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MINUTES OF THE
MARKETS COMMITTEE (MC) MEETING
HELD ON TUESDAY AND WEDNESDAY, JANUARY 13 and 14, 2015
IN WESTBOROUGH, MASSACHUSETTS
|Attendee |01/13 |01/14 |Member/ |Market Participant |
| | | |Alternate | |
|A. DiGrande |( |( |Chair |ISO New England Inc. |
|E. Abend |(* |(* |Member |Summit Hydropower, Inc. |
|K. Abernethy | |(* |Member |Ameresco CT LLC |
|C. Belew |( |( |Member |Mass Attorney General’s Office |
|C. A. Bowie |( |( |Member |Northeast Utilities Service Company |
|T. J. Brennan |( | |Member |National Grid, US |
|R. Cables |( |( |Member |United Illuminating Company |
|R. Carrier |( |( |Member |Energy America, LLC |
|D. Cavanaugh |( |( |Member |NRG Power Marketing, LLC |
|N. Chafetz |( |( |Member |Galt Power Inc. |
| | | |Temporary Alternate |Customized Energy Solutions for BP Energy Company, DTE Energy |
| | | | |Trading, Inc., Energy America, LLC, Mercuria Energy, Inc. and Hess |
| | | | |Corporation |
|J. Dannels |( |( |Member |Consolidated Edison Energy, Inc. |
|S. Dimou |( |( |Member |Emera Maine, Inc. |
|J. Elmer |( |( |Member |Conservation Law Foundation |
|D. A. Errichetti |( |( |Alternate |Northeast Utilities Service Company |
|M. A. Erskine |(* |(* |Alternate |Central Maine Power Company |
|F. Ettori |( |( |Member |Vermont Electric Power Company, Inc. |
|W. Fowler |( |( |Member |Granite Ridge Energy, LLC |
| | | |Alternate |EquiPower Resources Management, LLC and Exelon New England |
| | | | |Holdings, LLC |
| | | |Temporary Alternate |Dynegy Power Marketing, LLC, Calpine Energy Services, LP and |
| | | | |Entergy Nuclear Power Marketing LLC |
|B. Forshaw |(* |(* |Member |CMEEC |
|M. Gardner |( |( |Member |NextEra Energy Resources, LLC |
|J. Ginnetti | |(* |Member |EquiPower Resources Management, LLC |
|L. Guilbault |( |( |Member |H.Q. Energy Services (U.S.) Inc. |
|R. Hart |(* |(* |Member |Dominion Energy Marketing, Inc. |
|D. Hurley |( | |Member |Conservation Services Group, Inc. and Energy Federation Inc. |
| | | |Alternate |NH Office of Consumer Advocate |
| | | |Temporary Alternate |EnerNOC, Inc., Harvard Dedicated Energy Limited, The Energy |
| | | | |Consortium, Union of Concerned Scientists and Vermont Energy |
| | | | |Investment Corporation |
|J. Jones | |(* |Alternate |Emera Maine, Inc. |
|T. Kaslow |( |( |Member |GDF SUEZ Energy Marketing NA, Inc./FirstLight Power Resources |
| | | | |Management, LLC |
|J. Keene | |( |Member |First Wind Energy Marketing |
|W. Killgoar |( |( |Member |Long Island Power Authority |
|S. Kirk |( |( |Member |Exelon New England Holdings, LLC |
|A. Krich |(* |(* |Alternate |Generation Group Member |
|B. Kruse |( |( |Alternate |Calpine Energy Services, LP |
|A. W. Kuznecow |( |( |Secretary |ISO New England Inc. |
|A. Mitreski |(* | |Member |Brookfield Energy Marketing, Inc. |
|G. E. Morse |( | |Temporary Alternate |Vermont Public Power Supply Authority |
|J. Parenteau |(* |(* |Member |Reading Municipal Light Department |
|P. Peterson | |(* |Member |NH Office of Consumer Advocate |
| | | |Alternate |Union of Concerned Scientists |
| | | |Temporary Alternate |Harvard Dedicated Energy Limited, PowerOptions, Inc., The Energy |
| | | | |Consortium, The Energy Council of RI, Utility Services, Inc. and |
| | | | |Vermont Energy Investment Corporation |
|F. Plett |( |( |Alternate |Mass Attorney General’s Office |
|J. A. Rotger |( |( |Member |Cross Sound Cable Company, LLC |
|R. de R. Stein |( |( |Alternate |Signal Hill for Footprint Power LLC and H.Q. Energy Services (U.S.)|
| | | | |Inc. |
| | | |Temporary Alternate |Signal Hill for First Wind Energy Marketing and Generation Group |
| | | | |Member |
|B. Swalwell |(* |(* |Member |Tangent Energy Solutions, Inc. |
|D. Thompson |( |( |Temporary Alternate |CT Office of Consumer Counsel |
|B. S. Trayers |( | |Member |Citigroup Energy Inc. |
|J. Wadsworth |( | |Member |Vitol Inc. |
|G. Will |( |( |Member |MMWEC |
| | | |Temporary Alternate |CMEEC |
|Guest | | | |Affiliation |
|B. Anderson |( |( | |NEPGA |
|P. Asarese |( |( | |ISO New England Inc. |
|M. Beganny | |( | |ISO New England Inc. |
|J. Bentz |( |( | |NESCOE |
|T. Bessette |( |( | |MA DPU |
|P. Chattopadhyay |( |( | |NH Office of Consumer Advocate |
|R. Coutu |( | | |ISO New England Inc. |
|R. Coxe |( |( | |Champlain VT, LLC |
|B. D’Antonio |( | | |NESCOE |
|C. J. Denmark |( | | |ISO New England Inc. |
|D. Dolan | |(* | |NEPGA |
|J. Dombrowski |( | | |ISO New England Inc. |
|R. Dominguez | |(* | |ISO New England Inc. |
|J. Douglass |( |( | |ISO New England Inc. |
|C. Fitzpatrick |(* | | |FERC |
|M. Giaimo |( |( | |ISO New England Inc. |
|A. Gillespie |( |( | |ISO New England Inc. |
|M. Gonzalez |( | | |ISO New England Inc. |
|C. Hamal | |(* | |Navigant |
|C. Hamlen |( | | |ISO New England Inc. |
|S. Hodgdon |( |( | |ISO New England Inc. |
|R. Howland |(* | | |NH Electric Cooperative, Inc. |
|E. Jacobi |( |( | |CT DEEP |
|M. Karl |(* | | |ISO New England Inc. |
|K. Kekeisen |( | | |CPV Towantic, LLC |
|M. J. Krolewski |( |( | |VT PSB |
|T. Larkin |( | | |National Grid, US |
|K. Le | |( | |PCI |
|P. Leatch |(* | | |Waterside Power |
|S. Lombardi |( |( | |Day Pitney |
|C. Markum |(* | | |C-Power |
|A. McCullough | |( | |Emera Maine, Inc. |
|J. McDonald | |( | |ISO New England Inc. |
|C. McDonough |( | | |ISO New England Inc. |
|M. Menino |( |(* | |MA DPU |
|J. Murphy |( |( | |MA DPU |
|M. Paquette |(* | | |Northeast Utilities Service Company |
|C. Parent |( |( | |ISO New England Inc. |
|H. Patil | |( | |ISO New England Inc. |
|C. Sedlacek |( | | |ISO New England Inc. |
|L. Sunga | |(* | |Noble Americas Gas & Power Corp. |
|J. Wolfson | |( | |ISO New England Inc. |
| | | | | |
* -- Indicates participated by telephone
After determining that a quorum was present, the meeting was called to order.
Agenda Item #1: CHAIRWOMAN’S OPENING REMARKS
The Chair welcomed the Committee members and had those participating by telephone identify themselves. It was moved, seconded and unanimously approved by the Markets Committee on a show of hands to accept the minutes of December 9th and 10th Markets Committee meeting. The Chair stated the Committee will be asked if the January 22, 2015 Committee meeting should be an in person or a teleconference meeting when agenda item #3 (Elective Transmission Upgrades – Forward Capacity Market Conforming Changes) is discussed today. The Chair also provided the following FCM-related information to the Committee:
(1) Dispatch Zones for FCA #10 have been set and will be the same as they were for FCA #9. Specifically there will be 19 Dispatch Zones. Also, the Show of Interest Window for new resources interested in participating in FCA #10 opens February 17. Notices will be posted on the ISO-NE website as well.
(2) Market Resource Alternative (MRA) analysis for the SEMA/RI sub-area will be presented to PAC on January 28. The MRA analysis provides guidance to interested parties where to locate generation and/or demand side resources to satisfy transmission constraints identified as part of the regional planning process.
Agenda Item #2: FORWARD RESERVE OBLIGATION CHARGE ENHANCEMENTS
Mr. Denmark presented the ISO’s proposed revisions to Market Rule 1 to account for certain complexities related to the cascading and locational reserve accounting differences and their impact on the Forward Reserve Obligation Charge calculation to the Committee. There was no discussion by the Committee. The following motion was moved and seconded by the Markets Committee:
RESOLVED, that the Markets Committee recommends that the Participants Committee support the revisions to Market Rule 1 to account for certain complexities related to cascading and locational reserve accounting differences and their impact on the Forward Reserve Obligation Charge calculation as proposed by ISO New England Inc. (the “ISO”) and as circulated for this meeting with those further changes recommended by this Committee and supported by the ISO and such further non-substantive changes as the Chair and Vice-Chair approve.
The motion was then voted. Based on a show of hands, the motion passed unanimously.
Agenda Item #3: ELECTIVE TRANSMISSION UPGRADES – FORWARD CAPACITY MARKET CONFORMING CHANGES
Dr. Dombrowski presented the ISO’s proposed revisions to Market Rule 1 to implement the FCM changes to support the Elective Transmission Upgrades OATT changes as proposed at the Transmission Committee to the Committee. These incremental revisions are additional revisions as discussed at the last meeting. During and after the presentation, the following points were raised:
(1) A Committee member stated he had a market mitigation-related comparability concern between the situation where the C of the CNIIS is forfeited and the generator non-price retirement process.
(ISO: The ISO replied the IMM will be presenting later during today’s meeting and the issue should be raised there.)
(2) A Committee member stated during the contract period between an ETU and an Import Capacity Resource, the Import Capacity Resource qualifies as a new resource for the first year of the contract. If the contract is for a seven year period, does the Import Capacity Resource become an existing resource for the next six FCAs?
(ISO: The ISO answered the Import Capacity Resource would be qualified in the next six FCAs as an existing resource, consistent with the revised Tariff.)
The Committee member asked what happens if an Import Capacity Resource does not achieve qualification for a new contract period with the ETU?
(ISO: The ISO answered the ETU’s CNIIS becomes a NIIS.)
(3) A Committee member stated Section III.13.6.2.1.1.2 of Market Rule 1 applies only to internal generators and does not apply to the ETU subject.
(ISO: The ISO replied the provisions in the Rights and Obligations section of the FCM rules are scheduled to be reviewed and updated, and that the ISO expects to be back to the committee within the next year.)
(4) A Committee member stated it appears to him that at the conclusion of the 7 year price lock, the ETU has the ability to come back in the FCA without an incremental investment. Can something be done comparable on the generation side when a generator retires and then comes back as a new resource?
(ISO: The ISO replied FCM investment thresholds will apply to the ETU where the C of the CNIIS is forfeited for that ETU to determine whether the election options are available. The main way to lose the C of the CNIIS is when the Import Capacity Resource does not qualify for the upcoming FCA.)
The Committee member asked can an Import Capacity Resource achieve a 7 year price lock as a new resource after the initial contract period with the ETU.
(ISO: The ISO answered the Import Capacity Resource probably cannot be qualified as a new resource after the C is lost unless the ETU invests in an additional transmission upgrade for the second contract period.)
(5) A Committee member asked what if the Market Participant has a 7 year contract to cover the rate lock and then after the initial contract expires signs up for a new contract, can’t the Market Participant continue the 7 year price lock with the new contract.
(ISO: The ISO answered the second contract cannot receive another 7 year price lock absent meeting the investment threshold.)
The Committee member asked if after the initial 7 year contract, can the ETU establish the next contract for a period that is greater than one year.
(ISO: The ISO answered an Import Capacity Resource can submit a contract with an ETU for a period greater than one year in the subsequent contract. This is independent of the 7 year price lock option. The design permits an Import Capacity Resource to qualify over an existing interface as a new resource the first year and as an existing resource for the balance of the contract period.)
(6) A Committee member asked what happens in the year following the expiration of an ETU contract if there is no contract with an Import Capacity Resource in the following year.
(ISO: The ISO answered the CNIIS will revert to energy NIIS in the year following the expiration of the ETU contract.)
(7) A Committee member stated a Market Participant would have a desire to lock in the auction price for another 7 year period after the expiration of the first 7 year period.
(ISO: The ISO replied the 7 year price lock and associated provisioning are not intended to apply on a rolling 7 year basis.)
The Chair stated the Committee will vote on this subject after the Transmission Committee votes on its ETU-related Tariff revisions at its January 20 meeting. The Markets Committee has meeting scheduled for January 22 after the NEPOOL Budget & Finance Subcommittee teleconference meeting. The Chair asked the Committee if its January 22 meeting needs to be an in person meeting or is a teleconference the preferred method. Two Committee members stated their preference for a teleconference meeting on January 22. Hearing no other input, the Chair stated a teleconference meeting will be scheduled to vote on this subject.
Agenda Item #4: LMP CALCULATOR REPLACEMENT
Mr. Coutu presented the ISO’s proposed revisions to Market Rule 1 and ISO-NE Manual M-11 to replace the current Real-Time LMP calculator to the Committee. During and after the presentation, the following points were raised:
(1) A Committee member stated that there were existing LMP calculator descriptions that were struck within the proposed Market Rule 1 and Manual M-11 language and that he had difficulty in finding proposed language that describes the new calculator. Can the ISO point out where the proposed language is located in these two documents.
(ISO: The ISO reviewed the proposed language within Market Rule 1 that describes the new LMP calculator. As an example, Section III.2.5 of Market Rule 1 contains proposed language describing the ISO optimization objective.)
(2) A Committee member asked if the proposed nodal dispatch rate calculation would have similar pricing results when compared to the current LMP calculated pricing results.
(ISO: The ISO replied the differences between the two LMP calculator results will be within 15 cents or so. The IMM also saw similar differences in both directions between the results of the two LMP calculators.)
(3) A Committee member asked does the proposed optimization method not include the operating reserve, congestion and transmission losses.
(ISO: The ISO answered it does not minimize the operating reserve in the optimization method. Operating reserve is a constraint. There is no direct cost for operating reserve, only a requirement for operating reserve. The ISO is not changing the optimization calculation; it is just correcting the language currently contained in Market Rule 1. There are binding transmission constraints and the software tries to minimize the cost of respecting those constraints.)
Several Committee members expressed their appreciation of the ISO’s effort on this subject. The Chair stated the ISO will be seeking a vote on this subject at the February Committee meeting.
Agenda Item #5: PEAK ENERGY RENTS (PER) MODIFICATIONS: CCP10 AND BEYOND
Dr. McDonough presented the ISO’s proposal regarding the PER mechanism for the 6/1/19 – 5/31/20 Capacity Commitment Period and beyond to the Committee. During and after the presentation, the following points were raised:
(1) A Committee member asked if the ISO knows whether or not generators actually built the expected PER Adjustment values into their FCA offers.
(ISO: The ISO answered yes, generators have had this ability from the start of the FCM and some have opted to do so. However, with a plethora of capacity in previous FCAs, the expected PER adjustment probably had a minimal impact on FCA clearing prices.)
(2) A Committee member stated he knew capacity suppliers had an option of including PER as part of their new capacity price and thinks that the IMM would have developed their expected value of PER for mitigation review purposes. If the IMM expected values were compared with the actual values over the past FCAs, how did these expectations measure up?
(ISO: The ISO replied that in general the IMM reviews the bids for internal consistency. For example, if a resource uses one year of historical data to formulate part of its bid, it should also use one year of historical data to formulate other parts of its bid unless the resource has a compelling reason why a different method or time horizon should be used for a particular component. The ISO does not believe that the IMM generates its own estimate of the expected PER adjustment as part of its review process but this question should be directed to the IMM.)
(3) A Committee member stated that the PER adjustment mechanism never made sense and he supports the ISO proposal to delete the PER adjustment mechanism.
(4) A Committee member stated the ISO should be looking at whether resources are bidding the premium in the FCA. The objective of the FCM is that over the long run the demand curve will be setting the FCA clearing price at the CONE value. The question is how much of the risk should be included in the resource offer based on the demand curve.
Another Committee member stated the FCA will have offers reflecting the 43 cents and the demand curve without the PER adjustment (green curve) on slide 8 of the ISO’s presentation will be more parallel rather than intersecting at the foot.
(ISO: The ISO replied that eliminating the PER adjustment will only impact the starting price which is based on Net CONE, the foot of the demand curve is unaffected by the elimination of the PER adjustment because it is not set based on Net CONE.)
(5) A Committee guest asked is there a particular reason for the ISO to request a vote in February vs. March for this subject. Is it due to the litigation proceedings at FERC?
(ISO: The schedule has been set to ensure that the proposed change for FCA 10 is implemented prior to the due date for FCA 10 de-list bids on June 1, 2015. Although a FERC Order in response to the NEPGA complaint may not be issued prior to the Markets Committee vote, the FERC Order is likely to be released before the Participants Committee’s scheduled vote on this subject at its March meeting.)
(6) A Committee member stated he needed a better understanding of the CONE value based on the newest combined cycle technology. What are the theoretical risk premiums for these efficient combine cycle units? We need to be focused on the expectation of the efficient combined cycle CONE value to include the assumed risk premium and how that can be achieved moving forward. We need a better understanding of whether the PER adjustment mechanism as an insurance hedge provides any value to load.
A Committee guest stated he was not clear what was requested by the previous speaker.
(ISO: The ISO asked if the request was to provided more detail on how the $0.43 kW-mo estimate of the PER adjustment currently included in the Net CONE calculation was developed by The Brattle Group.)
The Committee member replied that is the first request. The second request is to have Dr. Cramton evaluate whether the insurance hedge provides any value.
(ISO: The ISO replied that the detail behind the $0.43 kW- mo estimate of the PER adjustment is included in the testimony supplied by The Brattle Group in support of its estimate of Net CONE. The ISO can provide additional detail regarding the approach used by The Brattle Group to develop the $0.43 kW-mo number but it is important to remember that the Net CONE used for FCA 9 and its components has already been vetted with NEPOOL stakeholders, filed and approved by FERC. Since the $0.43 kW-mo estimate is already included in the estimate of Net CONE, this is the number that will be removed from Net CONE if the PER adjustment is eliminated. As far as the Dr. Cramton review request, the ISO is not sure what we would ask Dr. Cramton to opine on regarding The Brattle Group estimate.)
The Committee member replied we need to understand whether the insurance hedge is still required or should it be eliminated as being proposed by the ISO. Dr. Cramton would provide his opinion on this question as he was involved in establishing the PER adjustment mechanism during the FCM settlement discussions.
(ISO: The ISO replied Dr. Cramton supported the PER adjustment prior to the implementation of the FCM. That view was based on economic theory and not on the five years of practical experience that we now have with the PER adjustment mechanism since the first Capacity Commitment Period in 2010. The proposal to eliminate the PER adjustment mechanism is based on practical issues and not economic theory. As we have discussed, from a theoretical perspective, the PER adjustment mechanism seems like a helpful way to reduce risk for end use customers and resource owners. However, theory does not consider or acknowledge the realities of how well the PER adjustment mechanism hedges against peak energy rents or the fact that the structure of retail supply arrangements in New England renders the PER adjustment effectively redundant to end use customers. In short, the ISO does not think a memo from Dr. Cramton is necessary to acknowledge the practical realities that the ISO, IMM and many Market Participants have been able to readily observe over the past five years.
(7) A Committee member stated the ISO’s proposal is to reduce the Net CONE value by 43 cents starting with FCA 10. The Dr. Cramton request would be simply stating that we have 10 years of experience with the PER adjustment mechanism and did the results of the PER adjustment mechanism turn out the way Dr. Cramton thought it would.
Another Committee member stated we have the Internal Market Monitor and the External Market Monitor that can look at this subject. In response to the insurance policy argument stated earlier, an entity purchases insurance for a claim that the entity may need to make in the future. The entity does not buy insurance for another entity’s property. A Market Participant sells energy in the Day-Ahead Energy Market and then pays a Real-Time Energy Market based PER value, that payment is a pure penalty payment. Anyone going into that business will need to factor in this penalty value in its price. Trying to achieve precision on speculative prices cannot be done.
(8) A Committee member stated none of her LSE clients view the PER adjustment mechanism as a hedge. They will try to estimate the PER value and factor it into their pricing. An LSE will purchase its own separate hedge for energy pricing. If energy prices spike the hedging entity will not see the PER value.
(9) A Committee member stated he needed more information than what is explained in the ISO’s presentation to undo the PER adjustment mechanism. Dr. Cramton would be the appropriate person to address this subject because he is the only one who can explain that the fact that the PER adjustment is based on the Real-Time LMP and most load clears in the Day-Ahead Energy Market should not be an issue for resource owners because real-time peak energy rents are embedded in the Day-Ahead LMPs.
(ISO: The ISO stated just to be clear, the proposal to eliminate the PER adjustment is based on practical issues with the PER adjustment that have nothing to do with the fact that the PER adjustment is calculated based on the Real-Time LMP and most load clears in the Day-Ahead Energy Market. Although some Market Participants clearly believe that this difference creates an added disconnect between the PER adjustment mechanism and payment/receipt of peak energy rents, the ISO has not identified this as one of its practical concerns about the PER adjustment which are noted on slide 5 of its presentation. With regard to the need for external endorsements for the proposed elimination of the PER adjustment, the ISO has spoken with Dr. Patton (External Market Monitor) and he is on board to eliminate the PER adjustment mechanism. The IMM is also on board to eliminate the PER adjustment mechanism. The ISO can have Dr. Patton provide his opinion on the ISO proposal to the Committee.)
The Committee member agreed that we would not need Dr. Cramton to weigh in on the Day-Ahead/Real-Time convergence issues but observed that since Dr. Cramton explained the value of the PER adjustment mechanism in the past that it would be appropriate for him to weigh in on this proposal.
(10) A Committee member asked what will the ISO do for FCA 11 regarding the Net CONE value.
(ISO: The ISO answered it will not include the PER adjustment in the Net CONE calculation.)
The Committee member asked will the proposed Market Rule language be deleted for FCA 11 and beyond.
(ISO: ISO Legal Counsel answered there would be some conforming changes proposed to the Committee as we approach 2019. The conforming changes would be on the order of removing the Market Rule provisions that are being utilized up to 2019.)
The Committee member asked if the recalculation of Net CONE is performed every 3 years.
(ISO: The ISO answered the recalculation of CONE is performed every 3 years at a minimum.)
Agenda Item #6: WINTER RELIABILITY SOLUTION: WINTER PERIODS PRIOR TO JUNE 1, 2018
Mr. Gillespie opened the discussion of the objective(s) that would be addressed by a winter reliability solution for the winter periods prior to the June 1, 2018 implementation date of FCM Performance Incentives with the Committee. During and after the presentation, the following points were raised:
(1) A Committee member asked if the ISO is planning to change the existing winter reliability program for the winter periods prior to June 1, 2018 if consensus is not reached by the Committee on a winter reliability solution.
(ISO: The ISO does not plan to pursue any additional comphrensive changes to the existing winter reliability program. The ISO plans to discuss how the current winter panned out and associated affects from the existing winter reliability program in the mid-February/March time frame.)
(2) A Committee member asked will the ISO be trying to find the line between large and small changes in its evaluation (e.g., the amount of fuel to be purchased and revise the program dates.).
(ISO: The ISO answered the fuel quantity changes will be dependent on what occurs this winter. Fuel assurance is the objective of the winter reliability program. The ISO perceives this program to work like ICR; price and quantity are the components that can change.)
Mr. Wadsworth (Vitol) proceeded to present a set of market considerations for future winter reliability solutions in New England. After the presentation, the following point was raised:
(1) A Committee member asked about the timing of the market considerations being presented.
(Vitol: Mr. Wadsworth replied the 150 day position shown on his charts represents the month of June and if the spark spread is negative it is rational to lock in the futures price. During the August/September timeframe the spark spread becomes positive and this results in an opportunity to sell power and buy fuel forward.)
A Committee member asked the Chair when will the Committee be asked to take a vote on this subject. The Chair answered the plan is to vote on this subject at the Committee’s March meeting.
Agenda Item #7: FCM OVERHEAD AND CAPITAL COST MITIGATION
Mr. Kirk presented Exelon’s identified issues and associated proposal regarding the mitigation of overhead costs in the FCM to the Committee. During and after the presentation, the following points were raised:
(1) A Committee guest asked if the Exelon proposal contains a default rate differential for the retirement of a coal plant vs. gas plant. Does the proposal contain one default rate for all resource types or separate default rates by resource type?
(Exelon: Mr. Kirk replied there are default rate differences between a coal plant and a gas plant but the differences are very small. The Exelon group that performs the default rate calculations has determined there is a three to five cent difference between coal and gas plants.)
(2) A Committee member stated that not being able to represent these overhead costs across the resource fleet is a concern. We believe those costs should be included in static de-list bids.
(3) A Committee member stated this subject is important for older power plants participating in the FCM. The ability to account for centralized support personnel (e.g., accounting and payroll) within a static de-list bid will allow the resource to recover its actual cost.
(Exelon: Mr. Kirk stated Exelon plans to revisit this subject in the future for newer resources.)
(4) A Committee member stated accounting for centralized costs is one parameter. Other overhead cost parameters include common support services for several plants. We need to receive adequate compensation for this type of support. Is it possible for New England to pursue a stakeholder effort similar to the overhead cost task force process in PJM?
(Exelon: Mr. Kirk replied PJM is pursuing identified buckets of overhead costs and placing a % value to each of the buckets based on the regional costs in PJM.)
The Committee member replied having this type of optionality would be beneficial to New England resource owners.
(Exelon: Mr. Kirk stated in New England we have a resource cost workbook issued by the IMM. Under the Exelon proposal, a default allowance of overhead costs could be included and if the Market Participant has higher costs than the default allowance, the Market Participant would then ask for the additional costs to be included in its bid.)
(5) A Committee member stated that when a resource is experiencing a continued net loss year after year, that resource will seek retirement within the region. We would expect to see fewer occurrences of resources seeking to retire by pursuing this type of proposal in New England.
(IMM: The IMM stated overhead costs are allowed in the Tariff. These type of costs could be allowed in a resource’s static de-list bid but they need to be shown as being avoidable. A default overhead value could contain non-avoidable costs. In order for overhead costs to be included in a de-list bid, the Market Participant must demonstrate that they are avoidable costs.)
(Exelon: Mr. Kirk replied Exelon has submitted these costs to the IMM, however, we have not been able to meet the burden of defining the avoidable costs with the IMM. Exelon has been able to demonstrate that the costs are avoidable in other RTOs. We would appreciate the IMM prescribing the avoidable costs and tell the Market Participant how to meet this burden.)
(6) A Committee member stated FERC has approved this type of proposal in other RTO markets. Would the IMM see a default rate as being acceptable in New England? These are overhead costs that need to be considered in the static de-list bid. It would be helpful to have a subgroup of Market Participants working on this subject that would define a set of acceptable costs. This is a large problem within New England.
(IMM: The IMM reiterated its position that submitted overhead costs need to be shown to be avoidable and if they are not, they should not be included in the static de-list bid.)
The Committee member replied if we do not get this fixed, resources will leave the New England market. We need to be able to work through this issue. It is valid what the RTOs have pursued across the country.
(7) A Committee member stated his support of the generators on this subject. Having penurious overhead costs and losing generators due to this condition and then replacing the lost capacity with $15 capacity cost resources does not bode well for rate payer.
(8) A Committee guest asked if a cap can be established for the avoidable cost value.
(Exelon: Mr. Kirk replied Exelon will review the question.)
Mr. Kirk presented Exelon’s identified issues and associated proposal regarding the allowance of capital expenditures in the FCM to the Committee. During and after the presentation, the following points were raised:
(1) A Committee guest asked if there was a way to claw back some of the recovery cost if the resource receives a higher capacity clearing price in future years.
(Exelon: Mr. Kirk stated that he agrees the capacity market is a boom/bust cycle, however, over a longer period of time (e.g., 15 years) a claw back might be appropriate.)
The Committee guest stated the resource will either over collect or collect nothing in future auctions.
(Exelon: Mr. Kirk replied he does not know what is going to occur in the future auctions. There are scenarios where the resource does not recover any cost.)
(2) A Committee member stated capital costs need to be appropriately reflected. Risk management can address either having certainty in the revenue stream in the amortization schedule or front end the costs for the amortization schedule. A resource may be losing money but there is no assurance that the capital will receive a return. If these costs cannot be managed in the auction then they will need to be managed outside of the auction.
(Exelon: Mr. Kirk replied Exelon could look at a shaved approach with a graduated percentage for the previous two auctions. This approach would have the resource commit to be in the energy market that year and then show the IMM that the dollars have not been spent at this time.)
(3) A Committee member stated that in the first nine FCAs there were 183 non-price retirement requests consisting of 5000 MW while there were zero permanent de-list bid submitted through the permanent de-list bid mechanism. For those requests that involved the Committee member, the non-price retirement requests had a cost estimate. These resources were either going to be marginal or experience a loss and exit the market. If we could have conveyed a price for a non-price retirement request, the market would have determined the non-price retirement decision. New England will continue to see the non-economic retirements that will cost millions and even billions to load by not fixing this issue.
(4) A Committee member stated his support of the generators on this subject. A resource needs to add the capital cost to its bid which would then be recovered over a period of time. There should be some residual compensation.
(5) A Committee member stated there are solid older units with low capacity factors in New England. These units will shutdown if their capital costs are not recoverable.
(IMM: The IMM stated the memo that was provided to the Committee was to assist with the understanding of the current cost recovery process in New England. It addresses many of the points made by Committee members. One of the important points made in the memo is that costs must be shown to be avoidable in order to be included in a de-list bid. With respect to capital expenditures, the capital cost recovery factors in the table included within the Exelon presentation are default factors assuming a 10% Weighted Average Cost of Capital (WACC). If resources believe that they require a greater recovery (e.g., a greater WACC), this can be communicated to the IMM during the de-list bid review process.)
Mr. Kirk stated that he will have the proposed Tariff language ready for the Committee’s February meeting and will ask for a vote at that meeting. A Committee member asked NEPOOL Counsel if presenting proposed Tariff language for the first time and requesting a vote at the same meeting meets the Markets Committee’s protocol. Mr. Lombardi replied that, absent exigent circumstances or in the case of a time-sensitive compliance requirement, the Participants Agreement requires that two Markets Committee meetings, at a minimum, be held to discuss and vote on an item before consideration by the Participants Committee. In practice, the Markets Committee has generally followed a three-meeting minimum to allow for discussions and a vote on a Markets Committee matter. Exelon’s request would not circumvent the Participants Agreement. If a Committee member determines that he/she needs additional information or time to review proposed Tariff language, that member can offer for the Committee’s consideration a motion to defer action. Such a motion would require at least a 2/3 Vote of the Committee to pass and any deferral shall be for no more than thirty-five (35) days from the vote to defer. A Committee guest asked Exelon if June 1 is the sought after implementation date for this subject. Mr. Kirk answered yes. The Chair stated this subject will be noticed for a vote at the February Committee meeting.
Agenda Item #8: FCM SLOPED DEMAND CURVE: LOCAL ZONES
Mr. Hodgdon presented the IMM’s concerns regarding comprehensive competitiveness test and market power concerns to the Committee. During and after the presentation, the following points were raised:
(1) A Committee guest asked if the IMM proposal is suggesting to have some kind of % adder or range regarding the pivotal supplier test.
(IMM: The IMM replied that many inputs to the pivotal supplier test can change prior to the auction. Finalizing the pivotal supplier test results before these inputs are final can produce inaccuracies. This potential outcome is what needs to be addressed.)
(2) A Committee member stated there is capacity that is likely to be offered and has a good chance of clearing (e.g., RTR exemption). Would those types of units be considered differently in the competitiveness test process?
(IMM: The IMM will take into consideration how capacity can and must offer into the auction when addressing this issue.)
(3) A Committee member stated there are Lead Market Participants that toll output on an annual basis for the resource and must submit the capacity offers 3-4 years forward based on the resource owner’s requirement. Those resources should not be included in that specific Market Participant’s pivotal supplier test.
(4) A Committee member stated there are Market Participants that manage a large portfolio where a number of resources within the portfolio are not controlled by the Market Participants, however, they submit the capacity offers for the non-owned resource. The IMM needs to take this situation into consideration when performing the pivotal supplier test. A suggested default would be the Market Participant owned resource within the pivotal supplier test.
(5) A Committee guest asked the IMM whether accounting for new resources would be addressed for this subject.
(IMM: The IMM replied it is looking for feedback on the presented subject. New resources are not included in the test. Is there a reason to include new resources in the test?)
The Committee guest replied a primary concern is the IMM does not know whether the new resources will show up in the auction. The Committee guest stated he would like discuss some of the ideas that have been raised by its members with the IMM after the meeting.
Dr. Patil presented the IMM’s concerns regarding market power in the FCM to the Committee. During and after the presentation, the following points were raised:
(1) A Committee member asked for clarification of the phrase “binding above the mitigated/approved de-list bid price”.
(IMM: The IMM answered it is in reference to the upper bound of the static delist bid after the IMM completes its review. The Market Participant can reduce the mitigated static de-list bid below the IMM approved level or choose to withdraw the mitigated static de-list bid.)
(2) A Committee member asked for clarification of the phrase “exploratory static de-list bids”. Is it to test the IMM to see whether that static de-list bid would clear when the true cost of the resource is lower than its static de-list bid?
(IMM: The IMM answered the phrase relates to the possibility where a Market Participant may be submitting a de-list bid with the objective of seeing what the IMM would accept. In these cases there may not be any intention to send a de-list bid to the FCA.)
The Committee member replied it can be a genuine effort on the part of the Market Participant to lower its static de-list bid. The IMM should not prejudge this action.
(IMM: The IMM replied there are different aspects regarding the lowering of the static de-list bid after the IMM completes its review. One aspect is the window timeframe that the information is available to project costs three years out. The exploratory aspect is the concern where an incentive has resulted to offer the highest cost and then receive the IMM review results which provides the Market Participant with some range of optionality to adjust the static de-list bid downward.)
(3) A Committee guest asked what was the original intent of the flexibility of the static de-list bid review and submittal. The Committee guest stated there is value in knowing that the resource is going to clear vs. the risk of not clearing and the Market Participant would evaluate this position and act appropriately. There are other reasons why a Market Participant would reduce its static de-list bid value. What was the original intent of the pricing flexibility for static de-list bids?
(ISO: The ISO stated the original intent was to provide a resource owner with time to fine tune its cost between the initial submittal of static de-list bids and the auction.)
(4) A Committee member stated he is failing to understand the problem being presented here. What is wrong with static de-list bids being lowered or staying in the auction as a price taker? If the problem is the complete FCM design, then we need to address the FCM design.
(IMM: The IMM replied the issue with the exploratory process is not the lower prices or withdrawn offers. It has to do with the validity of the original submission of the static de-list bid. When we have instances where exploratory bids are submitted, they are submitted to produce a value higher than its true going forward costs. This allows the resource to leave at a price higher than its going forward cost. When this inaccuracy is introduced, the effect could result in higher auction prices.)
The Committee member replied he is concerned the IMM does not have the right tools to determine the accuracy of the static de-list bid costs.
(IMM: The IMM stated it works with the Market Participant regarding its submissions, however, there are some aspects of static de-list bids where the IMM is limited in its knowledge about the resource.)
The Committee member asked if the IMM can improve its insight of the resource’s operations.
(IMM: The IMM responded the original submittal of costs is the accuracy that needs to be met by the resource owner.)
(5) A Committee member stated her belief that externalities, such as the FCM Performance Incentives rules may have had an influence on this subject during the past two FCA cycles. Does the IMM think there were some kind of anomalies in the previous two auctions with the significant overhaul made to the capacity market and the risk premium?
(IMM: The IMM stated its belief there was minor influence from the introduction of the risk premium for the FCM Performance Incentives rules. There was quite a bit of interaction between the IMM and Market Participants during that period. Even after the final determinations were issued by the IMM, many de-list bids were further reduced or withdrawn by Market Participants.)
(6) A Committee member stated he would encourage a different perspective on this issue. The market has not done a good job when it comes to the option value of a resource. The description being provided today appears to be more of an efficiency issue. A Market Participant overstates the static de-list bid and then the bid gets mitigated ending with the result that the mitigated value does not enter the market. There is no single price that reflects the right cost. Each price is based on a set of assumptions established by the Market Participant over a certain time period.
(7) A Committee member stated there is no exact price. The Market Participant cannot develop a price with a 100% certainty. We need to accept that probability and with the existence of the FCM Performance Incentives rules the lowering of the bid is showing acceptance of a higher probability of loss and lowers the price for all participants. What is the problem with lower bids?
(IMM: The IMM answered in cases where market power is identified, we need to establish the accurate going forward costs. The mitigation value might not be low enough due to the initial inflated value.)
The Committee member stated there appears to be a tendency to force economic resources out of the market prior to their actual departure and that is a concern from a load perspective.
(8) A Committee member stated his issue with static de-list bids is that the IMM does not believe the going forward cost being submitted by the Market Participant. If the resource does not take on a CSO then there is no money collected by the resource if the market clears below the static de-list bid offer. The initial static de-list bid is the actual value on behalf of the Market Participant and the IMM does not have to mitigate as much as it does.
(IMM: The IMM replied when it starts seeing history that the costs were reasonable for the resource during the bid preparation and submission, the IMM will arrive at the suggested place.)
(9) A Committee member asked why would the pivotal supplier have an incentive to offer below the mitigated price.
(IMM: The IMM stated it cannot comment on this question.)
(10) A Committee member asked is the IMM thinking of changing the threshold for dynamic de-list bids.
(IMM: The IMM does not have an answer to the question at this time.)
The Committee member reiterated his previous comment to rethink the capacity market design and whether all existing capacity should remain as price takers.
(11) A Committee member stated participating in the capacity market is suppose to be voluntary. The non-price retirement request was structured as the way out of the capacity market so that the Market Participant is not forced to lose money. Do not know a good solution to the problem but do not want the refusal of a non-price retirement request to be a solution.
(IMM: The IMM stated its concern is with uneconomic retirement. The objective is to look at the unit on its own and is it reasonably economic to continue operating the unit (outside of being a part of a portfolio). The IMM is not interested in placing anyone in a money losing position when the unit wants to retire. There are mechanisms in other RTOs that address this subject.)
The Committee member replied non-price retirement requests are submitted late in the FCM process. IMM’s mitigation of the static de-list bid affects the lateness of the non-price retirement request submittal. This is a concern with the timing issue.
(12) A Committee member stated it is late in the process to invoke how to design the capacity market. There has to be a way for a resource to exit the market. The resource should not have to convince anyone when it wants to leave the market. When a static de-list bid turns into a non-price retirement request then there is a failure in the process.
(IMM: The IMM replied it is when the resource is part of a portfolio that the IMM has a concern.)
The Committee member stated if we had competition to have new units replace retired units then we would not have this issue. The solution is to not make the old resources stay in the market forever.
(13) A Committee guest stated retiring old units and adding new units would be more efficient therefore it would have a positive impact on energy market prices due to the higher efficiency of the new units.
(IMM: The IMM replied it may have implications on the energy market or it may not have any implications; we do not know. The issue is when a Market Participant with a portfolio would have more information than other entities participating in the capacity market (e.g., banks would not have that information.)
(14) A Committee member stated the capital expenditure review by the IMM will affect the number of non-price retirement requests that would be submitted in New England. It is suggested that the IMM work with generators to clarify the cost review of static delist bids. Take a look at the Vermont Yankee situation. The ISO does not have Tariff authority to keep the resource within the pool.
(15) A Committee member stated if all existing resources do not have to be price takers, then this issue would stop being an issue.
(IMM: The IMM replied static de-list bids is a way for existing resources to not be a price taker in the auction.)
(16) A Committee guest stated he has a concern with FCA 9 and the potential clearing of small capacity zones with administrative pricing. An entity could have an economic incentive to clear in a small capacity zone even if the static de-list bid costs were 100% accurate. We need to protect the consumers in this situation.
Dr. McDonald presented the IMM’s concerns regarding pricing in the FCM with inadequate supply and no new entry to the Committee. During and after the presentation, the following points were raised:
(1) A Committee member stated he thought this was the whole point of the market and that is to send price signals to the market. Potentially moving back to an administrative price setting process is viewed as being skeptical and hesitant. This will result in an exhaustive effort to determine the correct administrative price for existing resources.
(IMM: The IMM stated it does not have a preferred alternative at this point. It is about achieving the right prices and not high or low prices.)
(2) A Committee member asked if the solution set would be found in the Tariff and not in Appendix A of Market Rule 1.
(IMM: The IMM stated it believes that is a correct statement and does not see how mitigation would be involved.)
(3) A Committee member stated when this subject is compared to other RTOs it is more difficult in New England. The Committee member stated it took 11 years for his company to build a resource in the bay area in California. At what point does a developer commit and take on the risk to develop a project? It is a little bit different for larger developers vs. smaller developers. Placing the information out five years in advance is good step but the Market Participant’s forecast is going to be different from the ISO’s forecast. Do not know what the ISO can do about this subject.
(4) A Committee member asked if the IMM is thinking about reducing information deficiencies. Does the IMM believe these situations lead to pricing that is not optimal and would lead to administrative pricing?
(IMM: The IMM replied little can be done with the barriers to entry issue by the ISO. Information release is an area the ISO can pursue. Impacts on the market that are unintended is another area the ISO can pursue.)
(5) A Committee member stated the barriers to entry issue is usually a dollar problem (i.e., noise mitigation, water availability, etc.). One way address this issue is to link to a reevaluation of CONE for the capacity zone.
(6) A Committee member stated wind, solar and energy efficiency are up and running within a year after permits are gained. Cost forward information is important to the Market Participant.
The Chair stated the IMM will be back at the February Committee meeting with additional information on these subjects.
Agenda Item #9: NEW WEBSITE DEMO AND FEEDBACK
Mr. Beganny presented an overview demonstration of the new ISO website to the Committee. During and after the demonstration, the following points were raised:
(1) A Committee member stated his company does not allow the use of any type of internet browser other than Microsoft’s Internet Explorer (IE). There are a number of issues with the ISO’s new website when utilizing IE including the loss of settings when the back button is used.
(ISO: The ISO replied that IE is the most used browser based on a Google search result, however, there are versions of IE that are not utilizing current browser technology. When Microsoft’s IE9 is implemented it will be a current technology browser. FYI, Chrome is the second most used browser. The only way to address the back button issue at this time is to open a new window.)
(2) A Committee member stated that the CEII certificate process does not work when utilizing Safari. Also, there are issues with an ICS file with the ISO website.
(ISO: The ISO replied Safari works with the back button when utilizing the ISO website. The ICS file does not get updated when it is downloaded from the ISO website.)
The Committee member stated the ISO website does not have a default sort for the ISO calendar when searching for historic meeting materials. One suggestion is to be able to sort Committee meetings by year when searching for historic meeting materials.
(ISO: The ISO suggested the use of the Committee meeting date filter on the left side of the ISO webpage.)
The Committee member replied he would like the capability of being able to scroll further in the Committee meeting date filter function.
(3) A Committee member asked if there was an advanced search capability after a preliminary search within the new ISO website. A nomenclature document would assist this process.
(ISO: The ISO replied the search feature will be addressed this year. One of the current search features is to add “AND” between two search words and the ISO website will search for the phrase that “AND” creates. The ISO will be pursuing the cleanup of the existing 50,000 documents currently residing on the ISO website this year. The cleanup effort will address naming of files, expiration date identification, etc. The ISO will also be establishing a company policy for posting documents to the website this year.)
(4) A Committee member stated the current FCM-related information organization is an issue on the ISO website.
(ISO: The ISO replied the FCM section on the website is scheduled to be reorganized in the first quarter of 2015.)
The Committee member replied one area of improvement would be the organization of the FCA results (e.g., just see the results of the annual FCAs and not the monthly and annual reconfigurations). Another area is the previously mentioned sorting by Committee meeting date when searching for meeting materials. The current meeting date sort only goes back to 2011. Searching by the start date and end date is somewhat annoying. Could we have another selection which would state archives and then be able to sort prior to 2011? Monthly NCPC summaries have disappeared from the new website. We would like to see those summaries back on the website. The daily NCPC summary by type is what is currently available on the ISO website.
(ISO: The ISO will review the monthly NCPC summary report request. When the monthly NCPC summary report is available the ISO will plan to place it on the website.)
The Committee member stated another feature of interest is to be able to look up a FERC filing without knowing the filing date. Is it possible to have a sort capability based on month and year (e.g., month and year drop down)?
(ISO: The ISO stated it will add this request to the statement of work.)
(5) A Committee member stated he is not able to zip separate files listed on the ISO website.
(ISO: The ISO replied website users will be able to zip up to 40 MB when the ISO IT department fixes the zip file bug.)
The Committee member stated part of his routine was to provide a list FERC filings and orders in a report. With the new website, this list can only be developed by copying and pasting one FERC filing name at a time vs. being able to copy and paste a group of names.
(ISO: The ISO replied it is aware of the issue and can provide some tips on how to address this effort.)
(6) A Committee member stated going back beyond 2011 when searching for Committee meeting materials is an issue. He stated he would like to see this area as an archived site and be able to search on a particular day vs. the current year/month entry.
(ISO: The ISO will review the request and see how it can be addressed.)
A number of Committee members stated their appreciation of the ISO’s effort to design and implement the new ISO website. The Chair thanked Mr. Beganny for his new ISO website demonstration. The Chair stated Committee member should feel free to contact Mr. Beganny with questions/suggestions/etc. on the new ISO website.
Agenda Item #10: OTHER BUSINESS
The Chair stated one of the FERC compliance requirements (i.e., to fix a citation in Section III.13.1.3.5.7 of Market Rule 1) contained in its December 15, 2014 Order was determined to be a non-substantive change by the Committee’s Chair and Vice-Chair and this compliance filing subject will not be addressed by the Committee. This note is being provided to the Committee because the non-substantive change decision deals with a FERC compliance requirement.
The Chair informed the Committee that this meeting will be Mr. Calvin Bowie’s last Committee meeting before Mr. Bowie’s retirement. The Chair and Vice-Chair thanked Mr. Bowie for his contributions to NEPOOL and the Committee as a representative of NU. The Vice-Chair presented a retirement gift to Mr. Bowie and wished him well in his retirement. Mr. Stein proceeded to state his pleasure of working with Mr. Bowie over the years addressing the New England wholesale electricity market subjects and wished him all best in his retirement. Mr. Bowie thanked the Committee and its Officers for the kind words and expressed his appreciation of having the experience of working with the Committee members over the years in New England.
NEXT MEETING
The next meeting of the Markets Committee is scheduled to be held on January 22, 2015 by teleconference.
Respectfully submitted,
______/s/____________
Alex W. Kuznecow
Secretary
Markets Committee[pic]
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