a reliability issue where as something like a liquidated damage is contracted it has to do with the financial issues – how you are managing your overall portfolio risk. From the contractual basis say a load is 200 we have to get an extra 30 megawatts, we would have to contract for a resource that would be delivered. Dawes – That was my hypothesis that we would contract for the extra 30. You say ‘No’ we don’t have to contract for it. But then you said just now we would contract for it. Balachandran – Sorry if I confused you by my answer. It wasn’t my intention to do that. I was trying to clarify the example you raised about energy. You are talking about 1000 gigs. This has nothing to do with that. So ‘Yes’. The rule is nine months before summer so in September of one year you have to show you had 103% of June’s needs. Dawes – Under contract. Balachandran – ‘yes’ The showing will be done by the NCPA to the ISO. ISO is responsible for reliability of the California grid. Dawes – How do they get the funds to make these commitments to buy power on behalf of all the pool customers? Balachandran – That is the second step. The first step is ISO sees what all of us have shown. PG&E, Edison, all the munies. We show that we have 103% of next year’s peak summer capacity Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 15 of 37 and then you have a month ahead showing so for June of next year when it comes to May 1 of next year, you have to show you have 115% so basically you have several months to go from 103 to 115. If you cannot show that and you have a deficit then the ISO will go and contract for capacity from a generator and they will charge either the deficit party or they are going to spread the cost over the entire grid. So rules are still being worked out as to how that is going to happen. Now the PUC sets the rules for the IOUs. Our council sets the rules for us. But ISO is the one that is responsible for reliability. It is a complete mess in terms of who is saying ‘what’ to ‘whom’ and making sure that all these regulatory processes go forward and you actually end up with a reliable system. Dawes - It does sound as though we will have to make firm contracts for 115% of our estimated peak load and if our plans are exactly right and we do not have to dig into that we will be in a surplus position and having to sell power on the market, presumable a day ahead on the market or something like that. Balachandran – This is where the confusion comes in. Dawes – The next question is if it is a cool summer everybody has a 115% under contract and everybody starts dumping their surplus power in the summer time the rates are going to be low. Balachandran – Let me answer your first question. It is capacity. You can buy combustion turbine capacity say you buy 30 megawatts of combustion capacity – well when you go into summer and you have that extra 15 percent and say loads don’t go up where you need it. Well, combustion turbine capacity is usually very expensive so it is not like its energy that you contracted for that you have to dump. You buy the raw capacity and the only way that city would run when market prices are higher than its variable costs. We aren’t contracting for a big pot of electricity that we now have to dispose of. We are basically contracting for a call option essentially. If there is a need we will call on it. Now, you can also buy say you need 15 extra megawatts – we can buy 15 megawatts round the clock product which will serve our energy needs and our capacity needs which in case you have surplus. But this is not the way we plan to fill in our resource adequacy. In our system basis we are adequate. We have Calaveras and we have Western. From the system standpoint, Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 16 of 37 we have sufficient capacity. The issue we are talking about here is local capacity. There are two levels of resource adequacies that are being imposed on us. One is for the system as a whole where we have sufficiently resourced. We have Calaveras that has 55 megawatts, we have Western 175 megawatts and we have landfill gas contracts. So there is no issue on the system side. We do not have to do anything. On the local side we may have to buy some capacity. Dawes – How does the wet year/dry year thing play into that? Do they adjust the capacity every quarter so you think you are in good shape but things aren’t what it should be and all of a sudden you are in a deficit come in spring. Balachandran – It does come into it but essentially the capacity of the unit is based on the probability of saying what kind of dry hydro year would you have – 90% of dry year what is the capacity associated with that. There are rules for how you count capacity for hydro plant and its probability based on kind of the hydro year. Associated with that energy all those numbers that you have in the chart are energy numbers and not capacity. Dawes – This to me says that in April of 05 Western said we are only going to be able to ship in the ensuing 12 months 250. Balachandran said that in any point of time they can run their generators at the maximum output. They cannot run the generators at the maximum output for every hour of the month. The whole point of reliability is that you have had enough generation during the peak hours of summer months. We are talking essentially about two hours or so of 8760 hours. The energy component, energy necessary to run the generators for those 200 hours even in a dry year, you had enough energy to run at that level. Dawes – This is a time related. Time is a critical ingredient on its capacity because it is a very short time period. Thank you for a good explanation. I finally got it and hope I did not waste too much time for my fellow commissioners. Melton – It was something that I was going to ask about. So we get down to the local reliability under the paragraph on local reliability you commented that we do not have sufficient local capacity though NCPA as a total group does. You say we will likely resolve this issue by doing some sort of Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 17 of 37 a pool sharing arrangement. Is that an NCPA task – is that actively being worked on to get that resolved. Balachandran – ‘Yes’ it is being worked on several levels. That particular issue is being folded in with a bigger piece of work which we have also identified of updating several NCPA agreements. The pooling agreement being one of them was signed in 1993 and the industry has completely changed since then. Some of the terminology still refers to things that no longer exist. Those have to be updated. We used to have a capacity market back in 1993 – the pooling agreement actually has references to the capacity market. In 1998 that capacity market went away. We no longer needed to show capacity with the interconnection agreed having expired in 2002. Now this capacity market is coming back. None of the definitions that were applicable from 1993 to 2002 are valid today. All those are being changed. They are being talked about as we speak. At the Utility Director Meeting tomorrow – that is one of the issues that will be talked about. The entire agreement is being changed. There are certain members that want NCPA to buy energy. Energy as a whole not capacity for them on a long term basis. The pooling agreement is not as clear as today’s energy contracts would require contracts fee. It seems more like set of principles in some parts of the agreement. Those have been tightened up and this is one of the sections that will be tightened up. Rosenbaum – On that issue the last time that NCPA negotiated a pool agreement, there were several years of hard feelings that were mainly directly towards Palo Alto. It was a very difficult process. Is it going to be easier this time? Are we still the big customer in the pool? Balachandran – I think it will be easier this time. We will not have another five year process. Last time it took from 1998 to 1993 to negotiate this agreement. It will not be a five year process again. The longest is going to take is one year. It is quite likely we would have major elements of the pooling agreement updated within six months. There is a need that has been expressed by the smaller members for NCPA to buy power on their behalf and given where prices are today, NCPA does need to act on that. Everyone is in agreement on that. We need to have some kind of resource adequacy philosophy that is applicable to all of us. Conceptually in a different place than we were last time this was negotiated. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 18 of 37 Moving on slide 2. The portfolio and again as you see from many of the charts. We will discuss it more when Tom talks about this financial also. It has been extremely wet year. Western thinks it is the top five on the entire history of the project. It is incredible year especially compared to what we were considering when we preparing the budget. The delta couldn’t have been more. On renewables – all the approved policies by Council on implementing a renewable portfolio many of those contracts that have been negotiated are coming on line. Here is an update of some of the renewable projects. The NCPA Green Power pool, the RFP for that power pool should be going out in a couple of weeks. Dawes – Before we leave the surplus power issues the hypothesis when we discuss this and previous things when years like this came and we ran a surplus and had to sell energy the prices would be diminished very considerably has this happened? What are the prices we are getting for the surplus power? Balachandran – There is some kind of correlation about the markets I can’t tell you that there has been correlation between hydro and market prices - a positive correlation. Dawes – there would be a lot of energy in the State because hydro is taking up this proportion show we are getting more than 50 bucks. Balachandran said – tremendously a lot more. The first week of July during the heat storm it was in triple digits. It was more than $200 in megawatt hour. These are market prices again just to show you that market prices are very high. You have seen gas prices also being historically high. Here is our load and resource balance. Essentially, this is a calendar year basis to report this. Essentially, we are in a pretty good position for this calendar year and fiscal year 2006-2007 we are about four percent surplus and we have a laddering strategy similar to what we have on gas and we continue to implement that strategy and buying from the market. The City Manager has signed a memorandum of understanding consistent with council approved policies endorsing the national action plan for energy efficiency and this was signed by the NRDC all the investors of Utilities, the CPUC and about eight or nine publicly owned utilities signed on to it. Council endorsed CMUA’s Green House gas principles and most of the Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 19 of 37 public power has endorsed these principles too. This is also in line with the public power posture of having good environmental stewardship policy. You will hear more about that as months roll along we will bring you climate action plan and energy efficiency plan. Little update on the public benefits program, update on the PV Partners, Palo Alto Green continues to do well. Energy efficiency programs are on track and there is a new program for small commercial customers that are going to be launched this month. That is all we have on the presentation for electric. After this Tom will talk about Attachment D – the Financial Report. Dawes – I have a couple of questions about the financial liability associated with couple of the items here. Probably Tom will touch on this. The first is page 4 of 18 – the EP Act 05 on co-tap it says NCPA ceases within the month……..capacity which sounds to me like we will not get income from that is that the case. If so what is the magnitude for what we are talking about. Balachandran – This is a very small amount. Dawes – Next is page 9 new claims for refunds from the IOU and what kind of reliability we are getting four and half million bucks back? Is this big bucks or little bucks? Balachandran said it is less than that. We are talking about just a couple of million at the most. Balachandran – we take every risk like this very seriously and this is being worked on by all of the public power. 20 public power entities in California are subject to the same suit. They are all working together. This is being taken very seriously and the risk associated with that combined with all the other regulatory risks that we had and the energy risk manager will talk about that in his presentation. Melton – The item says basically that the transmission related cost pass through two and a half million is the claim – it is a small number but do we have it build in into our reserves? Balachandran said that all these numbers are considered by us when we talk to you about our total risk exposure. In the risk manager’s report when he talks about the total electric risk exposure, these numbers are in that total. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 20 of 37 Melton – On page six you talked about some of our alternative energy sources and particularly in the second paragraph you talk about cogeneration. Frankly I can’t remember where I saw it. It was a discussion about reasonably newly developed the hydrogen cell like one megawatt hydrogen cell turn it on when you need, turn it off when you don’t need. I wondered if we looked at that, is that anything we looked at to meet some of our local needs or cogen requirements or anything. Balachandran – I can say with confidence that it has been looked at by Karl Knapp who is watching us. We plan to bring it to you in October Principles for ultra clean distributed generation incentive program. That would include any kind of fuel cell technology of ultra clean distributed cogeneration. We are working on some principles that would govern such a kind of incentive program. Melton – I would like to make another comment on Page 13 you report a little bit about Palo Alto Green. In terms of Kilowatt hours rather than number of customers. By my calculation given a quarterly number of nine million kilowatt hours that put us about three and a half percent of our annual. Do I recall we set four percent as a goal for kilowatt hours? Balachandran said ‘No’ there has not been such a goal. Most of the goals have been stated in terms of participation. Auzenne – The long term goal we had originally set for ourselves was 15 percent participation. Just because we are of such a size that on a kilowatt basis a much larger utility with much smaller participation with small part numbers. However, the national renewable energy laboratory tends to like participation rules. That is why we are number one in the nation because right now we are sitting at 14.6 percent and we will hit our 15% in short order. Melton asked if there were any questions on the electric report. Before we move on to the financial, I have a card here from Herb Borock who wants to address us on the subject of the quarterly report. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 21 of 37 Borock – Thank you chair Melton and good evening Commissioners. I want to speak specifically about the information received on fiber optic report which is a source and uses funds. Until May 2003 report you were also receiving income and expense statements and balance sheets. It seems to me that now that the City Council will be considering a request for proposal for universal telecommunication services that may include use and take over of the dark fiber what is in the fiber optic fund. It is important for City Council to receive and the commission to review and comment upon the kinds of documents you received in the fund accounting just as you do during the budget and that is the balance sheet and income and expense statement as well as sources and uses and funds, the kinds of assumptions that are made in cost allocations and appropriations, and how much money is left over un-spend from the various authorization accounts. As I recall four categories has been the original dark fiber backbone and then there have been two on-going capital improvement programs, fiber optic customer connections where the extensions of the backbone have been paid for entirely and completely by people who requested those extensions. Then there are fiber optic network system improvements where the city staff chooses where to add fiber backbone to complete a loop with the previous funds and sometimes they go to places where they think someone is out there will become a customer if the fiber was there. Although as I understand that the direct customers as opposed to the resellers tend to be on Stanford land and in the Research Park and maybe the extensions will be going through to Welch Road on Stanford land and research park and may be the extensions will be now going through to Welch Road. The fourth fund is the Foothills Communication Improvement Plan where the fiber optic cable is going up to the Foothills to serve utilities department, police and fire and also be available for residents. To me that is conceptually the same kind of fiber backbone as other fiber. Before city council initiates the RFP it should be council policy agreeing as to what those balance sheets and income statements are so the bidders know what they have to bid on is something that city council agrees with the numbers. It seems it would be the Utilities Advisory Commission would be the advisory board to go over those before it gets to the council. There are also assumptions on allocations and we help to reconcile all the reports that we got in different formats over times since the backbone was first started ten years ago. Thank you. Melton – I am sure staff will take those comments. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 22 of 37 Dawes – Before we leave this and I had when you had asked for final comments on this for some reason the Fiber Optic Financial Report is included in the electric update rather than the financial package and this is a sort of continuation of Herb’s point the format is different. Before it was essentially a profit and loss statement and I had assumed that’s what this is and it is called sources and uses rather than revenue and expenses – is this a profit and loss statement Tom? Auzenne – You can construe it as a profit and loss statement. This is the same format with sources and uses of funds that all dollars are reported to in all documents that you see pretty much coming from the Enterprise Funds. Dawes said he would summarize it by saying qualified ‘Yes’ it is not a GAAP accounting approach to life. It conforms to Enterprise Fund accounting and it conforms to the city’s methods of accounting and this is consistent with all of the other funds financial performances. Yeats – Once again, I want to assure you that we conform to all GAAP accounting standards. We had this conversation before Commissioner Dawes. We receive audited financial statements. The financial statements are awarded by the Government Finance Officers Association, and The California Society of Municipal Finance Officers Association. They are the highest awards for excellence and financial reporting. We conform with GAAP whether it is fund accounting or business accounting GAA is GAAP. Dawes - I understand we have had that conversation Carl. My question was does this piece of paper conform with those accounting principles which you just mentioned? I think we come out in the final annual statement that has been reviewed by our Accounts and so forth. I do not know if to the extent if this is embedded in that or not? Yeats – I think that this is what Tom just said, and that this is in the same format that all the Enterprise Funds are reporting in this format is that correct Tom? We even have our resident CPA sitting out here that is shaking her head Sharon Bozman. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 23 of 37 Dawes – Nodding her head or shaking her head? Yeats – Sharon gets nervous when I start talking accounting – I know that. Dawes thanked Yeats. Melton – That seems to have led us into the Financial portion of the report. I would just ask a question about the Dark Fiber financials here. Just in the way that we look at the numbers in the budget and then we look at the actuals it is pretty clear that the methodology changed during the year it looks like some direct costs went down and some allocations went up. From the way we expected to do it in the budget for instance allocated was budgeted at 7 and came in at actual at 83, obviously we changed some allocation principles during the year. Whereas direct salaries and benefits went down from 600 to 500 so I assume that this is just methodology changes during the year that is why we are seeing those variances in certain accounts. Yeats – The allocated charges will go up and down based upon a lot of different factors but mainly has to do with the cost of insurance, the cost of claims. We have claims that are incurred but not booked. Workers compensation charges and things like that. I do not know why such a low number was used in the original budget but certainly that is a number in terms of the fiber fund, I am really interested in getting this broken out from the electric fund so that on an allocated cost basis we can begin to truly track the cost based upon how much time a person spends on a particular project. Right now that is the only format that we have because it is not completely broken out at a sub-fund in the electric fund. Our goal is to move it into its own fund and then at budget time everything will be allocated or budgeted in that fund rather than moving through the year what actually occurred and then allocating based upon that. Melton – So ignoring those kinds of things one thing that I really had a question on in this fund was the capital improvement program spends only half of as much money as it was budgeted. We know from previous capital improvement program that may mean cost-savings or it may mean that money just got bumped out into the next year. Can you tell me which this is?> Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 24 of 37 Yeats – Looking at this I can’t but I can certainly get back to you and let you know what happened in terms of the capital projects. From looking at this I would assume that they completed X portion and the remainder was rolled forwarded or re-appropriated into the next year but I certainly can look into that. Tom says that he knows the answer. Auzenne – As was indicated earlier there are two CIPs associated with the Dark Fiber and so what you are seeing is cost recovery on one and probably I know for fact under spending on the other. So ‘Yes’ that part is rolling forward. Yeats – Any indication of what the status is on the CIPs for the fiber? Melton – I think we got enough of an answer. We do not need any more details. Auzenne – Once again we return to our favorite subject – The Financials. Again you have in front of you a different format that you have ever seen before. Auzenne said that in the interest of accuracy and clarity we continue to strive to provide you with best available information that we can so that you have a good understanding of what is going on in the Quarterly Report. As is the case with Electric, you should also note that before we get started, that there is probably ten months of actuals and two months worth of projected. What we have done is provide that the format you had seen prior to our last format revision, which did not go over very well and resulted in more confusion. We took a look at this from the staff basis and put a lot of time and effort into making some changes which are indicated on Page Three of the handouts that was made at your places. All of the numbers that you see in the Quarterly Report come from our SAP system. They all correlate with each other. We have separated the reserve activity from the operating activity so that we will hopefully increase some understanding of what is going on with the actual or the projected changes to the reserves as a result of the operating activity. We have updated the numbers so that the Adjusted Budget replaces the adopted budget when that information was available. The Accounting Activity Section which you will see on Page Three shows actual SAP transactions to date. The budget figures corresponding those values indicate variance of actuals to budget. The projected adjustments to date section at the bottom of page of that chart on Page Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 25 of 37 Three represents those transactions that are known, but has not yet been recorded in SAP. Hopefully, that will also add some precision to this. Next steps. I still remember my promise to put together a meeting between representatives of Council, UAC and staff to finalize report formats going forward, the timing for Quarterly Reports, the Ten Year Rate Forecast and re-proposals so that all of those come in a intelligent and logical sequence of events. I only did this for Electric for illustrative purposes. I haven’t gone through and laid out everything for gas and water. You can see how the numbers have been broken out. You will find that in the Risk Manager’s report, his numbers match with our numbers which makes him happy to no end. On the reserve activity, we have summed those projected adjustments from the bottom of Page four and listed it on there to show what the projected or impact on reserves should be, as best as we know it now. This concludes my presentation. Dawes – Just a point of clarification Tom. In Table 1 you show the projected sales revenues of roughly 84 million dollars and I am trying to reconcile Table II and net sales to date if you look at the unaudited actuals for both supply and distribution, you come up very close to that and I assume those balanced. My question is apparently in Table 1 we don’t assume other revenues today and sale surplus power I guess the retail sales revenue which is the way you described it. I guess I will not go into the philosophy of why things are separated like that but I understand it and I want to make sure that I did understand it and the answer is ‘Yes’. Auzenne – The philosophy is very simple. We wanted to be able to show you what was going on the retail side of the business here in Palo Alto separate from anything else that is going on in the wholesale side of the business. Dawes – I was surprised in fact that so much of the energy costs are assigned to the surplus energy revenues. When you look at the retail sales revenue, basically the revenue is the same as budget, but the purchase cost which includes the hydro cost of course plummet. Essentially, instead of buying stuff on the market we are getting it all from hdyro or not all, but a lot of it, so our cost really dramatically dropped. You allocate that evenly the hydro cost against the power that is sold surplus versus the retail power. I do not know how that allocation is done. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 26 of 37 Balachandran – Hydro is basically making other resources surplus. We don’t sell Western. In terms of the cost, it is not the cost of Western that pertains here. It is the cost of other resources that gets pushed up the stacks so to speak. Dawes – So you do it basically on actual basis. Balachandran mentioned that it is just one part of it. There are sales made in the pool and then the sales made to the wholesale market. NCPA also allocates certain purchases that they make for the entire pool, which gets allocated to us and then resold. Each one of those transactions get tracked and then through averaging process which we worked up basically the accounting department, which determine how they are going to be booked and the auditors get involved in this end of the year. How do you actually report this in the CAFR and if you look at all the CAFR’s they are basically cost associated with all the sales that you may and it is calculated cost based on our portfolio. It is not a one-to-one. We had the surplus block of power. We sold that block of power because transactions are happening at every hour and there is a lot of minute share involved in calculating this. Dawes agreed. Rosenbaum – That was my question. Dexter and I had talked about this once. The question is how do you determine the cost of what you sold? You say you do not look at the individual purchases; you take some sort of an average? Balachandran responded said the calculation is done. It is not allocating a certain sale and saying okay this is the cost of the power associated with that particular megawatt hour. It is impossible to do. We cannot actually track that down. Rosenbaum thinks that you could certainly pick and choose whether you were selling something that you paid a lot for or paid very little for and it would change the results. Balachandran said that anyone point in time when we have surplus power, you have to make a judgment as to what is in that surplus. We are essentially not selling Western. Everything else you calculate an average cost of all the surplus associated with that. There are pool sales that get allocated to us when NCPA is making purchases for the pool. What is the cost of that on an hour to hour basis? Do those get averaged out and this is the net result of that calculations? Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 27 of 37 Melton – Going back to Table 1 which is Table 1. I appreciated the fact especially when I go to the Table II, it is a kind of integrated into the whole picture. I think it is useful to be able to actually track the sales and cost that get sold for that product which we are actually selling to our customers as opposed to stuff that we are doing outside of our main business line. I would use Table 1 as being the business that we are in and Table II and the other items to be ancillary to that. I think the way you set up Table II worked for me. I was able to track the numbers quite well. The one question I had about it was are these the only operating cost or are CIPs included in this as well. Are they separate somewhere? Auzenne: They are separate. These are all operating costs. If you look at Page 11, as we talk about the CIPs it kind of gets ugly until the end of the year and all the books are closed. You have a snapshot at the beginning of the year. Until you get a final snapshot until the end of the year, we can try and report, but you get a melding effect. Dawes – So there is no CIP and other expenses today on Table II? Auzenne replied that is true. Bozman said it is just operating budget. Dawes said that was fine. He continued saying that looking out at the very wonderful reserve numbers estimated at year-end not yet being adjusted for CIP issues although I have to ask that question does the Table include some estimates of CIP for the year? Auzenne – ‘No’ It doesn’t because we make assumptions as to what they are going to be spending, they in fact if they return un-spend funds, then those will be reflected at that point when the books are closed and the CAFR gets published. Dawes – Conversely, those CIPs which have been approved during the year end and funded during the year don’t show up in this. Basically we know that the estimated ending balance is 65 million for the RSIR is overstated. Is that a correct statement? Auzenne replied that it may not be overstated. We don’t know. Dawes said we went through the whole business of how the allocations of the CIPs went but it would seem to me that it would be unlikely that the amount return to this reserve would be greater than the amount that was obligated for the CIPs during the year. That is how it would go up. It would mean a very low CIP allocation. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 28 of 37 Auzenne – If I understand your question correctly, ‘Yes’, the CIP would not be overspent because at that point it would have to go back to the Council and get approval for that. It can only be on target or under spent. Yeats – Every CIP when it is created it has to be approved by Council. Staff cannot generate new CIPs. I think what you are talking about Mr. Dawes is when a CIP is closed out there may be un- spend funds and that is returned to the Fund Reserves. Dawes – ‘No’, the funds are obligated. Are they set up as a charge to the Enterprise Fund? Are those numbers in this Table III? The answer is ‘No’ so the reserve is over stated to the extent that our net CIPs are omitted, net being net of the amount that gets back in the reserve because it was unspent. Auzenne – Now that I understand the question, ‘Yes’. Dawes agreed and continued to ask what implications does this have for our reserve policy and our rates potentially for going on into next year? The illustration is that this is one of the five best years ever and Western is terrific we could have one of the five worst next year should we be sitting on this? Or should we be thinking maybe we won’t have to raise rates quite aggressively as we have in our plan. How do we look forward and evaluate this? Balachandran – Those discussions are forthcoming and we are going to be talking about reserve philosophy. We have identified that some of the reserves do need to be fixed in terms of the guidelines that we have, and that is going to come to the Finance Committee I believe next week or so and then brought to the UAC for further discussion. Like Tom laid out on in one of his charts, the Ten Year Financial Forecast will also be brought to you. I think that is where those discussions would be the best time to talk about. So the timing of when those get brought to you is also important, the sequencing of those different reports in the next two quarters you are going to see all of those. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 29 of 37 Yeats – Our goal is to have that before heading it into the budget process and have the discussion, analysis and the recommendations back to the Finance Committee so that we can move through with the rates and adjust the reserves accordingly. Dawes expressed his thanks. Melton – The one thing we can say about the Electric Fund Reserves is we certainly have had a bonanza this year and it gives us substantially more flexibility than we have in some of the other funds. Dawes – One further question on the Budget for the Public Benefits – my recollection is that we spend less than a million dollars a year on that so we now have a year and a half to two years worth of spending in reserves is that my calibration right? Auzenne replied that as far as my memory – it is about 1.5 – 1.6 million a year that is in the budget. Obviously those dollars are affected because they are 2.8 percent of sales. Whenever there is a rate increase public benefits budget goes up, whenever it is flat, costs increase but revenues stays the same. Dawes wanted to know if staff is contemplating fattening up the public benefits so that we do not have a full year’s worth of spending in reserve? Auzenne said that the reserve goes up and down. It is very cyclical. Some years we have had almost nothing in reserves. Other years we go more into a planning mode and money sits there. This year we did not feel it was critical to sit there and try to pump money out for no particular reason until we saw what some of the effects of some of the legislative changes were going to be. We are also in the process of working on I believe a Ten Year Demand-Side Management Plan. Balachandran – To carry on with that AB 2021, which is the legislation that we expect the governor to sign, is going to require us to develop a ten year energy efficiency plan and the difference now is that it has to include all cost-effective energy efficiency options. So we are going to pass the paradigm of public benefits which there is a cost-effectiveness component. Now all cost-effective energy efficiency has to be identified. We have to update that plan once every three years. We have to establish annual targets of how much we hope to achieve and at the end of the year we have to report to the City Council, to our customers and to the CEC how we have done against our plan. This was a big deal in sense of legislation. The initial legislation had all the local control at Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 30 of 37 Sacramento. The end result of the bill same objectives but the control is pretty much with us, City Council. So there will be a lot more effort and potentially money spent in that area. Melton – Any other questions regarding Gas which is next in the Financial? I wanted to note in Table VI on the Gas Reserves that we actually had a net increase in reserves. It looks like we are going to end up with about nine million dollars in the two reserves – three and a half in one, and five and a half in the other and if I go back and look which I did the worksheets when we were doing rates early in the year that is a substantial better outcome that we were forecasting at that time, so we have finished the Fiscal Year in a better reserve situation in Gas than we had expected to. That is one observation I wanted to make is that the sum of the two according to Table VI is going to total about nine million dollars. Also I noticed that you haven’t booked it yet in SAP you have basically one and a half million dollar reallocation from distribution to rate stabilization that you plan to make that move and you talk about it in the verbiage – I don’t remember how you describe it. Some bundled gas revenue, which is currently in the distribution fund, is being reallocated, so it boosts that supply fund reserve from two million to three and a half million. It is one place where I saw that your numbers and Karl’s numbers didn’t match because he is still using the two million dollar numbers and you got it at three and a half. Will that get resolved? Auzenne – That is true. It will get resolved. When Karl makes his presentation even though the gas reserve as you say totals nine million for both electric and supply, I do believe that the supply reserve gives him some concerns. Melton said that he picked that up and that is why he is drawing the attention to these numbers now because when Karl gets up here I want to talk some more about that. I want to all have firmly in our mind nine million dollars is what our total gas reserve is which is better than what we thought it was going to be. I presume that because when we did the rate projection in gas prices were sort of at a real high and we were not sure of what is going to happen in fact they come down some and so we got some benefits. Auzenne added that unfortunately sales also went down. Melton – Any questions on water? Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 31 of 37 Dawes – we talked about the SFPUC and the fact that wasn’t included in the numbers yet. I guess that is going to be a change when we close the books out. Auzenne replied that was the effect that happened in July. This will not show up in the FY 06-07 books. Dawes: I thought that was retroactive. Auzenne said we are closing watching sales levels during this summer and the fall to see what revenue impacts that is going to have and as Lucie indicated we might be coming back at the mid-year with some suggestion/changes, but we don’t know yet. Melton – We did raise the water rate 20 percent. We under estimated the wholesale. Even in raising the rate 20 percent we did not fully account for the size of the wholesale rate increase. It is another bump in water especially when we look at our curve and we are at the top of the stack with all other cities it is a tough situation. Hirmina – Actually, the increase in water was seven percent in July. The gas was 20 percent. I apologize for that. Melton – so we had seven percent increase in water. Hirmina said the increase from San Francisco is implemented this year FY 06-07. Melton: Thanked Lucie. Melton – The financial sheet in the Financial is the CIP reserve balances which are the report we asked for and what I noticed is the amount of money we are carrying in CIP reserves continues to decline so we are cleaning those out quicker than we used to. We do not have as much as the rate-payers money tied up in the CIP reserves as we did two years ago. Auzenne - That is correct. We are putting the value in the street. Melton – Any other questions on any of the Financials? Thank you Tom. Next item on the agenda is the Risk Management Quarterly Report. Karl over to you. Van Orsdol - I just wanted to give you a short summary of the Quarterly Report that I produced. I will be able to answer any questions about what I talked about or whatever else is in the report. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 32 of 37 Basically, during the quarter all transactions were within limits. There were no exceptions. Market to market value of the contracts declined slightly for the fix price contracts. The total value of all contracts is about 43.5 million. Our credit exposure continues to fall with moderating prices and increasing quality of our counter parties. Like last quarter the value of risk that is the risk we have of the un-purchased portions of the electric supply remains very low but of gas it continues to increase now almost double of what the bench mark is and that is the result of the fact that gap reserves set aside gas supply reserves have continued to decline and our not really sufficient given the risk that those reserves are set aside to mitigate. Talking about reserves we have at the end of the year at 58.4 again these are SAP numbers. These do not include any of the additional income or expenses that may be allocated to SAP later. Minimum required under electricity under the current policy is 27 and our total risk exposure is estimated about 35 million for electricity. For gas again we had that 2 million number as end of the year reserves minimum policy is 7.8. If we look at our risk we really need to have about 4.7 to 5 million to cover the risk that our portfolio currently has. The next slide again shows you the value of risk for the gas versus electric and the absolute number of the value at risk for gas is not increased substantially, but the reserve level for gas has gone down pretty much consistently over time I think. At the first report three years ago when I came in front of this group we had a 5 million dollar gas reserve and now we down to about 2. So much of that slope much upward is because the gas reserve is really gone down over time. Again, this shows you the date that is in the report in terms of the beginning reserve balance that is what is in the CAFR the 44.2 million for electricity and 3.8 million for gas. The current policy on guidelines what the minimum maximum are and as Girish said there is going to be a joint front office, middle office analysis and presentations later on this year that is going to look at setting reserved balances on risk guidelines as opposed to simply percentage of the cost. Melton – I will remind you – we have been eagerly waiting for some months. Karl said that he realized that. I think we have a start in the sense that we are all now the front and the back of us we are all talking about the same numbers. I think we all have the bases for how we are really Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 33 of 37 going to look at the reserves. Dawes said even though the estimated numbers at the end of the FY are different between the two presentations. Van Orsdol – We have the same numbers for the SAP. I used to be in the sales organization we would have sales guy who would say I am going to close this deal – well you don’t book it until you get the check. It is a bit like – I need to use the official City’s Financial Report to do this assessment of reserves. I can’t take into account possibly changes that might occur. I have to use this. Even though I know well that they will differ from what happens later and next quarter I could look at these and have a different number. One of the reasons why I presenting to you in September was I normally present to you two months after the end of the quarter is because we wanted to try to get as much into the SAP system as possible as that we are as accurate as possible in these numbers. Dawes – A comment was made earlier that some of these numbers particularly in electric are two months behind. They do not have the numbers in yet. The electric number that you have of 58.4 does not have two months of activity in it. It is not really a 6/30 number. Karl responded that it is a 6/30 number. It is what is in SAP as 6/30. Dawes said we know we don’t have billings for couple of months May and June. Karl said that when he says it is un-audited actual reserve balance so that is what the books tell us is in there. I can’t think of any other way I could do it and be consistent with these financial statements. Dawes – Conceivably we could have a situation where the Risk Manager is saying we got a big problem here and the other set of numbers says we ain’t got a problem. What is the City Council going to do? You tell the City Council that there is two months of billing that we do not have in the system yet so we know that the numbers are going to change. Fortunately it is not quite that big you show 2 million for gas so this is 3 ½ this is almost double in terms of whether there is a problem here? Van Orsdol – Right and I would argue that we still have a problem even if it is 3.5 I think we need to have 4.7. Dawes said that people have to understand that these are not locked down numbers at Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 34 of 37 this juncture. Karl responded that he would categorize it that everything that has officially entered into the financial statement of the City it is included. Dawes – We know that these numbers have not been entered. Van Orsdol - If you look at the long caveat at the end of one of my slides, it refers to adjustments that could be made for anything related to liabilities for worker compensation, general liabilities, retirement medical benefits etc There is a whole series of things of data that would be entered in SAP by other people in Carl’s Department who are not related to Utilities. Dawes – Any recommendation that we might make to the City Council or you might make to the City Council has to be carefully crafted to illustrate to point out that while the numbers are exact to the penny out of SAP we know SAP has many entries yet to be made before the numbers are certified and blessed. Van Orsdol – I recognize that. That is why I tried in my text when I talk about the gas reserves to make suggestions that in the long term the current levels for the gas supply reserve are really not adequate. If I felt that there was an immediate issue with this, I would have the language be much stronger than it is. It is a long term issue not that this quarter something needs to be done issue. Melton – I want to make sure I understand what the ground rules are. The total reserves in the Gas Fund is 9 million dollars. It happens that it is heavily waited in the distribution reserves as opposed to the supply reserve. It is very clear that the supply reserve isn’t up to what you calculate what our real reserve needs are for the supply reserves. Am I correct as a policy matter I presume with the approval of the Council or just the management of the City while we can’t move reserve funds between funds that we could just as a matter of policy decision move money from the gas distribution reserve to the gas supply reserve make up that deficit – the gas distribution reserve would still be above its minimum and is just a balancing act. We do have enough reserves in the gas fund to meet the minimums of both the supply and the distribution – they are just out of balance right now and we could fix that with a stroke of a pen is that correct? Karl said that it is correct. Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 35 of 37 Dawes – You are talking about loans between the funds? Melton said it is all in the gas fund. It is just in the gas distribution fund. Dawes – I have also been told that you never really make a change from one reserve to another. Melton – From electric to gas you can’t. But within the gas fund you can do that. Van Orsdol – If you turn back to Tom’s presentation to Table VI, you will see the estimates for the gas stabilization reserve a 3.4 million and then of the rate – the distribution reserve a 5.5 That together combine represents the gas fund. Dawes – I just didn’t know that was a management judgment. I assumed it was an appropriate accounting adjustment that was made to the system. But if we are free to consider each enterprise fund in an aggregate rather than split between rates and distribution. That is a different ball game. Yeats – From the financial standpoint when we roll it up in CAFR it is reported at the fund level. Melton – I also noticed that if you look at the last forecast when we did rates back in the spring that there was this 20 percent increase in the gas. So the gas reserves are already programmed to start going up. So we not only we have adequate reserves in the gas fund and total presently, we have already taken the first step toward increasing those reserves by the rate increase earlier this year. As you say there isn’t an urgency right now and maybe we have already taken the first step towards solving the longer term trend. Van Orsdol – I am not making a clear on call for immediate increase of the fund. I am just stating that we have a systematic problem with the allocation that we made to the gas supply. Yeats – As Tom stated before one of the issues that we have is the timing issue and we have to do a better job of bringing you the information to make your decisions. When we have the most current information, certainly we are in the process of closing the books right now we will produce Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 36 of 37 the audited financial statements in November and so in November when the numbers are final we need to come to you and talk about the ten-year forecast and the reserves and all of those strategic decisions that we need to get your input on. That is the time to do it. If you do it now you will wind up in the dilemma that you are in what is in, what is out, what is the real number and so we are establishing a time issue that they are going to start the process in November when the numbers are final they are going to bring the ten-year forecast with all that information to you so we can have that discussion before we head into the budget. Melton – Thank you very much. This completes new business. The next regularly scheduled Meeting is October 4th. We have several items identified as being on the agenda for October or for November. It looks like we are stepping up to a pretty full calendar. Yeats – if I could give you just a quick update and certainly Chair Melton is aware of this. We have conducted interviews for the Utility Director. We are proceeding on a path, and hopefully we will have a new Utility Director identified in a very short time. It has been a long year and a few months for the Assistant City Manager, and a long year for me in trying to do dual roles. You get to the point where you are not really sure if you are being effective at either. We are both looking forward to having a Utility Director on board. Melton – As we all are. Dawes – A query, I have raised this question before. Probably, I will get the same answer this time. I am always in the East coast during the half of September, and the first half of October and in prior years I had participated in the October meeting by phone having posted the agenda on the front door, and for the requisite period, followed the rules and so forth. But the last input I got was that it was no longer going to be permitted. I guess the City Attorney is dealing with that. Is there any possibility that the City Attorney will change his mind and allow me to do what I have done for the last three or four years? Yeats – I will certainly ask him once again. His opinion is that if the meeting is supposed to be held in public in Palo Alto, if you are not in Palo Alto the Palo Alto public can’t very well show up at the Approved on October 4, 2006 Utilities Advisory Commission Minutes - Draft: Page 37 of 37 meeting for you. There is some logic to that somewhere, but I will certainly ask him about it again and get an answer for you. Dawes – I interpreted that our role is as much as to do the leg work and questioning that is with the purpose of informing the City Council which happens to be in public. But the primary purpose is not to inform the public but to inform the Council. So having somebody’s mind engaged in it addresses that issue so perhaps if you could call that a fact to his attention it might encourage him. Yeats – I will do my best and try to be persuasive with him. Dawes – Thank you and maybe you could send me an email as to which way the decision might go. Yeats – Sure. Melton – Dick do you plan to be here in October? Rosenbaum answered ‘yes’. Melton: Let us assume that we have a quorum for October 4th until we know otherwise. Meeting is adjourned. Respectfully submitted, Jennie Castelino City of Palo Alto Utilities