Loading...
HomeMy WebLinkAbout2005-09-07 Utilities Advisory Commission Summary MinutesSeptember 2005 UAC Minutes Approved 11-2-2005 Page 1 of 9 I. ROLL CALL The September Utilities Advisory Commission meeting was called to order on September 7, 2005 at 7:00 p.m. Those present included; John Melton, Dexter Dawes, and Dick Rosenbaum. Commissioner Bechtel was absent. II. ORAL COMMUNICATIONS None. III. APPROVAL OF THE MINUTES The minutes of the Utilities Advisory Commission meeting held on August 3, 2005 were approved as written. IV. AGENDA REVIEW AND REVISIONS None V. REPORTS FROM COMMISSIONER MEETINGS/EVENTS Melton reported on the NCPA meeting at Murphy’s. Dawes, Bechtel and Melton attended. It appeared to be an uneventful meeting from a business standpoint. It was useful to meet with the NCPA people to learn some of their plans and directions. VI. DIRECTOR OF UTILITIES REPORT John Ulrich commented that Bern Beecham actually Chaired the meeting at Murphy’s. We received 11 proposals from seven firms for new renewable resources.(wind, geothermal, biomass, solar thermal, and photovoltaic proposals. Ranging from $63 MWH hour for five years to $300 per MW hour increasing to 3.5% for 5 years. Staff is currently evaluating the proposals. Initial results indicate staff will recommend contracting for supplies with two of the proposals. NCPA is organizing an effort to jointly seek green power for it’s customers. We were unable to discuss the Sierra/Nevada Power Authority (SNEPA). There was a special meeting of the commission today. It was agreed by all the members that NCPA should join with the city of Redding to form the SNEPA to look at and procure energy resources to use an issue tax exempt bond. NCPA and Redding are now founders of SNEPA. VII. UNFINISHED BUSINESS There was no unfinished business. VIII. NEW BUSINESS 1. Mechanics of CIP Budgeting and the CIP Reserves Accounting Process Information This is your opportunity to look at and learn how we do our budgeting. With the comprehensive report and tonight’s presentation, the Commission should get a better idea of how we budget. John introduced Rosemary Ralston who will lead the presentation. Sample Project Ms. Ralston went over a chart that explains how we’ve budgeted with a sample project demonstration. The only part of the budget request that is approved is the first year. The rest is used as a projection for rates (only for the 2 years out – not the first year). Every year we revisit the entire project. As an example we have approved budget and $300,000 is available City of Palo Alto Utilities Advisory Commission September 2005 UAC Minutes Approved 11-2-2005 Page 2 of 9 in the current budget. We end up encumbering $100,000 of that money, we spend $25,000 and $75,000 is unspent and that is our encumbrance. There is $200,000 that is unencumbered at years end. The project managers, such as Roger and Tomm, notify Accounting through a process we have that yes we do need to carry over that encumbrance into the next fiscal year and as you follow the money, they notify Accounting we want the contract carried over. The balance in that contract is $75,000. As part of the year end closing process, that $75,000 is put into the CIP encumbrance reserves. Melton asked if there is any other way to encumber a fund? Ralston said we could also start with a Purchase Requisition which becomes a Purchase Order. It’s just the level we are talking about. Again the $200,000 that is remaining of the $300,000; the engineers will look at and say, I need that carried over to the next fiscal year to complete the project. Accounting then puts it in the CIP reappropriation reserves. Year 2 we begin the year with the $275,000 available in that project. Carryover is $25,000 and we have another $120,000 and they all fit into the two difference reserves. Year 3 we go through the budget process. Lucy looks at and says we need $3 million for the rates. That $3 million becomes part of the rates for that next year. The funding on the 3rd year of that project, is the new budget request and the carryover of the $25,000 and the $120,000. By the end of the year 3 we decide if we need to close the contract. We notify Accounting. Also that year, if we’re lucky, we manage to get a contract through for $3 million which involves a very elaborate bidding process close to 6 months to get through the bidding process and then we actually will encumber the money for that contract. We get the contract approved, we spend $1 million that first year, and then we have $2 million remaining at the end of the year and again, we tell Accounting to move it into the CIP Encumbrance Reserves. The money that is unencumbered, we have $120,000 carried forward; this time we have $100,000 labor charges and $20,000 unencumbered at year end and again, we request that Accounting remove it. We start year 4 with the money in those two reserves. We complete the work. We come in under budget. This time as we close out the contract and close out the project, we tell Accounting to return $500,000 we came in under the contract amount. This is the money that goes into the RSR. Again, this is what the Rates Manager looks at this as a reduction in the revenue requirement. The same thing happens when we spend everything we need to on labor. Melton asked we are doing this on a CIP basis and this process is for each CIP. At the end of the year, there is no money floating around outside of authorized CIP, is that correct? Ralston confirmed that is correct. It’s a very methodical process, there is nothing going outside of that. Ms. Ralston went over an actual project we have that mirrors the sample. Melton asked ‘if we started out in 02 with a design phase, for whatever operational reasons, the work was not accomplished, having that 2 year slip, why did we then in 0304 put through the request for construction when the design had not been done? We knew we were not ready to spend that money. Ulrich recalled that we did go through to Council because we felt we could do it. At the last minutes it was taken out because they wanted us to do the EIR. Why was the $2.210 Million put into the budget into the rate base when you knew the project was slipping? Ulrich replied that when we put it in we didn’t know the project would be slipping. Ulrich said once the money is put in, it stays there to describe what has taken place. Roger Cwiak said we were ready to build but the City process got in the way of us actually constructing the project. We budgeted in November of 2002, we put the budget together of what we think we’re going to build. Sometime in May or June, on the night the budget was going to be approved by the City, we were told we would have to complete an EIR for all the projects that were included in the study before we went forward with any construction work on any of the reservoir or wells and any rehab work. The only work we were able to go ahead with September 2005 UAC Minutes Approved 11-2-2005 Page 3 of 9 from the study was the work on the existing facilities in the Foothills. The motion from Council that night was to remove the design dollars on these projects and go back and renegotiate our consultant contract and that’s what the disencumberance was on this contract. We had to take part of the design dollars out of the contract with Carollo. Dawes commented that this seems like a special case, in terms of normal CIPs. Thinking of rate payers and whether there is a mechanism in place that makes sense to deal with issues like this where you have pretty big numbers that goes into a rate making decision and then gets deferred for several years. Maybe it averages out over time and you get a bump in the RSR because you are not spending that kind of money and the succeeding years rates aren’t changed as much as they would have been otherwise. Cwiak said the only time this money would go into the RSR is if the project was completely scrapped. We will be spending this plus more because of the time value of the dollars spent. Dawes remarked will the CAMPX charged into the cost of a particular enterprise fund is in a budget basis rather than an actual basis and this is a separate pot of unencumbered funds that are off balance sheet that doesn’t show up in the RSR. Cwiak stated it is in the other reserves that Rosemary described. It doesn’t go into the RSR until the very end of the project and it is completely disencumbered and we do not plan to use it at all for construction. Then it is completely returned to the RSR. John Ulrich made the point that it is very difficult unless you look at the chart to see where the money actually is. The important thing is that we can find the money and if not encumbered, it goes back into reserves. Dawes asked for some visibility on reporting of unencumbered CIP funds which he characterizes as off-balance sheet. We don’t see it. Ulrich said unless you look at each and every project you’re going to be looking at co-mingled funds. Look at the long term picture, we are spending the money we expect to spend on an on-going basis. Melton asked if the EIR situation had not come up, there was supposed to be a $950,000 design thing. In 2 years none or very little of that money got spent. You’re saying in the 3rd year we did request 2.2 million in construction because we thought we would be ready to go even though we had not spent the $950,000 for the design. How were we going to get there? Roger Cwiak said we had a negotiated contract but not an awarded contract which we were ready to take to Council which would have been completed in 7-9 months and then start construction. To start the project, the City rules say we must have the money in the budget prior to going out to bid. We cannot bid any project that we don’t already have the money in the account for. Ralston said the CAFR reports twice a year on the status of CIP projects. In the CAFR, the reserve balances show for 02/03 and 03/04. Look (page 4) where it says reappropriation and the next says recommitments. This is in the CAFR every year. It does combine capital and operating but we can separate that. Most of this money is the CIP. When you look at the carry- over it balances. When you look at the CAFR that is where you see the reappropriation of the unspent dollars. Melton asked to see the CAFR. Melton asked to see the CAFR. Ulrich said the purpose of this report is to give you whatever information you’d like to have. We purposely picked a project that demonstrates you don’t always spend what you have planned. But I want to give you a very firm commitment that the engineers and everyone who put together these projects together have every intent to do the work as scheduled and get it done. Rosenbaum thanked the staff for this very good presentation. He suggested it would be very helpful to have this information in the 5 year projection. Dawes said yes but he doesn’t know what he’d do with that information. What would the action item be? Is there a problem about the way we complain about them? Is Palo Alto suffering from the problem of being unable to make decisions, start work, get things done and wrap them up. A bulge in the reappropriation number might indicate that. September 2005 UAC Minutes Approved 11-2-2005 Page 4 of 9 Rosenbaum mentioned he usually get the CAFR information on CDs. Ulrich said it would be helpful to define what the commissioner feels we don’t provide. We may not always be able to spend the money when we plan but we know where the money is and how it’s accounted for. That is the message we are trying to deliver tonight. We can go through the bond analysis if you’d like. Melton noted the clause of the bond covenant that the money had to be spent in three years. The money was in fact spent on water and gas projects, just not the one it was intended to be spent on. Ulrich said he wants to make sure in a very clear way we know where the money is and why we haven’t spend it and that we’re not doing something inappropriate. Rosenbaum asked if it was possible to identify the CIP water projects that are in the pipeline that have already been funded? Ralston said yes, she has the details the commissioners have the roll up. Anything approved by Council is on this document. Rosenbaum said there may be escalation due to passage of time. This is very useful information and wants this information along with or part of the 5-year forecasts. Melton requested all of the RSR reserves be included in the 5-year forecast. Including the bottom line number of these other two reserves, the encumbrance and committed. Melton wants to see a line that says CIP encumbered reserve and CIP reappropriation reserve in the 5-year forecast. Lucie Hirmina said that information is in the 5-year forecast . We don’t change the CIP, we leave it, it’s included but it is not separated as part of the reserves. Part will be encumbered, part reappropriated. Melton wants CIP encumbered reserve and CIP reappropriation reserve – wants a line for each number. 2 reserves – for each enterprise fund. Wants a line for each reserve item and a number for this year/next year. Ralston reminded the commission that this is a one year number. Dawes asked electric fund 0405 last page item 1 – return to RSR – 6.1M, probably 1/3 of a typical year spending. Why such a large amount? Ralston said this is an unusual year due to the implementation of the SAP. This year actually represents money that would have been done last year and this year. The money sat in the CIP Reappropriation Reserves. Ralston stated that this is definitely off the balance sheet. Melton agreed that it is just on a balance sheet the commission doesn’t see regularly. Dawes agreed it’s not off balance sheet, it’s just in a pot we can’t see over there. Not like balance sheets we as businessmen are used to seeing. Ralston said fund accounting is difficult. Melton questioned in the CAFR the unencumbered funds in the reappropriation reserve are a combination of operating and CIP, is the operating a significant portion of that number? We don’t do reappropriations in the operating budget as a departmental policy. Any unspent money goes back into the RSR, the next year you still have a base budget. This is very strictly watched and there are guidelines that have to be followed. Remember CIP’s do not have base budgets. Melton thanked Rosemary for the very informative presentation. 2. Energy Risk Management Policy Information Karl Van Orsdol gave a brief description of the Energy Risk Management Policy. Key changes, enhanced conflict of interest provision, enhanced responsibilities of middle office, enhanced credit provision, credit review provision, a clear separation of duties between front office and in the back office, roles are more focused, has been extended to telecommunication utilities, and we’ve made some progress in making the document more understandable. This is scheduled to go to Council in October. Dawes suggested that in the future, put changes in bold so it’s easier to see what has been changed. No reference to ownership of production assets versus commodity purchase products – nothing about risk management getting involved in decisions as far as make versus buy. This will be a pretty important piece and should be put into the policy. September 2005 UAC Minutes Approved 11-2-2005 Page 5 of 9 3. Scenario Analysis of Hydro and Price Risk of Electric Portfolio Strategies Information Jane Ratchye’s presentation covered the objectives and strategies that were analyzed as well as the results of the analysis of the strategies in various scenarios of the future. A presentation on variable rates is to follow. The schedule is to bring recommendations to the UAC in the Fall on the portfolio strategies and variable rates and then an implementation plan in the Winter. No action is required today. The analysis was completed so that there would be a common platform to evaluate all the different options. The analysis was designed to understand the risks for all the different strategies under a variety of scenarios, what the range of costs could be and what reserves would be required. The UAC has seen the eight strategies in past presentations. In addition, Jane added a strategy of 100% spot purchases to provide a bookend. Strategies include buying an amount equal to about 120% of our load so that there is sufficient supply in a dry year, buying call options for dry years and put options for wet years. For each strategy, the cost for three years was calculated in different future scenarios. Jane went over each graph in the report and described the different scenarios. No costs were listed for the CHEX product. When the cost is available, all the points on each graph would move up by the amount of the actual cost. The results showed that many of the strategies manage price risk in the portfolio, however, only the hydro hedge strategies limit hydro risk, but the cost of those strategies may be high. Fixed-price purchases for 100% of the deficit or for 100% of the deficit if hydro were dry also limit risk to reserves, but also limit the ability to take advantage of possible lower future prices. Strategies with options are costly and limit price risks somewhat, but allow the portfolio to take advantage of potential lower prices in the future. Dawes asked why use cumulative three years on the cost side and where did the numbers come from? It was not clear to Dexter. He said he didn’t see individual years and expected costs for those years. Jane responded the model looked at a monthly cost on/off peak, this is the total summary of the analysis results. For example, for the base case scenario, the cost for each month of the three fiscal years was calculated. The price assumptions were based on a current quote. This shows that with the 100% spot, the cost could vary from $128 million (in three wet years with low prices in a row) over 3 years to $250 million (in three dry high years with high prices). The best thing would be to limit the high price risk and be able to retain exposure to a low market price but strategies that do that don’t exist except at a high price. Dawes commented that 100% spot is risky and we probably will not be doing that. By examining the chart you can conclude that the put options and call options look very expensive. For the same amount of risk control, they cost more. The weather insurance is also more expensive than other options that can provide the same amount of risk mitigation. More time is needed to look at the proposals received from suppliers on the CHEX product. Melton commented that on the attached chart if CHEX were free, it would clearly be below the efficient frontier and it would be a slam dunk. But if it’s $2 million a year, it is well to the right and doesn’t get much more impact on the reserves than selling Calavaras. Jane said this analysis is a fairly high level analysis. This is to focus your attention more on the strategies near the efficient frontier, which are the current ladder strategy, buying for 100% of load, selling or laying off of Calavaras or CHEX, if we can get the price we are hoping for. In response to a Request for Information that was sent to suppliers for the CHEX product, four proposals were received. Staff is still evaluating the proposals. We don’t have any numbers yet to share with the Commission. Overall, in summary, the ladder looks like a very good way to reduce quite a bit of the risks. Put and call options are expensive, for now. September 2005 UAC Minutes Approved 11-2-2005 Page 6 of 9 Buying 120% of the load in the “buy for dry hydro” strategy reduces price risk but it does not reduce the hydro risk. If you do buy that much, you reduce the opportunity to take advantage of prices if they do fall. Selling or laying off all or part of the Calavaras project looks attractive. We need to know what someone would really be willing to pay for the project. The weather insurance product looks expensive and doesn’t look particularly good compared to the other options. CHEX looks good if it costs about $1 million per year or less. This presentation described how our portfolio strategies can lay risks off to other counter- parties. In every case some risk remains which would be passed off to our other customers. The next presentation describes the supply rate stabilization reserve levels and variable rate design options and how they can complement each of the different strategy. John introduced Tom Auzenne and Monica Padilla for this portion of the presentation. Tom will be talking about the purpose of the presentation, the objective of the Rate Stabilization Reserves, risk and reserve requirements, our current practices, the alternatives to those current practices, an analysis of the electric portfolio risk mitigation strategies and reserves, and summary and next steps. The key objective of the electric and gas portfolio are to manage commodity cost and reserves to enable low and stable rates. We provide a high level overview of the relationship between the Electric and Gas Supply Rate Stabilization Reserves, frequency of rate changes, and risk level., assess the merits of using the Electric and Gas Supply Rate Stabilization Reserves to deal with risk, evaluate the impact on reserves associated with risk management strategies, introduce the concept of changing rates more often through Variable Rate Designs as an alternative to using reserves and/or hedging strategies, we are attempting to seek UAC feedback and there is no Staff Recommendation today but we do anticipate coming back to you in the future. When Resource Management talks about risks, the risk to the customer is defined as the difference between adverse market and/or supply conditions versus expected conditions. The cost associated with the risk is ultimately passed on to the customer. Hedging is used to manage customer risk. When the Rates people talk about risks, they are referring to the risk to Utilities that arises when there is insufficient cash to cover adverse changes in supply cost. Reserves and rate changes are used to manage the Utilities’ cash flow risk. Reducing risk reduces the need for reserves. The need for reserves is a function of the risk profile and the frequency of rate changes. Reducing risk reduces the need for reserves. Changing rates more often reduces the need for reserves. Our current practice is to carry enough funds in the electric and gas supply rate stabilization reserves (SRSR) in order to adjust rates once every two years. The amount of reserves needed is based on the risk to the supply portfolios associated with the laddering strategy (% of the portfolio exposed to market prices), the supply uncertainty (hydro and credit risk), and the legal and regulatory risk. Our current practice has pros and cons. The pros include relatively stable rates, financial stability and high credit rating, direct Council oversight on rates, and low administrative and oversight costs. Cons include delayed price signal to the customer, it does not reduce risk to customer, the annual cost of carrying reserves to ratepayers (assumed 2% difference between customer vs. city discount rate) is $1 M for electric if the $50M maximum reserve is maintained and $0.3 M for gas if the $15M maximum reserve is maintained. The retail rate stability is difficult to achieve when sustained market changes occur . Alternatives to our current practice include managing customer risk through more aggressive hedging strategies to reduce the need for high reserves , manage Utilities cash flow risk by adjusting retail rates more often or a combination of both. September 2005 UAC Minutes Approved 11-2-2005 Page 7 of 9 To reduce customer risk through more aggressive risk management for the Gas and Electric Portfolio, market price risk is managed through the laddering strategy and may be substantially diminished by buying 100% of load on a forward basis. For the Electric Portfolio, staff is evaluating hydro mitigation strategies, to manage supply risk including purchasing call options to exercise in dry years, buying more energy, assuming dry year – sell excess in average to wet years, buy more energy and in addition buy put options to sell in average to wet years, have an energy exchange agreement, such as CHEX, purchase weather insurance or lay-off all or part of Calaveras. The pros for this more aggressive management include reduction of customer risk and therefore the need for reserves and the cost of carrying reserves and better rate stability. The Cons include; high implementation costs, higher credit risk, commodity cost may be higher than prevailing market prices, in a declining market price scenario, and lower financial stability due to lower reserve levels. An alternative would be to change rates more often through new pricing options such as variable and fixed and convenient. Variable options include commodity cost adjustment, time of use (TOU), and real time pricing (RTP). Fixed and Convenient would provide annual or biennial changes or more often and expansion of the City’s “Budget Billing” program. Commodity Cost Adjustment (CCA) is known by various names for different utilities, Power Cost Adjustment Factor (PCA), Fuel Cost Adjustment Factor (FCA). These variable rates can be implemented automatically at regular intervals according to an established formula and may or may not have an expiration date. The pros of having a variable rate design include a reduced cash flow risk to the Utilities, and the need to carry high reserves, the portfolio risk and costs are more quickly passed on to the customer, within Council approved band, they can be used with any portfolio management strategy, and will provides customers a more current price signal. The cons include lower rate stability or higher rate uncertainty, higher administrative costs, does not reduce risk to the customer and lower financial stability due to lower reserve levels. Girish Balachandran went over the conclusions such as how much reserves we carry and how often we adjust rates does not affect the customers’ risk and implementing risk mitigation strategies along with changing rates more often through Variable Rates and an expanded “Budget Billing” may best achieve customer and Utilities objectives. Girish said our next steps will be to continue to evaluate relatively ‘inexpensive’ external hedging instruments such as laying off Calaveras, and maybe CHEX. A formal staff recommendation will be presented this Fall at a UAC meeting. We will continue evaluating new rate options; CCA, with rates adjusted more than once a year, evaluate implementation & billing system capabilities including automatic changes and proration and we plan to evaluate similar programs in other cities. We will further evaluate reserve level policies, rate setting practices, and optimal rate to replenish reserves, including the impact of reserve levels to credit rating. Girish asked for questions and feedback from the Commissioners on these last two presentations. Dawes asked if the laddering strategy would still play a role. Balachandran said the strategies are not mutually exclusive. Base case did have steam laddering strategy and part of the base case, yes it will be a combination of laddering with whatever other options we pick. Rosenbaum said changing rates once a year is often enough. Right now we do look at electric rates once a year and adjust the rates accordingly. He is convinced we have trouble in predicting the amount of hydro we will need but CHEX seems to take care of most of that. He said he would be very surprised if anyone is willing to sell us CHEX at a low price. Melton agreed with Commissioner Rosenbaum. He also said there are real advantages with TOU and RTP which are not included with things going forward. For now, if we are not going to pursue some of those strategies for electricity. Ulrich said no, we are not going to not look September 2005 UAC Minutes Approved 11-2-2005 Page 8 of 9 at them but we will look in conjunction with other strategies. He mentioned the CHEX as being an approach to solving the hydro issues, isn’t that what NCPA is trying to solve with their new org (SNEPA)? We wouldn’t necessarily have to do both, if SNEPA can solve the problems we wouldn’t have to do anything with CHEX, correct? Balachandran said CHEX is a totally different product. That is just one strategy, another is laying off some of our existing hydro. At this time, SNEPA is focused on flood control areas. We are looking at SNEPA as an alternative. Tom Auzenne said if you’re a fan of once a year rate making, real time pricing is probably the antithesis of that. RTP is the ultimate in variability because you’re sitting there getting a different price every 15 minutes. Rosenbaum said we’d like to eliminate our hydro risk. Balachandran said our load is relatively flat, it peaks in the summer. By laying off a portion of it, we could still hold enough for our load bearing needs. 4. Utilities Strategic Plan Performance Report (7/04 – 6/05) Information John Ulrich introduced the format of the USP and the process we go through. We will ask for feedback on our performance and some of the issues that the Commissioners may see about measuring ourselves in this way. John introduced Ipek Connolly who has collected this information. Ipek directed the Commissioners to Attachment B, detail. She went over the changes that have been made to the Plan. Dawes asked about ‘unique municipal values’ that the Actuals don’t show – how do you get those numbers? Ipek said it ties to first presentation today, what’s budgeted and what is spent. We wanted to complete greater than 90% of the projects. These figures represent the encumbered in the budget expenditures. Ulrich said none of the measures have to do with purchasing computers or anything like that. Melton said he thinks it deals with the reapportion thing that deals with carrying money over. Ulrich said it’s important to look at the amount of work being accomplished and not just the amount of money being spent. This is not a simple thing to do because you want to know you actually got work accomplished for money being spent. Melton said maybe a better measurement tool would be to measure the street number of projects – did you meet your goals. Ipek spoke of the Environment measures- we met or exceeded our renewable target. The PAGreen program we are proud of but the market has come to a certain saturation and we realize our target was too aggressive. We fell a little short of this target and as a result of the saturation, we will adjust our target. Resource efficiency we are looking at potential in Palo Alto and as we get results we will be able to set these goals. Next is the Financials there are two general areas: competitive bills and financial strengths. You, as a Commission, have asked us separate the electric, gas and water bills and compare Palo Alto bills against neighboring utilities averages. We did that and the results are shown on the report. Palo Alto customers are enjoying lower electric bills. Water bills are higher and results are mixed for gas, depending which Utility we are comparing ourselves against. People, safety and job satisfaction. We did not meet our goal of 0% safety index. We have not met that goal and it may be unrealistic but we are improving our incident counts. Rosenbaum asked about bill comparison. Santa Clara’s bills are lower than ours and perhaps this should be pointed out when this report goes to the Council. Tom Auzenne said the difficulty of comparing our bills with PG&E has worsened because they do pass on the costs on a monthly basis. We will be modifying our reporting methodology to reflect that difference between our supply cost and distribution cost and their supply cost and distribution cost. Rosenbaum asked why do we have to separate out those two? Auzenne said this will enable us to more accurately track market changes (going back). Going forward, everyone does September 2005 UAC Minutes Approved 11-2-2005 Page 9 of 9 market forecast on what they anticipate what the market price will be. Forecasts are often wrong. Rosenbaum said we have set the rates for 05/06 so we know, assuming there are no emergencies, we know what our costs will be for 0506. You have no information on PG&E’s supply cost for next year. He suggested we don’t try to make that comparison since we have no way to do it. Balachandran remarked that the difficulty when we present you with a budget and rate projections, is we say here is what we think our rates are going to be in 0506 and we compare it to an estimate of what we think PG&E’s rate is going to be which is the current market price because that is what Council asked for. What’s your rate versus what’s PG&E rate? Rosenbaum said clearly going backward is the only accurate on, why not just tell people we can’t make comparisons to PG&E looking forward. Ulrich said we don’t have a problem with that. We’re trying to be responsive and answer your questions. If you and the Council are not interested in guesstimates and going forward then we can stop doing that. A couple of months ago, one of our customers was here talking about a different methodology for billing for distribution gas rates and that ours is a flat rate depending on the class of customers whereas PG&E has a declining rate block for the same group of customers. It may be valuable for everyone to know what those differences are in the distribution methodology and why our rates are higher in Palo Alto for gas than they would be at PG&E or vice versa. Distribution may be easier to make comparison with. Dawes asked about Long Beach gas – they only do it once a year? Tom Auzenne said he is not familiar with what they are doing. He will be glad to come back to the Commission with more information. Melton observed that under municipal value – 3.5 transfer to the General Fund. He doesn’t use that as anything that is under the control of the Utility. It is a City policy decision. It is an item over which you have no control and it serves no purpose to report on this in the balanced scorecard. Dawes said if the cash flows were extremely adverse, there would be some pressure to deal with that. They would certainly hear from the UAC but if they would do anything about it remains to be seen. Rosenbaum said in the early 90’s we did not make the General Fund transfer in water because of the drought. There is some virtual to showing we are able to meet our obligation to the General Fund. Melton commented “under financial strength 2.2 – debt service coverage’. Earlier this evening we were talking about a recent bond issue for gas/water. Why is this debt service coverage only measured on the electric utility, why not to all utilities? Ulrich said that has to do with Calavaras. Ipek Connelly – Off microphone). Auzenne said Calavaras reserve represented such a large stranded cost back in 2001 when everything hit the fan. We have recovered the cost and that is why it shows up there. Ulrich said he doesn’t think we have debt in other areas. Melton said when he hears debt service coverage, he assumes that includes all the bonds that are outstanding and payments that are required on those bonds. Melton said this measure should cover all the debt the Utilities faces. Ulrich agrees. He will verify that the only reason electric is listed is because that is the only area we have debt. Rosenbaum will not be here October 5th. Dawes will be an absentee call in member for. Ulrich asked Dawes to confirm by email where he will be. Rosenbaum said you can call in but you need a quorum present to allow the call-in participation. Meeting adjourned.