"Markets Committee Meeting Minutes"
draft MINUTES OF THE MARKETS COMMITTEE (MC) MEETING HELD ON FRIDAY, MAY 29, 2009 IN MARLBOROUGH, MASSACHUSETTS Member/ Attendee 5/29 Alternate Market Participant C. Ide Chair ISO New England, Inc. E. Abend Member EPIC Merchant Energy NE, L.P. N. Bosse Alternate Brookfield Energy Marketing, Inc. C. A. Bowie Member Northeast Utilities System Companies T. J. Brennan Member National Grid, US J. Cammarata Member CMMEC Temporary Alternate MMWEC D. J. Capra Member International Power America Customized Energy Solutions for BP Energy N. Chafetz * Temporary Alternate Company and Energy America, LLC F. P. DaSilva Member NextEra Energy Resources, LLC K. Dell Orto Alternate Millenium Power Partners, LP S. Dimou * Alternate Bangor Hydro-Electric Company J. Dudley * Member CPower, Inc. M. A. Erskine * Alternate Central Maine Power Company B. Forshaw Alternate CMEEC Temporary Alternate MMWEC Boston Generating, LLC, Exelon Generation, LLC W. Fowler Member and Granite Ridge Energy, LLC BG Dighton Power, LLC, Calpine Energy Services, Dynegy Power Marketing, Inc., Entergy Nuclear Power Marketing LLC and First Light Temporary Alternate Power Resources Management, LLC P. D. Fuller Member NRG Power Marketing, LLC J. Gawronski Member United Illuminating Company J. S. Gordon Member PSEG Energy Resources & Trade LLC H. Healy Member EnerNOC, Inc. C. Hennequin Vice-Chair DC Energy, LLC Alternate DC Energy, LLC Temporary Alternate Constellation Energy Commodities Group, Inc. Conservation Services Group, Inc. and Gas D. Hurley Member Recovery Systems, Inc. Energy Federation Inc. and Vermont Energy Alternate Investment Corporation Comverge, Inc., CT Office of Consumer Counsel, EnerNOC, Inc., Seneca Energy II, LLC and Union Temporary Alternate of Concerned Scientists M. Kachru Member NSTAR Electric Company BG Dighton Power, LLC and FirstLight Power T. Kaslow Alternate Resources Management, LLC Boston Generating, LLC, Calpine Energy Temporary Alternate Services, LP and Dynegy Power Marketing, Inc. W. Killgoar Member Long Island Power Authority A. W. Kuznecow Secretary ISO New England Inc. CT Office of Consumer Counsel, NH Office of P. R. Peterson Member Consumer Advocate and Union of Concerned (i) Scientists Associated Industries of Massachusetts, Harvard Dedicated Energy Limited, The Energy Consortium, The Energy Council of Rhode Temporary Alternate Island and Utility Services LLC J. Reyes Member Mass. Attorney General’s Office J. A. Rotger * Member Cross Sound Cable Company, LLC W. G. Ryan * Alternate Vermont Electric Power Company, Inc. W. Seldon Alternate Reading Municipal Light Department D. Smith Temporary Alternate National Grid, US M. Smith Member Harvard Dedicated Energy Limited The Energy Consortium and The Energy Council Temporary Alternate of Rhode Island Industrial Energy Consumer Group, Maine D. J. Sipe Member Skiing Inc. and Mead Oxford Corporation R. de R. Stein Member Signal Hill for H.Q. Energy Services (U.S.) Inc. B. Swalwell Member Comverge, Inc. S. J. Weber * Member PPL EnergyPlus LLC G. Will Member MMWEC Guest Affiliation R. Allen VT PSB P. Asarese ISO New England Inc. T. Austin ME PUC C. Below * NH PUC E. Buzaid * Day Pitney D. Cooke * ISO New England Inc. A. DiGrande ISO New England Inc. J. Douglass * ISO New England Inc. J. Dwyer ISO New England Inc. D. Ellis Dynegy Power Marketing, Inc. B. Feldman Constellation Energy Commodities Group, Inc. M. Gardner Day Pitney M. Harrington * NH PUC E. Jacobi CT DPUC V. Karandrikas * McNees Wallace & Nurick LLC D. LaPlante * ISO New England Inc. R. Laurita ISO New England Inc. R. Pelletier MA DPU B. Sher Viridity Energy, Inc. R. Sullivan TransCanada Power Marketing Ltd. H. Yoshimura ISO New England Inc. * -- Indicates participated by telephone ii draft After determining that a quorum was present, the meeting was called to order. Agenda Item #1: CHAIRMAN’S OPENING REMARKS The Vice-Chair stated that the Chair will be arriving later this morning and that she would chair the meeting until his arrival. The Vice-Chair then welcomed the Committee and had those participating by telephone identify themselves. Agenda Item #1A: ADDRESSING FCA1 QUANTITY PRORATION REJECTIONS Mr. Gordon presented this item to the Committee. This presentation follows from the discussion at the April 3, 2009 Participants Committee meeting on the FCM Omnibus 4 proposal. At the Participants Committee meeting the ISO indicated there was not going to be available headroom for these resources to de-list and agreed to bring back the issue if it turned out that there was enough headroom. Later, the ISO determined there was sufficient headroom available and allowed a previous de-list bid from Norwalk Harbor that was rejected for reliability to take effect. Other Connecticut resources were not allowed to prorate on MW. 320 MW in Connecticut was still required to provide capacity after Norwalk Harbor’s Capacity Supply Obligation was let go. The Transmission System Analysis (TSA) was re-done to reflect a reduction in ICR and other factors so that there was headroom to release Norwalk Harbor. Mr. Gordon explained that the result was that only 94% (the resources’ full rating minus the 6% that could have been pro-rated) of these Connecticut resources were compensated. At this point in Mr. Gordon’s presentation, the following points were raised: (1) A Committee member asked whether the ISO did this re-evaluation as part of the Resource Adequacy Analyses, or at random times, or whatever. (Proponents: Mr. Gordon and Mr. Kaslow replied that they do not know. There was some analysis done near the time of the end of the FCA and the data were re-examined after the Participants Committee meeting discussion. We believe it may be that the ISO had to do the re-evaluation prior to June 1st in order to avoid taking the full MW amount for the upcoming Capacity Commitment Period.) (2) A Committee member asked how the stated 94% value was determined. (Proponents: Mr. Gordon replied that there was a 6% proration across the pool at the floor price that Connecticut resources were not allowed to elect. This results in incremental MW being supplied without incremental revenues. One could consider this situation as getting paid $4.25/MW for all capacity or $4.50/MW for the amount committed to and nothing for the rest. We view this situation as the latter.) Mr. Gordon continued his presentation stating that there is an uncompensated risk issue as well because the entire resource is subject to Shortage Event failure to perform penalties. Mr. Gordon then cited his position that there would also be uncompensated services because of the application of the PER adjustment to the incremental MW. Because these resources have a CSO for the full resource (rather than the 94% of MW that would have a CSO if these resources were allowed to prorate on MW), the following applies: (1) They must offer the incremental capacity into the Day-Ahead and Real-Time Energy Markets; (2) Export of the incremental capacity from these resources is precluded; (3) They are required to obtain outage approvals for the full capacity of the resource; (4) They are precluded from selling the incremental amount as Supplemental Availability; (5) The incremental MW may not be used in Bilateral transactions; and (6) The incremental MW may not be offered in reconfiguration auctions. 1 After this portion of the presentation, the following points were raised: (1) A Committee member asked if this would also mean there would be nothing available to buy in Connecticut. (Proponents: Mr. Gordon replied that someone could now buy from New Haven Harbor #2 but prior to that de-listing taking effect there was nothing available to buy in Connecticut.) (2) A Committee member asked if new DR would be available to purchase. (Proponents: Mr. Gordon answered that whatever is available has to be Qualified Capacity for 2010-2011, so it seems unlikely.) Mr. Gordon continued his presentation by placing forward the proponents proposed changes: (1) Exempt those resources prohibited from prorating from the Shortage Event Penalty; (2) Exempt resources prohibited from prorating from the PER adjustment for MW amounts above what they would have been allowed to prorate to by defining “CSO subject to PER adjustment” as the CSO less prohibited prorationing. The proponents would like to discuss this proposal again at the June Committee meeting and vote on the proposal in July. After the presentation, the following points were raised: (1) A Committee member asked whether this issue would go away once the floor price goes away. (Proponents: Yes. Mr. Gordon stated that it may also not apply to FCA#2 if no prorating is denied. We do not have data on that subject.) (2) A Committee member asked, for this top 6%, is there risk as to whether or not it will actually be available due to weather (i.e., summer de-rating). Is it correct that you were willing to take that risk at or above $4.50 but not at $4.25? (Proponents: Yes, except we view it as taking that risk for 94% of output at $4.50 and the incremental output taking that risk at $0.) (3) A Committee member asked if the ISO accepts some but not all prorating, would this still apply. (Proponents: Mr. Gordon stated that we see this as only happening in the first three auctions but would propose the rule change generically. If no prorating election is denied, it has no effect. The rule change would apply when prorating is denied regardless of the reason for the denial.) (4) A Committee member analogized the summer derating of generators and air conditioning PRD or efficiency programs. DR has been bidding conservatively, why not generators? (Proponents: Mr. Gordon responded that a major difference is that generators are required to use their 90-degree summer ratings. No one would agree to take this incremental risk at a zero price.) The Committee member asked how can you say this, if you are paid $4.25/MW. (Proponents: Mr. Gordon replied that our view is that the resource is paid $4.50 for 94% of output and zero for the rest.) (5) A Committee member stated that it seemed to him that the real difference to be addressed here is that these generators receive additional risk that is not imposed on generators outside of Connecticut. 2 (6) A Committee member stated his belief that a similar proposal was made several months ago and was opposed by the ISO because of the software requirements and that it would only apply for a single Capacity Commitment Period. Would this proposal require ISO settlement or other software changes? Are you proposing a sunset on this provision? (Proponents: Mr. Gordon answered that we see no application beyond the floor price.) The Committee member asked if the floor price were to remain effective, would you keep this provision. (Proponents: Yes.) The Committee member asked how many of those resources eligible to prorate based on MW elected not to prorate. Another Committee member stated there were a few but not many. (Proponents: Mr. Gordon stated that we do not know, however, 100% of these resources had the opportunity to do so.) (7) A Committee member asked if this proposal is agnostic as to eligible resource type. (Proponents: Yes, however, we were not certain how to apply this to DR where there is no explicit Shortage Event penalty.) Agenda Item #2: COMPETITIVE OFFERS OF CAPACITY IMPORTS The Vice-Chair pointed out that today’s discussion is limited to the ISO New England Manuals and whether they reflect what is contained in the filed Market Rule 1 language. This is not an opportunity to re-debate the Market Rule 1 provisions. Ms. DiGrande proceeded to present these revisions to the Committee: (1) The filed Market Rule 1 revisions added an offer requirement on External Transactions supporting ICAP Import Contracts and a failure to offer trigger for violations. These revisions also changed the calculation of the failure to deliver penalty to remove the EFORd margin. (2) The objective of today’s subject is to review the Manual revisions which conform to the filed Market Rule 1 revisions and add some detail. Ms. DiGrande presented the proposed revisions to ISO New England Manual M-11: (1) In Section 1.2.3, new language is added to provide for the posting of competitive offer thresholds (i.e., ex ante value, ex post value, final is max of the two). We will post the ex ante value by 10:30 a.m. The following points were raised with respect to these proposed changes to Section 1.2.3: (A) A Committee member asked whether, instead of using the previous day’s ex ante offer for mitigation, we could use later data once we have it. (ISO: The ISO asked would this occur prior to noon when offers are due. We will take that issue back.) The Committee member replied since we do not change the offer and just apply a penalty after the fact, why not use later data even if it becomes available after noon. In these situations we should apply the ex post or ex ante or later ex ante value. (B) A Committee member asked if the ex ante value were $100 and a Market Participant entered a $200 bid but the ex post value was $150, would there be a penalty. (ISO: Yes. The ISO stated that if the offer was at or below the maximum of the ex ante or ex post value, there would be a penalty. In both cases, these prices are 30-day averages so the missing data points (a few hours or even a day over the 30-day average) should not normally have a significant impact on the result. We will, nevertheless, look at the 3 proposal to use data on the ex ante value that we obtain after 10:00 a.m. for this calculation.) (2) Also in Section 1.2.3, a new subsection (17) indicating that the ISO will be posting the final competitive offer threshold 2 days after the Operating Day has been added. (A) A Committee member asked if these were hourly or daily values. (ISO: The ISO replied that the ex ante value is a daily value that is applied to each hour. The ex post value is hourly. The final is the greater of the ex ante or ex post value for each hour.) (3) Section 1.3.2 applies the competitive offer price threshold to priced External Transactions. (A) A Committee member suggested that we add a reference to section 18.104.22.168.2 for “competitively priced”. (ISO: OK.) (4) Section 2.5.1 has been revised to add the 10:30 a.m. posting to the activities list. (5) Several sections were revised to add references to the competitive offer price requirement. (6) For ICAP Imports, it has been clarified that the External Transactions offering in support of ICAP are required to offer into the Day-Ahead and Real-Time Energy Markets at a competitive price if submitted as a priced External Transaction. (7) For priced External Transactions, a competitive offer price is required if the External Transaction is backing an ICAP Import Contract. Ms. DiGrande then summarized the proposed revisions to ISO New England Manual M-20: (1) Revisions to Section 22.214.171.124 add the competitive price requirement to the offers required to be submitted by noon of the day before the Operating Day and added a reference to the exemption from the 24 hour offer requirement in certain circumstances. (2) Section 3.8.8 is revised to add the competitive offer threshold with a cross reference to Market Rule 1 and to add an example based on a failure to check-out with the other Control Area. Two points were raised by Committee members on this point: (A) A Committee member asked if this penalty provision would apply to curtailment due to TTC reductions. (ISO: No. That would be an ISO directed reduction.) (B) A Committee member asked if the previous response would change if it were the other Control Area that curtails transmission. (ISO: The ISO replied that in that case, presuming the reduction is for TTC across the tie line, ISO-NE would be reducing the TTC as well.) (C) A Committee member asked, with respect to Section 126.96.36.199 (4), whether we needed a parallel section for the Day-Ahead Energy Market. (ISO: The ISO believes the parallel section for the Day-Ahead Energy Market is contained in the Manual, however, we will check on that.) Agenda Item #3: FUTURE TREATMENT OF PRICE-RESPONSIVE DEMAND IN NEW ENGLAND Comverge Presentation Mr. Swalwell presented a review of the PJM approach for PRD and its current status to the Committee. After the presentation, the following points were raised: (1) A Committee member asked if the Industrial Customer Coalition (ICC) had a proposal in the PJM discussions. 4 (Comverge: Mr. Swalwell replied that the ICC ended up supporting PJM’s proposal (15% of the hours from the prior year sets the price at which the full LMP would be paid). DR does not burn fuel so that a fuel-price index did not seem appropriate to most. The remaining points of disagreement in PJM are whether to use the highest priced 15% versus 5% of hours and whether or not to have a sunset provision on payments of the full LMP.) (2) A Committee member noted that for the 2002-2007 time period, resources were paid the full LMP when the LMP was above $75. Were there any customer baseline provisions to measure performance? (Comverge: Yes. Mr. Swalwell stated that subject will be addressed later in the presentation.) (3) The ISO stated its understanding that the proposal includes a 3-year option for full LMP payment, that there were two proposals voted, and that both proposals failed to pass and were sent to working groups. Is that correct? (Comverge: Mr. Swalwell replied that on the 3-year option, that is correct. A resource can continue to participate after the three years, but not at the full LMP. There were two proposals and they were sent back from the PJM Board of Governors to its markets committee. State regulators intervened on the sunset provisions.) (4) A Committee member asked who pays for these programs in PJM. (Comverge: Mr. Swalwell answered that the LSE pays the difference between the applicable LMP and the retail rate. Where the full LMP is paid to DR, that cost is socialized to all who pay the LMPs.) The Committee member commented that we need to clarify who is an LSE. This terminology is different in PJM and ISO New England. (5) A Committee member pointed out that, initially, there were 4 proposals placed through the committee process in PJM, all of which were voted. None of the proposals received sufficient majority support. The ICC proposal received a majority but not enough to pass and so will be the first proposal voted in June. The ICC proposal leveraged off PJM’s proposal with 2 differences; (1) payment of the Day-Ahead LMP for those in the Day-Ahead Energy Market and (2) instead of a sunset provision, there would be a market-based determination of whether to continue based on a PJM study. For Day-Ahead Energy Market clearing, could you comment on the opportunity to load shape the amount bid over the day? (Comverge: Mr. Swalwell stated that resources do not have to offer a constant MW over the day in PJM. PJM in essence absorbed the ICC proposal in its most recent proposal.) (6) A Committee member noted that PJM performed a significant analysis on participation over a short number of hours versus participation over a long number of hours which Market Participants have struggled with in both markets. He also stated his belief that PJM has conclusively demonstrated DR lowers LMP and that the only remaining question is whether it is appropriate to compensate DR for lowering the LMP. (7) A Committee member asked how many customers fell off because of the change in compensation versus lack of infrastructure. (Comverge: Mr. Swalwell stated that PJM does not know this answer because it uses account level registrations. The ICC members were vocal that their drop in participation was due to compensation changes. As a DR Provider, our drop-off was across the board. There is anecdotal evidence only at this point.) (8) A Committee member stated that there are published materials that show a drop-off in participation with pricing changes. DR participation was increased by large amounts prior to the decrease in compensation but, with the price change, participation actually decreased despite similar LMP levels. In addition, there are two types of barriers; entry (mostly infrastructure) and participation (numerous lost opportunity costs). 5 (9) A Committee member asked about the distinction between LSE and Market Participant in PJM and whether an end-use customer can also be an LSE in PJM. (Comverge: Mr. Swalwell answered once an End User becomes its own LSE, it no longer participates in these programs because it does not make sense for them to do so.) Mr. Swalwell continued his presentation by outlining PJM revisions to the customer baseline (using a 45-day window excluding event days and going back a maximum of 60 days) to obtain 4 days of data. If there are not 4 days without events in the period examined, Event Days will be counted to get at least 4 days’ data. Alternative customer baselines can be proposed where this process does not work for a particular supplier. Once approved by PJM, an alternate customer baseline can become part of a library of available customer baseline methodologies. Mr. Swalwell also briefly outlined PJM’s Administrative Review Procedures. The Chair suggested that any further questions be forwarded to the Committee Secretary. We will forward these questions to the speaker and we will either have him come back or ask that he provide written responses to the questions. Future of PRD in New England Mr. Sipe presented the CDRI proposal to the Committee. Among the points he provided were the following: (1) This proposal provides for payment for deviation that would not occur without compensation. (2) As a general proposition, it is better to have accurate price signals that are visible to customers. (3) The ISO’s proposal and the other stakeholder supply-side proposals filter down to being elaborate rate design improvements, however, they will not achieve the optimal amount of DR that will be needed in New England. We will not achieve a level of DR participation that lowers LMPs for all. (4) Under the CDRI proposal, DR is not limited to items that are accomplished at the flip of a switch. This proposal includes longer term options that the algorithm can capture (i.e., shifting of an entire process to some other time period). After this portion of the presentation, the ISO asked if a LSE bids less load into the Day- Ahead Energy Market under the assumption that the day before’s Real-Time load is its load (not the DR Provider’s), would less of that LSE’s load clear in the Day-Ahead Energy Market and be priced at Real-Time. Mr. Sipe responded yes, Market Participants will figure that out over time. The ISO asked at what price does Day-Ahead priced bid-in load clear (i.e., clearing price or Day- Ahead Energy Market price). Mr. Sipe replied that his preliminary answer is that it would clear against the Day-Ahead Energy Market price (which includes the impact of DR). Mr. Sipe resumed his presentation with a discussion of customer baseline issues, including: (1) The issue with symmetric weather adjustments. (2) The issue with one-size fits all. (3) The issue with perfection. (4) Maintenance, shutdowns, and vacations. 6 Mr. Sipe acknowledged that there is a gaming concern in the current customer baseline methodology, however, the ISO’s revised methodology unduly interferes with legitimate pre- positioning. The current and proposed methodologies unduly stress reductions at the throw of a switch versus longer term actions that may make more sense. We need more flexibility to make this more usable for most customers. We ought to rely on the INTMMU’s review to address gaming or market power abuse rather than hardwire a restrictive market design to address these issues. Payments for coordination of maintenance schedules and vacation timing would help the system. We should make maintenance and vacation outages and their relocation biddable in some way and find a way to compensate resources that are flexible. Mr. Sipe also summarized a number of bidding issues which included the following: (1) Use of conditional bids. (2) Allow bidding of DR in blocks. (3) Provide for minimum and maximum run times. (4) Shoulder periods (ski area can come off but must be for minimum number of hours). (5) Should generators have more bid flexibility? After this portion of the presentation, the following points were raised: (1) A Committee member stated that under the CDRI proposal 100% of the compensated resources are presumed to reduce LMP. How can you justify that assumption? (CDRI: Mr. Sipe replied that justification of that assumption is not required. This statement is just a proof of concept and not a perfect system. The available evidence makes me believe DR lowers LMPs. The data from PJM indicates DR lowers LMPs. There is minimal evidence that the load would be reduced without DR. We need to design a customer baseline methodology to capture this impact as much as possible.) The Committee member asked if the reductions that would occur anyway have the same effect on LMPs. (CDRI: Yes.) (2) A Committee member asked, since under this proposal DR is paid as bid in the Day-Ahead Energy Market, what is the obligation to perform in Real-Time. (CDRI: Mr. Sipe replied that the obligation is to provide the bid-in reduction from its customer baseline.) The Committee member asked is there any actual obligation to do so. (CDRI: Yes.) The Committee member then asked is there a penalty. (CDRI: Mr. Sipe answered that is the next subject for further discussion. What penalty structure would you propose?) (3) A Committee member pointed out that the matrix outlining the various proposals states Real- Time participation is voluntary. (CDRI: Mr. Sipe stated that the intent is if a resource clears in the Day-Ahead Energy Market, it is obligated to perform to what cleared in the Day-Ahead Energy Market.) The Committee member asked will there be negative deviations in Real-Time from the DR cleared in the Day-Ahead Energy Market. (CDRI: No. All negative RTLO deviations would be charged. The amount of RTLO deviation from DR that cleared in the Day-Ahead Energy Market could not be separately identified.) (4) A Committee member asked if a self-scheduled generator at $200 would be equivalent to DR at $200. 7 (CDRI: Mr. Sipe replied that if DR is on the margin, it sets the LMP at the as-bid price of DR. We could set the LMP based on the next generator, however, this would create a competitive issue by discouraging bid competition among DR. Generators are all paid the clearing price while DR would be paid its as-bid cost.) (5) A Committee member asked why we would over collect in the Day-Ahead Energy Market. (CDRI: Mr. Sipe answered that this is done to solve the missing money issue because you do not know what is going to occur in Real-Time. There will be refunds to LSEs where negative deviations occur in Real-Time.) (6) A Committee member asked if another approach to the missing money issue could be to socialize that cost across all loads. (CDRI: Mr. Sipe replied that in some respects, yes. We are really over-collecting so that the Real-Time settlements work where you do not know which of the 1200 MW gets charged the Day-Ahead price. There really isn’t a missing money issue in terms of not collecting enough to pay all the Day-Ahead loads.) (7) A Committee guest asked doesn’t DR receive less money by being paid as-bid rather than the applicable LMP. Wouldn’t this situation discourage DR participation? (CDRI: Mr. Sipe replied that it might. We should consider whether or not to use the clearing price for everything. This proposal reflects opportunity cost curves at varied price levels. The algorithm works in simple examples with LMP payments. Our interest was in maximizing the participation of DR.) The Committee guest asked how do we resolve disputes about what we want or do we somehow let the market decide. (CDRI: Mr. Sipe stated that he does not believe we can let the market decide what the market design should be. Someone needs to make the policy decisions to establish the market design.) (8) A Committee member sought clarification that if the marginal resource is DR it sets the clearing price, however, other DR in the bid stack receives its as-bid price while all generators receive the clearing price. If we are going to continue to investigate this approach, we would like to see all resources clear at the clearing price. (CDRI: Mr. Sipe stated that he needs someone with more computer horsepower to assure there is stability as there is a lot of DR in the bid stack. Do we see un-dispatch in some cases at very high load levels? Additional study would be needed.) (9) A Committee member asked if this proposal is for all classes and sizes of DR. (CDRI: Mr. Sipe replied that depends on how we get to a customer baseline. The algorithm will work for anything we can calculate a customer baseline for.) (10) A Committee member asked if there would be any impact on LSE bidding behavior because they are held harmless from negative deviations. (CDRI: Mr. Sipe answered that at most, an LSE would be held harmless for DR that may have occurred within its footprint. Also, they are held harmless as a group and not on an individual basis.) (11) A Committee member asked if only one LSE has cleared 1 MW of load in the Day-Ahead Energy Market at $50 and, when we perform the reconciliation amount, it is $100, what happens. (CDRI: Mr. Sipe stated that he does not understand the question.) The Chair suggested a one on one discussion between the two parties. The Committee member then requested that we instead have a list of questions identified for CDRI. 8 The Chair replied that if you have an example or questions, please send them to the Committee Secretary. We will then forward all such questions to Mr. Sipe and distribute to the Committee. NECPUC Status Report Mr. Austin reported on NECPUC’s process regarding the PRD subject. NECPUC has not yet reached a final agreement on its PRD proposal. In broad terms, NECPUC’s approach will be well within the general scope of what the ISO is proposing with some differences and options. The NECPUC proposal should be available for Committee presentation in the near future. Potential Demand-Side Approach for PRD Mr. Yoshimura presented this subject to the Committee. Mr. Yoshimura called the Committee’s attention to the ISO memo posted for this meeting which summarizes an analysis of the ISO proposal for an all-in price for wholesale energy in Real-Time. The ISO proposal takes a two-pronged approach: (1) allow participation through the Real-Time Energy process and (2) use a supply-side option much like PJM’s approach with payment at the LMP minus a proxy for the generation portion of the applicable retail rate. There were numerous questions at the last Committee meeting about the ISO analysis of potential savings. The ISO compared the estimated annual energy bill for the G-1, G-2, and G-3 rates from NGRID to the Real-Time Energy Price. A list of the components included in the Real-Time Energy Price is contained in the materials provided to the Committee. The ISO has worked with NGRID to develop the spreadsheet that was posted for today’s meeting. The wholesale energy product, even with the changes made since the previous Committee discussion, is still 19% to 27% less than Basic Service over the 3 year period studied. Three changes were made since the last meeting: (1) The ISO modified the capacity price to reflect that loads were not at a 100% capacity factor. We instead used class averages that varied from 40% to 60% capacity factor in order for the per MWh capacity rate to collect the amount needed to pay Capacity Resources. This raised the Real-Time wholesale price by 3% to 4%. (2) For the Basic Service Rate, we increased the loss factor from 6% to 8%. This is a conservative assumption based on NGRID amounts of 6% to 8%. (3) The estimated cost of the Renewable Portfolio Standard (RPS) in Massachusetts added to the wholesale value (used NGRID numbers for default service since it is a market-based cost) by 3% to 4%. We presumed this cost would be collected somewhere by someone but not necessarily in the wholesale rate. It was added here to create an apples to apples comparison. Other states’ RPS costs can be added to the spreadsheet when performing your own comparisons. (4) Programs or the ISO’s supply-side approach create lesser benefits because the Real-Time Energy Price approach produced a benefit in 24 of the 28 months studied. After the presentation, the following points were raised: (1) A Committee member asked if the ISO’s table models the LMPs or the LMP less generation proxy. (ISO: The ISO replied the LMP less generation proxy.) The Committee member asked is there any more information available on the ISO supply-side approach. 9 (ISO: Yes. The ISO stated that the supply-side approach is reflected in NEPOOL Counsel’s matrix to be presented later today.) (2) A Committee member asked if it is the Real-Time Energy Price or the Basic Service Rate that is graphed in the pie chart in the ISO’s presentation. (ISO: The ISO replied that it is the Real-Time Energy Price applied to the average G-3 customer load shape for each hour of the 3 year period.) The Committee member asked how does NGRID know the RPS component? Did they receive this component from the entity that bid the Basic Service? (ISO: The ISO replied that it used the RPS rates that NGRID used for its Default Service across the same 3 year period as a proxy for what it would be in the Basic Service. They might not be exactly the same.) (NGRID: Mr. Smith stated that we believe the RPS rates we pay are the same as other suppliers’ cost for RPS.) The Committee member asked why was this period of time and this particular utility chosen? Are these the most favorable numbers for the ISO proposal? (ISO: The ISO chose NGRID because they had publicly available load shapes and other data for these rate classes. For other companies we would need to do a significant amount of pre- processing. Also, NGRID is a large utility, with a large portion of the load in New England. We did not look at other companies, so, no, we did not choose the most favorable data.) (3) A Committee member asked if the ISO had any guesses as to why there is this large difference between Basic Service and Real-Time prices. Is it just Day-Ahead versus Real-Time pricing? Another Committee member wondered why Market Participants bothered with hedging at all if they could achieve a 27% margin. (ISO: The ISO stated that it is probably more like 13% if you back out the 30% reduction price response that is included in the analysis. Also, Basic Service and Real-Time wholesale service are very different products. The Real-Time product places all the risk on consumers. If the Real-Time price is $1000 or more, the consumer pays this price. If the same load is on Basic Service, the supplier takes the hourly price volatility risk for a period of 6 months to a year and, appropriately, charges a risk premium for doing so.) (4) A Committee guest asked whether the 30% reduction for price response is aggressive, expected or something else. (ISO: The ISO did not perform that analysis. We took a simplified approach that whenever the price reaches a level (i.e., $100) the customer would reduce load by 30%. This was probably fairly aggressive (10% to 15% might be more realistic).) (5) A Committee member stated that he was used to seeing these results on a $/MWh or $/kW basis. Can the ISO provide this? (ISO: Yes. It is provided on the ISO web site.) The Committee member asked does this include the breakdown for Basic Service. (ISO: No. The ISO does not think it is bid that way. It is our understanding that the RFP requests a price per kWh that covers these elements. The spreadsheet is hour by hour so it can be done for any day, hour, month, year etc. based on the assumptions in the spreadsheet.) The Committee member requested the ISO provide the pie chart in its presentation in $/MWh units. (ISO: OK. The ISO will take the totals and divide by the MWh that the class average customer consumed.) (6) A Committee member sought clarification that what was modeled was a 30% reduction in load where the LMP hits the trigger price. (ISO: Yes.) 10 The Committee member asked with this aggressive reduction, what would the percentage of total energy market penetration be. Would it be fairly small still? (ISO: The ISO is not sure. $100 is not that high a price for this period of time. As a guess, it looks like the PJM proposal’s 15% of hours but it would vary by year.) (7) A Committee member asked what could we do in terms of DR? He further stated that he cannot believe the differential between Real-Time pricing and Basic Service in this presentation. He suggested that the ISO should stay with Real-Time information and the effect of actions without a comparison to Basic Service. (8) A Committee member said that it was not surprising to see this level of savings. He wondered if there was a distinction to be made on price elasticity between the two groups. Is it reasonable to assume the same response by those who receive only bill savings and those that receive bill savings plus LMP? Would it be reasonable to assume the latter group might do more? (ISO: The ISO stated that the comparison we presented was between those who could elect the unhedged Real-Time price and not pay a retail rate and those paid the LMP less a proxy for part of the retail rate. It is probably reasonable to conclude that if we had a compensation scheme that allows a resource to both avoid paying the LMP and receive payment, the increased compensation would create more response.) (9) A Committee member asked if this plan would require the ISO to become a LSE. (ISO: No. The ISO replied that this product would be offered in the wholesale market, the same as the other products. There would need to be adjustments for settlements, customer service, credit worthiness, etc. We would need to change our processes to deal with smaller customers, most of whom might be end users or aggregators of end users. We would need to behave more like Charles Schwab and less like the NYSE.) (10) A Committee guest indicated that he thought the ISO proposal would lower the bar to retail customers participating as wholesale customers in the New England markets. (ISO: Yes. The ISO stated that there would be more access to wholesale markets. By definition, those participating in such markets would be wholesale customers. It is not clear to us that it would be cost effective to offer this service to individual residential customers, especially initially. In order to service residential customers, there would need to be interval metering with the residential customer class.) (11) A Committee member asked what are the implications as more customers switch to Real-Time pricing for those that cannot or just do not switch (e.g., residential customers). (ISO: The ISO answered that Real-Time pricing is probably not for everyone and could be expensive and risky for some. We would expect that customers who can achieve the most savings would take advantage. This could mean that basic service would become a more expensive item to the extent that customers with more attractive load profiles leave basic service.) (12) A Committee member asked if there is some level of savings that has to be demonstrated on an apples to apples analysis for us to pursue Tariff changes. (ISO: The ISO replied that when we discuss the matrix we will discuss process as well. We were not really looking at any threshold just whether loads could benefit. The first requirement is meeting the filing deadline in July. What options are we going to recommend to the FERC?) (13) A Committee member noted that there are numerous issues to be addressed in the implementation of these options. For the Real-Time pricing option we would be offering a service at the retail level with no idea how many customers will use what could be a very expensive program. Simply demonstrating potential savings will not guarantee a large 11 percentage of customers would participate in this market. We should not expend a significant amount of money to design and implement something no one will use. (14) A Committee member asked if the ISO can provide 2005 and 2009 YTD data. She also indicated that the savings may be inflated because of the inclusion of 2006 which was impacted by Hurricane Katrina. (ISO: The ISO replied if we can retrieve the data, we will provide the additional analysis results. Other Committee members have asked for a larger data base. Can your company provide its data for 2005-2009 YTD as well?) The Committee member indicated that she would pursue this request at her company. (15) A Committee member sought confirmation that those electing Real-Time pricing would no longer be in the retail program. She also urged the ISO to retrieve additional data to see if the margin between Real-Time prices and basic service rates is really there. Evaluation Matrix of PRD Approaches Ms. Gardner presented the matrix and solicited input on getting the matrix ready for use in framing the discussion at our next Committee meeting and moving towards a design basis document that would be transformed into proposed Market Rule 1 language. After the presentation, the following input was offered: (1) A Committee member suggested that we need to have a field that tells us whether the Day- Ahead and/or Real-Time dispatch or pricing algorithm change for each proposal. (NEPOOL Counsel: OK. Ms. Gardner stated that she will also add earlier written comments received from other stakeholders. If you have an approach you think should be added or pieces of the PJM approach you think we should consider, please provide them to me.) (2) A Committee member suggested adding something about the penetration of DR (in percentage terms) in the market that is estimated for each approach. (ISO: The ISO asked how this suggestion would be accomplished.) The Committee member stated that we will work with you on this topic. (3) A Committee member asked whether the ISO is still thinking about a supply-side option. If so, have you added additional details since the last two weeks? (ISO: The ISO is proposing both approaches as a package in order to make both options available.) (4) A Committee member asked how much will these proposals cost to implement? We need the ISO to provide an estimate of what its proposal might cost. Not a cost-benefit analysis. Just a rough cost estimate. (5) A Committee guest indicated that he would like to schedule time on a future Committee meeting agenda to provide a presentation on how these options relate to standard offer from a state regulatory perspective. (6) A Committee member stated that we need to clarify whether this can even be accomplished in some of the states without legislative changes. A Committee guest replied that it seemed to him that there are work-arounds to avoid law changes from being required. Agenda Item #4: OTHER BUSINESS The Chair announced that the Committee is in need of a Chair for the Information Policy Working Group and urged Committee members to forward any nominations they might have to the Chair and NEPOOL Counsel. 12 NEXT MEETING The next meeting of the Markets Committee is scheduled to be held on June 9 and 10, 2009 at the Courtyard Marriott in Marlborough, MA. Respectfully submitted, ______/s/____________ Alex W. Kuznecow Secretary Markets Committee 13